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Home My WebLink About20150331Volume II.pdfLet’s turn the answers on. Integrated Resource Plan Volume II - Appendices 2 0 1 5 March 31, 2 0 1 5 This 2015 Integrated Resource Plan Report is based upon the best available information at the time of preparation. The IRP action plan will be implemented as described herein, but is subject to change as new information becomes available or as circumstances change. It is PacifiCorp’s intention to revisit and refresh the IRP action plan no less frequently than annually. Any refreshed IRP action plan will be submitted to the State Commissions for their information. For more information, contact: PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 (503) 813-5245 irp@pacificorp.com http://www.pacificorp.com This report is printed on recycled paper Cover Photos (Top to Bottom): Wind Turbine: Marengo II Solar: Residential Solar Install Transmission: Populus to Terminal Tower Construction Demand-Side Management: Wattsmart Flower Thermal-Gas: Lake Side 1 PACIFICORP – 2015 IRP TABLE OF CONTENTS I TABLE OF CONTENTS Table of Contents ........................................................................................................................... i Index of Tables ............................................................................................................................. vi Index of Figures............................................................................................................................ ix Appendix A – Load Forecast Details ........................................................................................... 1 INTRODUCTION ......................................................................................................................................... 1 Summary Load Forecast ...................................................................................................................... 1 LOAD FORECAST ASSUMPTIONS ............................................................................................................... 4 Regional Economy by Jurisdiction ....................................................................................................... 4 Utah ...................................................................................................................................................... 5 Oregon .................................................................................................................................................. 6 Wyoming ............................................................................................................................................... 7 Washington ........................................................................................................................................... 7 Idaho..................................................................................................................................................... 8 California ............................................................................................................................................. 8 WEATHER ................................................................................................................................................. 9 Statistically Adjusted End-Use (SAE) ................................................................................................. 10 Individual Customer Forecast ............................................................................................................ 10 Actual Load Data ............................................................................................................................... 10 System Losses ..................................................................................................................................... 12 FORECAST METHODOLOGY OVERVIEW ................................................................................................. 12 Class 2 Demand-side Management Resources in the Load Forecast ................................................ 12 Modeling overview ............................................................................................................................. 12 SALES FORECAST AT THE CUSTOMER METER ........................................................................................ 13 Residential .......................................................................................................................................... 14 Commercial ........................................................................................................................................ 14 Industrial ............................................................................................................................................ 14 STATE SUMMARIES ................................................................................................................................. 15 Oregon ................................................................................................................................................ 15 Washington ......................................................................................................................................... 15 California ........................................................................................................................................... 15 Utah .................................................................................................................................................... 16 Idaho................................................................................................................................................... 16 Wyoming ............................................................................................................................................. 17 ALTERNATIVE LOAD FORECAST SCENARIOS ......................................................................................... 17 Appendix B – IRP Regulatory Compliance .............................................................................. 19 INTRODUCTION ....................................................................................................................................... 19 GENERAL COMPLIANCE .......................................................................................................................... 19 California ........................................................................................................................................... 20 Idaho................................................................................................................................................... 20 Oregon ................................................................................................................................................ 21 Utah .................................................................................................................................................... 21 Washington ......................................................................................................................................... 21 Wyoming ............................................................................................................................................. 22 Appendix C – Public Input Process ........................................................................................... 55 PARTICIPANT LIST .................................................................................................................................. 55 Commissions and/or Commission Staff .............................................................................................. 56 Stakeholders and Industry Experts ..................................................................................................... 56 PACIFICORP – 2015 IRP TABLE OF CONTENTS II PUBLIC INPUT MEETINGS ....................................................................................................................... 57 General Meetings ............................................................................................................................... 57 June 5, 2014 – General Public Meeting ......................................................................................... 57 July 17-18, 2014 – General Public Meeting .................................................................................. 58 August 7-8, 2014 – General Public Meeting .................................................................................. 58 September 25-26, 2014 – General Public Meeting ........................................................................ 58 November 14, 2014 – General Public Meeting .............................................................................. 59 December 8, 2014 – Confidential Technical Workshop (Salt Lake City) ..................................... 59 December 10, 2014 – Confidential Technical Workshop (Portland) ............................................. 59 January 29-30, 2015 – General Public Meeting ............................................................................. 59 February 26, 2015 – General Public Meeting ................................................................................ 59 State Meetings .................................................................................................................................... 59 June 10, 2014 – Washington State Stakeholder Meeting ............................................................... 59 June 18, 2014 – Utah State Stakeholder Meeting .......................................................................... 59 June 19, 2014 – Wyoming State Stakeholder Meeting .................................................................. 59 June 26, 2014 – Oregon State Stakeholder Meeting ...................................................................... 59 STAKEHOLDER COMMENTS .................................................................................................................... 59 CONTACT INFORMATION ........................................................................................................................ 61 Appendix D – Demand-Side Management Resources ............................................................. 63 INTRODUCTION ....................................................................................................................................... 63 DEMAND-SIDE RESOURCE POTENTIAL ASSESSMENTS FOR 2015-2034 ................................................. 63 DSM – ECONOMIC CLASS 2 DSM RESOURCE SELECTIONS – PREFERRED PORTFOLIO ......................... 64 DSM – STATE IMPLEMENTATION PLANS ............................................................................................... 64 Background ........................................................................................................................................ 64 DSM Resource Selections ................................................................................................................... 65 Class 1 DSM resources (dispatchable or scheduled firm capacity resources) ............................... 65 Class 2 DSM Resources (energy efficiency) ................................................................................. 65 Class 3 DSM Resources (price responsive capacity resources) ..................................................... 66 Class 4 DSM Resources (Customer Education of Efficient Energy Management) ....................... 67 Program Portfolio Offerings by State for DSM Resource Classes 1, 2, and 4 .................................. 67 Estimated Expenditures by State and Year ......................................................................................... 69 State Specific Demand-Side Management Implementation Plans ...................................................... 69 2015 Demand-Side Management Communications and Outreach Plan ............................................ 71 Overview ........................................................................................................................................ 71 Customer Communications Tactics (all states) .............................................................................. 72 Messaging ...................................................................................................................................... 72 California ....................................................................................................................................... 73 Oregon ........................................................................................................................................... 74 Washington .................................................................................................................................... 75 Idaho .............................................................................................................................................. 77 Utah ................................................................................................................................................ 78 Wyoming ....................................................................................................................................... 80 Communications and Outreach Budget ......................................................................................... 81 Appendix E – Smart Grid .......................................................................................................... 83 INTRODUCTION ....................................................................................................................................... 83 Transmission System Efforts .............................................................................................................. 84 Dynamic Line Rating ..................................................................................................................... 84 Synchrophasors .............................................................................................................................. 84 Distribution System Efforts ................................................................................................................ 84 Distribution Reliability Efforts: Communicating Faulted Circuit Indicators ................................ 84 Customer Information and Demand-Side Management Efforts ......................................................... 85 Advanced Metering Strategy ......................................................................................................... 85 FUTURE SMART GRID ............................................................................................................................. 85 PACIFICORP – 2015 IRP TABLE OF CONTENTS III Appendix F – Flexible Resource Needs Assessment ................................................................ 87 INTRODUCTION ....................................................................................................................................... 87 FLEXIBLE RESOURCE REQUIREMENTS FORECAST.................................................................................. 87 Contingency Reserve .......................................................................................................................... 87 Regulating Margin ............................................................................................................................. 88 FLEXIBLE RESOURCE SUPPLY FORECAST ............................................................................................... 89 FLEXIBLE RESOURCE SUPPLY PLANNING ............................................................................................... 92 Appendix G – Plant Water Consumption ................................................................................. 93 Appendix H – Wind Integration Study ..................................................................................... 97 INTRODUCTION ....................................................................................................................................... 97 Technical Review Committee ............................................................................................................. 98 Executive Summary ............................................................................................................................ 99 DATA .................................................................................................................................................... 101 Historical Load Data .................................................................................................................... 102 Historical Wind Generation Data ................................................................................................. 103 METHODOLOGY .................................................................................................................................... 105 Method Overview ............................................................................................................................. 105 Operating Reserves ...................................................................................................................... 105 Determination of Amount and Costs of Regulating Margin Requirements ................................. 106 Regulating Margin Requirements .................................................................................................... 107 Hypothetical Operational Forecasts ............................................................................................. 107 Analysis of Deviations ................................................................................................................. 112 Back Casting ................................................................................................................................ 116 Application to Component Reserves ........................................................................................... 117 Application of Regulating Margin Reserves in Operations ............................................................. 120 Determination of Wind Integration Costs ........................................................................................ 120 SENSITIVITY STUDIES ........................................................................................................................... 123 Modeling Regulating Margin on a Monthly Basis ....................................................................... 123 Separating Regulating and Following Reserves .......................................................................... 125 ENERGY IMBALANCE MARKET (EIM) .................................................................................................. 126 SUMMARY ............................................................................................................................................. 128 EXHIBIT A - PACIFICORP 2014 WIND INTEGRATION STUDY TECHNICAL MEMO ................................ 130 Background ...................................................................................................................................... 130 TRC Process ..................................................................................................................................... 131 Introduction ...................................................................................................................................... 132 Analytical Methodology ................................................................................................................... 132 Assumptions ...................................................................................................................................... 133 Results .............................................................................................................................................. 133 Discussion and Conclusions ............................................................................................................. 133 Recommendations for Future Work ................................................................................................. 134 Concurrence provided by: ................................................................................................................ 134 Appendix I – Planning Reserve Margin Study....................................................................... 135 INTRODUCTION ..................................................................................................................................... 135 METHODOLOGY .................................................................................................................................... 135 Development of Resource Portfolios ................................................................................................ 136 Development of Reliability Metrics .................................................................................................. 137 Development of System Variable Costs ............................................................................................ 137 Calculating the Incremental Cost of Reliability ............................................................................... 138 RESULTS ............................................................................................................................................... 138 Resource Portfolios .......................................................................................................................... 138 Reliability Metrics ............................................................................................................................ 138 System Costs ..................................................................................................................................... 141 PACIFICORP – 2015 IRP TABLE OF CONTENTS IV Incremental Cost of Reliability ......................................................................................................... 142 CONCLUSION ........................................................................................................................................ 143 Appendix J – Western Resource Adequacy Evaluation ........................................................ 145 INTRODUCTION ..................................................................................................................................... 145 WESTERN ELECTRICITY COORDINATING COUNCIL RESOURCE ADEQUACY ASSESSMENT ................. 145 PACIFIC NORTHWEST RESOURCE ADEQUACY FORUM’S ADEQUACY ASSESSMENT ............................ 149 CUSTOMER VERSUS SHAREHOLDER RISK ALLOCATION ...................................................................... 149 Appendix K – Detail Capacity Expansion Results ................................................................. 151 PORTFOLIO CASE BUILD TABLES ......................................................................................................... 151 Appendix L – Stochastic Production Cost Simulation Results ............................................. 211 INTRODUCTION ..................................................................................................................................... 211 Appendix M – Case Study Fact Sheets ................................................................................... 245 CASE FACT SHEET OVERVIEW .............................................................................................................. 245 CORE CASE FACT SHEETS .................................................................................................................... 248 SENSITIVITY CASE FACT SHEETS ......................................................................................................... 356 Appendix N – 2014 Wind and Solar Capacity Contribution Study ..................................... 405 INTRODUCTION ..................................................................................................................................... 405 METHODOLOGY .................................................................................................................................... 406 RESULTS ............................................................................................................................................... 407 CONCLUSION ........................................................................................................................................ 410 Appendix O – Distributed Generation Resource Assessment Study ................................... 411 INTRODUCTION ..................................................................................................................................... 411 DISTRIBUTED GENERATION RESOURCE ASSESSMENT FOR LONG-TERM PLANNING STUDY ............... 413 EXECUTIVE SUMMARY ......................................................................................................................... 419 INTRODUCTION ..................................................................................................................................... 423 DG TECHNOLOGY DEFINITIONS ........................................................................................................... 427 RESOURCE COST & PERFORMANCE ASSUMPTIONS .............................................................................. 441 DG MARKET POTENTIAL AND BARRIERS ............................................................................................. 450 METHODOLOGY TO DEVELOP 2015 IRP DG PENETRATION FORECASTS ............................................. 457 RESULTS ............................................................................................................................................... 470 APPENDIX A. GLOSSARY ...................................................................................................................... 493 APPENDIX B. SUMMARY TABLE OF RESULTS ....................................................................................... 494 Appendix P – Anaerobic Digesters Resource Assessment Study .......................................... 495 INTRODUCTION ..................................................................................................................................... 495 ANAEROBIC DIGESTERS RESOURCE ASSESSMENT FOR PACIFICORP WASHINGTON SERVICE TERRITORY .............................................................................................................................................................. 497 SECTION 1 – EXECUTIVE SUMMARY ..................................................................................................... 500 SECTION 2 – DIGESTER TECHNOLOGY .................................................................................................. 506 SECTION 3 – POWER PRODUCTION ESTIMATE ...................................................................................... 512 SECTION 4 – ENVIRONMENTAL AND REGULATORY ............................................................................. 522 SECTION 5 – DEVELOPMENT COST ....................................................................................................... 526 SECTION 6 – OPERATING COSTS ........................................................................................................... 528 Appendix Q – Energy Storage Screening Study .................................................................... 531 TABLE OF CONTENTS ............................................................................................................................ 534 1. EXECUTIVE SUMMARY ..................................................................................................................... 538 2. INTRODUCTION ................................................................................................................................. 542 2.1 Integrating Variable Energy Resources ..................................................................................... 542 3. ENERGY STORAGE SYSTEMS AND TECHNOLOGY ............................................................................. 544 3.1 Pumped Storage ......................................................................................................................... 544 3.2 Batteries ..................................................................................................................................... 564 PACIFICORP – 2015 IRP TABLE OF CONTENTS V 3.2 Compressed Air Energy Storage ................................................................................................ 579 3.5 Liquid Air Energy Storage ......................................................................................................... 588 3.6 Supercapacitors .......................................................................................................................... 589 4. COMPARISON OF STORAGE TECHNOLOGIES .................................................................................... 591 4.1 Technology Development ........................................................................................................... 591 4.2 Applications ................................................................................................................................ 592 4.3 Space Requirements ................................................................................................................... 592 4.4 Performance Characteristics ..................................................................................................... 593 4.5 Project Timeline ......................................................................................................................... 595 4.6 Cost ............................................................................................................................................. 595 5. CONCLUSIONS ................................................................................................................................... 597 References ........................................................................................................................................ 598 Appendix R – Uncertainty Parameters Study ........................................................................ 603 PACIFICORP – 2015 IRP INDEX OF TABLES AND FIGURES VI INDEX OF TABLES Table A.1 – Forecasted Annual Load Growth, 2015 through 2024 (Megawatt-hours) ................................ 3 Table A.2 – Forecasted Annual Coincident Peak Load (Megawatts) ........................................................... 3 Table A.3 – Annual Load Growth Change: September 2014 Forecast less October 2013 Forecast (Megawatt-hours) ................................................................................................................................ 3 Table A.4 – Annual Coincident Peak Growth Change: September 2014 Forecast less October 2013 Forecast (Megawatts) .......................................................................................................................... 4 Table A.5 – Weather Normalized Jurisdictional Retail Sales 2000 through 2014 ..................................... 11 Table A.6 – Non-Coincident Jurisdictional Peak 2000 through 2014 ........................................................ 11 Table A.7 – Jurisdictional Contribution to Coincident Peak 2000 through 2014 ....................................... 12 Table A.8 – System Annual Sales Forecast 2015 through 2024 ................................................................. 14 Table A.9 – Forecasted Sales Growth in Oregon ........................................................................................ 15 Table A.10 – Forecasted Sales Growth in Washington .............................................................................. 15 Table A.11 – Forecasted Retail Sales Growth in California ....................................................................... 16 Table A.12 – Forecasted Retail Sales Growth in Utah ............................................................................... 16 Table A.13 – Forecasted Retail Sales Growth in Idaho .............................................................................. 17 Table A.14 – Forecasted Retail Sales Growth in Wyoming ....................................................................... 17 Table B.1 – Integrated Resource Planning Standards and Guidelines Summary by State ......................... 23 Table B.2 – Handling of 2015 IRP Acknowledgment and Other IRP Requirements ................................. 28 Table B.3 – Oregon Public Utility Commission IRP Standard and Guidelines .......................................... 36 Table B.4 – Utah Public Service Commission IRP Standard and Guidelines ............................................ 45 Table B.5 – Washington Utilities and Transportation Commission IRP Standard and Guidelines (RCW 19.280.030 and WAC 480-100-238) ..................................................................................... 50 Table B.6 – Wyoming Public Service Commission IRP Standard and Guidelines (Docket 90000- 107-XO-09) ....................................................................................................................................... 53 Table D.1 – Incremental and Cumulative Class 1 Resource Selections by State, Product and Year ......... 65 Table D.2 – Existing Class 1 DSM resources (2015 Preferred Portfolio) .................................................. 65 Table D.3 – Class 2 DSM Resources (2015 IRP Preferred Portfolio, Incremental Resources) .................. 66 Table D.4 – Existing Program Services and Offerings by Sector and State ............................................... 68 Table D.5 – Existing wattsmart Outreach and Communications Activities ............................................... 69 Table D.6 – Preliminary DSM Program Budget, DSM Classes 1, 2 and 4 ($000) ..................................... 69 Table D.7 – DSM Implementation Items by Sector and State .................................................................... 70 Table F.1 – Reserve Requirements (MW) .................................................................................................. 89 Table F.2 – Flexible Resource Supply Forecast (MW) ............................................................................... 90 Table G.1 – Plant Water Consumption with Acre-Feet Per Year ............................................................... 94 Table G.2 – Plant Water Consumption by State (acre-feet) ........................................................................ 95 Table G.3 – Plant Water Consumption by Fuel Type (acre-feet) ............................................................... 95 Table G.4 – Plant Water Consumption for Plants Located in the Upper Colorado River Basin (acre- feet) ................................................................................................................................................... 96 Table H.1 – 2012 WIS TRC Recommendations ......................................................................................... 98 Table H.2 – Average Annual Regulating Margin Reserves, 2011 – 2013 (MW) ..................................... 100 Table H.3 – Wind Integration Cost, $/MWh ............................................................................................ 100 Table H.4 – Historical Wind Production and Load Data Inventory.......................................................... 101 Table H.5 – Examples of Load Data Anomalies and their Interpolated Solutions ................................... 103 Table H.6 – Percentiles Dividing the June 2013 East Load Regulating Forecasts into 20 Bins ............... 113 Table H.7 – Recorded Interval Load Regulating Forecasts and their Respective Deviations for June 2013 Operational Data from PACE ................................................................................................ 114 Table H.8 – Sample Reference Table for East Load and Wind Following Component Reserves (MW) ............................................................................................................................................... 116 Table H.9 – Sample Reference Table for East Load and Wind Regulating Component Reserves ........... 117 Table H.10 – Load Forecasts and Component Reserve Requirement Data for Hour-ending 11:00 a.m. June 1, 2013 in PACE ..................................................................................................................... 118 PACIFICORP – 2015 IRP INDEX OF TABLES AND FIGURES VII Table H.11 – Interval Wind Forecasts and Component Reserve Requirement Data for Hour-ending 11 a.m. June 1, 2013 in PACE ........................................................................................................ 118 Table H.12 – Wind Integration Cost Simulations in PaR ......................................................................... 121 Table H.13 – Wind Integration Cost Simulations in PaR, 2012 WIS ....................................................... 123 Table H.14 – 2014 Wind Integration Costs, $/MWh ................................................................................ 123 Table H.15 – Comparison of Wind Integration Costs Calculated Using Monthly and Hourly Reserve Requirements as Inputs to PaR, ($/MWh) ...................................................................................... 124 Table H.16 – Average Natural Gas and Electricity Prices Used in the 2012 and 2014 Wind Integration Studies .......................................................................................................................... 124 Table H.17 – Total Load and Wind Monthly Reserves, Separating Regulating and Following Reserves (MW) ............................................................................................................................... 126 Table H.18 – Estimated Reduction in PacifiCorp’s Regulating Margin Due to EIM ............................... 128 Table H.19 – Wind Integration Cost with and without EIM Benefit, $/MWh ......................................... 128 Table H.20 – Regulating Margin Requirements Calculated for PacifiCorp’s System (MW) ................... 129 Table H.21 – 2014 WIS Wind Integration Costs as Compared to 2012 WIS, $/MWh ............................ 129 Table I.1 – Expansion Resources Additions by PRM ............................................................................... 138 Table I.2 – Expected Reliability Metrics by PRM .................................................................................... 139 Table I.3 – Fitted Reliability Metrics by PRM ......................................................................................... 139 Table I.4 – System Variable, Up-front Capital, and Run-rate Fixed Costs by PRM ................................ 141 Table I.5 – Incremental Cost of Reliability by PRM ................................................................................ 142 Table J.1 – 2012 WECC Forecasted Planning Reserve Margins .............................................................. 148 Table K.1 – Core Case Study Reference Guide ........................................................................................ 151 Table K.2 – Sensitivity Case Study Reference Guide ............................................................................... 152 Table K.3 – East-Side Resource Name and Description ........................................................................... 153 Table K.4 – West-Side Resource Name and Description ......................................................................... 155 Table K.5 – Core Case System Optimizer Results ................................................................................... 157 Table K.6 – Sensitivity Case System Optimizer Results .......................................................................... 158 Table K.7 – Core Cases, Detailed Capacity Expansion Portfolios ........................................................... 159 Table K.8 – Sensitivity Cases, Detailed Capacity Expansion Portfolios .................................................. 193 Table L.1 – Stochastic Mean PVRR ($m) by Price Scenario, Core Cases ............................................... 216 Table L.2 – Stochastic Mean PVRR ($m) by Price Scenario, Sensitivity Cases ...................................... 217 Table L.3 – Stochastic Risk Results, PVRR ($m), Core Cases, Low Price Curve ................................... 218 Table L.4 – Stochastic Risk Results, PVRR ($m), Core Cases, Base Price Curve ................................... 219 Table L.5 – Stochastic Risk Results, PVRR ($m), Core Cases, High Price Curve .................................. 220 Table L.6 – Stochastic Risk Results, PVRR ($m), Core Cases, High CO2 Price Curve ........................... 221 Table L.7 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, Low Price Curve .......................... 222 Table L.8 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, Base Price Curve ......................... 222 Table L.9 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, High Price Curve ......................... 223 Table L.10 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Core Cases ................................ 224 Table L.11 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Sensitivity Cases ...................... 225 Table L.12 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Core Cases ..................... 226 Table L.13 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Sensitivity Cases ........... 227 Table L.14 – Average Annual Energy Not Served (2015 – 2034), Core Cases, Low Price Curve .......... 228 Table L.15 – Average Annual Energy Not Served (2015 – 2034), Core Cases, Base Price Curve .......... 229 Table L.16 – Average Annual Energy Not Served (2015 – 2034), Core Cases, High Price Curve .......... 230 Table L.17 – Average Annual Energy Not Served (2015 – 2034), Core Cases, High CO2 Price Curve .. 231 Table L.18 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Low Price Curve . 232 Table L.19 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Base Price Curve ............................................................................................................................................... 232 Table L.20 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Price Curve ......... 233 Table L.21 – Portfolio PVRR ($m) Cost Components, Core Cases, Low Price Curve ............................ 235 Table L.22 – Portfolio PVRR ($m) Cost Components, Core Cases, Base Price Curve ........................... 236 Table L.23 – Portfolio PVRR ($m) Cost Components, Core Cases, High Price Curve ........................... 237 Table L.24 – Portfolio PVRR ($m) Cost Components, Core Cases, High CO2 Price Curve .................... 238 PACIFICORP – 2015 IRP INDEX OF TABLES AND FIGURES VIII Table L.25 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, Low Price Curve ................... 239 Table L.26 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, Base Price Curve .................. 240 Table L.27 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, High Price Curve .................. 241 Table L.28 –10-year Average Incremental Customer Rate Impact ($m), Final Screen Portfolios ........... 242 Table L.29 – Loss of Load Probability for a Major (> 25,000 MWh) July Event, Final Screen Portfolios, Base Price Curve ........................................................................................................... 242 Table L.30 – Average Loss of Load Probability during Summer Peak, Final Screen Portfolios, Base Price Curve ...................................................................................................................................... 243 Table N.1 – Peak Capacity Contribution Values for Wind and Solar ...................................................... 405 Table N.2 – Peak Capacity Contribution Values for Wind and Solar ...................................................... 407 PACIFICORP – 2015 IRP INDEX OF TABLES AND FIGURES IX INDEX OF FIGURES Figure A.1 – PacifiCorp System Energy Load Forecast Change .................................................................. 2 Figure A.2 – PacifiCorp System Peak Forecast Change ............................................................................... 2 Figure A.3 – PacifiCorp Annual Retail Sales 2000 through 2014 and Western Region Employment ......... 4 Figure A.4 – PacifiCorp Annual Residential Use per Customer 2001 through 2014 ................................... 5 Figure A.5 – IHS Global Insight Utah Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast ........................................................................... 6 Figure A.6 – IHS Global Insight Oregon Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast .................................................................. 6 Figure A.7 – IHS Global Insight Wyoming Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast .................................................................. 7 Figure A.8 – IHS Global Insight Washington Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast .................................................... 8 Figure A.9 – IHS Global Insight Washington Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast .................................................... 8 Figure A.10 – IHS Global Insight California Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast .................................................................. 9 Figure A.11 – Comparison of Utah 5, 10, and 20 Year Average Peak Producing Temperatures ................. 9 Figure A.12 – Load Forecast Scenarios for 1-in-20 Weather, High, Base Case and Low .......................... 18 Figure F.1 – Comparison of Reserve Requirements and Resources, East Balancing Authority Area (MW) ................................................................................................................................................. 91 Figure F.2 – Comparison of Reserve Requirements and Resources, West Balancing Authority Area (MW) ................................................................................................................................................. 91 Figure H.1 – Representative Map, PacifiCorp Wind Generating Stations Used in this Study ................. 104 Figure H.2 – Illustrative Load Following Forecast and Deviation ........................................................... 109 Figure H.3 – Illustrative Wind Following Forecast and Deviation ........................................................... 110 Figure H.4 – Illustrative Load Regulating Forecast and Deviation .......................................................... 111 Figure H.5 – Illustrative Wind Regulating Forecast and Deviation .......................................................... 112 Figure H.6 – Histogram of Deviations Occurring About a June 2013 PACE Load Regulating Forecast between 5,568 MW and 5,720 MW (Bin 14) ................................................................... 115 Figure H.7 – Average Hourly Wind Reserves for 2013, MW .................................................................. 125 Figure H.8 – Energy Imbalance Market .................................................................................................... 127 Figure I.1 – Workflow for Planning Reserve Margin Study ..................................................................... 136 Figure I.2 – Expected and Fitted Relationship of EUE to PRM ............................................................... 140 Figure I.3 – Expected and Fitted Relationship of LOLH to PRM ............................................................ 140 Figure I.4 – Simulated Relationship of Loss of Load Episode to PRM .................................................... 141 Figure I.5 – Incremental Cost of Reliability by PRM ............................................................................... 142 Figure J.1 – WECC Forecasted Power Supply Margins, 2007 to 2014 .................................................... 147 Figure J.2 – 2014 less 2012 WECC PSA .................................................................................................. 148 Figure L.1 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, Low Price ....................... 212 Figure L.2 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, Base Price ...................... 212 Figure L.3 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, High Price ...................... 213 Figure L.4 – Stochastic Risk Profile under Regional Haze Scenario 2, Low Price .................................. 213 Figure L.5 – Stochastic Risk Profile under Regional Haze Scenario 2, Base Price .................................. 214 Figure L.6 – Stochastic Risk Profile under Regional Haze Scenario 2, High Price ................................. 214 Figure L.7 – Stochastic Risk Profile, High CO2 ....................................................................................... 215 Figure N.1 – Daily LOLP ......................................................................................................................... 408 Figure N.2 – Monthly Resource Capacity Factors as Compared to LOLP ............................................... 408 Figure N.3 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in April ... 409 Figure N.4 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in July ..... 409 Figure N.5 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in December ........................................................................................................................................ 410 PACIFICORP – 2015 IRP INDEX OF TABLES AND FIGURES X PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 1 APPENDIX A – LOAD FORECAST DETAILS Introduction This appendix reviews the load forecast used in the modeling and analysis of the 2015 Integrated Resource Plan (“IRP”), including scenario development for case sensitivities. The load forecast used in the IRP is an estimate of the energy sales, and peak demand over a 20-year period. The 20-year horizon is important to anticipate electricity demand in order to develop timely response of resources. In the development of its load forecast PacifiCorp employs econometric models that use historical data and inputs such as regional and national economic growth, weather, seasonality, and other customer usage and behavior changes. The forecast is divided into classes that use energy for similar purposes and at comparable retail rates. The classes are modeled separately using variables specific to their usage patterns. For residential customers, typical energy uses include space heating, water heating, lighting, cooking, refrigeration, dish washing, laundry washing, televisions and various other end use appliances. Commercial and industrial customers use energy for production and manufacturing processes, space heating, air conditioning, lighting, computers and other office equipment. Jurisdictional peak load forecasts are developed using econometric equations that relate observed monthly peak loads, peak load producing weather and the weather-sensitive loads for all classes. The system coincident peak forecast, which is used in portfolio development, is the maximum load required on the system in any hourly period and is extracted from the hourly forecast model. Summary Load Forecast The Company updated its load forecast in September 2014. The average annual energy growth rate for the 10-year period (2015 through 2024) is 0.85 percent, with the average peak growth at 0.89 percent. Relative to the load forecast prepared for the 2013 IRP update, PacifiCorp’s 2024 energy forecast decreased in all jurisdictions and system energy requirements decreased approximately 3.2 percent. Likewise, peak forecasts are down, or flat across all jurisdictions as compared to the 2013 IRP Update. Figures A.1 and A.2 have comparisons of energy and peak forecasts respectively from the 2013 IRP (July 2012), 2013 IRP Update (October 2013) and the 2015 IRP (September 2014). PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 2 Figure A.1 – PacifiCorp System Energy Load Forecast Change Figure A.2 – PacifiCorp System Peak Forecast Change 58,000 60,000 62,000 64,000 66,000 68,000 70,000 72,000 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Gi g a w a t t Ho u r s (G W h ) Comparison of System Energy Forecast 2013 IRP (Jul 2012)2013 IRP Update (Oct 2013)2015 IRP (Sept 2014) 9,000 9,500 10,000 10,500 11,000 11,500 12,000 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Me g a W a t t (M W ) Comparison of System Peak Forecast 2013 IRP (Jul 2012)2013 IRP Update (Oct 2013)2015 IRP (Sept 2014) PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 3 Tables A.1 and A.2 show the annual load and coincident peak load forecast excluding load reduction projections from new energy efficiency measures (Class 2 DSM).1 Tables A.3 and A.4 show the forecast changes relative to the 2013 IRP update load forecast for loads and coincident system peak, respectively. Table A.1 – Forecasted Annual Load Growth, 2015 through 2024 (Megawatt-hours) Table A.2 – Forecasted Annual Coincident Peak Load (Megawatts) Table A.3 – Annual Load Growth Change: September 2014 Forecast less October 2013 Forecast (Megawatt-hours) 1 Class 2 DSM load reductions are included as resources in the System Optimizer model. Year Total OR WA CA UT WY ID SE-ID 2015 63,594,000 15,055,940 4,546,380 897,240 26,470,940 10,597,730 3,762,400 2,263,370 2016 63,644,160 15,197,090 4,604,260 903,780 27,119,080 10,879,850 3,787,070 1,153,030 2017 63,414,410 15,340,670 4,632,780 906,110 27,727,030 11,000,420 3,807,400 2018 64,335,670 15,477,180 4,667,630 909,820 28,297,970 11,150,420 3,832,650 2019 65,099,110 15,626,100 4,700,270 912,960 28,789,180 11,210,330 3,860,270 2020 65,882,150 15,751,620 4,731,330 914,010 29,245,590 11,352,800 3,886,800 2021 66,317,890 15,808,060 4,736,960 912,370 29,595,670 11,358,260 3,906,570 2022 67,038,440 15,932,470 4,759,830 914,420 30,038,620 11,459,580 3,933,520 2023 67,731,040 16,087,420 4,784,020 916,660 30,491,320 11,489,280 3,962,340 2024 68,656,720 16,271,900 4,822,220 921,460 31,023,270 11,620,590 3,997,280 2015-2024 0.85% 0.87% 0.66% 0.30% 1.78% 1.03% 0.68% Average Annual Growth Rate for 2013-2022 Year Total OR WA CA UT WY ID SE-ID 2015 10,368 2,329 731 148 4,770 1,372 687 331 2016 10,225 2,354 737 150 4,881 1,400 702 2017 10,381 2,383 742 151 4,985 1,415 706 2018 10,522 2,404 750 152 5,076 1,431 710 2019 10,635 2,426 752 152 5,153 1,439 713 2020 10,755 2,451 758 151 5,234 1,453 708 2021 10,876 2,472 761 152 5,313 1,456 722 2022 10,996 2,494 765 153 5,389 1,468 727 2023 11,105 2,517 769 154 5,462 1,472 732 2024 11,224 2,536 773 154 5,540 1,486 735 2015-2024 0.89% 0.95% 0.62% 0.41% 1.68% 0.89% 0.76% Average Annual Growth Rate for 2013-2022 Year Total OR WA CA UT WY ID SE-ID 2015 373,230 (133,280) 28,180 1,130 441,250 17,880 18,070 - 2016 101,140 (133,390) 36,650 1,410 54,900 80,730 9,760 51,080 2017 (11,630) (183,100) 39,860 2,210 65,380 56,920 7,100 - 2018 (43,330) (177,400) 36,750 2,320 43,290 47,240 4,470 - 2019 (226,250) (168,110) 31,380 1,760 (36,240) (57,880) 2,840 - 2020 (1,027,540) (206,720) 15,950 (1,930) (727,930) (103,730) (3,180) - 2021 (1,347,880) (230,220) (10) (4,480) (891,830) (214,150) (7,190) - 2022 (1,598,130) (243,850) (12,730) (6,210) (1,064,760) (260,230) (10,350) - 2023 (1,969,980) (249,430) (25,340) (7,850) (1,292,670) (381,130) (13,560) - 2024 (2,234,000) (249,400) (38,210) (9,300) (1,486,080) (433,810) (17,200) - PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 4 Table A.4 – Annual Coincident Peak Growth Change: September 2014 Forecast less October 2013 Forecast (Megawatts) Load Forecast Assumptions Regional Economy by Jurisdiction The PacifiCorp electric service territory is comprised of six states and within these states the Company serves a total of 90 counties. The level of retail sales for each state and county is correlated with economic conditions and population statistics in each state. The Company uses both economic data, such as employment, and population information, such as household data, to forecast its retail sales. Looking at historical sales and employment data for PacifiCorp’s service territory, 2000 through 2014, in Figure A.3, it is apparent that the Company’s retail sales are correlated to economic conditions in its service territory, and most recently the 2008-2009 recession. Figure A.3 – PacifiCorp Annual Retail Sales 2000 through 2014 and Western Region Employment Sources: PacifiCorp and United States Department of Labor, Bureau of Labor Statistics Year Total OR WA CA UT WY ID SE-ID 2015 216 (9) (7) 2 196 36 (4) 1 2016 183 (3) (6) 2 151 43 (4) 2017 172 (12) (7) 2 157 37 (5) 2018 170 (12) (8) 2 161 35 (6) 2019 152 (12) (8) 2 155 24 (8) 2020 (22) (14) (10) 1 (10) 20 (10) 2021 (53) (16) (12) 1 (21) 6 (11) 2022 (80) (18) (13) 1 (38) 0 (12) 2023 (127) (21) (14) 1 (65) (13) (14) 2024 (143) (21) (16) 1 (76) (16) (15) 28 29 30 31 32 33 34 35 42,000 44,000 46,000 48,000 50,000 52,000 54,000 56,000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Em p l o y m e n t (m i l l i o n s ) GW h Retail Sales and Service Territory Employment System Annual Sales Western Region Employment PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 5 As discussed below, although both the economic and demographic forecast is relatively unchanged from the 2013 IRP Update, the load forecast has decreased. There are two changes which are driving the 2015 IRP load and peak forecast down. First, the relationship between the economic growth and sales has “flattened.” Second, there have been changes in expected sales to our largest customers. Since the Great Recession that occurred in 2008-2009, the relationship between electric usage and economic growth has changed. While there is still a relationship between electric usage and the economic growth, electric usage has generally become less responsive to economic changes and has resulted in a lower usage forecast. Residential use per customer has been decreasing since 2010. Figure A.4 shows the weather normalized average system residential use per customer. Figure A.4 – PacifiCorp Annual Residential Use per Customer 2001 through 2014 Residential use per customer across all six of PacifiCorp’s states is changing due to increased energy efficiency driven primarily by lighting efficiency standards resulting from the 2007 Federal Energy legislation. In addition, there has been a shift from single-family and manufactured housing to multi-dwelling units and a trend of replacing older electric appliances with more energy efficient appliances. Utah PacifiCorp serves 26 of the 29 counties in the state of Utah. Utah is expected to be one of the leading states in terms of job growth, with non-farm employment increasing 2.0 percent annually over the next 10 years. Figure A.5 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that both the economic and demographic forecasts are very similar. Relative to the load forecast prepared for the 2013 IRP update, the Utah 2024 energy forecast decreased approximately 4.6 percent. 10,000 10,100 10,200 10,300 10,400 10,500 10,600 10,700 10,800 10,900 11,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Av e r a g e kW h pe r Re s i d e n t i a l Cu s t o m e r System Residential Use per Customer PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 6 Figure A.5 – IHS Global Insight Utah Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast A risk to the Utah forecast is commodity prices, such as oil and natural gas, where volatility in prices and profitability can lead to swings in production and employment potentially translating to swings in the retail sales forecast. Oregon PacifiCorp serves 25 of the 36 counties in Oregon, but only 28 percent of ultimate electric retail sales in the state of Oregon.2 In 2013 and 2014, Oregon employment growth has outpaced the national economy by approximately one percentage point.3 Figure A.6 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that the forecast of households has decreased slightly, while the employment forecast has increased slightly. Relative to the load forecast prepared for the 2013 IRP update, the Oregon 2024 energy forecast decreased approximately 1.5 percent. Figure A.6 – IHS Global Insight Oregon Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast 2 Source: Oregon Public Utility Commission, 2013 Oregon Utility Statistics. 3 Source: Bureau of Labor Statistics. PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 7 Wyoming The Company serves 15 of the 23 counties in Wyoming, with the largest metropolitan area served by the Company being Casper, Wyoming. Industrial sales make up approximately 74% of the Company’s Wyoming sales. Figure A.7 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that both the forecast of households and employment forecast have increased slightly. Relative to the load forecast prepared for the 2013 IRP update, the Wyoming 2024 energy forecast decreased approximately 3.6 percent. Figure A.7 – IHS Global Insight Wyoming Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast A risk to the Wyoming forecast is commodity prices, such as oil and natural gas, where volatility in prices and profitability can lead to swings in production and employment which translates to potential swings in the retail sales forecast. Washington PacifiCorp serves the following counties in Washington state: Benton, Columbia, Garfield, Klickitat, Walla Walla, and Yakima. Yakima is the most populated area that the Company serves in Washington State and has a large concentration of agriculture and food processing. Residential and commercial sales are roughly equal in size each making up approximately 38 percent of the Company’s Washington sales. Figure A.8 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that both the forecast of households and employment forecast have decreased slightly. Relative to the load forecast prepared for the 2013 IRP update, the Washington 2024 energy forecast decreased approximately 0.8 percent. PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 8 Figure A.8 – IHS Global Insight Washington Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast Idaho The Company serves 14 of the 44 counties in the state of Idaho, with the majority of the Company’s service territory in rural Idaho. Idaho Falls and Pocatello are the largest cities in the area and are not served by PacifiCorp. Industrial sales make up approximately 50% of the Company’s Idaho sales. Figure A.9 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that both the forecast of households and employment forecast have decreased slightly. Relative to the load forecast prepared for the 2013 IRP update, the Idaho 2024 energy forecast decreased approximately 0.4 percent. Figure A.9 – IHS Global Insight Washington Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast California The four northern California counties served by PacifiCorp are largely rural: Del Norte, Modoc, Shasta and Siskiyou. Redding, the largest city in this area, is not served by PacifiCorp. Residential sales make up approximately 47 percent of the Company’s California sales. Figure A.10 shows the change in household and employment forecasts for the 2013 IRP Update relative to the 2015 IRP forecast. This figure illustrates that both the forecast of households and employment forecast have decreased slightly. Relative to the load forecast prepared for the 2013 IRP update, the California 2024 energy forecast decreased approximately 1.0 percent. PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 9 Figure A.10 – IHS Global Insight California Household and Employment forecasts from the October 2013 load forecast and the September 2014 load forecast Weather The Company’s load forecast is based on normal weather defined by the 20-year time period of 1994-2013. The Company updated its temperature spline models to the five-year time period of 2009-2013. The Company’s spline models are used to model the commercial and residential class temperature sensitivity at varying temperatures. The Company has reviewed the appropriateness of using the average weather from a shorter time period as its “normal” peak weather. Figure A.11 indicates that peak producing weather does not change significantly when looking at a five, 10, or 20 year average. Figure A.11 – Comparison of Utah 5, 10, and 20 Year Average Peak Producing Temperatures PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 10 Statistically Adjusted End-Use (SAE) The Company models sales per customer for the residential class using the SAE model, which combines the end-use modeling concepts with traditional regression analysis techniques. Major drivers of the SAE-based residential model are heating and cooling related variables, equipment shares, saturation levels and efficiency trends, and economic drivers such as household size, income and energy price. The Company uses ITRON for its load forecasting software and services, as well as SAE. To predict future changes in the efficiency of the various end uses for the residential class, an excel spreadsheet model obtained from ITRON was utilized; the model includes appliance efficiency trends based on appliance life as well as past and future efficiency standards. The model embeds all currently applicable laws and regulations regarding appliance efficiency, along with life cycle models of each appliance. The life cycle models, based on the decay and replacement rate are necessary to estimate how fast the existing stock of any given appliance turns over, i.e. newer more efficient equipment replacing older less efficient equipment. The underlying efficiency data is based on estimates of energy efficiency from the US Department of Energy’s Energy Information Administration (EIA). The EIA estimates the efficiency of appliance stocks and the saturation of appliances at the national level and for individual Census Regions. Individual Customer Forecast The Company updated its load forecast for a select group of large industrial customers, self- generation facilities of large industrial customers, and data center forecasts within the respective jurisdictions. Customer forecasts are provided by the customer to the Company through a customer account manager (CAM). Actual Load Data With the exception of the industrial class, the Company uses actual load data from January 2000 through February 2014. The historical data period used to develop the industrial monthly sales is from January 2000 through February 2014 in Utah and Wyoming, January 2002 through February 2014 in Idaho, Oregon, and Washington, and January 2003 through February 2014 in California. The following tables are the annual actual retail sales, non-coincident peak, and coincident peak by state used in calculating the 2015 IRP retail sales forecast. PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 11 Table A.5 – Weather Normalized Jurisdictional Retail Sales 2000 through 2014 Table A.6 – Non-Coincident Jurisdictional Peak 2000 through 2014 Year California Idaho Oregon Utah Washington Wyoming System 2000 779 3,072 14,040 18,803 4,084 7,400 48,178 2001 778 2,956 13,505 18,478 4,020 7,684 47,421 2002 800 3,212 13,079 18,620 4,009 7,407 47,127 2003 819 3,242 13,033 19,248 4,050 7,475 47,868 2004 843 3,284 13,152 19,829 4,096 7,806 49,009 2005 836 3,245 13,326 20,214 4,205 8,042 49,868 2006 859 3,333 14,015 21,081 4,120 8,256 51,663 2007 877 3,364 14,067 21,973 4,068 8,492 52,840 2008 870 3,412 13,865 22,626 4,063 9,203 54,039 2009 832 2,949 13,173 22,082 4,025 9,262 52,323 2010 840 3,389 13,115 22,561 4,043 9,674 53,621 2011 806 3,432 12,994 23,343 4,011 9,764 54,350 2012 786 3,489 12,965 23,825 4,034 9,410 54,510 2013 776 3,546 12,989 23,834 4,047 9,561 54,754 2014 769 3,506 12,962 24,371 4,095 9,593 55,297 2000-14 -0.09% 0.95% -0.57% 1.87% 0.02% 1.87% 0.99% *System retail sales do not include sales for resale System Retail Sales - Gigawatt-hours (GWh)* Average Annual Growth Rate Year California Idaho Oregon Utah Washington Wyoming System 2000 176 686 2,603 3,684 785 1,061 8,995 2001 162 616 2,739 3,480 755 1,124 8,876 2002 174 713 2,639 3,773 771 1,113 9,184 2003 169 722 2,451 4,004 788 1,126 9,260 2004 193 708 2,524 3,862 920 1,111 9,317 2005 189 753 2,721 4,081 844 1,224 9,811 2006 180 723 2,724 4,314 822 1,208 9,970 2007 187 789 2,856 4,571 834 1,230 10,466 2008 187 759 2,921 4,479 923 1,339 10,609 2009 193 688 3,121 4,404 917 1,383 10,705 2010 176 777 2,552 4,448 893 1,366 10,213 2011 177 770 2,686 4,596 854 1,404 10,486 2012 159 800 2,550 4,732 797 1,337 10,376 2013 182 814 2,980 5,091 886 1,398 11,351 2014 161 818 2,598 5,024 871 1,360 10,831 2000-14 -0.64% 1.27% -0.01% 2.24% 0.75% 1.78% 1.34% *Non-coincident peaks do not include sales for resale Non-Coincident Peak - Megawatts (MW)* Average Annual Growth Rate PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 12 Table A.7 – Jurisdictional Contribution to Coincident Peak 2000 through 2014 System Losses System line losses were updated to reflect actual losses for the 5-year period ending December 31, 2013. Forecast Methodology Overview Class 2 Demand-side Management Resources in the Load Forecast PacifiCorp modeled Class 2 DSM as a resource option to be selected as part of a cost-effective portfolio resource mix using the Company’s capacity expansion optimization model, System Optimizer. The load forecast used for IRP portfolio development excluded forecasted load reductions from Class 2 DSM; System Optimizer then determines the amount of Class 2 DSM— expressed as supply curves that relate incremental DSM quantities with their costs—given the other resource options and inputs included in the model. The use of Class 2 DSM supply curves, along with the economic screening provided by System Optimizer, determines the cost-effective mix of Class 2 DSM for a given scenario. Modeling overview The load forecast is developed by forecasting the monthly sales by customer class for each jurisdiction. The residential sales forecast is developed as a use-per-customer forecast multiplied by the forecast number of customers. The customer forecasts are based on a combination of regression analysis and exponential smoothing techniques using historical data from January 2000 to February 2014. For the residential class, the Company forecasts the number of customers using IHS Global Insight’s forecast of each state’s number of households as the major driver. Year California Idaho Oregon Utah Washington Wyoming System 2000 154 523 2,347 3,684 756 979 8,443 2001 124 421 2,121 3,479 627 1,091 7,863 2002 162 689 2,138 3,721 758 1,043 8,511 2003 155 573 2,359 4,004 774 1,022 8,887 2004 120 603 2,200 3,831 740 1,094 8,588 2005 171 681 2,238 4,015 708 1,081 8,895 2006 156 561 2,684 3,972 816 1,094 9,283 2007 160 701 2,604 4,381 754 1,129 9,730 2008 171 682 2,521 4,145 728 1,208 9,456 2009 153 517 2,573 4,351 795 987 9,375 2010 144 527 2,442 4,294 757 1,208 9,373 2011 143 549 2,187 4,596 707 1,204 9,387 2012 156 782 2,163 4,731 749 1,225 9,806 2013 156 674 2,407 5,091 797 1,349 10,474 2014 150 630 2,345 5,024 819 1,294 10,263 2000-14 -0.19% 1.34% 0.00% 2.24% 0.58% 2.01% 1.40% *Coincident peaks do not include sales for resale Average Annual Growth Rate Coincident Peak - Megawatts (MW)* PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 13 The Company models sales per customer for the residential class using the SAE model discussed above, which combines the end-use modeling concepts with traditional regression analysis techniques. For the commercial class, the Company forecasts sales using regression analysis techniques with non-manufacturing employment designated as the major economic driver, in addition to weather- related variables. Monthly sales for the commercial class are forecast directly from historical sales volumes, not as a product of the use per customer and number of customers. The development of the forecast of monthly commercial sales involves an additional step; to reflect the addition of a large “lumpy” change in sales such as a new data center, monthly commercial sales are increased based on input from the Company’s CAM’s. Although the scale is much smaller, the treatment of large commercial additions is similar to the methodology for large industrial customer sales, which is discussed below. Monthly sales for irrigation and street lighting are forecast directly from historical sales volumes, not as a product of the use per customer and number of customers. The majority of industrial sales are modeled using regression analysis with trend and economic variables. Manufacturing employment is used as the major economic driver. For a small number of the very largest industrial customers, the Company prepares individual forecasts based on input from the customer and information provided by the CAM’s. After the Company develops the forecasts of monthly energy sales by customer class, a forecast of hourly loads is developed in two steps. First, monthly peak forecasts are developed for each state. The monthly peak model uses historical peak-producing weather for each state, and incorporates the impact of weather on peak loads through several weather variables that drive heating and cooling usage. The weather variables include the average temperature on the peak day and lagged average temperatures from up to two days before the day of the forecast. The peak forecast is based on average monthly historical peak-producing weather for the 20-year period, 1994 through 2013. Second, the Company develops hourly load forecasts for each state using hourly load models that include state-specific hourly load data, daily weather variables, the 20-year average temperatures as identified above, a typical annual weather pattern, and day-type variables such as weekends and holidays as inputs to the model. The hourly loads are adjusted to match the monthly peaks from the first step above. Hourly loads are then adjusted so the monthly sum of hourly loads equals monthly sales plus line losses. After the hourly load forecasts are developed for each state, hourly loads are aggregated to the total system level. The system coincident peaks can then be identified, as well as the contribution of each jurisdiction to those monthly peaks. Sales Forecast at the Customer Meter This section provides total system and state-level forecasted retail sales summaries measured at the customer meter by customer class including load reduction projections from new energy efficiency measures from the Preferred Portfolio. PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 14 Table A.8 – System Annual Sales Forecast 2015 through 2024 Residential Average annual growth of the residential class sales forecast declined from 0.6 percent in the 2013 IRP Update to -0.2 percent in the 2015 IRP. The number of residential customers across PacifiCorp’s system is expected to grow at an annual average rate of 1.0 percent, reaching approximately 1.7 million customers in 2024, with Rocky Mountain Power states adding 1.4 percent per year and Pacific Power states adding 0.4 percent per year. New customers on PacifiCorp’s system will also contribute to declining average use of the residential class. It is expected that new single-family homes are likely to use more efficient appliances and use gas instead of electricity for both space and water heating. Commercial Average annual growth of the commercial class sales forecast declined from 1.1 percent annual average growth in the 2013 IRP Update to 0.4 percent expected average annual growth. The Company lowered its data center load expectations in Utah and Oregon in the 2015 IRP load forecast due to lower than expected initial loads and additional energy efficiency gains in the technology industry. PacifiCorp total commercial customers are expected to grow at an annual average rate of 0.8 percent, reaching almost 219,000 total customers in 2024. Rocky Mountain Power is expected to add commercial customers at 1.4 percent annually, and Pacific Power is forecasted to add 0.4 percent annually. Industrial Average annual growth of the industrial class sales forecast declined from 1.7 percent annual average growth in the 2013 IRP Update to 0.4 percent expected annual growth. A portion of the Company’s industrial load is in the oil and natural gas sector in Utah and Wyoming; therefore, changes in natural gas and oil prices can impact the Company’s load forecast. The Company has seen several large industrial customers cancel expected new load when gas and oil prices have fallen. The risk to the Company’s load forecast due to commodity price changes is reflected in the high and low economic growth scenarios discussed below. Year Residential Commercial Industrial Irrigation Lighting Public Authority Total 2015 15,624,212 17,342,946 20,720,928 1,389,301 143,460 274,200 55,495,047 2016 15,671,354 17,579,292 21,041,923 1,388,035 144,040 274,940 56,099,585 2017 15,626,345 17,727,257 21,082,095 1,386,409 143,650 274,200 56,239,956 2018 15,630,039 17,820,123 21,115,922 1,384,596 143,700 274,200 56,368,580 2019 15,651,098 17,843,052 21,154,829 1,382,404 143,710 274,200 56,449,292 2020 15,575,099 17,929,515 21,319,441 1,381,044 144,130 274,940 56,624,168 2021 15,479,683 17,894,201 21,288,648 1,379,452 143,720 274,200 56,459,905 2022 15,443,463 17,901,109 21,366,407 1,377,766 143,720 274,200 56,506,666 2023 15,355,476 17,915,244 21,391,383 1,375,943 143,720 274,200 56,455,966 2024 15,333,417 17,966,054 21,525,322 1,374,111 144,140 274,940 56,617,985 2015-24 -0.2% 0.4% 0.4% -0.1% 0.1% 0.0% 0.2% Average Annual Growth Rate System Retail Sales – Gigawatt-hours (GWh) PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 15 State Summaries Oregon Table A.9 summarizes Oregon state forecasted retail sales growth by customer class. Table A.9 – Forecasted Sales Growth in Oregon Washington Table A.10 summarizes Washington state forecasted retail sales growth by customer class. Table A.10 – Forecasted Sales Growth in Washington California Table A.11 summarizes California state forecasted sales growth by customer class. Year Residential Commercial Industrial Irrigation Lighting Total 2015 5,360,653 5,154,353 2,210,849 336,200 38,120 13,100,175 2016 5,368,670 5,173,475 2,152,886 336,220 38,230 13,069,482 2017 5,350,386 5,177,190 2,150,466 336,200 38,120 13,052,362 2018 5,353,337 5,169,956 2,146,991 336,200 38,120 13,044,604 2019 5,359,816 5,168,774 2,158,608 336,200 38,120 13,061,519 2020 5,332,311 5,182,723 2,174,162 336,220 38,230 13,063,647 2021 5,298,646 5,167,021 2,170,389 336,200 38,120 13,010,376 2022 5,302,350 5,168,914 2,179,082 336,200 38,120 13,024,666 2023 5,316,727 5,178,033 2,201,761 336,200 38,120 13,070,841 2024 5,351,686 5,197,730 2,221,090 336,220 38,230 13,144,955 2015-24 -0.02% 0.09% 0.05% 0.00% 0.03% 0.04% Oregon Retail Sales – Gigawatt-hours (GWh) Average Annual Growth Rate Year Residential Commercial Industrial Irrigation Lighting Total 2015 1,569,627 1,493,393 799,153 146,360 9,880 4,018,413 2016 1,565,767 1,511,324 799,998 146,360 9,920 4,033,370 2017 1,550,682 1,516,347 795,591 146,360 9,880 4,018,861 2018 1,541,720 1,519,230 793,175 146,360 9,880 4,010,365 2019 1,532,980 1,516,819 789,882 146,360 9,880 3,995,921 2020 1,521,339 1,520,946 790,678 146,360 9,910 3,989,234 2021 1,504,294 1,510,434 786,721 146,360 9,880 3,957,689 2022 1,495,254 1,503,091 784,623 146,360 9,880 3,939,208 2023 1,487,377 1,494,554 782,226 146,360 9,880 3,920,397 2024 1,485,476 1,490,312 782,385 146,360 9,910 3,914,444 2015-24 -0.61% -0.02% -0.24% 0.00% 0.03% -0.29% Washington Retail Sales – Gigawatt-hours (GWh) Average Annual Growth Rate PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 16 Table A.11 – Forecasted Retail Sales Growth in California Utah Table A.12 summarizes Utah state forecasted sales growth by customer class. Table A.12 – Forecasted Retail Sales Growth in Utah Idaho Table A.13 summarizes Idaho state forecasted sales growth by customer class. Year Residential Commercial Industrial Irrigation Lighting Total 2015 367,336 245,057 48,405 97,200 2,440 760,438 2016 363,742 247,502 47,931 97,210 2,450 758,834 2017 357,816 247,990 47,065 97,200 2,440 752,510 2018 352,992 247,459 46,246 97,200 2,440 746,338 2019 347,391 245,401 45,669 97,200 2,440 738,100 2020 341,676 244,571 45,479 97,210 2,450 731,387 2021 335,190 241,147 44,996 97,200 2,440 720,974 2022 330,807 238,115 44,644 97,200 2,440 713,207 2023 324,464 234,168 44,250 97,200 2,440 702,522 2024 318,273 229,737 44,007 97,210 2,450 691,677 2015-24 -1.58% -0.71% -1.05% 0.00% 0.05% -1.05% Average Annual Growth Rate California Retail Sales – Gigawatt-hours (GWh) Year Residential Commercial Industrial Irrigation Lighting Public Authority Total 2015 6,573,550 8,458,275 8,706,305 197,050 78,630 274,200 24,288,010 2016 6,612,206 8,640,260 8,879,349 197,070 79,000 274,940 24,682,825 2017 6,613,877 8,771,098 8,863,813 197,050 78,820 274,200 24,798,858 2018 6,632,592 8,859,585 8,825,036 197,050 78,870 274,200 24,867,333 2019 6,660,939 8,882,841 8,871,333 197,050 78,880 274,200 24,965,243 2020 6,638,380 8,941,286 8,945,399 197,070 79,100 274,940 25,076,174 2021 6,613,722 8,938,827 8,968,815 197,050 78,890 274,200 25,071,504 2022 6,593,527 8,953,660 9,010,338 197,050 78,890 274,200 25,107,665 2023 6,511,571 8,970,081 9,054,936 197,050 78,890 274,200 25,086,727 2024 6,462,703 9,003,525 9,125,505 197,070 79,110 274,940 25,142,854 2015-24 -0.19% 0.70% 0.52% 0.00% 0.07% 0.03% 0.39% Utah Retail Sales – Gigawatt-hours (GWh) Average Annual Growth Rate PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 17 Table A.13 – Forecasted Retail Sales Growth in Idaho Wyoming Table A.14 summarizes Wyoming state forecasted sales growth by customer class. Table A.14 – Forecasted Retail Sales Growth in Wyoming Alternative Load Forecast Scenarios The purpose of providing alternative load forecast cases is to determine the resource type and timing impacts resulting from a change in the economy or system peaks as a result of higher than normal temperatures. The September 2014 forecast is the baseline scenario. For the high and low economic growth scenarios assumptions from IHS Global Insight were applied to the economic drivers in the Company’s load forecasting models. These growth assumptions were extended for the entire forecast horizon. Year Residential Commercial Industrial Irrigation Lighting Total 2015 691,046 431,993 1,735,730 587,611 2,620 3,449,001 2016 694,712 434,035 1,739,113 586,295 2,630 3,456,785 2017 693,151 439,322 1,739,284 584,719 2,620 3,459,097 2018 693,955 445,150 1,739,788 582,906 2,620 3,464,420 2019 699,839 451,275 1,735,331 580,714 2,620 3,469,779 2020 702,725 458,506 1,734,443 579,304 2,630 3,477,608 2021 704,164 462,363 1,731,347 577,762 2,620 3,478,257 2022 709,279 467,475 1,728,793 576,076 2,620 3,484,243 2023 714,575 472,812 1,726,178 574,253 2,620 3,490,438 2024 722,386 478,436 1,724,423 572,371 2,630 3,500,246 2015-24 0.49% 1.14% -0.07% -0.29% 0.04% 0.16% Idaho Retail Sales – Gigawatt-hours (GWh) Average Annual Growth Rate Year Residential Commercial Industrial Irrigation Lighting Total 2015 1,061,999 1,559,876 7,220,486 24,880 11,770 9,879,011 2016 1,066,258 1,572,694 7,422,646 24,880 11,810 10,098,288 2017 1,060,434 1,575,309 7,485,875 24,880 11,770 10,158,268 2018 1,055,442 1,578,744 7,564,685 24,880 11,770 10,235,521 2019 1,050,132 1,577,942 7,554,005 24,880 11,770 10,218,729 2020 1,038,667 1,581,482 7,629,280 24,880 11,810 10,286,119 2021 1,023,668 1,574,408 7,586,380 24,880 11,770 10,221,106 2022 1,012,246 1,569,855 7,618,926 24,880 11,770 10,237,676 2023 1,000,763 1,565,596 7,582,031 24,880 11,770 10,185,041 2024 992,892 1,566,315 7,627,912 24,880 11,810 10,223,809 2015-24 -0.74% 0.05% 0.61% 0.00% 0.04% 0.38% Wyoming Retail Sales – Gigawatt-hours (GWh) Average Annual Growth Rate PACIFICORP – 2015 IRP APPENDIX A – LOAD FORECAST 18 Recognizing the volatility associated with the oil and gas extraction industries, PacifiCorp applied additional assumptions for the Utah and Wyoming industrial class load forecasts in the high and low scenario. Specifically, the Company focused on the increased uncertainty of the industrial load forecast as it moves further out in time. In order to capture this increased uncertainty the Company modeled 1,000 possible annual loads for each year based on the standard error of the medium scenario regression equation. The 1,000 load values are then ranked and the Company selected the 95th percentile and 5th percentile of the Utah and Wyoming industrial loads for both the low and high growth scenarios. For the 1-in-20 year (5 percent probability) extreme weather scenario, the Company used 1-in-20 year peak weather for summer (July) months for each state. The 1-in-20 year peak weather is defined as the year for which the peak has the chance of occurring once in 20 years. Figure A.12 shows the comparison of the above scenarios relative to the Base Case scenario. Figure A.12 – Load Forecast Scenarios for 1-in-20 Weather, High, Base Case and Low PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 19 APPENDIX B – IRP REGULATORY COMPLIANCE Introduction This appendix describes how PacifiCorp’s 2015 IRP complies with (1) the various state commission IRP standards and guidelines, (2) specific analytical requirements stemming from acknowledgment orders for the Company’s last IRP (2013 IRP), and (3) state commission IRP requirements stemming from other regulatory proceedings. Included in this appendix are the following tables: ● Table B.1 – Provides an overview and comparison of the rules in each state for which IRP submission is required.4 ● Table B.2 – Provides a description of how PacifiCorp addressed the 2013 IRP acknowledgement requirements and other commission directives. ● Table B.3 – Provides an explanation of how this plan addresses each of the items contained in the Oregon IRP guidelines. ● Table B.4 – Provides an explanation of how this plan addresses each of the items contained in the Public Service Commission of Utah IRP Standard and Guidelines issued in June 1992. ● Table B.5 – Provides an explanation of how this plan addresses each of the items contained in the Washington Utilities and Trade Commission IRP guidelines issued in January 2006. ● Table B.6 – Provides an explanation of how this plan addresses each of the items contained in the Wyoming Public Service Commission IRP guidelines. General Compliance PacifiCorp prepares the IRP on a biennial basis and files the IRP with state commissions. The preparation of the IRP is done in an open public process with consultation between all interested 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 all parties on the planning issues and approach. The public input process for this IRP, described in Volume I, Chapter 2 (Introduction), as well as Volume II, Appendix C (Public Input Process) fully complies with IRP Standards and Guidelines. The IRP provides a framework and plan for future actions to ensure PacifiCorp continues to provide 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 resources required to meet this load. To fill any gap between changes in loads and existing resources, while taking into consideration potential early retirement of existing coal units as an alternative to investments that achieve compliance with environmental regulations, the IRP evaluates a broad range of available resource options, as required by state commission rules. These resource alternatives include 4 California guidelines exempt a utility with less than 500,000 customers in the state from filing an IRP. However, PacifiCorp files its IRP and IRP supplements with the California Public Utilities Commission to address the Company plan for compliance with the California RPS requirements. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 20 supply-side, demand-side, market, and transmission alternatives. The evaluation of the alternatives in the IRP, as detailed in Volume I, Chapters 7 (Modeling and Portfolio Evaluation Approach) and Chapter 8 (Modeling and Portfolio Selection Results) meets this requirement and includes the impact to system costs, system operations, supply and transmission reliability, and the impacts of various risks, uncertainties and externality costs that may occur. To perform the analysis and evaluation, PacifiCorp employs a suite of models that simulate the complex operation of the PacifiCorp system and its integration within the Western Interconnection. The models allow for a rigorous testing 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 in detail in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). 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, reliability, customer rate impacts, and average annual CO2 emissions. This portfolio analysis and the results and conclusions drawn from the analysis are described in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). Consistent with the IRP Standards and Guidelines of Oregon, Utah, and Washington, this IRP includes an action plan in Volume I, Chapter 9 (Action Plan and Resource Procurement). The action plan details near-term actions that are necessary to ensure PacifiCorp continues to provide reliable and least-cost electric service after considering risk and uncertainty. Volume I, Chapter 9 also provides a progress report on action items contained in the 2013 IRP. The 2015 IRP and related action plan are filed with each commission with a request for prompt acknowledgment. Acknowledgment means that a commission recognizes the IRP as meeting all regulatory requirements at the time of acknowledgment. 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 their acknowledgment standards. State commission acknowledgment orders or letters typically stress that an acknowledgment does not indicate approval or endorsement of IRP conclusions or analysis results. Similarly, an acknowledgment does not imply that favorable ratemaking treatment for resources proposed in the IRP will be given. California Subsection (i) of California Public Utilities Code, Section 454.5, states that utilities serving less than 500,000 customers in the state are exempt from filing an IRP for California. The number of PacifiCorp customers, located in the most northern parts of the state, fall below this threshold. PacifiCorp 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 PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 21 Resource 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 flexibilities and analyses considered during comprehensive resource planning, such as: (1) examination of load forecast uncertainties; (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 2015, and fully addresses the above report components. Oregon This IRP is submitted to the Oregon Public Utility Commission (OPUC) in compliance with its planning guidelines issued in January 2007 (Order No. 07-002). The Commission’s IRP guidelines consist of substantive requirements (Guideline 1), procedural requirements (Guideline 2), plan filing, review, and updates (Guideline 3), plan components (Guideline 4), transmission (Guideline 5), conservation (Guideline 6), demand response (Guideline 7), environmental costs (Guideline 8, Order No. 08-339, dated June 30, 2008), direct access loads (Guideline 9), multi- state utilities (Guideline 10), reliability (Guideline 11), distributed generation (Guideline 12), resource acquisition (Guideline 13), and flexible resource capacity (Order No. 12-0135). Consistent with the earlier guidelines (Order 89-507, dated Aril 20, 1989), the Commission notes that acknowledgment does not guarantee favorable ratemaking treatment, only that the plan seems reasonable at the time acknowledgment is given. Table B.3 provides detail on how this plan addresses each of the requirements. Utah This IRP is submitted to the State of Utah Public Service Commission (PSC) in compliance with its 1992 Order on Standards and Guidelines for Integrated Resource Planning (Docket No. 90- 2035-01, “Report and Order on Standards and Guidelines”). Table B.4 documents how PacifiCorp complies with each of these standards. Washington 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 requires PacifiCorp to submit a work plan for informal commission review not later than 12 months prior to the due date of the plan. The work plan is to lay out the contents of the IRP, the resource assessment method, and timing and extent of public participation. PacifiCorp 5 Public Utility Commission of Oregon, Order No. 12-013, Docket No. 1461, January 19, 2012. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 22 filed a work plan with the Commission on March 31, 2014 in Docket No. UE-140546. Table B.5 provides detail on how this plan addresses each of the rule requirements. Wyoming Wyoming Public Service Commission (WPSC) Rule 253 provides guidance on filing IRPs for any utility serving Wyoming customers. The rule, shown below, went into effect in September 2009. Table B.6 provides detail on how this plan addresses the rule requirements. Rule 253: Integrated Resource Planning. Any utility serving in Wyoming required to file an integrated resource plan (IRP) in any jurisdiction, shall file that IRP with the Wyoming Public Service Commission. The Commission may require any utility serving in Wyoming to prepare and file an IRP when the Commission determines it is in the public interest. Commission advisory staff shall review the IRP as directed by the Commission and report its findings to the Commission in open meeting. The review may be conducted in accordance with guidelines set from time to time as conditions warrant. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 23 Table B.1 – Integrated Resource Planning Standards and Guidelines Summary by State Topic Oregon Utah Washington Idaho Wyoming Source Order No. 07-002, Investigation Into Integrated Resource Planning, January 8, 2007, as amended by Order No. 07-047. Order No. 08-339, Investigation into the Treatment of CO2 Risk in the Integrated Resource Planning Process, June 30, 2008. Order No. 09-041, New Rule OAR 860-027- 0400, implementing Guideline 3, “Plan Filing, Review, and Updates”. Order No. 12-013, “Investigation of Matters related to Electric Vehicle Charging”, January 19, 2012. Docket 90-2035-01 Standards and Guidelines for Integrated Resource Planning June 18, 1992. WAC 480-100-251 Least cost planning, May 19, 1987, and as amended from WAC 480-100-238 Least Cost Planning Rulemaking, January 9, 2006 (Docket # UE- 030311) Order 22299 Electric Utility Conservation Standards and Practices January, 1989. See Wyoming section above for Wyoming Commission Rule 253. Filing Requirements Least-cost plans must be filed with the Commission. An Integrated Resource Plan (IRP) is to be submitted to Commission. Submit a least cost plan to the Commission. Plan to be developed with consultation of Commission staff, and with public involvement. Submit “Resource Management Report” (RMR) on planning status. Also file progress reports on conservation, low-income programs, lost opportunities and capability building. Any utility serving in Wyoming required to file an integrated resource plan (IRP) in any jurisdiction, shall file that IRP with the Wyoming Public Service Commission. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 24 Topic Oregon Utah Washington Idaho Wyoming Frequency Plans filed biennially, within two years of its previous IRP acknowledgment order. An annual update to the most recently acknowledged IRP is required to be filed on or before the one-year anniversary of the acknowledgment order date. While informational only, utilities may request acknowledgment of proposed changes to the action plan. File biennially. File biennially. RMR to be filed at least biennially. Conservation reports to be filed annually. Low income reports to be filed at least annually. Lost Opportunities reports to be filed at least annually. Capability building reports to be filed at least annually. The Commission may require any utility serving in Wyoming to prepare and file an IRP when the Commission determines it is in the public interest. Commission Response Least-cost plan (LCP) acknowledged if found to comply with standards and guidelines. A decision made in the LCP process does not guarantee favorable rate- making treatment. The OPUC may direct the utility to revise the IRP or conduct additional analysis before an acknowledgment order is issued. Note, however, that Rate Plan legislation allows pre-approval of near- term resource investments. IRP acknowledged if found to comply with standards and guidelines. Prudence reviews of new resource acquisitions will occur during rate making proceedings. The plan will be considered, with other available information, when evaluating the performance of the utility in rate proceedings. WUTC sends a letter discussing the report, making suggestions and requirements and acknowledges the report. Report does not constitute pre-approval of proposed resource acquisitions. Idaho sends a short letter stating that they accept the filing and acknowledge the report as satisfying Commission requirements. Commission advisory staff shall review the IRP as directed by the Commission and report its findings to the Commission in open meeting. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 25 Topic Oregon Utah Washington Idaho Wyoming Process The public and other utilities are allowed significant involvement in the preparation of the plan, with opportunities to contribute and receive information. Order 07- 002 requires that the utility present IRP results to the OPUC at a public meeting prior to the deadline for written public comments. Commission staff and parties should complete their comments and recommendations within six months after IRP filing. Competitive secrets must be protected. Planning process open to the public at all stages. IRP developed in consultation with the Commission, its staff, with ample opportunity for public input. In consultation with Commission staff, develop and implement a public involvement plan. Involvement by the public in development of the plan is required. PacifiCorp is required to submit a work plan for informal commission review not later than 12 months prior to the due date of the plan. The work plan is to lay out the contents of the IRP, resource assessment method, and timing and extent of public participation. Utilities to work with Commission staff when reviewing and updating RMRs. Regular public workshops should be part of process. The review may be conducted in accordance with guidelines set from time to time as conditions warrant. The Public Service Commission of Wyoming, in its Letter Order on PacifiCorp’s 2008 IRP (Docket No. 2000-346-EA-09) adopted Commission Staff’s recommendation to expand the review process to include a technical conference, an expanded public comment period, and filing of reply comments. Focus 20-year plan, with end- effects, and a short-term (two-year) action plan. The IRP process should result in the selection of that mix of options which yields, for society over the long run, the best combination of expected costs and variance of costs. 20-year plan, with short- term (four-year) action plan. Specific actions for the first two years and anticipated actions in the second two years to be detailed. The IRP process should result in the selection of the optimal set of resources given the expected combination of costs, risk and uncertainty. 20-year plan, with short- term (two-year) action plan. The plan describes mix of resources sufficient to meet current and future loads at “lowest reasonable” cost to utility and ratepayers. Resource cost, market volatility risks, demand- side resource uncertainty, resource dispatchability, ratepayer risks, policy impacts, and environmental risks, must be considered. 20-year plan to meet load obligations at least-cost, with equal consideration to demand side resources. Plan to address risks and uncertainties. Emphasis on clarity, understandability, resource capabilities and planning flexibility. Identification of least- cost/least-risk resources and discussion of deviations from least- cost resources or resource combinations. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 26 Topic Oregon Utah Washington Idaho Wyoming Elements Basic elements include:  All resources evaluated on a consistent and comparable basis.  Risk and uncertainty must be considered.  The primary goal must be least cost, consistent with the long-run public interest.  The plan must be consistent with Oregon and federal energy policy.  External costs must be considered, and quantified where possible. OPUC specifies environmental adders (Order No. 93-695, Docket UM 424).  Multi-state utilities should plan their generation and transmission systems on an integrated- system basis.  Construction of resource portfolios over the range of identified risks and uncertainties.  Portfolio analysis shall include fuel transportation and transmission requirements.  Plan includes IRP will include:  Range of forecasts of future load growth  Evaluation of all present and future resources, including demand side, supply side and market, on a consistent and comparable basis.  Analysis of the role of competitive bidding  A plan for adapting to different paths as the future unfolds.  A cost effectiveness methodology.  An evaluation of the financial, competitive, reliability and operational risks associated with resource options, and how the action plan addresses these risks.  Definition of how risks are allocated between ratepayers and shareholders The plan shall include:  A range of forecasts of future demand using methods that examine the effect of economic forces on the consumption of electricity and that address changes in the number, type and efficiency of electrical end-uses.  An assessment of commercially available conservation, including load management, as well as an assessment of currently employed and new policies and programs needed to obtain the conservation improvements.  Assessment of a wide range of conventional and commercially available nonconventional generating technologies  An assessment of transmission system capability and reliability.  A comparative evaluation of energy supply resources (including transmission and Discuss analyses considered including:  Load forecast uncertainties;  Known or potential changes to existing resources;  Equal consideration of demand and supply side resource options;  Contingencies for upgrading, optioning and acquiring resources at optimum times;  Report on existing resource stack, load forecast and additional resource menu. Proposed Commission Staff guidelines issued on January 2009 cover:  Sufficiency of the public comment process  Utility strategic goals and preferred portfolio  Resource need and changes in expected resource acquisitions  Environmental impacts  Market purchase evaluation  Reserve margin analysis  Demand-side management and energy efficiency PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 27 Topic Oregon Utah Washington Idaho Wyoming conservation potential study, demand response resources, environmental costs, and distributed generation technologies.  Avoided cost filing required within 30 days of acknowledgment. distribution) and improvements in conservation using “lowest reasonable cost” criteria.  Integration of the demand forecasts and resource evaluations into a long-range (at least 10 years) plan.  All plans shall also include a progress report that relates the new plan to the previously filed plan. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 28 Table B.2 – Handling of 2015 IRP Acknowledgment and Other IRP Requirements Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP Idaho Order No. PAC-E-13-05, p. 12. The Commission directs the Company to increase its efforts toward achieving higher levels of cost-effective DSM. In future IRP and DSM filings, the Commission directs the Company to present clear and quantifiable metrics governing its actions regarding decisions to implement or decline to implement energy efficiency programs. PacifiCorp has targeted all cost-effective DSM as selected by System Optimizer in the 2015 IRP and provides an update on its DSM acquisition action items from the 2013 IRP in Volume I, Chapter 9. DSM selections and the associated action plan from the 2015 IRP are presented in Volume I, Chapter 8 and Volume I, Chapter 9. PacifiCorp’s 2015 IRP DSM state implementation plans are provided in Appendix D. Oregon Order No. 14- 252, p. 3 Beginning in the third quarter of 2014, PacifiCorp will appear before the Commission to provide quarterly updates on coal plant compliance requirements, legal proceedings, pollution control investments, and other major capital expenditures on its coal plants or transmission projects. PacifiCorp may provide a written report and need not appear if there are no significant changes between the quarterly updates. OPUC Order No. 14-288 modified the requirements, moving the date of the first meeting from the third quarter of 2014 to the fourth quarter of 2014. The initial meeting was held on October 28, 2014. A copy of the presentation made to the OPUC is available on their website at the following location: http://www.puc.state.or.us/meetings/pmemos/2014/ 102814-pac/pacpresentation.pdf The first quarter 2015 meeting was held March 16, 2015. Order No. 14- 252, p. 3 In future IRPs, PacifiCorp will provide:  Timelines and key decision points for expected pollution control options and transmission investments; and  Tables detailing major planned expenditures with estimated costs in each year for each plant or transmission project, under different modeled scenarios. Volume III contains timelines that outline key decision points for pollution control options at Wyodak, Naughton Unit 3, Dave Johnston Unit 3, and Cholla Unit 4. Volume III further contains tables detailing major planned expenditures by year specific to each compliance scenario studied for Wyodak, Naughton Unit 3, Dave Johnston Unit 3, and Cholla Unit 4. Additional annual cost detail for existing coal units modeled among four different Regional Haze scenarios applied during the resource portfolio development process are included in Confidential data disks files with the 2015 IRP. Order No. 14- 252, p. 5 Rather than detail a specific coal analysis that will be required in the future, we instead direct the participants to schedule several workshops, at least one of which we will attend, to be held within the next six months to determine the parameters of coal analyses in future IRPs. PacifiCorp held a total of four workshops dedicated solely to the modeling approach for coal plant investments. These meetings were attended by OPUC Staff and intervening parties to the 2013 IRP filed under Docket LC 57. The OPUC Commissioners attended the fourth workshop, held on August 6, 2014. Following the final workshop, Staff presented a memo at the OPUC public meeting outlining what they described as “an appropriate coal analysis framework for PacifiCorp’s 2015 Integrated Resource Plan.” The OPUC later issued Order No. 14-296 memorializing the analysis framework as presented by Staff. PacifiCorp met all requirements of this Order in its analysis summarized in Volume III. Additionally, the analysis approach was also discussed fully with all stakeholders at the September 25-26, 2014 Public Input Meeting. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 29 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP Order No. 14- 252, p. 6 OPUC Commission modified Action Item 8a for Naughton Unit 3 to read as follows: Evaluate the Naughton Unit 3 investment decision in the 2015 IRP with updated analysis, including the option of shutdown versus conversion. The required analysis is included in Volume III. Order No. 14- 252, p. 10 The modified Action Item 8d is: Continue to evaluate alternative compliance strategies that will meet Regional Haze compliance obligations, related to the US. Environmental Protection Agency's Federal Implementation Plan requirements to install SCR equipment at Cholla Unit 4. Provide an analysis of the Cholla Unit 4 compliance alternatives in a special, designated IRP Update within six months of the final order in LC 57 and well enough in advance to allow for all viable pollution control alternatives to be adequately considered and pursued. On September 29, 2014 PacifiCorp filed a Special Update to the 2013 IRP containing the Cholla analysis as directed by the OPUC. The analysis presented in the special update is also included in the Volume III of the 2015 IRP. Order No. 14- 252, p. 10 Within three months of the order in this proceeding, PacifiCorp will schedule and hold a confidential technical workshop to review existing analysis on planned Craig and Hayden environmental investments. A special public meeting was held on August 6, 2014 to provide the requested analysis. The meeting was confidential, limited to parties subject to the confidentiality provisions included with Docket LC 57. Order No. 14- 252, p. 13 Prior to the end of 2014, PacifiCorp will work with participants to explore options for how PacifiCorp plans to model and perform analysis in the 2015 IRP related to what is known about the requirements of §111(d) of the Clean Air Act. PacifiCorp discussed its 111(d) modeling approach with Oregon stakeholders at the coal analysis workshops, discussed above. OPUC Commissioners attended the workshop on August 6, 2014. PacifiCorp further discussed its 111(d) modeling approach at multiple public input meetings and hosted two technical workshops (one in Portland and one in Salt Lake City) to demonstrate the use of the 111(d) Scenario Maker spreadsheet tool developed for the 2015 IRP for the sole purpose of modeling 111(d) policy and compliance uncertainties. Order No. 14- 252, p. 13 In the acknowledgement order the Commission provided the following recommendation: As part of the 2015, 2017, and 2019 IRPs, PacifiCorp will provide an updated version of the screening tool spreadsheet model that was provided to participants in the 2011 (docket LC 52) IRP Update. PacifiCorp has provided three different versions of the screening model. These models are specific for different variations of Regional Haze scenarios analyzed in the 2015 IRP. The models are included on the confidential data disks filed with the 2015 IRP. Order No. 14- 252, p. 16 Provide twice yearly updates on the status of DSM IRP acquisition goals to the Commission in 2014 and 2015, including a summary of DSM acquisitions from large special contract customers. PacifiCorp provided two DSM updates to the OPUC in 2014. The first update was on August 6, 2014, and the second was on December 3, 2014. A third meeting was held March 10, 2015. Order No. 14- 252, p. 16 Include in the 2014 conservation potential study information specific to PacifiCorp's service territory for all states other than Oregon that quantifies how much Class 2 DSM programs can be accelerated and how much it will cost to accelerate The conservation potential study contains the requested information. It is available on the 2015 IRP data disk and online, with all appendices at the following location: http://www.pacificorp.com/es/dsm.html PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 30 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP acquisition. Order No. 14- 252, p. 16 Include a PacifiCorp service area specific implementation plan as part of the 2015 IRP filing. Appendix D contains the implementation plan as requested. Order No. 14- 252, p. 16 In future IRPs, PacifiCorp will provide yearly Class 1 and Class 2 DSM acquisition targets in both GWh and MW for each year in the planning period, by state. See Appendix D for the breakdown by state and year for both energy and capacity selected for the preferred portfolio. Order No. 14- 252, p. 20 Order 14-252 modified Action Item 9b to read: Continue permitting Segments D, E, F, and H until PacifiCorp files its 2015 IRP, at which time a SBT analysis for these segments will be performed. See the 2013 IRP Action Plan Status Update in Volume I, Chapter 9 which includes the following: PacifiCorp has continued to permit the Segments as discussed above. The Company is not proposing an acknowledgement Action Item for the Segments in the 2015 IRP – thus there is not an SBT analysis provided. Utah Order, Docket o. 13-2035-01, p. 14. Because EPA’s proposed and final implementation plans and challenges to those implementation plans continue to fluctuate, we encourage PacifiCorp to continue to monitor and prudently respond to the constantly changing landscape in its IRP update to be filed in 2014 (2013 IRP Update) and in the 2015 IRP. PacifiCorp is fully engaged in state and EPA Regional Haze implementation plan activity. Background on Regional Haze is provided in Volume I, Chapter 3. Prospective Regional Haze requirements and potential compliance outcomes are considered in the 2015 IRP resource portfolio development process (Volume I, Chapter 7 and Volume I, Chapter 8). Impacts of Regional Haze outcomes are assessed in the 2015 IRP acquisition path analysis (Volume I, Chapter 9). PacifiCorp provides a detailed update on Regional Haze requirements Wyodak, Naughton Unit 3, Dave Johnston Unit 3, and Cholla Unit 4 in Volume III. Action items related to these coal units are outlined in Volume I, Chapter 9. Order, Docket o. 13-2035-01, p. 15. While the SBT shows some promise in demonstrating non-modeled benefits and costs, we are not persuaded it adequately identifies these benefits in the 2013 IRP... However, PacifiCorp should continue to discuss with state agencies and other interested parties how best to consider this information in the identification of a preferred portfolio prior to its use. PacifiCorp held several workshops with interested stakeholders to discuss options for quantifying potential transmission benefits. See Volume I, Chapter 9, Action Item 9a update for more information. Going forward, PacifiCorp will develop cost and benefit support for transmission projects for which it is seeking Commission acknowledgement. Order, Docket o. 13-2035-01, p. 15. The Division and other parties indicate the IRP process is difficult and time- consuming...Further, we understand process improvements are being discussed informally, which we encourage. The Company held a meeting on September 23, 2013 to discuss potential improvements in the IRP process, as well as accepting written comments from stakeholders. These comments and suggestions resulted in several changes to the 2015 IRP. Some examples include scheduling multi-day public input meetings to ensure there is adequate time to cover topics thoroughly, addition of a Feedback Form for stakeholders to provide comments throughout the public input process. Comments received through this process directly influenced assumptions and PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 31 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP core case definitions adopted for the 2015 IRP. PacifiCorp is also increasing transparency by including data disks with its 2015 IRP filing, and held technical workshops on new models introduced to the 2015 IRP (the 111(d) Scenario Maker model). PacifiCorp further improved its modeling approach by including estimates of transmission integration and reinforcement costs specific to each unique resource portfolio. Order, Docket o. 13-2035-01, p. 17. As we have stated in the past, sensitivity analysis should be an effective tool for evaluating the effect on resource selection of various assumptions regarding solar and wind resource costs. We recognize there are differences of opinion, and some uncertainties, regarding renewable resource cost assumptions. We encourage PacifiCorp and stakeholders to develop a strategy to address this issue in the 2015 IRP. Further, the results of this effort could be utilized in PacifiCorp’s acquisition path analysis to inform decisions if the future unfolds differently than expected. See Volume I, Chapter 6 for discussion related to cost assumptions related to new resources. Resource cost assumptions were reviewed and discussed with stakeholders at the August 7, 2014 public input meeting. As part of the 2015 IRP PacifiCorp requested stakeholder feedback on all topics, including renewable resource costs, which resulted in sensitivity around potential future solar costs (S-12) with assumptions provided by members of the stakeholder group. Sensitivity assumptions are discussed in Volume I, Chapter 7. Sensitivity results are provided in Volume I, Chapter 8. Order, Docket o. 13-2035-01, p. 19. UCE questions the annual limit of available rooftop solar resource in Utah...We support PacifiCorp’s commitment to address this issue in the 2015 IRP cycle. PacifiCorp has included an updated distributed generation (DG) assessment, prepared by Navigant Consulting, in the 2015 IRP. This DG assessment is used to support DG penetration levels (inclusive of rooftop solar and other DG technologies) among base, low and high scenarios. The study is discussed in Volume I, Chapter 5, and included in Volume II, Appendix O. Order, Docket o. 13-2035-01, p. 19. PacifiCorp’s treatment of RECs in the 2013 IRP is questioned by several parties. First, in its replacement of 208 megawatts of wind resource in the Preferred Portfolio with unbundled RECs, PacifiCorp does not analyze the comparative risks of the two alternatives, essentially concluding that a wind resource and an unbundled REC carry the same risks for customers. Parties argue this conclusion should be tested rather than assumed. Second, parties argue the value o a REC should be included in the cost of a renewable resource as an offset. We direct PacifiCorp to further address both of these issues in the 2013 IRP Update. PacifiCorp addressed this issue in the 2013 IRP Update as directed. Please see pages 45-46 of the 2013 IRP Update for discussion on the Renewable Energy Credit value. Order, Docket o. 13-2035-01, p. 19-20. UCE and Interwest argue PacifiCorp’s assumed capacity contribution at the time o peak demand for wind and solar resources is understated and is inconsistent with the method and values approved by the Commission in its August 16, 2013, Order on Phase II Issues in Docket No. 12-035- 100 (“August Order”) on avoided costs for qualifying facilities (“QF”s)....In the 2013 IRP Update we direct PacifiCorp to perform PacifiCorp’s 2013 IRP Update contained the sensitivity case as directed. These renewable sensitivities are discussed on pages 59-67 of the 2013 IRP Update, with the specific capacity sensitivity results on page 67. PacifiCorp further produced a solar and wind capacity contribution study in support of its 2015 IRP. This study is provided in Volume II, Appendix N. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 32 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP a sensitivity case with stochastic analysis using the values in the August Order for wind and solar capacity contribution. Order, Docket o. 13-2035-01, p. 22. The Office recommends the Commission require PacifiCorp “to provide a contingency plan for the IRP’s heavy reliance on [front office transactions] to be used in the event that market supplies tighten and prices increase significantly...We encourage PacifiCorp to examine the Office’s recommendation in the 2015 IRP cycle. Such analysis could be included in the section of the IRP devoted to acquisition path analysis. PacifiCorp discusses its assumed market limits in Volume I, Chapter 6. Modeling of market purchases is discussed in Volume I, Chapter 7. Core case definitions include a scenario that limits market purchases at NOB and Mona (Volume I, Chapter 7), which is used to address market limits in the acquisition path analysis (Volume I, Chapter 9). PacifiCorp provides an assessment of western resource adequacy in Volume II, Appendix J. With reduced loads, increasing DG penetration, and increased DSM acquisition, market purchases in the 2015 IRP preferred portfolio are down by 29% through 2024 relative to the 2013 IRP preferred portfolio. Order, Docket o. 13-2035-01, p. 23. We accept a 13 percent planning reserve as reasonable for this IRP and recommend continued analysis of this issue, both through LOLP study and tradeoff analysis. PacifiCorp presented the results of its Planning Reserve Margin study at the September 25-26 public input meeting. The study itself is included as Volume II, Appendix I. Order, Docket o. 13-2035-01, p. 23-24. We direct PacifiCorp to present in the 2015 IRP an analysis of whether the available historical cooling degree day information is an appropriate predictor of future “normal” conditions and, if warranted, to identify and implement a superior predictor in that IRP. This topic was addressed at the July 17-18, 2014 public input meeting and discussed in Appendix A. In short, the peak producing weather has not changed significantly when looking at five, ten, or twenty year averages. As such, PacifiCorp has not adjusted the historic time period for load forecasting. Order, Docket o. 13-2035-01, p. 24. UCE and WRA also dispute PacifiCorp’s decision to eliminate the long-run load volatility parameter from its stochastic analysis. PacifiCorp argues this parameter produces results that are not useful for comparing the costs and risks of portfolios and that it is more appropriate to study long-term load risk through load forecast scenario analysis. We direct PacifiCorp to facilitate a discussion of this issue in the 2015 IRP cycle. Stochastic parameters were discussed at the August 7-8, 2014 public input meeting as well as the September 25-26, 2014 public input meeting. PacifiCorp continues to use short-term volatility and mean reversion parameters to model load volatility. Long-term load uncertainties are analyzed using load sensitivity analysis, described in Volume I, Chapter 7 with results presented in Volume I, Chapter 8. These sensitivities inform the 2015 IRP acquisition path analysis in Volume I, Chapter 9. Order, Docket o. 13-2035-01, p. 24 The Division notes PacifiCorp includes historic load data in the 2013 IRP. We note the annual coincident peak load data by state in Table A.7 on page 13 of Appendix A, appears rather to provide each state’s highest monthly peak load which is coincident with the system rather than its load coincident with the time of annual system peak. PacifiCorp should correct this table and provide it in its 2013 IRP Update. A corrected table was provided as Appendix E in the 2013 IRP Update. Order, Docket No. 13-2035-01, p. 25. The Division notes PacifiCorp includes in Table 9.2, “an excellent summary of actions [PacifiCorp] may undertake should the future start to turn out See Volume I, Chapter 9, specifically Table 9.3 for the acquisition path analysis discussion. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 33 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP significantly different than anticipated as reflected in [PacifiCorp’s] preferred portfolio.” We concur with the Division this is a very useful table and we encourage PacifiCorp to expand its use of this table in its 2013 IRP Update and 2015 IRP to address additional issues. Order, Docket No. 13-2035-01, p. 25. WRA and UCE request PacifiCorp conduct a workshop on its stochastic risk modeling. We find this to be a reasonable request and suggest PacifiCorp include this topic in a separate workshop in its 2015 IRP cycle. Stochastic modeling was a topic at several of the public input meetings: August 7-8, 2014 and September 25-26, 2014. The results of the stochastic modeling were presented at the January 29-30, 2015 public input meeting. Order, Docket No. 13-2035-01, pp. 25-26. The Division and other parties state PacifiCorp did not perform the third stage of the three stage process outlined in the Commission’s Report and Order on PacifiCorp’s 2008 IRP in Docket No. 09- 2035-01 (“2008 Order”)...We agree that, although not a required Guideline, the third stage identifies an optimal portfolio that is robust across different uncertain futures and we encourage PacifiCorp to utilize the third stage in the 2015 IRP. PacifiCorp included a deterministic risk analysis (the “third stage” as referenced in the Commission Report and Order). The methodology is discussed in Volume I, Chapter 7. Results, used to inform selection of the preferred portfolio, are provided in Volume I, Chapter 8. Order, Docket No. 13-2035-01, pp. 26-27. We encourage PacifiCorp to work with stakeholders in the 2015 IRP cycle to ensure cases of interest to stakeholders, including sensitivity cases, are fully evaluated against cost, risk and performance measures. For the 2015 IRP PacifiCorp developed a feedback form to capture, among other things, cases of interest to stakeholders. Two core cases of specific interest to stakeholders included those associates with EPA’s 111(d) rule implemented as a mass cap, cases with CO2 price assumptions incremental to 111(d) requirements, and a case with limited FOT availability. Sensitivity cases were also influenced by stakeholder comments, including sensitivities related to solar resource costs, high CO2 price assumptions, and 111(d) compliance. Sensitivity cases were also analyzed in PaR. Order, Docket No. 13-2035-01, p. 28. We note PacifiCorp provided a link to access the 2013 DSM Potentials Study in the 2013 IRP but did not file it as required. We direct PacifiCorp to file the 2013 DSM Potentials Study in this docket within 45 days. The study was filed on January 16, 2014 in Docket No. 13-2035-01 as required. The updated conservation potential study is saved to data disks filed with the 2015 IRP. Order, Docket No. 13-2035-01, p. 30. We note PacifiCorp did not present the Business Plan as a sensitivity case in the 2013 IRP. We remind PacifiCorp to provide this sensitivity in the 2013 IRP Update and all future IRPs. The 2013 IRP Update contained a sensitivity on the Business Plan. See pages 56-58 specifically for the analysis. Utah Commission Staff suggested this requirement be met by discussing the business plan in the context of the acquisition path analysis. PacifiCorp notes in its acquisition path analysis that resource changes in resource procurement strategies driven by changes in the planning environment are captured in the IRP and future business plan cycles. PacifiCorp further explains differences between its fall 2014 ten-year business plan resource portfolio and the 2015 IRP preferred portfolio in Volume I, Chapter 9. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 34 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP Washington UE-120416, p. 2. PacifiCorp should continue purchasing RECs through requests for proposals at regular intervals to ensure that the REC- based compliance strategy remains the lowest-cost option. The Company has issued RFPs to meet Washington requirements in both 2013 and 2014. Bids were selected with compelling price and/or structure criteria. See also Volume I, Chapter 9 for further discussion. The 2015 IRP action plan calls for further REC RFPs to meet projected Washington RPS requirements. UE-120416, p. 3. Depending on how the new regulations for existing coal plants are implemented and how much authority and flexibility is afforded to state air quality and economic regulators, these regulations will likely place a price on carbon, either directly or indirectly. Therefore, we request that the Company’s modeling account for the possible range of carbon prices consistent with regulations developed under Section 111(d) of the Clean Air Act, 42 U.S.C. Sec. 7411, for existing plants. The 2015 IRP includes extensive modeling to address 111(d) policy and compliance uncertainties. PacifiCorp’s 111(d) modeling approach and case definitions are described in Volume I, Chapter 7. Results are presented in Volume I, Chapter 8. Summaries of each case, including representation of 111(d) compliance by state is included in case fact sheets provided in Volume II, Appendix M. PacifiCorp further included core cases and sensitivity cases that impose CO2 prices that are incremental to assumed 111(d) requirements. UE-120416, pp. 3-4. The Company’s original approach using a wide range of future natural gas price assumptions was instructive. However, a more detailed analysis that focuses on the gaps between the various projections that the Company used and identifies the price level at which it would become cost- effective to switch an existing coal plant to natural gas is required to better inform the Company’s decision-making process. Given these developments, the Commission concludes that PacifiCorp should update its coal analysis as part of its 2013 IRP Update. PacifiCorp provided a breakeven analysis as requested in Confidential Appendix F of the 2013 IRP Update. UE-120416, p. 4. The Commission appreciates the IRP’s in- depth attention to transmission planning. The System Operational and Reliability Benefits Tool (SBT) that the Company has developed to analyze potential new transmission investments has the potential to more accurately portray the economics of transmission projects... The Company should continue to engage stakeholders in the refinement of this evolving and potentially important transmission planning tool. PacifiCorp solicited stakeholder participation in an SBT workgroup in June, 2013. There were a total of four workshops held to discuss refinement of the tools. PacifiCorp will develop cost and benefit support for transmission projects for which it is seeking Commission acknowledgement. See Action Item 9A in Table 9.2 – 2013 IRP Action Plan Status Update for further discussion. UE-120416, p. 5. Therefore we believe it is both impractical and unrealistic to use a zero cost of carbon in the base case, or business-as-usual case, in the next IRP cycle. PacifiCorp’s next IRP must include a non-zero cost of carbon in its base case. PacifiCorp has not assumed a zero cost of carbon base case for many IRP cycles. For the 2015 IRP, PacifiCorp’s base case incorporates EPA’s proposed 111(d) rule (see Volume I, Chapter 7). PacifiCorp further includes scenarios that impose a CO2 price incremental to 111(d) requirements. UE-120416, p. 5. The Company’s 2015 IRP should also examine ways in which PacifiCorp can contribute to Washington’s goal of reducing carbon emissions to 1990 levels See Volume I, Chapter 8 for an assessment of portfolios that meet Washington’s goal of reducing carbon emissions to 1990 levels by 2020. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 35 Reference IRP Requirement or Recommendation How the Requirement or Recommendation is Addressed in the 2015 IRP by 2020 and evaluate the rate impacts of any such measure. UE-120416, pp. 5-6. In its 2011 IRP Acknowledgment letter, the Commission requested that the Company model its West and East control areas separately in the 2013 IRP. The Company must model the two areas separately in the next IRP as a prerequisite for acknowledgment. PacifiCorp included sensitivity case S-10 that meets this requirement. See Volume I, Chapter 7 for a description of the sensitivity case and Volume I, Chapter 8 for presentation of the results. UE-120416, p. 6. The Commission requests that the Company update its energy storage analysis and use more current data as an input to the 2015 IRP. PacifiCorp completed an update to the Energy Storage Screening Study as discussed in Volume I, Chapter 6. A copy of the study is included on the data disks filed with the 2015 IRP. UE-120416, p. 6. Regarding anaerobic digesters, the Commission believes that PacifiCorp’s modeling in the IRP process did not address adequately the Commission’s 2011 request for the Company to analyze the potential for this technology in its Washington service territory...We expect a rigorous analysis of the potential for this form of generation in the next IRP cycle. In 2014, PacifiCorp commissioned Harris Group Incorporated to perform an extensive assessment on power generation potential from anaerobic digestion. See Volume I, Chapter 6 for discussion of the results and the full study is included on the data disks filed with the 2015 IRP. Additionally, a public presentation on the report findings was prepared and made at the 2015 Integrated Resource Plan Public Input Meeting 4 on September 25, 2014. UE-120416, p. 7. Additionally, the Commission expects that PacifiCorp’s 2015 IRP will contain a more robust analysis of smart grid technologies and potential opportunities for the Company recognizing that, like electric storage, this technology is dynamic and potentially becoming more cost-effective over time. See Appendix E for discussion of smart grid. Wyoming The Wyoming Public Service Commission provided the following comment in its Letter Order (Docket No. 20000- 424-EA-13, record No. 13425, dated September 4, 2013) on PacifiCorp’s 2011 IRP: Pursuant to open meeting action taken on August 29, 2013, Rocky Mountain Power’s 2013 Integrated Resource Plan is hereby placed in the Commission’s files. No further action will be taken and this matter is closed. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 36 Table B.3 – Oregon Public Utility Commission IRP Standard and Guidelines No. Requirement How the Guideline is Addressed in the 2015 IRP Guideline 1. Substantive Requirements 1.a.1 All resources must be evaluated on a consistent and comparable basis: All known resources for meeting the utility’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. PacifiCorp considered a wide range of resources including renewables, DSM, energy storage, power purchases, thermal resources, and transmission. Volume I, Chapter 4 (Transmission Planning), Chapter 6 (Resource Options), and Chapter 7 (Modeling and Portfolio Evaluation Approach) document how PacifiCorp developed these resources and modeled them in its portfolio analysis. All these resources were established as resource options in the Company’s capacity expansion optimization model, System Optimizer, and selected by the model based on load requirements, relative economics, resource size, availability dates, and other factors. 1.a.2 All resources must be evaluated on a consistent and comparable basis: Utilities should compare different resource fuel types, technologies, lead times, in-service dates, durations and locations in portfolio risk modeling. All portfolios developed with System Optimizer were subjected to Monte Carlo production cost simulation. These portfolios contained a variety of resource types with different fuel types (coal, gas, biomass, nuclear fuel, and “no fuel” renewables), lead-times, in-service dates, operational lives, and locations. See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), Chapter 8 (Modeling and Portfolio Selection Results), and Volume II, Appendix K (Detail Capacity Expansion Results) and Appendix L (Stochastic Production Cost Simulation Results). 1.a.3 All resources must be evaluated on a consistent and comparable basis: Consistent assumptions and methods should be used for evaluation of all resources. PacifiCorp fully complies with this requirement. The Company developed generic supply-side resource attributes based on a consistent characterization methodology. For demand-side resources, the company used supply curves supported by an updated conservation potential assessment (CPA), specific to PacifiCorp’s service territory. The CPA was based on a consistently applied methodology for determining technical, market, and achievable DSM potentials. All portfolio resources were evaluated using the same sets of price and load forecast inputs. These inputs are documented in Volume I, Chapter 5 (Resource Needs Assessment), Chapter 6 (Resource Alternatives), and Chapter 7 (Modeling and Portfolio Evaluation Approach) as well as Volume II, Appendix D (Demand-Side Management and Supplemental Resources). 1.a.4 All resources must be evaluated on a consistent and comparable basis: The after-tax marginal weighted-average cost of capital (WACC) should be used to discount all future resource costs. PacifiCorp applied its after-tax WACC of 6.66% to discount all cost and revenue streams. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 37 No. Requirement How the Guideline is Addressed in the 2015 IRP 1.b.1 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 outages, fuel prices, electricity prices, and costs to comply with any regulation of greenhouse gas emissions. PacifiCorp performs stochastic risk modeling of load, price, hydro generation, and thermal outage variables in PaR. Price scenarios are also used in PaR to perform cost and risk analysis among resource portfolios. Load scenarios are further tested in sensitivity analysis. CO2 policy risk and uncertainty is analyzed via scenario analysis. The 2015 IRP includes extensive analysis of 111(d) policy and compliance uncertainties and includes cases where CO2 prices are applied incremental to assumed compliance requirements stemming from EPA’s draft 111(d) rule. See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). 1.b.2 Risk and uncertainty must be considered: Utilities should identify in their plans any additional sources of risk and uncertainty. Resource risk mitigation is discussed in Volume I, Chapter 9 (Action Plan and Resource Procurement). 1.c The primary goal must be the selection of a portfolio of resources with the best combination of expected costs and associated risks and uncertainties for the utility and its customers (“best cost/risk portfolio”). PacifiCorp evaluated cost/risk tradeoffs for each of the portfolios considered. See Volume I, Chapter 8 (Modeling and Portfolio Selection Results), Volume I, Chapter 9 (Action Plan), and Volume II, Appendix K (Detailed Capacity Expansion Results) and Volume II, Appendix L (Stochastic Production Cost Simulation Results) for the Company’s portfolio cost/risk analysis and determination of the preferred portfolio. 1.c.1 The planning horizon for analyzing resource 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 resource. PacifiCorp used a 20-year study period (2015-2034) for portfolio modeling, and a real levelized revenue requirement methodology for treatment of end effects. 1.c.2 Utilities should use present value of revenue 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 well as all short- lived resources such as gas supply and short- term power purchases. Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) provides a description of the PVRR methodology. Resource cost assumptions and resource life assumptions are outlined in Chapter 6 (Resource Options). 1.c.3.1 To address risk, the plan should include, at a minimum: 1. Two measures of PVRR risk: one that measures the variability of costs and one that measures the severity of bad outcomes. PacifiCorp uses the standard deviation of stochastic production costs as the measure of cost variability. See Volume II Appendix L (Stochastic Production Cost Simulation Results). For the severity of bad outcomes, the Company calculates several measures, including stochastic upper-tail mean PVRR (mean of highest three Monte Carlo iterations) and the 95th percentile stochastic production cost PVRR. See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), as well as Volume II Appendix L (Stochastic Production Cost Simulation Results). PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 38 No. Requirement How the Guideline is Addressed in the 2015 IRP 1.c.3.2 To address risk, the plan should include, at a minimum: 2. Discussion of the proposed use and impact on costs and risks of physical and financial hedging. A discussion on hedging is provided in Volume I, Chapter 9 (Action Plan and Resource Procurement). 1.c.4 The utility should explain in its plan how its resource choices appropriately balance cost and risk. Volume I, Chapter 8 (Modeling and Portfolio Selection Results) summarizes the results of PacifiCorp’s cost/risk tradeoff analysis, and describes what criteria the Company used to determine the best cost/risk portfolios and the preferred portfolio. 1.d The plan must be consistent with the long-run public interest as expressed in Oregon and federal energy policies. PacifiCorp considered both current and potential state and federal energy/pollutant emission policies in portfolio modeling. Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) describes the decision process used to derive portfolios, which includes consideration of state and federal resource policies and regulations that are summarized in Volume I, Chapter 3 (The Planning Environment). Volume I, Chapter 8 (Modeling and Portfolio Selection Results) provides the results. Volume I, Chapter 9 (Action Plan) presents an acquisition path analysis that describes resource strategies based on trigger events. Guideline 2. Procedural Requirements 2.a The public, which includes other utilities, should be allowed significant involvement in the preparation of the IRP. Involvement includes opportunities to contribute information and ideas, as well as to receive information. Parties must have an opportunity 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 responsive, may be submitted to the Commission for resolution. PacifiCorp fully complies with this requirement. Volume I, Chapter 2 (Introduction) provides an overview of the public process, all public meetings held for the 2015 IRP, which are documented in Volume II, Appendix C (Public Input Process). PacifiCorp also made use of a Feedback Form for stakeholders to provide comments and offer suggestions. 2.b While confidential information must be protected, the utility should make public, in its plan, any non-confidential information that is relevant to its resource evaluation and action plan. Confidential information may be protected through use of a protective order, through aggregation or shielding of data, or through any other mechanism approved by the Commission. 2015 IRP Volumes I and II provide non-confidential information the Company used for portfolio evaluation, as well as other data requested by stakeholders. PacifiCorp also provided stakeholders with non-confidential information to support public meeting discussions via email. Volume III of the 2015 IRP is confidential and is protected through the use of a protective order. Data disks will be available with public data. Additionally, data disks with confidential data are protected through use of a protective order. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 39 No. Requirement How the Guideline is Addressed in the 2015 IRP 2.c The utility must provide a draft IRP for public review and comment prior to filing a final plan with the Commission. PacifiCorp distributed draft IRP materials for external review throughout the process prior to each of the public input meetings and solicited/and received feedback at various times when developing the 2015 IRP. The materials shared with stakeholders at these meetings, outlined in Volume I Chapter 2 (Introduction), is consistent with materials presented in Volumes I, II, and III of the 2015 IRP report. PacifiCorp requested and responded to comments from stakeholders in developing core case and sensitivity definitions. The Company considered comments received via the Feedback form in developing its final plan. Guideline 3: Plan Filing, Review, and Updates 3.a 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 2015 IRP complies with this requirement. 3.b The utility must present the results of its filed plan to the Commission at a public meeting prior to the deadline for written public comment. This activity will be conducted subsequent to filing this IRP. 3.c Commission staff and parties should complete their comments and recommendations within six months of IRP filing. This activity will be conducted subsequent to filing this IRP. 3.d 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 IRP before issuing an acknowledgment order. This activity will be conducted subsequent to filing this IRP. 3.e The Commission may provide direction to a utility regarding any additional analyses or actions that the utility should undertake in its next IRP. Not applicable. 3.f (a) Each energy utility must submit an annual update on its most recently acknowledged IRP. The update is due on or before the acknowledgment order anniversary date. Once a utility anticipates a significant deviation 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 summarize the update at a Commission public meeting. The utility may request acknowledgment of changes in proposed actions identified in an update. This activity will be conducted subsequent to filing this IRP. 3.g Unless the utility requests acknowledgment of This activity will be conducted subsequent to filing PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 40 No. Requirement How the Guideline is Addressed in the 2015 IRP changes in proposed actions, the annual update is an informational filing that:  Describes what actions the utility has taken to implement the plan;  Provides an assessment of what has changed since the acknowledgment order that affects the action plan to select best portfolio of resources, including changes in such factors as load, expiration of resource contracts, supply-side and demand-side resource acquisitions, resource costs, and transmission availability; and  Justifies any deviations from the acknowledged action plan. this IRP. Guideline 4. Plan Components: At a minimum, the plan must include the following elements 4.a An explanation of how the utility met each of the substantive and procedural requirements. The purpose of this table is to comply with this guideline. 4.b Analysis of high and low load growth scenarios in addition to stochastic load risk analysis with an explanation of major assumptions. PacifiCorp developed low, high, and extreme peak temperature (one-in-twenty probability) load growth forecasts for scenario analysis using the System Optimizer model. Stochastic variability of loads was also captured in the risk analysis. See Volume I, Chapters 5 (Resource Needs Assessment) and Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), and Volume II, Appendix A (Load Forecast) for load forecast information. 4.c For electric utilities, a determination of the levels of peaking capacity and energy capability 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 additions associated with the resource portfolios tested. See Volume I, Chapter 5 (Resource Need Assessment) for details on annual capacity and energy balances. Existing transmission rights are reflected in the IRP model topologies. Future transmission additions used in analyzing portfolios are summarized in Volume I, Chapter 4 (Transmission) and Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). Results of sensitivity analysis with future transmission projects are summarized in Volume I, Chapter 8. 4.d For gas utilities only Not applicable 4.e Identification and estimated costs of all supply- side and demand side resource options, taking into account anticipated advances in technology Volume I, Chapter 6 (Resource Options) identifies the resources included in this IRP, and provides their detailed cost and performance attributes. Additional information on energy efficiency resource characteristics is available in Volume II, Appendix D (Demand-Side Management and Supplemental Resources). 4.f Analysis of measures the utility intends to take to provide reliable service, including cost-risk tradeoffs In addition to incorporating a 13% planning reserve margin for all portfolios evaluated, as supported by an updated planning reserve margin study (Volume II, Appendix I), the Company used several measures to evaluate relative portfolio supply reliability. These measures (Energy Not Served and Loss of Load Probability), which are described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). 4.g Identification of key assumptions about the future (e.g., fuel prices and environmental Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) describes the key assumptions PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 41 No. Requirement How the Guideline is Addressed in the 2015 IRP compliance costs) and alternative scenarios considered and alternative scenarios used in this IRP. Volume II, Appendix M (Case Study Fact Sheets) includes summaries of assumptions used for each case definition analyzed in the 2015 IRP. 4.h Construction of a representative set of resource portfolios to test various operating characteristics, resource types, fuels and sources, technologies, lead times, in-service dates, durations and general locations – system- wide or delivered to a specific portion of the system This Plan documents the development and results of portfolios designed to determine resource selection under a variety of input assumptions in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) and Volume I, Chapter 8 (Modeling and Portfolio Selection Results). 4.i Evaluation of the performance of the candidate portfolios over the range of identified risks and uncertainties Volume I, Chapter 8 (Modeling and Portfolio Selection Results) presents the stochastic portfolio modeling results, and describes portfolio attributes that explain relative differences in cost and risk performance. 4.j Results of testing and rank ordering of the portfolios by cost and risk metric, and interpretation of those results. Volume I, Chapter 8 (Modeling and Portfolio Selection Results) provides tables and charts with performance measure results, including rank ordering. 4.k Analysis of the uncertainties associated with each portfolio evaluated. See responses to 1.b.1 and 1.b.2 above. 4.l Selection of a portfolio that represents the best combination of cost and risk for the utility and its customers. See 1.c above. 4.m Identification and explanation of any inconsistencies of the selected portfolio with any state and federal energy policies that may affect a utility’s plan and any barriers to implementation. This IRP is designed to avoid inconsistencies with state and federal energy policies therefore none are currently identified. Risks to resource procurement activities are addressed in Chapter 9 (Action Plan and Resource Procurement). 4.n 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 activity was acknowledged in a previous IRP, with the key attributes of each resource specified as in portfolio testing. Volume I, Chapter 9 (Action Plan and Resource Procurement) presents the 2015 IRP action plan identifying resource actions required over the next two to four years. Guideline 5: Transmission 5 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 resource options, taking into account their value for making additional purchases and sales, accessing less costly resources in remote locations, acquiring alternative fuel supplies, and improving reliability. Costs for fuel transportation and transmission are factored into each resource portfolio evaluated for the 2015 IRP. Fuel transport costs are reflected in the fixed costs and/or variable fuel costs for each resource option, as applicable (Volume I, Chapter 6). Transmission costs include integration and reinforcement costs, specific to each resource portfolio (Volume I, Chapter 6 and Chapter 7). PacifiCorp further evaluated two sensitivities on Energy Gateway transmission project configurations on a consistent and comparable basis with respect to other resources. Where new resources would require additional transmission facilities the associated costs were factored into the analysis. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 42 No. Requirement How the Guideline is Addressed in the 2015 IRP Guideline 6: Conservation 6.a Each utility should ensure that a conservation potential study is conducted periodically for its entire service territory. A multi-state conservation potential assessment was updated and used to support the 2015 IRP. 6.b To the extent that a utility controls the level of funding for conservation programs in its service territory, the utility should include in its action plan all best cost/risk portfolio conservation resources for meeting projected resource needs, specifying annual savings targets. PacifiCorp’s energy efficiency supply curves incorporate Oregon resource potential. Oregon potential estimates were provided by the Energy Trust of Oregon. See the demand-side resource section in Volume I, Chapter 6 (Resource Alternatives), the results in Volume I, Chapter 8 (Modeling and Portfolio Selection Results), the targeted amounts in Volume I, Chapter 9 (Action Plan and Resource Procurement). State implementation plans are included in Volume II, Appendix D. 6.c To the extent that an outside party administers conservation programs in a utility’s 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 action plan consistent with the outside party’s projection of conservation acquisition. See the response for 6.b above. Guideline 7: Demand Response 7 Plans should evaluate demand response resources, including voluntary rate programs, on par with other options for meeting energy, capacity, and transmission needs (for electric utilities) or gas supply and transportation needs (for natural gas utilities). PacifiCorp evaluated demand response resources (Class 1 and 3 DSM) on a consistent basis with other resources. Guideline 8: Environmental Costs 8.a Base case and other compliance scenarios: The utility should construct a base-case scenario to reflect what it considers to be the most likely regulatory compliance future for carbon dioxide (CO2), nitrogen oxides, sulfur oxides, and mercury emissions. The utility should develop several compliance scenarios ranging from the present CO2 regulatory level to the upper reaches of credible proposals by governing entities. Each compliance scenario should include a time profile of CO2 compliance requirements. The utility should identify whether the basis of those requirements, or “costs,” would be CO2 taxes, a ban on certain types of resources, or CO2 caps (with or without flexibility mechanisms such as allowance or credit trading as a safety valve). The analysis should recognize significant and important upstream emissions that would likely have a significant impact on resource decisions. Each See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). PacifiCorp’s base scenario assumes implantation of EPA’s proposed 111(d) rule as an emission rate standard allowing flexible allocation of existing renewable resources among states to achieve compliance. Additional 111(d) policy scenarios and compliance strategies are also studied. Further, PacifiCorp studies CO2 policy scenarios with CO2 prices incremental to compliance requirements assumed in EPA’s draft 111(d) rule. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 43 No. Requirement How the Guideline is Addressed in the 2015 IRP compliance scenario should maintain logical consistency, to the extent practicable, between the CO2 regulatory requirements and other key inputs. 8.b Testing alternative portfolios against the compliance scenarios: The utility should estimate, under each of the compliance scenarios, the present value revenue requirement (PVRR) costs and risk measures, over at least 20 years, for a set of reasonable alternative portfolios from which the preferred portfolio is selected. The utility should incorporate end-effect considerations in the analyses to allow for comparisons of portfolios containing resources with economic or physical lives that extend beyond the planning period. The utility should also modify projected lifetimes as necessary to be consistent with the compliance scenario under analysis. In addition, the utility should include, if material, sensitivity analyses on a range of reasonably possible regulatory futures for nitrogen oxides, sulfur oxides, and mercury to further inform the preferred portfolio selection. Volume II, Appendix L (Stochastic Production Costs Simulation Results) provides the Stochastic mean PVRR versus upper tail mean less stochastic mean PVRR scatter plot diagrams that for portfolios developed with a range of compliance scenarios as summarized in 8.a above. The Company considers end-effects in its use of real levelized revenue requirement analysis, as summarized in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) and uses a 20-year planning horizon. A range of potential Regional Haze scenarios, reflecting hypothetical inter-temporal and fleet trade- off compliance outcomes. Detailed analysis of Regional Haze compliance alternatives for Wyodak, Naughton Unit 3, Dave Johnston Unit 3, and Cholla Unit 4 is included in Volume III. All studies in the 2015 IRP reflect assumed costs for compliance with known and prospective regulations (MATs, CCR, ELG, and cooling water intake structures), as applicable. 8.c Trigger point analysis: The utility should identify at least one CO2 compliance “turning point” scenario, which, if anticipated now, would lead to, or “trigger” the selection of a portfolio of resources that is substantially different from the preferred portfolio. The utility should develop a substitute portfolio appropriate for this trigger-point scenario and compare the substitute portfolio’s expected cost and risk performance to that of the preferred portfolio – under the base case and each of the above CO2 compliance scenarios. The utility should provide its assessment of whether a CO2 regulatory future that is equally or more stringent that the identified trigger point will be mandated. See Volume I, Chapter 8 (Modeling and Portfolio Selection Results), which includes a Trigger Point Analysis, summarizing portfolios developed with CO2 policy assumptions that are substantially different from the preferred portfolio. 8.d Oregon compliance portfolio: If none of the above portfolios is consistent with Oregon energy policies (including state goals for reducing greenhouse gas emissions) as those policies are applied to the utility, the utility should construct the best cost/risk portfolio that achieves that consistency, present its cost and risk parameters, and compare it to those the preferred and alternative portfolios. Two portfolios yield system emissions aligned with state goals for reducing greenhouse gas emissions. These cases are summarized in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). Guideline 9: Direct Access Loads 9 An electric utility’s load-resource balance should exclude customer loads that are effectively committed to service by an PacifiCorp continues to plan for load for direct access customers. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 44 No. Requirement How the Guideline is Addressed in the 2015 IRP alternative electricity supplier. Guideline 10: Multi-state Utilities 10 Multi-state utilities should plan their generation and transmission systems, or gas supply and delivery, on an integrated system basis that achieves a best cost/risk portfolio for all their retail customers. The 2015 IRP conforms to the multi-state planning approach as stated in Volume I, Chapter 2 under the section “The Role of PacifiCorp’s Integrated Resource Planning”. Guideline 11: Reliability 11 Electric utilities should analyze reliability within the risk modeling of the actual portfolios being considered. Loss of load probability, expected planning reserve margin, and expected and worst-case unserved energy should be determined by year for top-performing portfolios. Natural gas utilities should analyze, on an integrated basis, gas supply, transportation, and storage, along with demand- side resources, to reliably meet peak, swing, and base-load system requirements. Electric and natural gas utility plans should demonstrate that the utility’s chosen portfolio achieves its stated reliability, cost and risk objectives. See the response to 1.c.3.1 above. Volume I, Chapter 8 (Modeling and Portfolio Selection Results) walks through the role of reliability, cost, and risk measures in determining the preferred portfolio. Scatter plots of portfolio cost versus risk at for different price curve assumptions were used to inform the cost/risk tradeoff analysis. Stochastic and risk analysis results for specific portfolios are also included in Volume II Appendix L (Stochastic Production Costs Simulation Results). Guideline 12: Distributed Generation 12 Electric utilities should evaluate distributed generation technologies on par with other supply-side resources and should consider, and quantify where possible, the additional benefits of distributed generation. PacifiCorp contracted with Navigant to provide estimates of expected distributed generation penetration. The study was incorporated in the analysis as a reduction to load. Sensitivities looked at both high and low penetration rates for distributed generation. The study in included in Volume II, Appendix O. Guideline 13: Resource Acquisition 13.a An electric utility should, in its IRP: 1. Identify its proposed acquisition strategy for each resource in its action plan. 2. Assess the advantages and disadvantages of owning a resource instead of purchasing power from another party. 3. Identify any Benchmark Resources it plans to consider in competitive bidding. Volume I, Chapter 9 (Action Plan and Resource Procurement) outlines the procurement approaches for resources identified in the preferred portfolio. A discussion of the advantages and disadvantages of owning a resource instead of purchasing it is included in Volume I, Chapter 9 (Action Plan and Resource Procurement). There are no Benchmark Resources in Chapter 9 (Action Plan and Resource Procurement). 13.b For gas utilities only Not applicable Flexible Capacity Resources 1 Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the balancing reserves needed at different time intervals (e.g. ramping needed within 5 minutes) to respond to variation in load and intermittent renewable generation over the 20-year planning period. See Volume II, Appendix F (Flexible Resource Needs Assessment). 2 Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing See Volume II, Appendix F (Flexible Resource Needs Assessment). PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 45 No. Requirement How the Guideline is Addressed in the 2015 IRP reserves available at different time intervals (e.g. ramping available within 5 minutes) from existing generating resources over the 20-year planning period. 3 Evaluate Flexible Resources on a Consistent and Comparable Basis: In planning to fill any gap between the demand and supply of flexible capacity, the electric utilities shall evaluate all resource options, including the use of EVs, on a consistent and comparable basis. See Volume II, Appendix F (Flexible Resource Needs Assessment). Table B.4 – Utah Public Service Commission IRP Standard and Guidelines No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP Procedural Issues 1 The Commission has the legal authority to promulgate Standards and Guidelines for integrated resource planning. Not addressed; this is a Public Service Commission of Utah responsibility. 2 Information Exchange is the most reasonable method for developing and implementing integrated resource planning in Utah. Information exchange has been conducted throughout the IRP public input process. 3 Prudence reviews of new resource acquisitions will occur during ratemaking proceedings. Not an IRP requirement as the Commission acknowledges that prudence reviews will occur during ratemaking proceedings, outside of the IRP process. 4 PacifiCorp's integrated resource planning process will be open to the public at all stages. The Commission, its staff, the Division, the Committee, appropriate Utah state agencies, and other interested parties can participate. The Commission will pursue a more active-directive role if deemed necessary, after formal review of the planning process. PacifiCorp’s public process is described in Volume I, Chapter 2 (Introduction). A record of public meetings is provided in Volume II, Appendix C (Public Input Process). 5 Consideration of environmental externalities and attendant costs must be included in the integrated resource planning analysis. PacifiCorp used a scenario analysis approach, including scenarios addressing EPA’s proposed 111(d) rule and additional scenarios that apply CO2 costs incremental to requirements in EPA’s proposed 111(d) rule. See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) for a description of the methodology employed, including how CO2 policy uncertainty is factored into the portfolio development process. 6 The integrated resource plan must evaluate supply-side and demand-side resources on a consistent and comparable basis. Supply, transmission, and demand-side resources were evaluated on a comparable basis using PacifiCorp’s capacity expansion optimization model. Also see the response to number 4.b.ii below. 7 Avoided cost should be determined in a manner consistent with the Company's Integrated Resource Plan. Consistent with the Utah rules, PacifiCorp determination of avoided costs in Utah is handled in a manner consistent with the IRP, updated with the most current information available. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 46 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP 8 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. This IRP was developed in consultation with parties from all state jurisdictions, and meets all formal state IRP guidelines. 9 The Company's Strategic Business Plan must be directly related to its Integrated Resource Plan. Volume I, Chapter 9 (Action Plan) describes the linkage between the 2015 IRP preferred portfolio, the 2013 IRP Update portfolio, and the fall 2014 ten-year business plan portfolio. The 2015 IRP preferred portfolio will serve as the starting point for the fall 2015 ten-year business plan resource assumptions, updated with more current information, as applicable. Standards and Guidelines 1 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 services needs at the lowest total cost to the utility and its customers, and in a manner consistent with the long-run public interest. The process should result in the selection of the optimal set of resources given the expected combination of costs, risk and uncertainty. Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) outlines the portfolio performance evaluation and preferred portfolio selection process, while Volume I, Chapter 8 (Modeling and Portfolio Selection Results) chronicles the modeling and preferred portfolio selection process. This IRP also addresses concerns expressed by Utah stakeholders and the Utah commission concerning comprehensiveness of resources considered, consistency in applying input assumptions for portfolio modeling, and explanation of PacifiCorp’s decision process for selecting top- performing portfolios and the preferred portfolio. 2 The Company will submit its Integrated Resource Plan biennially. The company submitted its last IRP on April 30, 2013, and filed this IRP on March 31, 2015 meeting the requirement. 3 IRP will be developed in consultation with the Commission, its staff, the Division of Public Utilities, the Committee of Consumer 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 public process is described in Volume I, Chapter 2 (Introduction). A record of public meetings is provided in Volume II, Appendix C (Public Input Process). 4.a PacifiCorp's integrated resource plans will include: a range of estimates or forecasts of load growth, including both capacity (kW) and energy (kWh) requirements. PacifiCorp implemented a load forecast range for both capacity expansion optimization scenarios as well as for stochastic variability, covering both capacity and energy. Details concerning the load forecasts used in the 2015 IRP are provided in Volume I, Chapter 5 (Resource Needs Assessment) and Volume II, Appendix A (Load Forecast Details). 4.a.i The forecasts will be made by jurisdiction and by general class and will differentiate energy and capacity requirements. The Company will include in its forecasts all on-system loads and those off- system loads which they have a contractual obligation 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 will have on risks Load forecasts are differentiated by jurisdiction and differentiate energy and capacity requirements. See Volume I, Chapter 5 (Resource Needs Assessment) and Volume II, Appendix A (Load Forecast Details). Non-firm off-system sales are not incorporated into the load forecast. Off-system sales markets are included in IRP modeling and are used for system balancing purposes. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 47 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP associated with different acquisition strategies. 4.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. Volume II, Appendix A (Load Forecast Details) documents how demographic and price factors are used in PacifiCorp’s load forecasting methodology. 4.b An evaluation of all present and future resources, including future market opportunities (both demand-side and supply-side), on a consistent and comparable basis. Resources were evaluated on a consistent and comparable basis using the System Optimizer model and Planning and Risk production cost model using both supply side and demand side alternatives. See explanation in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) and the results in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). Resource options are summarized in Volume I, Chapter 6 (Resource Options). 4.b.i An assessment of all technically feasible and cost- effective improvements in the efficient use of electricity, including load management and conservation. PacifiCorp included supply curves for Class 1 DSM (dispatchable/schedulable load control) and Class 2 DSM (energy efficiency measures) in its capacity expansion model. Details are provided in Volume I, Chapter 6 (Resource Options). A sensitivity study of demand-response programs (Class 3 DSM) is described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) with results reported in in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). 4.b.ii An assessment of all technically feasible generating technologies including: renewable resources, cogeneration, power purchases from other sources, and the construction of thermal resources. PacifiCorp considered a wide range of resources including renewables, market purchases, thermal resources, energy storage, and Energy Gateway transmission configurations. Volume I, Chapters 6 (Resource Options) and 7 (Modeling and Portfolio Evaluation Approach) contain assumptions and describe the process under which PacifiCorp developed and assessed these technologies and resources. 4.b.iii The resource assessments should include: life expectancy of the resources, the recognition of whether the resource is replacing/adding capacity or energy, dispatchability, lead-time requirements, flexibility, efficiency of the resource and opportunities for customer participation. PacifiCorp captures and models these resources attributes in its IRP models. Resources are defined as providing capacity, energy, or both. The DSM supply curves used for portfolio modeling explicitly incorporate estimated rates of program and event participation. The distributed generation study produces penetration levels, modeled as a reduction to load, that considers rates of participation. Replacement capacity is considered in the case of assumed coal unit retirements as evaluated in this IRP. Dispatchability is accounted for in both IRP models; however, PaR model provides a more detailed representation of unit dispatch considering unit commitment and operating reserves not captured in System Optimizer. 4.c An analysis of the role of competitive bidding for demand-side and supply-side resource A description of the role of competitive bidding and other procurement methods is provided in Volume I, PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 48 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP acquisitions Chapter 9 (Action Plan and Resource Procurement). 4.d A 20-year planning horizon. This IRP uses a 20-year study horizon (2015-2034) 4.e An action plan outlining the specific resource 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 specific 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 contained in the previous action plan. The IRP action plan is provided in Volume I, Chapter 9 (Action Plan and Resource Procurement). A status report of the actions outlined in the previous action plan (2013 IRP update) is provided in Volume I, Chapter 9 (Action Plan and Resource Procurement). In Volume I, Chapter 9 (Action Plan and Resource Procurement) Table 9.1 identifies actions anticipated in the next two years and in the next four years. 4.f A plan of different resource acquisition paths for different economic circumstances with a decision mechanism to select among and modify these paths as the future unfolds. Volume I, Chapter 9 (Action Plan and Resource Procurement) includes an acquisition path analysis that presents broad resource strategies based on trigger events such as changes in load growth, changes in environmental policies, and changes in market conditions. 4.g 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 effectiveness estimates of resource options. PacifiCorp provides resource-specific utility and total resource cost information in Volume I, Chapter 6 (Resource Options). The IRP document addresses the impact of social concerns on resource cost-effectiveness in the following ways: ● Portfolios were evaluated using a range of CO2 compliance methods, most included emissions rate targets, but there was examination of additional CO2 price adders. ● A discussion of environmental policy status and impacts on utility resource planning is provided in Volume I, Chapter 3 (The Planning Environment). ● State and proposed federal public policy preferences for clean energy are considered for development of the preferred portfolio, which is documented in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). ● Volume II, Appendix G (Plant Water Consumption) of reports historical water consumption for PacifiCorp’s thermal plants. 4.h An evaluation of the financial, competitive, reliability, and operational risks associated 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 bear such risk, the ratepayer or the stockholder. The handling of resource risks is discussed in Volume I, Chapter 9 (Action Plan and Resource Procurement), and covers managing environmental risk for existing plants, risk management and hedging and treatment of customer and investment risk. Resource capital cost uncertainty and technological risk is addressed in Volume I, Chapter 6 (Resource Options). For reliability risks, the stochastic simulation model incorporates stochastic volatility of forced outages for new thermal plants and hydro availability. These PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 49 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP 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 Volume I, Chapter 9 (Action Plan and Resource Procurement). 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 options. Flexibility in the planning and procurement processes is highlighted in Volume I, Chapter 9 (Action Plan and Resource Procurement). Permitting activities related to Energy Gateway are described in Volume I, Chapter 4 (Transmission). 4.j An analysis of tradeoffs; for example, between such conditions of service as reliability and dispatchability and the acquisition of lowest cost resources. PacifiCorp examined the trade-off between portfolio cost and risk, taking into consideration a broad range of resource alternatives defined with varying levels of dispatchability. This trade-off analysis is documented in Volume I, Chapter 8 (Modeling and Portfolio Selection Results), and highlighted through the use of scatter-plot graphs showing the relationship between stochastic mean and upper-tail mean stochastic PVRR. 4.k 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 example, in terms of the amount of emissions released and dollar estimates of the costs of such externalities. PacifiCorp incorporated environmental externality costs for CO2 and costs for complying with current and proposed U.S. EPA regulatory requirements. For CO2 externality costs, the company used scenarios with various compliance requirements to capture a reasonable range of cost impacts. These modeling assumptions are described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). Results are documented in Volume I, Chapter 8 (Modeling and Portfolio Selection Results). 4.l A narrative describing how current rate design is consistent with the Company's integrated resource planning goals and how changes in rate design might facilitate integrated resource planning objectives. See Volume I, Chapter 3 (The Planning Environment). The role of Class 3 DSM (price response programs) at PacifiCorp and how these resources are modeled in the IRP are described in Volume I, Chapter 6 (Resource Options). 5 PacifiCorp will submit its IRP for public comment, review and acknowledgment. PacifiCorp distributed draft IRP materials for external review throughout the process prior to each of the public input meetings and solicited/and received feedback while developing the 2015 IRP. The materials shared with stakeholders at these meetings, outlined in Volume I Chapter 2 (Introduction), is consistent with materials presented in Volumes I, II, and III of the 2015 IRP report. PacifiCorp requested and responded to comments from stakeholders in developing core case and sensitivity definitions. The Company considered comments received via the Feedback Form in developing its final plan. 6 The public, state agencies and other interested parties will have the opportunity to make formal Not addressed; this is a post-filing activity. PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 50 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP comment to the Commission on the adequacy of the Plan. The Commission 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 Company with comments and suggestions for change. This process should lead more quickly to the Commission's acknowledgment of an acceptable Integrated Resource Plan. The Company will give an oral presentation of its report to the Commission and all interested public parties. Formal hearings on the acknowledgment of the Integrated Resource Plan might be appropriate but are not required. 7 Acknowledgment of an acceptable Plan will not guarantee favorable ratemaking treatment of future resource acquisitions. Not addressed; this is not a PacifiCorp activity. 8 The Integrated Resource Plan will be used in rate cases to evaluate the performance of the utility and to review avoided cost calculations. Not addressed; this refers to a post-filing activity. Table B.5 – Washington Utilities and Transportation Commission IRP Standard and Guidelines (RCW 19.280.030 and WAC 480-100-238) No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP Requirements prior to IRP Filing (4) Work plan filed no later than 12 months before next IRP due date. PacifiCorp filed the IRP work plan on March 31, 2014 in Docket No. UE-140546, given an anticipated IRP filing date of March 31, 2015. (4) Work plan outlines content of IRP. See pages 1-2 of the Work Plan document for a summary of IRP contents. (4) Work plan outlines method for assessing potential resources. (See LRC analysis below) See pages 3-5 of the Work Plan document for a summary of resource analysis. (5) Work plan outlines timing and extent of public participation. See pages 5-6 of the Work Plan. Figure 2, page 6, document for the IRP schedule. (4) Integrated resource plan submitted within two years of previous plan. The Commission issued an Order on December 11, 2008, under Docket no. UE-070117, granting the Company permission to file its IRP on March 31 of each odd numbered year. PacifiCorp filed the 2015 IRP on March 31, 2015 within two years of the 2013 IRP filed on April 30, 2013. (5) Commission issues notice of public hearing after company files plan for review. This activity is conducted subsequent to filing this IRP. (5) Commission holds public hearing. This activity is conducted subsequent to filing this IRP. Requirements specific to IRP filing (2)(a) Plan describes the mix of energy supply resources. Volume I, Chapter 5 (Resource Need Assessment) describes the mix of existing resources, while Volume I, Chapter 8 (Modeling and Portfolio Selection Results) describes the 2015 IRP preferred portfolio. (2)(a) Plan describes conservation supply. See Volume I, Chapter 6 (Resource Options) for a description of how conservation supplies are represented and modeled, and PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 51 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP Volume I, Chapter 8 (Modeling and Portfolio Selection Results) for conservation supply in the preferred portfolio. Additional information on energy efficiency resource characteristics is available in Appendix D. (2)(a) Plan addresses supply in terms of current and future needs at the lowest reasonable cost to the utility and its ratepayers. The 2015 IRP preferred portfolio was based on a resource needs assessment that accounted for forecasted load growth, expiration of existing power purchase contracts, resources under construction, contract, as well as a capacity planning reserve margin. Details on PacifiCorp’s findings of resource need are described in Volume I, Chapter 5 (Resource Needs and Assessment). (2)(b) Plan uses lowest reasonable cost (LRC) analysis to select the mix of resources. PacifiCorp uses portfolio performance measures based on the Present Value of Revenue Requirements (PVRR) methodology. See the section on portfolio performance measures in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) and Volume I Chapter 8 (Modeling and Portfolio Selection Results). (2)(b) LRC analysis considers resource costs. Volume I, Chapter 6 (Resource Options), provides detailed information on costs and other attributes for all resources analyzed for the IRP. (2)(b) LRC analysis considers market- volatility risks. PacifiCorp employs Monte Carlo production cost simulation with a stochastic model to characterize market price and gas price volatility. Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) provides a summary of the modeling approach. (2)(b) LRC analysis considers demand side resource uncertainties. PacifiCorp captured demand-side resource uncertainties through the development of numerous portfolios based on different sets of input assumptions. (2)(b) LRC analysis considers resource dispatchability. PacifiCorp uses two IRP models that simulate the dispatch of existing and future resources based on such attributes as heat rate, availability, fuel cost, and variable O&M cost. The chronological production cost simulation model also incorporates unit commitment logic for handling start-up, shutdown, ramp rates, minimum up/down times, and run up rates, and reserve holding characteristics of individual generators. (2)(b) LRC analysis considers resource effect on system operation. PacifiCorp’s IRP models simulate the operation of its entire system, reflecting dispatch/unit commitment, forced/unforced outages, access to markets, and system reliability and transmission constraints. (2)(b) LRC analysis considers risks imposed on ratepayers. PacifiCorp explicitly models risk associated with uncertain CO2 regulatory regimes, wholesale electricity and natural gas price escalation and volatility, load growth uncertainty, resource reliability, renewable portfolio standard requirement uncertainty, plant construction cost escalation, and resource affordability. These risks and uncertainties are handled through stochastic modeling and scenarios depicting alternative futures. In addition to risk modeling, the IRP discusses a number of resource risk topics not addressed in the IRP system simulation models. For example, Volume I, Chapter 9 (Action Plan and Resource Procurement) covers the following topics: (1) managing carbon risk for existing plants, (2) assessment of owning vs. purchasing power, (3) purpose of hedging, (4) procurement delays and (5) treatment of customer and investor risks. Volume I, Chapter 4 (Transmission) covers similar risks associated with transmission system expansion. (2)(b) LRC analysis considers public policies regarding resource preference adopted by Washington state or federal government. In Volume I, Chapter 7 (Modeling and Portfolio Evaluation) the IRP modeling incorporates resource expansion constraints tied to renewable portfolio standards (RPS) currently in place for Washington. PacifiCorp also evaluated various CO2 regulatory PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 52 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP schemes, and future Regional Haze compliance requirements. The I-937 conservation requirements are also explicitly accounted for in developing Washington conservation resource costs. (2)(b) LRC analysis considers cost of risks associated with environmental effects including emissions of carbon dioxide. See (2)(b) above. PacifiCorp includes in Volume I, Chapter 8 (Modeling and Portfolio Selection Results) portfolios that meet Washington’s goal of reducing emissions to 1990 levels by 2020. (2)(c) Plan defines conservation as any reduction in electric power consumption that results from increases in the efficiency of energy use, production, or distribution. A description of how PacifiCorp classifies and defines energy conservation is provided in Volume I, Chapter 6 (Resource Options). (3)(a) Plan includes a range of forecasts of future demand. PacifiCorp implemented a load forecast range. Details concerning the load forecasts used in the 2015 IRP (high, low, and extreme peak temperature) are provided in Volume I, Chapters 5 (Resource Needs Assessment) and Volume II, Appendix A (Load Forecast Details). (3)(a) Plan develops forecasts using methods that examine the effect of economic forces on the consumption of electricity. PacifiCorp’s load forecast methodology employs econometric forecasting techniques that include such economic variables as household income, employment, and population. See Volume II, Appendix A (Load Forecast Details) for a description of the load forecasting methodology. (3)(a) Plan develops forecasts using methods that address changes in the number, type and efficiency of electrical end- uses. Residential sector load forecasts use a statistically-adjusted end-use model that accounts for equipment saturation rates and efficiency. See Volume II, Appendix A (Load Forecast Details), for a description of the residential sector load forecasting methodology. (3)(b) Plan includes an assessment of commercially available conservation, including load management. PacifiCorp updated its conservation potential assessment (CPA) in support of the 2015 IRP, which served as the basis for developing DSM resource supply curves for resource portfolio modeling. The supply curves account for technical and achievable (market) potential, while the IRP capacity expansion model identifies a cost- effective mix of DSM resources based on these limits and other model inputs. The DSM potentials study is included on the data disk, and available on PacifiCorp’s IRP website. (3)(b) Plan includes an assessment of currently employed and new policies and programs needed to obtain the conservation improvements. A description of the current status of DSM programs and on-going activities to implement current and new programs is provided in Volume I, Chapter 5 (Resource Needs Assessment). (3)(c) Plan includes an assessment of a wide range of conventional and commercially available nonconventional generating technologies. PacifiCorp considered a wide range of resources including renewables, market purchases, thermal resources, energy storage, and transmission. Volume I, Chapters 6 (Resource Options and Chapter 7 (Modeling and Portfolio Evaluation Approach) document how PacifiCorp developed and assessed these technologies. (3)(d) Plan includes an assessment of transmission system capability and reliability; to the extent such information can be provided consistent with applicable laws. PacifiCorp modeled transmission system capability to serve its load obligations, factoring in updates to the representation of major load and generation centers, regional transmission congestion impacts, import/export availability, external market dynamics, and significant transmission expansion plans explained in Volume I, Chapter 4 (Transmission) and Chapter 7 (Modeling and Portfolio Evaluation Approach). System reliability given transmission capability was analyzed using stochastic production cost simulation and measures of insufficient energy and capacity for a load area (Energy Not Served and Unmet Capacity, respectively). PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 53 No. Requirement How the Standards and Guidelines are Addressed in the 2015 IRP (3)(e) Plan includes a comparative evaluation of energy supply resources (including transmission and distribution) and improvements in conservation using LRC. PacifiCorp’s capacity expansion optimization model (System Optimizer) is designed to compare alternative resources for the least- cost resource mix. System Optimizer was used to develop numerous resource portfolios for comparative evaluation on the basis of cost, risk, reliability, and other performance attributes. Potential energy savings associated with conservation voltage reduction are discussed in Volume I, Chapter 5 (Resource Needs Assessment). (3)(f) Plan includes integration of the demand forecasts and resource evaluations into a long range integrated resource plan describing the mix of resources that is designated to meet current and project future needs at the lowest reasonable cost to the utility and its ratepayers. PacifiCorp integrates demand forecasts, resources, and system operations in the context of a system modeling framework described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). The portfolio evaluation covers a 20-year period (2015- 2034). PacifiCorp developed its preferred portfolio of resources judged to be least-cost after considering load requirements, risk, uncertainty, supply adequacy/reliability, and government resource policies in accordance with this rule. (3)(g) Plan includes a two-year action plan that implements the long range plan. See Table 9.1 in Volume I, Chapter 9 (Action Plan and Resource Procurement), for PacifiCorp’s 2015 IRP action plan. (3)(h) Plan includes a progress report on the implementation of the previously filed plan. See Table 9.2 for a status report on action plan implementation in Volume I, Chapter 9 (Action Plan and Resource Procurement). Requirements from RCW 19.280.030 not discussed above (1)(e) An assessment of methods, commercially available technologies, or facilities for integrating renewable resources, and addressing overgeneration events, if applicable to the utility's resource portfolio; Volume I, Chapter 6 for discussion of options available for selection in the 2015 IRP. Also see Volume II, Appendix H for PacifiCorp’s Wind Integration Study, (1)(f) The integration of the demand forecasts and resource evaluations into a long-range assessment describing the mix of supply side generating resources and conservation and efficiency resources that will meet current and projected needs, including mitigating overgeneration events, at the lowest reasonable cost and risk to the utility and its ratepayers; and See Volume II, Appendix A for a discussion of the load forecasts, Supply-side and demand-side are discussed in Volume I, Chapter 6. DSM resources are discussed in Volume II, Appendix D. Volume I, Chapters 8 (Modeling and Portfolio Selection Results) describes how preferred portfolio resources meet capacity and energy needs. Appendix F summarizes a flexible resource needs assessment based on the preferred portfolio. Table B.6 – Wyoming Public Service Commission IRP Standard and Guidelines (Docket 90000-107-XO-09) No. Requirement How the Guideline is Addressed in the 2015 IRP A The public comment process employed as part of the formulation of the utility’s IRP, including a description, timing and weight given to the public process; PacifiCorp’s public process is described in Volume I, Chapter 2 (Introduction) and in Volume II, Appendix C (Public Input Process). B The utility’s strategic goals and resource planning goals and preferred resource portfolio; Volume I, Chapter 8 (Modeling and Portfolio Selection Results) documents the preferred resource portfolio and rationale for selection. Volume I, Chapter 9 (Action Plan and Resource Procurement) constitutes the IRP action plan and the descriptions of resource strategies and risk management. C The utility’s illustration of resource need over the near-term and long- See Volume I, Chapter 5 (Resource Needs Assessment). PACIFICORP – 2015 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 54 No. Requirement How the Guideline is Addressed in the 2015 IRP term planning horizons; D A study detailing the types of resources considered; Volume, I Chapter 6 (Resource Options), presents the resource options used for resource portfolio modeling for this IRP. F Changes in expected resource acquisitions and load growth from that presented in the utility’s previous IRP; A comparison of resource changes relative to the 2013 IRP Update is presented in Volume I, Chapter 9 (Action Plan and Resource Procurement). A chart comparing the peak load forecasts for the 2013 IRP, 2013 IRP Update, and 2015 IRP is included in Volume II, Appendix A (Load Forecast Details). G The environmental impacts considered; Portfolio comparisons for CO2 and a broad range of environmental impacts are considered. See Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach) and Chapter 8 (Modeling and Portfolio Selection Results) as well as Volume II, Appendix L (Stochastic and Production Cost Simulation Results). H Market purchases evaluation; Modeling of firm market purchases (front office transactions) and spot market balancing transactions is included in this IRP. See also Volume II Appendix J for the Western Resource Adequacy Evaluation. I Reserve Margin analysis; and PacifiCorp’s planning reserve margin study, which documents selection of a capacity planning reserve margin is in Volume I, Appendix I (Planning Reserve Margin Study). J Demand-side management and conservation options; See Volume I, Chapter 6 (Resource Options) for a detailed discussion on DSM and conservation resource options. Additional information on energy efficiency resource characteristics is available in Appendix D. PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 55 APPENDIX C – PUBLIC INPUT PROCESS A critical element of this Integrated Resource Plan (IRP) is the public input process. PacifiCorp has pursued an open and collaborative approach involving the Commissions, customers and other stakeholders in PacifiCorp’s IRP prior to making resource planning decisions. Since these decisions can have significant economic and environmental consequences, conducting the IRP with transparency and full participation from interested and affected parties is essential. Stakeholders have been involved in the IRP from the beginning. In fact, public input was solicited starting immediately following the conclusion of the 2013 IRP. A meeting was held on September 23, 2013 to discuss potential improvements to the IRP process; written comments were requested as well. Comments from participants helped shape 2015 IRP process improvements. Some examples of process improvements include the scheduling of multiple-day public input meetings to ensure sufficient time to cover agenda items in depth, use of a feedback form, providing opportunities for stakeholders to submit written comments at any point during the public input process, and the inclusion of data disks submitted with this filing. The public input meetings (PIM) held beginning in in June 2014 were the cornerstone of the direct public input process. There were a total of seven PIMs, with four lasting two days, the remainder being single days. Meetings were held jointly in both Salt Lake City, Utah and Portland, Oregon via video conference. Attendees off-site were able to conference in via phone. The IRP public process also included state-specific stakeholder dialogue sessions held in June 2014. The goal of these sessions was to capture key IRP issues of most concern to each state and to discuss how a state’s concerns might be addressed from a system planning perspective. PacifiCorp also wanted to ensure that stakeholders understood IRP planning principles. These meetings continued to enhance interaction with stakeholders in the planning cycle, and provided a forum to directly address stakeholder concerns regarding equitable representation of state interests during general public meetings. PacifiCorp solicited agenda item recommendations from the state stakeholders in advance of the state meetings. There was additional open time to ensure that participants had adequate opportunity to discuss any topic of interest. Some follow-up activities arising from the sessions were addressed in subsequent public meetings. PacifiCorp’s comment website housed the Feedback form discussed earlier. This standardized form allowed stakeholders opportunities to provide comments, questions, and suggestions. Comments are posted on the following link: (http://www.pacificorp.com/es/irp/irpcomments.html). Participant List PacifiCorp’s 2015 IRP public process was robust, involving input from many parties throughout. Organizations actively participated in the development of material, modeling process, and public meetings. Participants included commissioners, commission staff, stakeholders, and industry experts. The following organizations were represented and actively involved in this collaborative effort: PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 56 Commissions and/or Commission Staff Idaho Public Utilities Commission Oregon Public Utilities Commission Public Service Commission of Utah Washington Utilities and Transportation Commission Wyoming Public Service Commission Stakeholders and Industry Experts ABB Enterprise Software Inc. (formerly known as Ventyx Inc.) Apex Clean Energy Applied Energy Group Avista Utilities Black & Veatch Blue Castle Holdings, Inc. Citizen’s Utility Board of Oregon EDF-Renewable Energy Energy Trust of Oregon E-Quant Consulting First Wind GE Energy Harris Group Inc. HDR Engineering Health Environment Alliance of Utah Horizon Wind Energy Idaho Conservation League Idaho Power Company Individual Customers Industrial Customers of Northwest Utilities Interwest Energy Alliance Kennecott Utah Copper Magnum Energy Mitsubishi Monsanto Company Mormon Environmental Stewardship Alliance National Parks Conservation Association National Renewable Energy Laboratory Navigant Consulting, Inc. Northwest Power and Conservation Council Northern Laramie Range Alliance Northwest Pipeline GP NW Energy Coalition Oregon Department of Energy Oregon Department of Environmental Quality Erin O'Neill (Independent Consultant) Portland General Electric Powder River Basin Resource Council Renewable Energy Coalition PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 57 Renewables Northwest Sargent & Lundy Sierra Club Siemens SolarCity Southwest Energy Efficiency Project Sugar House Community Council Synapse Energy Economics University of Utah For Utah Association of Energy Users Utah Associated Municipal Power Systems Utah Clean Energy Utah Division of Public Utilities Utah Industrial Energy Consumers Utah Municipal Power Agency Utah Office of Consumer Services Utah Office of Energy Development Utah Physicians for a Healthy Environment Wartsila Western Clean Energy Campaign Western Electricity Coordination Council Western Resource Advocates West Wind Wires Wyoming Industrial Energy Consumers Wyoming Office Of Consumer Advocate PacifiCorp extends its gratitude for the time and energy these participants have given to the IRP. Their participation has contributed significantly to the quality of this plan, and their continued participation will help PacifiCorp as it strives to improve its planning efforts going forward. Public Input Meetings As mentioned above, PacifiCorp hosted seven public input meetings, as well as five state meetings during the public process. The Company also held confidential workshops in Portland and Salt Lake City to review the Company’s 111(d) Scenario Maker spreadsheet-based modeling tool developed to analyze EPA’s proposed rule under §111(d) of the Clean Air Act.6 During the 2015 IRP public process, presentations and discussions covered various issues regarding model input assumptions, risks, modeling techniques, and analytical results. Below are the agendas from the public input meetings and the technical workshops; the presentations, and materials may be found on the data disks provided. General Meetings June 5, 2014 – General Public Meeting  Introductions  2015 IRP Schedule 6 Also known as the Clean Power Plan, as proposed by the Environmental Protection Agency, June 2, 2014. PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 58  Process Improvements  2013 IRP Update Highlights  2013 IRP Requirements  Action Plan status updates July 17-18, 2014 – General Public Meeting Day 1  Introductions  Environmental Policy  Renewable Portfolio Standards  Transmission  Portfolio Development Day 2  Sensitivities and Risk Analysis Process  DSM Potential Study  Load Forecast August 7-8, 2014 – General Public Meeting Day 1  Introductions  Supply-Side Resources o Includes Energy Storage Study  Needs Assessment  Distributed Generation Study  Plant Efficiency Study Day 2  Portfolio Development  Wind Integration  Planning Reserve Margin  Wind & Solar Capacity Contribution Discussion on Volume 3 September 25-26, 2014 – General Public Meeting Day 1  Introductions  Stochastic Modeling & Portfolio Selection Process  Portfolio Development Cases  Smart Grid Update  Conservation Voltage Reduction Day 2  Anaerobic Digester Study  Modeling for Confidential Volume III  Planning Reserve Margin Results  Resource Capacity Contribution Results  Wind Integration Cost Results PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 59 November 14, 2014 – General Public Meeting  Introductions  Energy Imbalance Market (EIM) Update  Price Curve Scenarios  Portfolio Development Draft Results  Portfolio Development Draft Results December 8, 2014 – Confidential Technical Workshop (Salt Lake City)  111(d) Scenario Maker December 10, 2014 – Confidential Technical Workshop (Portland)  111(d) Scenario Maker January 29-30, 2015 – General Public Meeting  Confidential Coal Analysis  Preferred Portfolio Overview  PaR Modeling Update  Preferred Portfolio Selection  Sensitivity Studies February 26, 2015 – General Public Meeting  2015 IRP Draft Action Plan  High CO2 PaR Results  Sensitivity Studies  Wrap-up Discussion State Meetings June 10, 2014 – Washington State Stakeholder Meeting June 17, 2014 – Idaho State Stakeholder Meeting June 18, 2014 – Utah State Stakeholder Meeting June 19, 2014 – Wyoming State Stakeholder Meeting June 26, 2014 – Oregon State Stakeholder Meeting Stakeholder Comments For the 2015 IRP, PacifiCorp introduced a feedback form which offered stakeholders a direct opportunity to provide comments, questions, and suggestions outside the PIMs. PacifiCorp recognizes the importance of stakeholder feedback to the IRP public input process. A blank form, as well as those submitted by stakeholders, is housed on the PacifiCorp website at IRP comments webpage at: http://www.pacificorp.com/es/irp/irpcomments.html The form itself allowed the Company to easily review and summarize issues by topic as well as identify specific recommendations that were provided. Information collected was used to inform assumptions and modeling efforts in the 2015 IRP. Comment forms were received from the following stakeholders: PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 60  Blue Castle Holdings  Citizens' Utility Board of Oregon  Clean Energy Scenario Stakeholders  HEAL Utah  Idaho Conservation League  Industrial Customers of Northwest Utilities  Interwest Energy Alliance  Individual Customer  Mormon Environmental Stewardship Alliance  Northern Laramie Range Alliance (NLRA)  NW Energy Coalition  Oregon Department of Energy (ODOE)  Oregon Public Utility Commission  Powder River Basin Resource Council  Renewable Energy Coalition  Renewable Northwest  Sierra Club  Southwest Energy Efficiency Project (SWEEP)  Utah Association of Energy Users  Utah Clean Energy  Utah Clean Energy with WRA and SWEEP  Utah Division of Public Utilities  Utah Office of Consumer Services  Washington Department of Commerce  Washington Utilities and Transportation Commission  Western Clean Energy Campaign  Western Resource Advocates (WRA) Some topics of note addressed in the forms include:  Application of EPA’s proposed 111(d) rule  Resource cost and performance assumptions (solar/wind/nuclear)  Demand side management  Allocation of RPS costs  Modeling questions  Anaerobic digester study  Load forecast  Renewable capacity values  Transmission  EPA BART timing for Utah  Wholesale power availability  Additional CO2 costs  Specific sensitivity case recommendations PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 61 Contact Information PacifiCorp’s IRP internet website contains many of the documents and presentations that support recent Integrated Resource Plans. To access these materials, please visit the Company’s IRP website at http://www.pacificorp.com/es/irp.html. PacifiCorp requests that any informal request be sent in writing to the following address or email address below. PacifiCorp IRP Resource Planning Department 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 Electronic Email Address: IRP@PacifiCorp.com Phone Number: (503) 813-5245 PACIFICORP - 2015 IRP APPENDIX C – PUBLIC INPUT PROCESS 62 PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 63 APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES Introduction Appendix D reviews the studies and reports used to support the demand-side management (DSM) resource information used in the modeling and analysis of the 2015 Integrated Resource Plan (IRP). In addition, it provides information on the economic DSM selections in the 2015 IRP’s Preferred Portfolio, a summary of existing DSM program services and offerings, the preliminary budgets to acquire the resources and the State specific implementation actions, including communications and outreach activity, the Company intends to pursue in the acquisition of those resources. Demand-Side Resource Potential Assessments for 2015-2034 Since 1989, PacifiCorp has developed biennial IRPs to identify an optimal mix of resources that balance considerations of cost, risk, uncertainty, supply reliability/deliverability, and long-run public policy goals. The optimization process accounts for capital, energy, and ongoing operation costs as well as the risk profiles of various resource alternatives, including: traditional generation and market purchases, renewable generation, and DSM resources such as energy efficiency, and demand response or capacity-focused resources. Since the 2008 IRP, DSM resources have competed directly against supply-side options, allowing the IRP model to guide decisions regarding resource mixes, based on cost and risk. This study, conducted by Applied Energy Group (AEG), primarily seeks to develop reliable estimates of the magnitude, timing, and costs of DSM resources likely available to PacifiCorp over a 20-year planning horizon, beginning in 2015. The study focuses on resources realistically achievable during the planning horizon, given normal market dynamics that may hinder resource acquisition. Study results were incorporated into PacifiCorp’s 2015 IRP and will be used to inform subsequent DSM planning and program design efforts. This study serves as an update of similar studies completed in 2007, 2011 and 2013. For resource planning purposes, PacifiCorp classifies DSM resources into four classifications, differentiated by two primary characteristics: reliability and customer choice. These resources classifications can be defined as: Class 1 DSM (firm, capacity focused), Class 2 DSM (energy efficiency), Class 3 DSM (non-firm, capacity focused), and Class 4 DSM (educational). From a system-planning perspective, Class 1 DSM resources can be considered the most reliable, as they can be dispatched by the utility. In contrast, behavioral changes, resulting from voluntary educational programs included in Class 4 DSM, tend to be the least reliable. With respect to customer choice, Class 1 DSM and Class 2 DSM resources should be considered involuntary in that, once equipment and systems have been put in place, savings can be expected to flow. Class 3 and Class 4 DSM activities involve greater customer choice and control. This assessment estimates potential from Class 1, 2, and 3 DSM. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 64 This study excludes an assessment of Oregon’s Class 2 DSM resource potential, as this work has been captured in an assessment commissioned by the Energy Trust, which provides energy- efficiency potential in Oregon to PacifiCorp for resource planning purposes. PacifiCorp’s Demand-Side Resource Potential Assessment for 2015-2034, completed by AEG, can be found at: http://www.pacificorp.com/es/dsm.html Energy Trust of Oregon’s Energy Efficiency Resource Assessment Report, completed by Navigant Consulting, can be found at: http://energytrust.org/About/policy-and-reports/Reports.aspx DSM – Economic Class 2 DSM Resource Selections – Preferred Portfolio The following table shows the economic selections by state and year of the Class 2 DSM resources in the 2015 IRP preferred portfolio, C05a-3Q. For the 20-year assumed nameplate capacity contributions (MW impacts) by state and year associated with the Class 2 DSM resource selections above see Table 8.7 – PacifiCorp’s 2015 IRP Preferred Portfolio, in Volume I of the 2015 IRP. DSM – State Implementation Plans Background The Public Utility Commission of Oregon acknowledged PacifiCorp’s 2013 Integrated Resource Plan with exceptions and revisions in Order No. 14-252, entered on July 8, 2014. Appendix A – Adopted Recommendations of the Order states the Company must “Include a PacifiCorp service area specific implementation plan as part of the 2015 IRP filing.” The Order further states that “At twice yearly updates to the Commission, [the Company must] provide a summary of savings potential, gaps and how PacifiCorp specific implementation plan and programs are achieving the identified potential.” This document serves to comply with the implementation plan requirement Energy Efficiency Energy (MWh) Selected by State and Year State 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 CA 6,390 7,500 8,580 9,670 10,500 6,430 6,800 7,100 7,460 7,140 OR 191,240 168,400 154,140 140,780 124,750 116,150 105,880 104,610 99,210 97,320 WA 37,880 41,200 44,600 44,260 48,610 38,230 40,240 41,910 44,270 43,740 UT 264,360 303,040 333,400 351,640 381,660 329,310 345,410 368,050 371,170 381,920 ID 13,570 15,800 17,570 19,170 20,920 15,910 16,750 17,680 18,550 19,200 WY 37,770 48,180 57,590 68,550 79,170 71,430 75,910 82,380 86,220 89,830 Total System 551,210 584,120 615,880 634,070 665,610 577,460 590,990 621,730 626,880 639,150 Energy Efficiency Energy (MWh) Selected by State and Year State 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 CA 6,010 6,260 6,400 6,380 6,300 5,800 5,760 5,550 5,580 5,350 OR 87,980 90,980 89,180 89,080 86,480 87,560 84,080 86,820 82,200 81,260 WA 36,040 35,530 35,130 35,810 34,900 31,190 30,960 30,500 30,400 29,560 UT 309,050 308,630 313,970 312,190 300,950 280,910 277,410 274,700 271,590 268,920 ID 18,050 18,110 17,980 17,850 17,290 15,830 16,220 15,840 15,940 14,920 WY 72,180 75,080 77,150 84,910 84,410 85,120 89,910 92,620 93,560 96,090 Total System 529,310 534,590 539,810 546,220 530,330 506,410 504,340 506,030 499,270 496,100 PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 65 by providing DSM state acquisition selections, preliminary budgets, program overviews, and major actions planned for calendar years 2015-2018. DSM Resource Selections Class 1 DSM resources (dispatchable or scheduled firm capacity resources) As a result of the Company’s resource position and favorable cost resource cost alternatives, no incremental additions to the Company’s Class 1 DSM resources were selected within the 2015- 2018 implementation plan window. Incremental Class 1 DSM selections begin in 2022 with the selection of 5 megawatts (MW) of Oregon irrigation load control. In total, 41.7 MWs of incremental Class 1 DSM resources were selected over the 20 year planning horizon. Selections by State, Product, and Year are provided in Table D.1 for informational purposes only. Table D.1 – Incremental and Cumulative Class 1 Resource Selections by State, Product and Year State/Product by Year 2022 2023 2026 2029 2033 Total/Products (MW) Oregon Irrigation Load Control 5 5 Oregon Curtailment Agreements 10.6 10.6 10.6 31.8 Utah Res. Load Control Cooling 4.9 4.9 Cumulative Total by Year (MW) 5 15.6 26.2 36.8 41.7 41.7 In preparation for the 2022 west-side capacity requirement, near-term Class 1 DSM efforts will focus on a Company proposal of an Oregon and California irrigation load control program pilot (Klamath Basin) in order to 1) test the effectiveness of the Company’s Idaho and Utah program design in smaller markets, and 2) given the differences in grower operations in the west to better understand west-side irrigation customers capabilities and challenges in participating in load management programs. The load control pilot will complement the Company’s Oregon and proposed California time-of-use pilots and provide growers a second alternative to manage their peak usage and save money. The Company will also seek further refinements to its existing Class 1 DSM products in Utah and Idaho, seeking to identify additional operational improvements and integration of dispatch strategies in order to maximize resource value and effectiveness. Table D.2 provides a summary of the Company’s existing Class 1 DSM resources relied upon in the development of the 2015 Integrated Resource Plan’s load resource balance position. Table D.2 – Existing Class 1 DSM resources (2015 Preferred Portfolio) State/Product by Year 2015 2016 2017 2018 Idaho Irrigation DLC 170 170 170 170 Utah Residential DLC Irrigation DLC 115 20 115 20 115 20 115 20 Idaho and Utah Special Contract Load 149 175 175 175 Total (MW) 454 480 480 480 Class 2 DSM Resources (energy efficiency) The acquisition of Class 2 DSM resources continues to be the largest demand-side resource in the 2015 IRP, contributing 2,385 gigawatt hours (GWh) of cost-effective energy savings by 7 The projected increase in Special Contract Load under management in 2016 is result of expected agreement renegotiation, not due to 2015 IRP model selections. The resources are classified as “existing” rather than “new” for purposes of resource planning. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 66 2018; maximum demand reduction of 565 MW8. By 2018, Class 2 DSM selections in the 2015 IRP Preferred Portfolio exceed those in the 2013 IRP by 37 percent. Initial analysis indicates changing market assumptions and measure costs coupled with increased resource opportunities in lighting, space conditioning, water heating, appliances and industrial process end-uses (both capital and non-capital) are responsible for the majority of the increase in economic resource selections9. Table D.3 provides the selection of Class 2 DSM resources by State and Year for years 2015-2018 contained in the 2015 IRP Preferred Portfolio10. Table D.3 – Class 2 DSM Resources (2015 IRP Preferred Portfolio, Incremental Resources) State/Year 2015 2016 2017 2018 Total (MWh) Total (MW) California 6,390 7,500 8,580 9,670 32,140 7 Idaho 13,570 15,800 17,570 19,170 66,110 17 Oregon 191,240 168,400 154,140 140,780 654,560 151 Utah 264,360 303,040 333,400 351,640 1,252,440 317 Washington 37,880 41,200 44,600 44,260 167,940 37 Wyoming 37,770 48,180 57,590 68,550 212,090 36 Total (MWh) 551,210 584,120 615,881 634,070 2,385,280 565 Class 3 DSM Resources (price responsive capacity resources) The Company has numerous Class 3 DSM offerings currently in place encouraging customers to do their part in helping reduce loads during peak use periods. They include metered time-of-day and time-of-use pricing plans (in all states, availability varies by customer class), residential seasonal inverted block rates (Idaho, Utah and Wyoming), residential year-round inverted block rates (California, Oregon and Washington) and the Energy Exchange program (all states). Residential customers not voluntarily opting for a time-of-use rate are currently subject to mandatory seasonal or year-round inverted block rate plans, depending on the state. Savings realized through customer response to these programs is captured in the Company’s historical load information used to inform customer load requirements in the IRP, and as a result is recognized when developing the Company’s Preferred Portfolio. Although not a selectable planning resource like Class 1 and 2 DSM resources, Class 3 DSM resources are relied upon to provide important pricing signals as to the time variant cost of electricity and managing peak loads. In 2014 the Company launched a two year irrigation time-of-use pilot in Oregon. First year results were limited. Following grower meetings and surveys in late 2014 the Company expects 2015 participation and impact results to be more indicative of how growers might respond to a well-designed price product as an alternative to a Class 1 DSM irrigation direct load control program. As noted in the Class 1 DSM section above, the Company plans to propose an irrigation direct load control pilot beginning in 2016 and will compare the results of both approaches for the purpose of developing the most cost efficient and effective strategy to manage these seasonal loads. 8 Class 2 DSM capacity reduction represents maximum nameplate rating contribution of the resources selected, not coincident peak reduction. 9 For a more thorough comparison of the increase in Class 2 DSM opportunities between the 2013 DSM resource assessment and the 2015 resource assessment see PacifiCorp Demand-Side Resource Potential Assessment For 2015-2034, Volume 2: Class 2 DSM Analysis, Chapter 8 – Comparison With Previous DSM Potential Assessment on the Company’s website at Demand-Side Management Resource Potential Assessment 10 State specific acquisition forecasts to be filed in states where such requirements exist and may vary from the IRP selection amounts due state specific planning and forecasting requirements/timelines as well as existing program performance results. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 67 Class 4 DSM Resources (Customer Education of Efficient Energy Management) Educating customers regarding energy efficiency and load management opportunities is an important component of the Company’s long-term resource acquisition plan. A variety of channels are used to educate customers including television, radio, newspapers, bill inserts and messages, newsletters, school education programs, and personal contact. The impacts from these messages are captured in customer usage and usage patterns which are taken into consideration in the development of customer load forecasts. The Company manages a comprehensive DSM communications and outreach plan encouraging customers to use energy wisely by providing low cost or no cost energy savings tips as well as directing customers to Company programs available to help them with efficiency improvements at their homes and businesses. See the Demand-Side Management Communications & Outreach Plan later in this document for more information on these efforts and details on the Company’s 2015 state specific campaigns. Program Portfolio Offerings by State for DSM Resource Classes 1, 2, and 4 Currently there are two Class 1 DSM programs running within PacifiCorp’s six-state service area; Utah’s “Cool Keeper” residential and small commercial air conditioner load control program and the irrigation load control program in Utah and Idaho. The two programs contribute approximately 305 MW of load reduction capability, helping the Company better manage demand during peak periods11. In addition to the Class 1 products, the Company offers ten distinct Class 2 DSM programs or initiatives, most of which are offered in multiple states; size of opportunity and need dependent. In all, the combination of Class 2 DSM programs across PacifiCorp’s six states totals twenty- seven12 with program services in some states combined within programs (i.e. the refrigerator and freezer recycling service in California is part of the Home Energy Savings program and therefore is not counted as a standalone effort). Table D.4 provides a representative overview of the breadth of program services and offerings available by Sector and State. Table D.5 provides a brief overview of DSM related wattsmart Outreach and Communication activities (Class 4 DSM activities) by state. Energy efficiency services listed in Oregon, except for low income weatherization services, are provided in collaboration with the Energy Trust of Oregon13. 11 Actual reductions may vary by event (temperature and month and time dependent), cited load reduction represents the sum of the highest event performance available across the three states for the two programs and account for line losses (are “at generator” values). In addition to these two programs, the Company has additional interruptible load under contract with select Utah and Idaho special contract customers, see Table 5.12 in the 2015 IRP for additional detail. 12 PacifiCorp collaborates with the Energy Trust of Oregon and the Northwest Energy Efficiency Alliance (in Washington) in delivering two of the ten programs/initiatives. . 13 Funds for Low-income weatherization services are forwarded to Oregon Housing and Community Services. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 68 Table D.4 – Existing Program Services and Offerings by Sector and State Program Services & Offerings by Sector and State California Oregon Washington Idaho Utah Wyoming Refrigerator And Freezer Recycling Program       Lighting Incentives       New Appliance Incentives       Heating And Cooling Incentives       Weatherization Incentives - Windows, Insulation, Duct Sealing, etc.      New Homes     Low-Income Weatherization       Air Conditioner Direct Load Control  Home Energy Reports      School Curriculum   Energy Saving Kits       Financing Options With On-Bill Payments  Trade Ally Outreach       Incentives       Energy Engineering Services       Billing Credit Incentive (offset to DSM charge)   Energy Management      Load Control (Cool Keeper) Load Control (Irrigation Load Control)  Energy Profiler Online       Business Solutions Toolkit       Trade Ally Outreach       Small Business Lighting      Small to Mid-Sized Business Facilitation       DSM Project Managers Partner With Customer Account Managers       Residential Sector Non-Residential Sector PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 69 Table D.5 – Existing wattsmart Outreach and Communications Activities Estimated Expenditures by State and Year14 Table D.6 provides a preliminary DSM budget by state. The budget represents the expected funding needed to maintain existing initiatives and increase acquisitions necessary to achieve the DSM resources selected in the 2015 IRP; Classes 1, 2 and 4, through 2018. Table D.6 – Preliminary DSM Program Budget, DSM Classes 1, 2 and 4 ($000) State/Year 2015 2016 2017 2018 Total California $2,387 $2,560 $2,969 $3,706 $11,622 Idaho $4,156 $3,982 $4,572 $5,558 $18,268 Oregon15 $42,047 $37,951 $35,605 $33,332 $148,935 Utah $59,893 $64,960 $63,625 $74,045 $262,523 Washington $11,280 $11,713 $10,965 $9,338 $43,296 Wyoming $6,734 $9,247 $10,546 $12,789 $39,316 Non-Situs Costs16 $6,360 $6,360 $6,360 $6,360 25,440 Total17 $132,857 $136,773 $134,642 $145,128 $545,718 State Specific Demand-Side Management Implementation Plans The Company intends to complement its existing program services and outreach and communications activities in order to facilitate the acquisition of the demand-side resources selected in the 2015 IRP. For information on energy efficiency activities planned in the company’s Oregon service area, see the Energy Trust of Oregon’s 2015 Annual Budget and 2015-2016 Action Plan.18 Table D.7 provides a breakdown of the company’s implementation items identified to be addressed over the 2015 and 2016 calendar years by sector and state. 14 Expenditures are estimates based on assumed acquisition costs, including program administration, customer incentives, communications and outreach, and evaluation, measurement and verification expenses. More detailed budgets will be developed as part of the Company’s business planning/10-year plan budget work that will occur in the fall of 2015 (October 2015). 15 Includes the combined SB1149 and SB838 funding forecasts. 16 Costs associated with the delivery of the Idaho irrigation load control program. 17 Expenditures exclude costs for Special Contract curtailment resources, which are compensated as a component of their contracted retail rates, and the costs (if approved) of the Oregon and California irrigation load control pilot program. 18 Plan can be accessed on the Energy Trust of Oregon website at http://energytrust.org/About/policy-and- reports/Plans.aspx wattsmart Outreach & Communications (incremental to program specific advertising)California Oregon Washington Idaho Utah Wyoming Advertising      Sponsorships   Social Media       Contests (video) Public Relations (Habitat for Humanity, other)    Business Advocacy (awards at customer meetings, sponsorships, chamber partnership, university artnership)     wattsmart Workshops  Rockin wattsmart Assemblies  PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 70 Table D.7 – DSM Implementation Items by Sector and State Sector and State California Oregon Washington Idaho Utah Wyoming Appliance recycling – competitively bid contract for appliance recycling for 2016     Home energy reports – expand program to residential customers  Home energy reports – implement targeted campaign strategies     New construction – revise offering to increase builder participation  New construction – add incentives targeting residential new construction  Home energy savings program – competitively bid contract for 2016     Multi-family – develop and implement improvements in delivery to the multi-family sector     Manufactured homes – develop and implement improvements in delivery to the manufactured homes sector     Low income – add LED replacement bulbs to program  Low income – increase refrigerator replacements in program  Community-based initiatives – support communities participating in 2-year Georgetown University Energy Prize   Lighting – expand commercial LED lighting channels     Commercial buildings – add system functionality for whole-building benchmarking     Small to mid-sized business programs – competitively bid contract for mid-2016     Behavioral pilot – evaluate a small to mid-sized business behavioral pilot program  Targeted business sectors – improve delivery of current programs to the oil and gas sector   Incentive payments – expand bill credit incentive option (offset to DSM charge) Energy management – improve delivery capabilities and customer awareness     Waste heat to power and regenerative technologies – incorporate efficiency measures into business program   Irrigation Direct Load Control Pilot   Residential Sector Non-Residential Sector PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 71 2015 Demand-Side Management Communications and Outreach Plan Overview The Demand Side Management Communications and Outreach Plan (DCOP) is a comprehensive plan, encompassing all communications to customers and the communities served by Pacific Power and Rocky Mountain Power. The DCOP incorporates the wattsmart outreach and communications plans for Idaho, Oregon (838), Utah, Washington and Wyoming; See ya later, refrigerator communications; wattsmart Business plans for Idaho, Utah, Washington and Wyoming; Energy FinAnswer and FinAnswer Express plans in California; load control marketing in Utah and Idaho; and demand-side management program marketing activities for all states. Rocky Mountain Power and Pacific Power working with regulators and interested stakeholders, have implemented comprehensive portfolios of energy efficiency and peak reduction programs in California, Idaho, Oregon, Utah, Washington and Wyoming. Through these portfolios, the Company provides residential, commercial, industrial and agricultural customers with incentives and tools that enable them to employ energy-savings in their home or business. Programs within the portfolio also allow the Company to better manage customer loads during peak usage periods. Starting with Utah in 2009, the Commission approved the Company’s proposal to implement a communications and outreach plan intended to increase participation in these programs and to grow customer appreciation and understanding of the benefits associated with the efficient use of energy. This document provides detailed information on proposed campaign activities in 2015. wattsmart is an overarching energy efficiency campaign with the overall goal to engage customers in reducing their energy usage through behavioral changes, and pointing them to the programs and information to help them do it. Rocky Mountain Power/Pacific Power wants to help you save energy and money” is the key message, and the Company utilizes earned media, customer communications advertising and program specific marketing to communicate the value of energy efficiency, provide information regarding low-cost, no-cost energy efficiency measures, and to educate customers on the availability of programs, services and incentives. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 72 The overall paid media plan objective is to effectively reach our customers through a multi- media mix that extends both reach and frequency. Beyond paid media; the Company also uses statement communications, email, website, social media and news coverage. Tapping into all resources with consistent messaging has been the approach and will continue to be refined. Working with our third-party program marketers, the Company has provided a “wattsmart approved” graphic to help customers identify the programs which will help them save energy and money. In each state the media mix varies depending upon approved budget, reach, readership and ratings. The larger states, where there is greater budget allocation, benefit from utilization of more advertising channels and greater reach and frequency. Customer Communications Tactics (all states) Website  rockymountainpower.net/wattsmart (wattsmart.com)  pacificpower.net/watt smart (bewattsmart.com)  URLs link directly to the energy efficiency landing page. Once there, customers can self- select their state for specific programs and incentives.  Home page messages promote seasonal wattsmart/energy efficiency each month. Social Media  Twitter feed promotes energy efficiency tips and wattsmart programs multiple times per week.  Facebook posts watt smart messages three to five times per week. Newsletters  Voices residential newsletter is sent via bill insert (and email to online bill pay customers) six times a year; each issue includes energy efficiency tips and incentive program information  wattsup insert is a seasonal change insert dedicated to energy efficiency, distributed to customers in May and October.  Energy Connections, Energy Update, Energy Insights, segmented newsletters to businesses and communities leaders, contain articles on commercial and industrial energy efficiency as well as represented case studies on a monthly and quarterly basis. Messaging Key messages for wattsmart  Using energy wisely at home and in your business saves you money.  Rocky Mountain Power is your energy partner o We want to help you keep your costs down. o We offer wattsmart programs and cash incentives to help you save money and energy in your home or business. Energy efficiency message focus (all states)  Earn cash incentives for HVAC equipment, appliances and weatherization upgrades PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 73  Get special pricing on high-efficiency LED and CFL bulbs  Turn off lights and unplug electronics when not in use  Recycle your old energy-wasting refrigerator or freezer and earn cash back Specific message focus for winter peak states (Idaho, Oregon, Washington, Wyoming)  Keeping the thermostat set to 68 degrees in the winter  Weatherization upgrades can help you save Specific message focus for summer peak and cooling in Utah  Peak use management  Reducing energy consumption associated with summer cooling;  Summer tiered pricing  Evaporative cooling  Keeping the thermostat set to 78 degrees in the summer  Enroll in Cool Keeper to help manage the demand for electricity in the summer Key messages for wattsmart Business  We can help you save energy and money, which improves your business’s bottom line. We offer proven programs and incentives for energy-efficient lighting, heating and cooling systems, motors, compressed air, farm and dairy equipment and more, to help businesses save energy and money.  Reducing energy costs improves your company's profitability.  wattsmart Business incentives make it simple for your business to save energy and money.  Using less energy will not only save your business money, it can enhance worker comfort and improve productivity.  Cash incentives are available for energy-efficient LED lighting for indoor and outdoor applications.  Energy efficiency is just one way to demonstrate your commitment to sustainable business practices. California Residential customer programs  Home Energy Savings & wattsmart Starter Kits o Includes Refrigerator/Freezer Recycling (See ya later, refrigerator)  Low-income Weatherization Services Business customer programs  Energy FinAnswer  FinAnswer Express The Home Energy Savings program communicates to customers, retailers and trade allies through a variety of channels, including bill inserts, brochures, in-store/point-of-purchase collateral, social media and website. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 74 To help customers start on the path to home energy savings, customers can order free or low-cost wattsmart Starter Kits. Kits are promoted through direct mail, Facebook advertising, bill inserts and emails. In 2015, the Home Energy Savings program will focus on cooling, heating and lighting measures during key seasonal selling windows. Some of the key measures of focus for California will include LED lighting, ductless heat pumps, duct sealing, duct insulation and air sealing. Driving customers to online incentive information and applications will continue to be a focus this year. In addition, the Home Energy Savings program will work to maximize opportunities through a well-trained trade ally network. For the See ya later, refrigerator program, the Company will reach customers through print and radio ads, Facebook, bill inserts and newsletters. The Company will continue its partnership with two local non-profit agencies that install energy efficiency measures in the home of limited income households through the Low-income weatherization program. The service is provided at no-cost to participants. Business customer program In 2015, the Company expects to combine the existing Energy FinAnswer and FinAnswer Express programs into a single program called wattsmart Business to make customer participation easier and more streamlined. The business program will be promoted through a light schedule of radio and print advertising, plus direct mail to irrigation customers. Customer success stories will be featured in print ads and newsletter articles. Customer outreach will be coordinated with trade ally partners. Oregon The Company incorporate SB838 spending at seasonally optimal periods to promote “being wattsmart” and directing customers to the programs and incentives offered by Energy Trust of Oregon. Personal Energy Reports continue to be mailed to 11,000 residential customers, and this effort may be expanded in the near future. These reports provide usage comparisons and energy-saving tips. Business customers will be invited to attend informative events to learn about incentives for lighting and other upgrades available through Energy Trust of Oregon. The Company will develop a brochure and print advertising to showcase Oregon business customer success stories for distribution at events. Irrigation customers will also be targeted with direct mail outreach. In 2015, the Company will support Bend and Corvallis as the communities compete for the Georgetown University Energy Prize. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 75 Communication Tactic - Oregon Timing/status Television, Radio, Newspaper, Outdoor  Starting in March the Company will run TV, radio, print and outdoor.  Focus of the campaign will be saving energy with a strong push to lighting, energy saver kits and Home Energy Review.  The Company will continue to utilize the wattsmart, Oregon campaign developed in 2014.  The Company will utilize Eco Posters in certain markets. Business print Starting in January the Company will run in Cascade Business Book of lists as well as the Cascade Business News and Bend Chamber Business Journal Trail Blazers sponsorship PacifiCorp developed a business teamwork spot which will run this season in addition to the residential teamwork spot.  Two (2) 30 second commercials in Trail Blazers Courtside, airing weekly on the Trail Blazer's Radio Network (56 commercials)  Title sponsorship of Trail Blazers Courtside, airing weekly on the Trail Blazer's Network (28 shows)  One (1) billboard in Trail Blazers Courtside, airing weekly on the Trail Blazers Radio Network (28 shows)  Ninety (90) 30 second commercials in the pre-game show on the Trail Blazers Radio Network during the regular season  Ninety two (92) 30 second radio commercials in play-by-play on the Trail Blazers Radio Network during the regular season  Ninety (90) 30 second radio commercials in the post-game show on the Trail Blazers Radio Network during the regular season Include banner ads on local sites, blogs, behavioral ad targeting, and pay-per- click ad placements. Digital ads will be an important part of the media mix. PR – Capitalize on existing assets and tools to deploy news media outreach and consumer engagement efforts that are aligned with marketing (corporate) objectives. Washington Residential customer programs  Home Energy Savings & wattsmart Starter Kits  Refrigerator/Freezer Recycling (See ya later, refrigerator)  See ya later, refrigerator  Low-income Weatherization Services  Home Energy Reports  Be wattsmart, Begin at home school curriculum PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 76 Business customer programs  wattsmart® Business The Home Energy Savings program communicates to customers, retailers and trade allies through a variety of channels, including bill inserts, brochures, in-store/point-of-purchase collateral, social media and website. To help customers start on the path to home energy savings, customers can order free or low-cost wattsmart Starter Kits. Kits are promoted through direct mail, Facebook advertising, bill inserts and emails. In 2015, the Home Energy Savings program will focus on cooling, heating and lighting measures during key seasonal selling windows. Some of the key measures of focus for Washington will include LED lighting, ductless heat pumps, duct sealing, duct insulation and air sealing. Driving customers to online incentive information and applications will continue to be a focus this year. In addition, the Home Energy Savings program will work to maximize opportunities through a well-trained trade ally network. See ya later, refrigerator recycling TV and digital advertising will run in the spring and summer to encourage participation. The Company will also reach customers through bill inserts, newsletters and social media. The Company will continue its partnership with three local non-profit agencies that install energy efficiency measures in the home of limited income households through our Low-income weatherization program. The service is provided at no-cost to participants. Home Energy Reports are mailed to approximately 52,000 residential customers with usage comparisons and energy-saving tips. Customer with valid emails are sent an electronic version of their report and directed to go online where they can view more information about their energy usage and other residential programs and services. The wattsmart Business program will be promoted through radio, print and digital with the addition of LinkedIn ads in 2015. Customer success stories will be featured in print ads and newsletter articles. Direct mail and email will target vertical markets and outreach will be coordinated with trade ally partners to reinforce messaging in direct mail with industry specific incentives and targeted events. In 2015, the Company will support Walla Walla as the community competes for the Georgetown University Energy Prize. Communication Tactic - Washington Timing/status Television: A selection of ads will be rotated, both 30- second and 15-second TV spots, with an average of 100 TV placements each week that the campaign is on the air. Utilize creative developed in 2014. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 77 Communication Tactic - Washington Timing/status KAPP (ABC), KIMA (CBS), KNDO (NBC), KUNV (UNIV) and Charter (Cable). Radio: An average of 100 radio spots per week. Radio stations on which campaign spots will air include KARY- FM (Oldies), KATS-FM (Classic Rock), KDBL-FM (Country), KFFM-FM (Contemporary Hits), KHHK-FM (Rhythmic CHR) KRSE-FM (Modern), KXDD-FM (Country), KZTA-FW (Mexican Regional). Utilize creative developed in 2014. Newspaper Dayton Chronicle, The East Washingtonian, La Voz Hispanic News, The Waitsburg Times, Walla Walla Union Bulletin and Yakima Herald-Republic. Utilize creative developed in 2014. Digital Include banner ads on local sites, blogs, behavioral ad targeting, and pay-per-click ad placements and digital search for business customers. Utilize creative developed in 2014. PR: Capitalize on existing assets and tools to deploy news media outreach and consumer engagement efforts that are aligned with marketing (corporate) objectives. Idaho Residential programs  Home Energy Savings & wattsmart Starter Kits  Refrigerator/Freezer Recycling (See ya later, refrigerator)  Low-income Weatherization Services  Home Energy Reports Business programs  wattsmart Business  Irrigation Load Control The Home Energy Savings program communicates to customers, retailers and trade allies through a variety of channels, including bill inserts, brochures, in-store/point-of-purchase collateral, social media and website. To help customers start on the path to home energy savings, customers can order free or low-cost wattsmart Starter Kits. Kits are promoted through direct mail, Facebook advertising, bill inserts and emails. In 2015, the Home Energy Savings program will focus on cooling, heating and lighting measures during key seasonal selling windows. Some of the key measures of focus for Idaho will include LED lighting, ductless heat pumps, and duct sealing, duct insulation and air sealing. Driving customers to online incentive information and applications will continue to be a focus this year. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 78 In addition, the Home Energy Savings program will work to maximize opportunities through a well-trained trade ally network. See ya later, refrigerator recycling digital advertising will run in the spring and summer to encourage participation. The Company will also reach customers through bill inserts, newsletters and social media. The Company will continue its partnership with two local non-profit agencies that install energy efficiency measures in the home of limited income households through the Low-income weatherization program. The service is provided at no-cost to participants. Home Energy Reports are mailed to approximately 17,250 residential customers with usage comparisons and energy-saving tips. Customer with valid emails are sent an electronic version of their report and directed to go online where they can view more information about their energy usage and other residential programs and services. The wattsmart Business program will be promoted through radio and print. Customer success stories will be featured in print ads and newsletter articles. Direct mail and email will target vertical markets and outreach will be coordinated with trade ally partners to reinforce messaging in direct mail with industry specific incentives and targeted events. Communication Tactic - Idaho Timing/status Television - Idaho Falls: A selection of ads will be rotated, both 30-second and 15-second TV spots. New TV spots in 2015 Radio - Idaho Falls New spots in 2015 Newspapers:  Jefferson Star/Shelley Pioneer  Idaho State Journal  Idaho Falls Post Register  News‐Examiner  Preston Citizen  Rexburg Standard Journal New print ads in 2015 to support the broadcast campaign and business programs. PR – Capitalize on existing assets and tools to deploy news media outreach and consumer engagement efforts that are aligned with marketing (corporate) objectives. Digital Display and Google Search – Idaho Falls Include banner ads on local sites, blogs, behavioral ad targeting, and pay-per-click ad placements. Home Energy Reports Direct mail and email to targeted customers throughout the year Utah Residential customer programs  Home Energy Savings & wattsmart Starter Kits  Refrigerator/Freezer Recycling (See ya later, refrigerator)  Low-income Weatherization Services  Air Conditioner Load Control (Cool Keeper) PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 79  Home Energy Reports  Be wattsmart, Begin at home school curriculum Business customer program  wattsmart® Business  Small Business Air Conditioner Load Control (Cool Keeper)  Irrigation Load Control wattsmart advertising remains strong and will introduce new creative (“wattsmart, Utah”) which will be featured in TV spots, radio commercials, print, transit and digital mediums, incorporated into the school curriculum program and featured at local events, be part of the University of Utah sponsorship, and will include a digital game and video contest. High-level plans for wattsmart programs:  See ya later, refrigerator recycling TV and digital advertising will run throughout the spring and summer to encourage participation.  The Company will continue its partnerships with local non-profit agencies that install energy efficiency measures in the home of limited income households through the Low- income weatherization program. The service is provided at no-cost to participants.  wattsmart incentives and wattsmart Starter Kits (new for 2015) will be promoted primarily through bill inserts, newsletters, email, website features, social media, in- store/point-of-purchase collateral and the spring and fall home show events. New applications will allow customers to apply for more incentives online.  In 2015, the Home Energy Savings program will focus on cooling, heating and lighting measures during key seasonal selling windows. Some of the key measures of focus for Utah will include LED lighting, electronically commutated motors, ductless heat pumps, and duct sealing, duct insulation and air sealing.  Rocky Mountain Power will again participate in the Spring Home & Garden Festival with a booth offering customers free wattsmart Starter Kits as well as other activities to draw interest and engagement.  Cool Keeper air conditioning load control will be promoted through door-to-door canvassing, call center education during new customer account setup, bill inserts and on- report messaging to participating home energy report customers.  Home Energy Reports continue to be mailed to approximately 290,000 residential customers with usage comparisons and energy-saving tips.  wattsmart Business will be promoted through traditional advertising as well as LinkedIn and digital search and the business advocacy outreach efforts. Customer success stories will be featured in print ads and newsletter articles. Direct mail and email will target vertical markets and outreach will be coordinated with trade ally partners to reinforce messaging in direct mail with industry specific incentives and targeted events. In 2015, the Company will support Park City/Summit County and Kearns as the communities compete for the Georgetown University Energy Prize. Communication Tactic - Utah Timing/status Television Develop new creative in 2015 Radio Develop new creative in 2015 PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 80 Communication Tactic - Utah Timing/status Newspapers Develop new creative in 2015 Outdoor/transit Develop new creative in 2015 Sponsorships SL Real, University of Utah Football, Basketball and Women’s Gymnastics, KUED Children’s Programming, Ragnar Relay Mobile game Develop a custom wattsmart energy efficiency mobile game promoted via banner ads and social media Act wattsmart video contest Launch in March 2015, Contest runs through mid-May. Winner announced Mid-June Education component wattsmart Begin at Home runs through 2014/15 school year and RFP for 2015/16 school year; Rockin wattsmart assemblies PR – Capitalize on existing assets and tools to deploy news media outreach and consumer engagement efforts that are aligned with marketing (corporate) objectives. Wyoming Residential programs  Home Energy Savings & wattsmart Starter Kits  Refrigerator/Freezer Recycling (See ya later, refrigerator)  Low-income Weatherization Services  Home Energy Reports Business programs  wattsmart® Business “wattsmart, Wyoming” and wattsmart Business campaigns will play early advertising roles in 2015. The Home Energy Savings program communicates to customers, retailers and trade allies through a variety of channels, including bill inserts, brochures, in-store/point-of-purchase collateral, social media and website. In 2015, the Home Energy Savings program will focus on cooling, heating and lighting measures during key seasonal selling windows. Some of the key measures of focus for Wyoming will include LED lighting, ECMs, ductless heat pumps, duct sealing, duct insulation, air sealing and wattsmart Starter Kits (new for 2015). Driving customers to online incentive information and applications will continue to be a focus this year. In addition, the Home Energy Savings program will work to maximize opportunities through a well-trained trade ally network. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 81 See ya later, refrigerator recycling TV and digital advertising will run in the spring and summer to encourage participation. The Company will also reach customers through bill inserts, newsletters and social media. The Company will continue its partnerships with local non-profit agencies that install energy efficiency measures in the home of limited income households through the Low-income weatherization program. The service is provided at no-cost to participants. Home Energy Reports are mailed to approximately 18,000 residential customers with usage comparisons and energy-saving tips. Customers with valid emails are sent an electronic version of their report and directed to go online where they can view more information about their energy usage and other residential programs and services. The wattsmart Business program will be promoted through radio, print and digital with the addition of LinkedIn ads in 2015. Customer success stories will be featured in print ads and newsletter articles. Direct mail and email will target vertical markets and outreach will be coordinated with trade ally partners to reinforce messaging in direct mail with industry specific incentives and targeted events. Communication Tactic - Wyoming Timing/status Television: A selection of ads will be rotated, both 30- second and 15-second TV spots. Utilize creative developed in 2014. Radio Utilize creative developed in 2014. Newspapers: Cody Enterprise, Powell Tribune, Casper Star-Tribune, Riverton Ranger, Laramie Boomerang, Rock Springs Rocket-Miner, Green River Star, Kemmerer Gazette, Rawlins Daily Times Other papers to consider: Uinta Daily Herald in Evanston, Douglas Budget/Glenrock Independent and the Casper Journal. Utilize creative developed in 2014. Outdoor Poster coverage–Utilize creative developed in 2014. PR – Capitalize on existing assets and tools to deploy news media outreach and consumer engagement efforts that are aligned with marketing (corporate) objectives. Digital Include banner ads on local sites, blogs, behavioral ad targeting, and pay-per-click ad placements. Utilize creative developed in 2014. Communications and Outreach Budget The 2015 wattsmart outreach and communications budget is $2,650,00019 and is included in the forecasted dollars in Table D.6 – Preliminary DSM Program Budget, DSM Classes 1, 2 and 4 provided earlier in Appendix D. 19 The Company is working on expanding current the current wattsmart DSM outreach and communications funding in some states and implementing funding in California effective 2016. This plan and funding complements other company efficiency messaging as well as program specific advertising whose costs are captured within the specific program’s budget. PACIFICORP – 2015 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 82 In addition to the above communications and outreach, the Company supports networks of trade allies (contractors, distributors, manufacturer representatives, etc.) who can bring the business customer program offering to their clients and encourage them to upgrade to higher efficiency equipment. Similarly, the Company implements other customer direct outreach efforts including “eblast” email communications, targeted town events, one-on-one customer calls/visits and more. PACIFICORP – 2015 IRP APPENDIX E – SMART GRID 83 APPENDIX E – SMART GRID Introduction The Smart Grid is the application of advanced communications and controls to the electric power system, including generation, transmission, distribution, and the customer premise. As a result, a wide array of applications can be defined under the smart grid umbrella. Smart Grid technologies include dynamic line rating, phasor measurement units (synchrophasors), energy storage, power line sensors, distribution automation, integrated volt/var optimization, advanced metering infrastructure, automated demand response, and smart renewable and/or distributed generation controls (e.g., smart inverters). For PacifiCorp the smart grid definition started with a review of relevant technologies for transmission, substation and distribution systems, as well as smart metering and home area networks, which enable consumer response to price fluctuations and load curtailment requests. For the interoperation of these technologies the most critical infrastructure decision to be made during smart grid design is the communications network. This network must be high speed, secure and highly reliable, and must be scalable to support PacifiCorp’s entire service territory. The network must accommodate both normal and emergency operation of the electrical system and must be available at all times, especially during the first critical moments of a large-scale disturbance to the system. PacifiCorp regularly evaluates the applicability of smart grid technologies to the power system. Applications that show a positive net benefit for PacifiCorp’s customers are implemented where they are needed. Technologies that PacifiCorp has tested or implemented include dynamic line rating, synchrophasors, and communicating faulted circuit indicators. Technologies studied, but not considered in the smart-grid financial analysis, include fully redundant “self-healing” distribution systems, distributed energy systems (including electric vehicles) and direct load control programs. It is PacifiCorp’s goal to leverage smart grid technologies in a way that aligns with the Integrated Resource Plan (IRP) goals to achieve a portfolio that is chosen based on least-cost/least-risk metrics. This will result in an optimized electrical grid when and where it is economically feasible, operationally beneficial, and in the best interest of customers. Through a comprehensive review and analysis of smart grid report published each year, PacifiCorp is able to ascertain the value proposition of emerging technologies and, at the appropriate time, recommend them for demonstration or integration. Included for reference on the data disk accompanying the 2015 IRP are the most recent reports filed in the states of Oregon, Utah, Washington, and Wyoming. The overall goal is to work in synchronicity with state commissions, with goals of improving reliability, increasing energy efficiency, enhancing customer service, and integrating renewable resources. These goals will be met by utilizing strategies that employ analyzing the total cost of ownership, performing well researched cost-benefit analyses, and focusing on customer outreach. In order to mitigate the costs and risks to the Company and its customers it is essential that technology leaders be identified and that system interoperability and security issues be verified and resolved with national standards. PacifiCorp will continue to monitor technological advances and utility developments throughout the nation as more advanced metering and other smart grid PACIFICORP – 2015 IRP APPENDIX E – SMART GRID 84 related projects are built. This will allow for improved estimates of both costs and benefits. With large-scale deployments progressing throughout the country, it is expected that the smart grid market leaders will become evident within the next few years. Demonstration projects will reveal the sustainability of large-scale rollouts and give utilities a better idea of which areas of the smart grid are best suited for implementation on their systems. Transmission System Efforts Dynamic Line Rating Dynamic line rating is the application of sensors to transmission lines, which indicate the real- time current-carrying capacity of the lines. Transmission lines are generally rated by an assumption of worst-case condition of the season (e.g., hottest summer day or coldest winter day). Dynamic line rating allows an increased capacity during times when this assumption does not hold true. Two dynamic line rating projects were implemented in 2014. One project, Miners-Platte, is operational. The other project, West-of-Populus, requires further data collection and analysis. West-of-Populus is planned to be operational in 2015. Dynamic line rating is considered for all future transmission needs as a means for increasing capacity vis-à-vis traditional construction methods. Dynamic line rating is only applicable for thermal constraints and provides capacity only during site-dependent time periods, which may or may not align with the expected transmission need. Dynamic line rating is but one tool within the transmission planner’s toolbox to be considered when applicable. Synchrophasors Transmission synchrophasors, also called phasor measurement units, can lead to a more reliable network by comparing phase angles of certain network elements with a base element measurement. The phasor measurement unit can also be used to increase reliability by synchrophasor-assisted protection due to line condition data being relayed faster through the communication network. Phasor measurement unit implementation and further development may enable transmission operators to integrate variable resources and energy storage more effectively into their balancing areas and minimize service disruptions. PacifiCorp participated in the Western Electricity Coordinating Council (WECC) Western Interconnection Synchrophasor Project (WISP). The Company, and many other utilities installed phasor measurement units throughout the WECC, and that are currently collection data. The project will support WECC and Peak Reliability, which was formed through a division of WECC, to maintain the stability of the power system. PacifiCorp installed a total of eight phasor measurement units at eight substations. WECC and Peak Reliability are continuing to develop data access for utility participants. The system of synchrophasors will support the prevention of system blackouts, as well as provide historical data for the analysis of any future power system failure. The data may prove useful for utility operations in the future. Distribution System Efforts Distribution Reliability Efforts: Communicating Faulted Circuit Indicators Traditional non-communicating faulted circuit indicators are used to visually indicate fault current paths on the distribution system, while communicating faulted circuit indicators wirelessly by sending a signal to the utility. Communicating faulted circuit indicators have the PACIFICORP – 2015 IRP APPENDIX E – SMART GRID 85 potential to improve reliability indices, such as customer average interruption duration index (CAIDI), by reducing the amount of time associated with initial fault reporting and determining fault location. Project Summary PacifiCorp has installed 48 communicating faulted circuit indicators in early 2014. Future actions include integration with PacifiCorp’s outage management system, validation, and cost/benefit analysis; these actions are anticipated to be complete in spring of 2015. The communicating faulted circuit indicators were installed on five circuits in eastern Utah in March 2014. These circuits had poor reliability, were in difficult-to-access rural areas, and had limited supervisory control and data acquisition (SCADA). Sensor alerts and loading data are currently being hosted through a vendor-hosted web portal accessed by area engineers and dispatchers. A project to integrate communicating faulted circuit indicators sensor data with the Company’s outage management system is in progress. Integration of the communicating faulted circuit indicators and outage management system is expected to provide operation personnel with an enhanced view of system status and accelerate the use of the data from new equipment. Validation of sensor performance is on-going; a cost-benefit analysis should be complete by spring of 2015. Given positive results this technology will be considered for similar circuits elsewhere. Customer Information and Demand-Side Management Efforts Advanced Metering Strategy PacifiCorp has been evaluating the applicability of smart meters to its Oregon service area. PacifiCorp expended considerable effort during 2014 further developing and refining its strategy aimed at implementing an advanced metering system (AMS) in the state of Oregon. Potential benefits as well as costs were researched, evaluated, and refined, producing multiple business case models. PacifiCorp’s objectives were threefold; identify a solution and strategy that would deliver solid projected benefits to our customers, deliver financial results that make economic sense, and minimize impact on consumer rates. PacifiCorp made significant headway during 2014 in expanding its understanding of the implications for implementing an advanced metering system in the state of Oregon. The costs were further refined through the request for proposal process and enabled PacifiCorp to clarify the economics and better understand the full impact that a system of this nature will have on customers. The results of the proposals and associated economic analyses were encouraging and further work with vendors is scheduled in the upcoming months. A final decision on the project is expected in late 2015. Future Smart Grid PacifiCorp is continuing to evaluate smart grid technologies that may benefit customers as well as validating those that are being piloted. PacifiCorp regularly develops and updates a business case to examine the quantifiable costs and benefits of a smart grid system and each individual component. While the net present value of implementing a comprehensive smart grid system throughout PacifiCorp is negative at this time, PacifiCorp has implemented specific projects and programs that have positive benefits for customers, and explored pilot projects in other areas of interest. PACIFICORP – 2015 IRP APPENDIX E – SMART GRID 86 PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 87 APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT Introduction In its Order No. 12013 issued on January 19, 2012 in Docket No. UM 1461 on “Investigation of matters related to Electric Vehicle Charging,” the Oregon Public Utility Commission (OPUC) adopted the OPUC staff’s proposed IRP guideline: 1. Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the balancing reserves needed at different time intervals (e.g. ramping needed within 5 minutes) to respond to variation in load and intermittent renewable generation over the 20-year planning period; 2. Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing reserves available at different time intervals (e.g. ramping available within 5 minutes) from existing generating resources over the 20-year planning period; and 3. Evaluate Flexible Resources on a Consistent and Comparable Basis: In planning to fill any gap between the demand and supply of flexible capacity, the electric utilities shall evaluate all resource options including the use of electric vehicles (EVs), on a consistent and comparable basis. In this appendix, the Company first identifies its flexible resource needs for the IRP study period of 2015 through 2034, and the calculation method used to estimate those requirements. The Company then identifies its supply of flexible capacity from its generation resources, in accordance with the Western Electricity Coordinating Council (WECC) operating reserves guidelines, demonstrating that PacifiCorp has sufficient flexible resources to meet its requirements. Flexible Resource Requirements Forecast PacifiCorp’s flexible resource needs are the same as its operating reserves requirements over the planning horizon for maintaining reliability and compliance with the North American Electric Reliability Corporation (NERC) regional reliability standards. NERC regional reliability standard BAL-002-WECC-2 requires each Balancing Authority Area to carry sufficient operating reserve at all times.20 Operating reserve consists of contingency reserve and regulating margin. Each type of operating reserve is further defined below. Contingency Reserve Contingency reserve is capacity that the Company holds in reserve to respond to unforeseen events on the power system, such as an unexpected outage of a generator or a transmission line. Contingency reserve may not be applied to manage other system fluctuations such as changes in load or wind generation output. 20 http://www.nerc.com/files/BAL-002-WECC-2.pdf PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 88 Regulating Margin Regulating margin is the additional capacity the Company holds in reserve to ensure it has adequate reserve levels at all times to meet the NERC Control Performance Criteria in BAL-001- 221. In this IRP, the Company further segregates regulating margin into two components: ramp reserve and regulation reserve, which are discussed in more details in Volume II, Appendix H, PacifiCorp’s 2014 Wind Integration Study (WIS). They are summarized here, as follows: Ramp Reserve: Both load and wind change from minute-to-minute, hour-to-hour, continuously at all times. This variability requires ready capacity to follow changes in load and wind continuously, through short deviations, at all times. Treating this variability as though it is perfectly known (as though the operator would know exactly what the net balancing area load would be a minute from now, 10-minutes from now, and an hour from now) and allowing just enough generation flexibility on hand to manage it defines the ramp reserve requirement of the system. Regulation Reserve: Changes in load or wind generation which are not considered contingency events, but require resources be set aside to meet the needs created when load or wind generation change unexpectedly. The Company has defined two types of regulation reserve: those covering short term variations (moment to moment using automatic generation control) in system load and wind (“regulating reserve”), and those covering uncertainty across an hour when forecast changes unexpectedly (“following reserves”). Since contingency reserve and regulating margin are separate and distinct components, PacifiCorp estimates the forward requirements for each separately. The contingency reserve requirements are derived from a stochastic simulation study which captures the changes in the hourly interchange and generation dispatch of the preferred portfolio. These simulations were run using the Planning and Risk (PaR) model. The regulating margin requirements are part of the inputs to the PaR model, and are calculated by applying the methods developed in the WIS. For this study and given the similar response time requirements of the two regulating margin components, they are grouped together with spinning reserves for modeling in this IRP. The reserve requirements for PacifiCorp’s two balancing authority areas are shown in Table F.1. 21 NERC Standard BAL-001-2: http://www.nerc.com/files/BAL-001-2.pdf. PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 89 Table F.1 – Reserve Requirements (MW) Year East Requirement Spin Non-Spin West Requirement Spin Non-Spin 2015 624 209 250 90 2016 626 204 253 91 2017 631 208 254 92 2018 634 211 255 93 2019 634 213 255 94 2020 636 216 256 95 2021 637 217 258 96 2022 640 220 246 97 2023 639 222 247 97 2024 639 223 244 98 2025 632 224 245 99 2026 635 226 246 100 2027 638 230 247 100 2028 642 235 247 101 2029 640 233 243 101 2030 634 234 242 102 2031 621 236 243 103 2032 623 242 244 103 2033 604 241 244 104 2034 613 250 244 105 Flexible Resource Supply Forecast Requirements by NERC and the WECC dictate the types of resources that can be used to serve the reserve requirements. For contingency reserves, at least one half of the requirements are spinning reserves, while the remainder are non-spinning reserves:  Spinning reserves can only be served by resources currently online and synchronized to the transmission grid;  Non-spinning reserves may be served by fast-start resources that are capable of being online and synchronized to the transmission grid within ten minutes. Interruptible load can only serve non-spinning reserves. Non-spinning reserves may be served by resources that are capable of providing spinning reserves. Regulation reserves are added to the spinning half of the contingency reserve requirements, which are referred to as spinning reserves in the subsequent discussions. The resources that PacifiCorp employs to serve its reserve requirements include owned hydro resources that have storage, owned thermal resources, and purchased power contracts that provide the Company with reserve capabilities. Hydro resources are generally deployed first to meet the spinning reserve requirements because of their flexibility and their ability to respond quickly. The amount of reserves that these PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 90 resources can provide depends upon the difference between their expected capacities and their generation level at the time. The hydro resources that PacifiCorp may use to cover reserve requirements in the PacifiCorp West balancing authority area include its facilities on the Lewis River and the Klamath River as well as contracted generation from the Mid-Columbia projects. In the PacifiCorp East balancing authority area, the Company may use facilities on the Bear River to provide spinning reserves. Thermal resources are also used to meet the spinning reserve requirements when they are online. The amount of reserves provided by these resources is determined by their ability to ramp up within a 10-minute interval. For natural gas-fired thermal resources, the amount of reserves can be close to the differences between their nameplate capacities and their minimum generation levels. In the current IRP, PacifiCorp’s reserves are served not only from existing coal- and gas- fired resources that the Company operates, but also from new gas-fired resources selected in the preferred portfolio. Table F.2 lists the annual capacity of resources that are capable of serving reserves in PacifiCorp’s East and West balancing authority areas. All the resources included in the calculation are capable of providing all types of reserves. The non-spinning reserve resources under third party contracts are excluded in the calculations. The changes in the flexible resource supply reflect retirement of existing resources, addition of new preferred portfolio resources, variation in hydro capability due to forecasted streamflow conditions, and expiration of contracts from the Mid-Columbia projects that are reflected in the preferred portfolio. Table F.2 – Flexible Resource Supply Forecast (MW) Year East Supply West Supply 2015 1,100 794 2016 1,100 770 2017 1,096 746 2018 1,096 752 2019 1,096 774 2020 1,097 774 2021 1,097 745 2022 1,097 745 2023 1,097 745 2024 1,097 745 2025 1,097 745 2026 1,097 745 2027 1,097 745 2028 1,242 745 2029 1,242 745 2030 1,438 745 2031 1,438 745 2032 1,438 745 2033 1,503 745 2034 1,773 745 Figure F.1 and Figure F.2 graphically display the balances of reserve requirements and capability of spinning reserve resources in PacifiCorp’s East and West balancing authority areas PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 91 respectively. The graphs demonstrate that PacifiCorp’s system has sufficient resources to serve its reserve requirements throughout the IRP planning period. Figure F.1 – Comparison of Reserve Requirements and Resources, East Balancing Authority Area (MW) Figure F.2 – Comparison of Reserve Requirements and Resources, West Balancing Authority Area (MW) PACIFICORP – 2015 IRP APPENDIX F – FLEXIBLE RESOURCE NEEDS ASSESSMENT 92 Flexible Resource Supply Planning In actual operations, PacifiCorp has been able to serve its reserve requirements and has not experienced any incidences where it was short of reserves. PacifiCorp manages its resources to meet its reserve obligation in the same manner as meeting its load obligation – through long term planning, market transactions, utilization of the transmission capability between the two balancing authority areas, and operational activities that are performed on an economic basis. PacifiCorp and the California Independent System Operator Corporation implemented the energy imbalance market (EIM) on November 1, 2014. This implementation is expected to provide a more optimized economic dispatch of PacifiCorp’s resources and may eventually reduce regulating margin requirements. As indicated in the OPUC order, electric vehicle technologies may be able to meet flexible resource needs at some point in the future. However, the electric vehicle technology and market have not developed sufficiently to provide data for the current study. Since this analysis shows no gap between forecasted demand and supply of flexible resources over the IRP planning horizon, this IRP does not include whether electric vehicles could be used to meet future flexible resource needs. PACIFICORP – 2015 IRP APPENDIX G – PLANT WATER CONSUMPTION 93 APPENDIX G – PLANT WATER CONSUMPTION The information provide in this appendix is for PacifiCorp owned plants. Total water consumption and generation includes all owners for jointly-owned facilities PACIFICORP – 2015 IRP APPENDIX G – PLANT WATER CONSUMPTION 94 Table G.1 – Plant Water Consumption with Acre-Feet Per Year **Gadsby includes a mix of both rankine steam units and peaking gas turbines Plants Owned and Operated by PacifiCorp Total water consumption and generation includes all owners for jointly-owned facilities 1 acre-foot of water is equivalent to: 325,851 Gallons or 43,560 Cubic Feet Plant Name Zero Discharge Cooling Media 2010 2011 2012 2013 Average 2010 2011 2012 2013 Gals/ MWH GPM/ MW Carbon Utah 2,193 2,458 2,307 1940 2,241 1,296,004 1,332,218 1,287,240 1,197,765 582 9.7 Chehalis Washington 24 43 55 86 52 1,296,741 664,323 849,938 1,674,194 15 0.2 Currant Creek Yes Utah 82 78 90 84 87 2,536,660 2,397,142 2,132,523 2,359,924 12 0.2 Dave Johnston Wyoming 6,604 7,233 7,721 8941 7,538 4,704,694 5,059,927 4,906,422 5,295,081 481 8.0 Gadsby Utah 893 864 1,059 610 755 359,404 194,389 214,739 339,592 672 11.2 Hunter Yes Utah 18,941 16,961 18,266 17001 18,308 8,785,827 8,719,300 9,118,876 9,546,313 641 10.7 Huntington Yes Utah 9,549 9,069 10,423 10643 10,332 6,107,379 5,961,371 6,744,160 6,768,625 512 8.5 Jim Bridger Yes Wyoming 20,757 22,282 23,977 25059 24,126 14,828,906 12,771,611 13,625,135 14,817,041 545 9.1 Lake Side Utah 1,533 1,154 1,693 1361 1,475 2,537,046 1,781,198 2,890,938 2,508,960 196 3.3 Naughton Wyoming 13,354 14,157 8,745 9622 11,286 5,339,385 5,102,251 5,056,959 5,533,895 714 11.9 Wyodak Yes Wyoming 396 367 322 319 369 2,565,341 1,831,459 2,526,307 2,518,120 48 0.8 74,326 74,664 74,658 75,666 78,143 50,357,387 45,815,189 49,353,237 52,559,510 411 6.8 Acre-Feet Per Year MWhs Per Year TOTAL PACIFICORP – 2015 IRP APPENDIX G – PLANT WATER CONSUMPTION 95 Table G.2 – Plant Water Consumption by State (acre-feet) Percent of total water consumption = 43.4% Percent of total water consumption = 56.6% Table G.3 – Plant Water Consumption by Fuel Type (acre-feet) Percent of total water consumption = 97.0% Percent of total water consumption = 3.0% UTAH PLANTS Plant Name 2008 2009 2010 2011 2012 2013 Carbon 2,199 2,349 2,193 2,458 2,307 1,940 Currant Creek 82 108 82 78 90 84 Gadsby 426 680 893 864 1,059 610 Hunter 19,380 19,300 18,941 16,961 18,266 17,001 Huntington 11,385 10,922 9,549 9,069 10,423 10,643 Lake Side 1,821 1,287 1,533 1,154 1,693 1,361 TOTAL 35,293 34,646 33,191 30,583 33,838 31,639 WYOMING PLANTS Plant Name 2008 2009 2010 2011 2012 2013 Dave Johnston 7,746 6,983 6,604 7,233 7,721 8,941 Jim Bridger 27,322 25,361 20,757 22,282 23,977 25,059 Naughton 10,992 10,846 13,354 14,157 8,745 9,622 Wyodak 446 365 396 367 322 319 TOTAL 46506 43555 41111 44039 40765 43941 COAL FIRED PLANTS Plant Name 2008 2009 2010 2011 2012 2013 Generation Capacity Ac-ft/MW Carbon 2,199 2,349 2,193 2,458 2,307 1,940 172 13.0 Dave Johnston 7,746 6,983 6,604 7,233 7,721 8,941 762 9.9 Hunter 19,380 19,300 18,941 16,961 18,266 17,001 1,341 13.6 Huntington 11,385 10,922 9,549 9,069 10,423 10,643 903 11.4 Jim Bridger 27,322 25,361 20,757 22,282 23,977 25,059 2,118 11.4 Naughton 10,992 10,846 13,354 14,157 8,745 9,622 700 16.1 Wyodak 446 365 396 367 322 319 335 1.1 TOTAL 79,470 76,126 71,794 72,526 71,761 73,525 Average 10.9 NATURAL GAS FIRED PLANTS Plant Name 2008 2009 2010 2011 2012 2013 Generation Capacity Ac-ft/MW Currant Creek 82 108 82 78 90 84 537 0.2 Gadsby 426 680 893 864 1,059 610 351 2.2 Lake Side 1,821 1,287 1,533 1,154 1,693 1,361 544 2.7 TOTAL 2,329 2,075 2,508 2,096 2,842 2,055 Average 1.7 PACIFICORP – 2015 IRP APPENDIX G – PLANT WATER CONSUMPTION 96 Table G.4 – Plant Water Consumption for Plants Located in the Upper Colorado River Basin (acre-feet) Percent of total water consumption = 86.6% Plant Name 2008 2009 2010 2011 2012 2013 Hunter 19,380 19,300 18,941 16,961 18,266 17,001 Huntington 11,385 10,922 9,549 9,069 10,423 10,643 Carbon 2,199 2,349 2,193 2,458 2,307 1,940 Naughton 10,992 10,846 13,354 14,157 8,745 9,622 Jim Bridger 27,322 25,361 20,757 22,282 23,977 25,059 TOTAL 71,278 68,778 64,794 64,927 63,718 64,265 PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 97 APPENDIX H – WIND INTEGRATION STUDY Introduction This wind integration study (WIS) estimates the operating reserves required to both maintain PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation (NERC) reliability standards. The Company must provide sufficient operating reserves to meet NERC’s balancing authority area control error limit (BAL-001-2) at all times, incremental to contingency reserves, which the Company maintains to comply with NERC standard BAL-002- WECC-2.22,23 Apart from disturbance events that are addressed through contingency reserves, these incremental operating reserves are necessary to maintain area control error24 (ACE), due to sources outside direct operator control including intra-hour changes in load demand and wind generation, within required parameters. The WIS estimates the operating reserve volume required to manage load and wind generation variation in PacifiCorp’s Balancing Authority Areas (BAAs) and estimates the incremental cost of these operating reserves. The operating reserves contemplated within this WIS represent regulating margin, which is comprised of ramp reserve, extracted directly from operational data, and regulation reserve, which is estimated based on operational data. The WIS calculates regulating margin demand over two common operational timeframes: 10-minute intervals, called regulating; and one-hour- intervals, called following. The regulating margin requirements are calculated from operational data recorded during PacifiCorp’s operations from January 2012 through December 2013 (Study Term). The regulating margin requirements for load variation, and separately for load variation combined with wind variation, are then applied in the Planning and Risk (PaR) production cost model to determine the cost of the additional reserve requirements. These costs are attributed to the integration of wind generation resources in the 2015 Integrated Resource Plan (IRP). Estimated regulating margin reserve volumes in this study were calculated using the same methodology applied in the Company’s 2012 WIS25, with data updated for the current Study Term. The regulating margin reserve volumes in this study account for estimated benefits from PacifiCorp’s participation in the energy imbalance market (EIM) with the California Independent System Operator (CAISO). The Company expects that with its participation in the EIM future wind integration study updates will benefit as PacifiCorp gains access to additional and more specific operating data. 22 NERC Standard BAL-001-2: http://www.nerc.com/files/BAL-001-2.pdf 23 NERC Standard BAL-002-WECC-2 (http://www.nerc.com/files/BAL-002-WECC-2.pdf), which became effective October 1, 2014, replaced NERC Standard BAL-STD-002, which was in effect at the time of this study. 24 “Area Control Error” is defined in the NERC glossary here: http://www.nerc.com/pa/stand/glossary of terms/glossary_of_terms.pdf 25 2012 WIS report is provided as Appendix H in Volume II of the Company’s 2013 IRP report: http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/Pacifi Corp-2013IRP_Vol2-Appendices_4-30-13.pdf PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 98 Technical Review Committee As was done for its 2012 WIS, the Company engaged a Technical Review Committee (TRC) to review the study results from the 2014 WIS. The Company thanks each of the TRC members, identified below, for their participation and professional feedback. The members of the TRC are:  Andrea Coon - Director, Western Renewable Energy Generation Information System (WREGIS) for the Western Electricity Coordinating Council (WECC)  Matt Hunsaker - Manager, Renewable Integration for the Western Electricity Coordinating Council (WECC)  Michael Milligan - Lead research for the Transmission and Grid Integration Team at the National Renewable Energy Laboratory (NREL)  J. Charles Smith - Executive Director, Utility Variable-Generation Integration Group (UVIG)  Robert Zavadil - Executive Vice President of Power Systems Consulting, EnerNex In its technical review of the Company’s 2012 WIS, the TRC made recommendations for consideration in future WIS updates.26 The following table summarizes TRC recommendations from the 2012 WIS and how these recommendations were addressed in the 2014 WIS. Table H.1 – 2012 WIS TRC Recommendations 2012 WIS TRC Recommendations 2014 WIS Response to TRC Recommendations Reserve requirements should be modeled on an hourly basis in the production cost model, rather than on a monthly average basis. The Company modeled reserves on an hourly basis in PaR. A sensitivity was performed to model reserves on monthly basis as in the 2012 WIS. Either the 99.7% exceedance level should be studied parametrically in future work, or a better method to link the exceedance level, which drives the reserve requirements in the WIS, to actual reliability requirements should be developed. In discussing this recommendation with the TRC, it was clarified that the intent was a request to better explain how the exceedance level ties to operations. PacifiCorp has included discussion in this 2014 WIS on its selection of a 99.7% exceedance level when calculating regulation reserve needs, and further clarifies that the WIS results informs the amount of regulation reserves planned for operations. Future work should treat the categories “regulating,” “following,” and “ramping” differently by using the capabilities already in PaR and comparing these results to those using of the root-sum-of-squares (RSS) formula. A sensitivity study was performed demonstrating the impact of separating the reserves into different categories. Given the vast amount of data used, a simpler and more transparent analysis could be performed using a flexible statistics package rather than spreadsheets. PacifiCorp appreciates the TRC comment; however, PacifiCorp continued to rely on spreadsheet-based calculations when calculating regulation reserves for its 2014 WIS. This allows stakeholders, who may not have access to specific statistics packages, to review work papers underlying PacifiCorp’s 2014 WIS. 26 TRC’s full report is provided at: http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/Wind_Integratio n/2012WIS/Pacificorp_2012WIS_TRC-Technical-Memo_5-10-13.pdf PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 99 2012 WIS TRC Recommendations 2014 WIS Response to TRC Recommendations Because changes in forecasted natural gas and electricity prices were a major reason behind the large change in integration costs from the 2010 WIS, sensitivity studies around natural gas and power prices, and around carbon tax assumptions, would be interesting and provide some useful results. Changes in wind integration costs continue to align with movements in forward market prices for both natural gas and electricity. PacifiCorp describes how market prices have changed in relation to wind integration costs as updated in the 2014 WIS. With the U.S. Environmental Protection Agency’s draft rule under §111(d) of the Clean Air Act, CO2 tax assumptions are no longer assumed in PacifiCorp’s official forward price curves. Although the study of separate east and west BAAs is useful, the WIS should be expanded to consider the benefits of PacifiCorp’s system as a whole, as some reserves are transferrable between the BAAs. It would be reasonable to conclude that EIM would decrease reserve requirements and integration costs. PacifiCorp has incorporated estimated regulation reserve benefits associated with its participation in EIM in the 2014 WIS. With its involvement in EIM, future wind studies will benefit as PacifiCorp gains access to better operating data. Executive Summary The 2014 WIS estimates the regulating margin requirement from historical load and wind generation production data using the same methodology that was developed in the 2012 WIS. The regulating margin is required to manage variations to area control error due to load and wind variations within PacifiCorp’s BAAs. The WIS estimates the regulating margin requirement based on load combined with wind variation and separately estimates the regulating margin requirement based solely on load variation. The difference between these two calculations, with and without the estimated regulating margin required to manage wind variability and uncertainty, provides the amount of incremental regulating margin required to maintain system reliability due to the presence of wind generation in PacifiCorp’s BAAs. The resulting regulating margin requirement was evaluated deterministically in the PaR model, a production cost model used in the Company’s Integrated Resource Plan (IRP) to simulate dispatch of PacifiCorp’s system. The incremental cost of the regulating margin required to manage wind resource variability and uncertainty is reported on a dollar per megawatt-hour ($/MWh) of wind generation basis.27 When compared to the result in the 2012 WIS, which relied upon 2011 data, the 2014 WIS uses 2013 data and shows that total regulating margin increased by approximately 27 megawatts (MW) in 2012 and 47 MW in 2013. These increases in the total reserve requirement reflect different levels of volatility in actual load and wind generation. This volatility in turn impacts the operational forecasts and the deviations between the actual and operational forecast reserve requirements, which ultimately drives the amount of regulating margin needed. Table H.2 depicts the combined PacifiCorp BAA annual average regulating margin calculated in the 2014 WIS, and separates the regulating margin due to load from the regulating margin due to wind. The total regulating margin increased from 579 MW in the 2012 WIS to 626 MW in the 2014 WIS. 27 The PaR model can be run with stochastic variables in Monte Carlo simulation mode or in deterministic mode whereby variables such as natural gas and power prices do not reflect random draws from probability distributions. For purposes of the WIS, the intention is not to evaluate stochastic portfolio risk, but to estimate production cost impacts of incremental operating reserves required to manage wind generation on the system based on current projections of future market prices for power and natural gas. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 100 Table H.2 – Average Annual Regulating Margin Reserves, 2011 – 2013 (MW) Year Type West BAA East BAA Combined 2011 (2012 WIS) Load-Only Regulating Margin 147 247 394 Incremental Wind Regulating Margin 54 131 185 Total Regulating Margin 202 378 579 Wind Capacity 589 1,536 2,126 2012 Load-Only Regulating Margin 141 259 400 Incremental Wind Regulating Margin 77 129 206 Total Regulating Margin 217 388 606 Wind Capacity 785 1,759 2,543 2013 (2014 WIS) Load-Only Regulating Margin 166 275 441 Incremental Wind Regulating Margin 55 130 186 Total Regulating Margin 222 405 626 Wind Capacity 785 1,759 2,543 Table H.3 lists the cost to integrate wind generation in PacifiCorp’s BAAs. The cost to integrate wind includes the cost of the incremental regulating margin reserves to manage intra-hour variances (as outlined above) and the cost associated with day-ahead forecast variances, the latter of which affects how dispatchable resources are committed to operate, and subsequently, affect daily system balancing. Each of these component costs were calculated using the PaR model. A series of PaR simulations were completed to isolate each wind integration cost component by using a “with and without” approach. For instance, PaR was first used to calculate system costs solely with the regulating margin requirement due to load variations, and then again with the increased regulating margin requirements due to load combined with wind generation. The change in system costs between the two PaR simulations results in the wind integration cost. Table H.3 – Wind Integration Cost, $/MWh 2012 WIS (2012$) 2014 WIS (2015$) Intra-hour Reserve $2.19 $2.35 Inter-hour/System Balancing $0.36 $0.71 Total Wind Integration $2.55 $3.06 The 2014 WIS results are applied in the 2015 IRP portfolio development process as part of the costs of wind generation resources. In the portfolio development process using the System Optimizer (SO) model, the wind integration cost on a dollar per megawatt-hour basis is included as a cost to the variable operation and maintenance cost of each wind resource. Once candidate resource portfolios are developed using the SO model, the PaR model is used to evaluate the risk profiles of the portfolios in meeting load obligations, including incremental operating reserve needs. Therefore, when performing IRP risk analysis using PaR, specific operating reserve requirements consistent with this wind study are used. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 101 Data The calculation of regulating margin reserve requirement was based on actual historical load and wind production data over the Study Term from January 2012 through December 2013. Table H.4 outlines the load and wind generation 10-minute interval data used during the Study Term. Table H.4 – Historical Wind Production and Load Data Inventory Wind Nameplate Capacity (MW) Beginning of Data End of Data BAA Wind Plants within PacifiCorp BAAs Chevron Wind 16.5 1/1/2012 12/31/2013 East Combine Hills 41.0 1/1/2012 12/31/2013 West Dunlap 1 Wind 111.0 1/1/2012 12/31/2013 East Five Pine and North Point 119.7 12/1/2012 12/31/2013 East Foot Creek Generation 85.1 1/1/2012 12/31/2013 East Glenrock III Wind 39.0 1/1/2012 12/31/2013 East Glenrock Wind 99.0 1/1/2012 12/31/2013 East Goodnoe Hills Wind 94.0 1/1/2012 12/31/2013 West High Plains Wind 99.0 1/1/2012 12/31/2013 East Leaning Juniper 1 100.5 1/1/2012 12/31/2013 West Marengo I 140.4 1/1/2012 12/31/2013 West Marengo II 70.2 1/1/2012 12/31/2013 West McFadden Ridge Wind 28.5 1/1/2012 12/31/2013 East Mountain Wind 1 QF 60.9 1/1/2012 12/31/2013 East Mountain Wind 2 QF 79.8 1/1/2012 12/31/2013 East Power County North and Power County South 45.0 1/1/2012 12/31/2013 East Oregon Wind Farm QF 64.6 1/1/2012 12/31/2013 West Rock River I 49.0 1/1/2012 12/31/2013 East Rolling Hills Wind 99.0 1/1/2012 12/31/2013 East Seven Mile Wind 99.0 1/1/2012 12/31/2013 East Seven Mile II Wind 19.5 1/1/2012 12/31/2013 East Spanish Fork Wind 2 QF 18.9 1/1/2012 12/31/2013 East Stateline Contracted Generation 175.0 1/1/2012 12/31/2013 West Three Buttes Wind 99.0 1/1/2012 12/31/2013 East Top of the World Wind 200.2 1/1/2012 12/31/2013 East Wolverine Creek 64.5 1/1/2012 12/31/2013 East Long Hollow Wind 1/1/2012 12/31/2013 East Campbell Wind 1/1/2012 12/31/2013 West Horse Butte 6/19/2012 12/31/2013 East Jolly Hills 1 1/1/2012 12/31/2013 East Jolly Hills 2 1/1/2012 12/31/2013 East Load Data PACW Load n/a 1/1/2012 12/31/2013 West PACE Load n/a 1/1/2012 12/31/2013 East PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 102 Historical Load Data Historical load data for the PacifiCorp east (PACE) and PacifiCorp west (PACW) BAAs were collected for the Study Term from the PacifiCorp PI system.28 The raw load data were reviewed for anomalies prior to further use. Data anomalies can include:  Incorrect or reversal of sign (recorded data switching from positive to negative);  Significant and unexplainable changes in load from one 10-minute interval to the next;  Excessive load values. After reviewing 210,528 10-minute load data points in the 2014 WIS, 1,011 10-minute data points, roughly 0.5% of the data, were identified as irregular. Since reserve demand is created by unexpected changes from one time interval to the next, the corrections made to those data points were intended to mitigate the impacts of irregular data on the calculation of the reserve requirements and costs in this study. Of the 1,011 load data points requiring adjustment, 984 exhibited unduly long periods of unchanged or “stuck” values. The data points were compared to the values from the Company’s official hourly data. If the six 10-minute PI values over a given hour averaged to a different value than the official hourly record, they were replaced with six 10-minute instances of the hourly value. For example, if PACW’s measured load was 3,000 MW for three days, while the Company’s official hourly record showed different hourly values for the same period, the six 10- minute “stuck” data points for an hour were replaced with six instances of the value from the official record for the hour. Though the granularity of the 10-minute readings was lost, the hour- to-hour load variability over the three days in this example would be captured by this method. In total, the load data requiring replacement for stuck values represented only 0.47% of the load data used in the current study. The remaining 27 of data points requiring adjustment were due to questionable load values, three of which were significantly higher than the load values in the adjacent time intervals, and 24 of which were significantly lower. While not necessarily higher or lower by an egregious amount in each instance, these specific irregular data collectively averaged a difference of several hundred megawatts from their replacement values. Table H.5 depicts a sample of the values that varied significantly, as compared to the data points immediately prior to and after those 10-minute intervals. The replacement values, calculated by interpolating the prior value and the successive 10-minute period to form a straight line, are also shown in the table. 28 The PI system collects load and generation data and is supplied to PacifiCorp by OSISoft. The Company Web site is http://www.osisoft.com/software-support/what-is-pi/what_is_PI_.aspx. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 103 Table H.5 – Examples of Load Data Anomalies and their Interpolated Solutions Time Original Load Value (MW) Final Load Value (MW) Method to Calculate Final Load Value 1/5/2012 12:20 5,805 5,805 n/a 1/5/2012 12:30 5,211 5,793 12:20 + 1/5 of (13:10 minus 12:20) 1/5/2012 12:40 5,074 5,781 12:20 + 2/5 of (13:10 minus 12:20) 1/5/2012 12:50 5,063 5,769 12:20 + 3/5 of (13:10 minus 12:20) 1/5/2012 13:00 5,465 5,756 12:20 + 4/5 of (13:10 minus 12:20) 1/5/2012 13:10 5,744 5,744 n/a 5/6/2013 8:50 5,651 5,651 n/a 5/6/2013 9:00 4,583 5,694 Average of 8:50 and 9:10 5/6/2013 9:10 5,737 5,737 n/a Historical Wind Generation Data Over the Study Term, 10-minute interval wind generation data were available for the wind projects as summarized in Table H.4. The wind output data were collected from the PI system. In 2011 the installed wind capacity in the PacifiCorp system was 589 MW in the west BAA and 1,536 MW in the east BAA. For 2012 and 2013, these capacities increased to 785 MW and 1,759 MW in the west and east BAAs, respectively. The increases were the result of 195 MW of existing wind projects transferring from Bonneville Power Administration (BPA) to PacifiCorp’s west BAA, and 222 MW of new third party wind projects coming on-line during 2012 in the east BAA. Figure H.1 shows PacifiCorp owned and contracted wind generation plants located in PacifiCorp’s east and west BAAs. The third-party wind plants located within PacifiCorp’s BAAs which the Company does not purchase generation from or own are not depicted in this figure. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 104 Figure H.1 – Representative Map, PacifiCorp Wind Generating Stations Used in this Study The wind data collected from the PI system is grouped into a series of sampling points, or nodes, which represent generation from one or more wind plants. In consideration of occasional irregularities in the system collecting the data, the raw wind data was reviewed for reasonableness considering the following criteria:  Incorrect or reversal of sign (recorded data switching from positive to negative);  Output greater than expected wind generation capacity being collected at a given node;  Wind generation appearing constant over a period of days or weeks at a given node. Some of the PI system data exhibited large negative generation output readings in excess of the amount that could be attributed to station service. These meter readings often reflected positive generation and a reversed polarity on the meter rather than negative generation. In total, only 38 of 3,822,048 10-minute PI readings, representing 0.001% of the wind data used in this WIS, required substituting a positive value for a negative generation value. Some of the PI system data exhibited large positive generation output readings in excess of plant capacity. In these instances, the erroneous data were replaced with a linear interpolation between the value immediately before the start of the excessively large data point and the value immediately after the end of the excessively large data point. In total, only 49 10-minute PI readings, representing 0.002% of the wind data used in this WIS, required substituting a linear interpolation for an excessively large generation value. Similar to the load data, the PI system wind data also exhibited patterns of unduly long periods of unchanged or “stuck” values for a given node. To address these anomalies, the 10-minute PI values were compared to the values from the Company’s official hourly data, and if the six 10- minute PI values over a given hour averaged to a different value than the official hourly record, PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 105 they were replaced with six 10-minute instances of the hourly value. For example, if a node’s measured wind generation output was 50 MW for three weeks, while the official record showed different hourly values for the same time period, the six 10-minute “stuck” data points for an hour were replaced with six instances of the value from the official record for the hour. Though the granularity of the 10-minute readings was lost, the hour-to-hour wind variability over the three weeks in this example would be captured by this method. In total, the wind generation data requiring replacement for stuck values represented only 0.2% of the wind data used in the WIS. Methodology Method Overview This section presents the approach used to establish regulating margin reserve requirements and the method for calculating the associated wind integration costs. 10-minute interval load and wind data were used to estimate the amount of regulating margin reserves, both up and down, in order to manage variation in load and wind generation within PacifiCorp’s BAAs. Operating Reserves NERC regional reliability standard BAL-002-WECC-2 requires each BAA to carry sufficient operating reserve at all times.29 Operating reserve consists of contingency reserve and regulating margin. These reserve requirements necessitate committing generation resources that are sufficient to meet not only system load but also reserve requirements. Each of these types of operating reserve is further defined below. Contingency reserve is capacity that the Company holds in reserve that can be used to respond to contingency events on the power system, such as an unexpected outage of a generator or a transmission line. Contingency reserve may not be applied to manage other system fluctuations such as changes in load or wind generation output. Therefore, this study focuses on the operating reserve component to manage load and wind generation variations which is incremental to contingency reserve, which is referred to as regulating margin. Regulating margin is the additional capacity that the Company holds in reserve to ensure it has adequate reserve at all times to meet the NERC Control Performance Criteria in BAL-001-2, which requires a BAA to carry regulating reserves incremental to contingency reserves to maintain reliability.30 However, these additional regulating reserves are not defined by a simple formula, but rather are the amount of reserves required by each BAA to meet the control performance standards. NERC standard BAL-001-2, called the Balancing Authority Area Control Error Limit (BAAL), allows a greater ACE during periods when the ACE is helping frequency. However, the Company cannot plan on knowing when the ACE will help or exacerbate frequency so the L10 is used for the bandwidth in both directions of the ACE. 31,32 Thus the Company determines, based on the unique level of wind and load variation in its 29 NERC Standard BAL-002-WECC-2: http://www.nerc.com/files/BAL-002-WECC-2.pdf 30 NERC Standard BAL-001-2:http://www.nerc.com/files/BAL-001-2.pdf 31 The L10 represents a bandwidth of acceptable deviation prescribed by WECC between the net scheduled interchange and the net actual electrical interchange on the Company’s BAAs. Subtracting the L10 credits customers with the natural buffering effect it entails. 32 The L10 of PacifiCorp’s balancing authority areas are 33.41MW for the West and 47.88 MW for the East. For more information, please refer to: http://www.wecc.biz/committees/StandingCommittees/OC/OPS/PWG/Shared%20Documents/Annual%20Frequenc y%20Bias%20Settings/2012%20CPS2%20Bounds%20Report%20Final.pdf PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 106 system, and the prevailing operating conditions, the unique level of incremental operating reserve it must carry. This reserve, or regulating margin, must respond to follow load and wind changes throughout the delivery hour. For this WIS, the Company further segregates regulating margin into two components: ramp reserve and regulation reserve. Ramp Reserve: Both load and wind change from minute-to-minute, hour-to-hour, continuously at all times. This variability requires ready capacity to follow changes in load and wind continuously, through short deviations, at all times. Treating this variability as though it is perfectly known (as though the operator would know exactly what the net balancing area load would be a minute from now, 10-minutes from now, and an hour from now) and allowing just enough generation flexibility on hand to manage it defines the ramp reserve requirement of the system. Regulation Reserve: Changes in load or wind generation which are not considered contingency events, but require resources be set aside to meet the needs created when load or wind generation change unexpectedly. The Company has defined two types of regulation reserve – regulating and following reserves. Regulating reserve are those covering short term variations (moment to moment using automatic generation control) in system load and wind. Following reserves cover uncertainty across an hour when forecast changes unexpectedly. To summarize, regulating margin represents operating reserves the Company holds over and above the mandated contingency reserve requirement to maintain moment-to-moment system balance between load and generation. The regulating margin is the sum of two parts: ramp reserve and regulation reserve. The ramp reserve represents an amount of flexibility required to follow the change in actual net system load (load minus wind generation output) from hour to hour. The regulation reserve represents flexibility maintained to manage intra-hour and hourly forecast errors about the net system load, and consists of four components: load and wind following and load and wind regulating. Determination of Amount and Costs of Regulating Margin Requirements Regulating margin requirements are calculated for each of the Company’s BAAs from production data via a five step process, each described in more detail later in this section. The five steps include: 1. Calculation of the ramp reserve from the historical data (with and without wind generation). 2. Creation of hypothetical forecasts of following and regulating needs from historical load and wind production data. 3. Recording differences, or deviations, between actual wind generation and load values in each 10-minute interval of the study term and the expected generation and load. 4. Group these deviations into bins that can be analyzed for the reserve requirement per forecast value of wind and load, respectively, such that a specified percentage (or tolerance level) of these deviations would be covered by some level of operating reserves. 5. The reserve requirements noted for the various wind and load forecast values are then applied back to the operational data enabling an average reserve requirement to be calculated for any chosen time interval within the Study Term. Once the amount of regulating margin is estimated, the cost of holding the specified reserves on PacifiCorp’s system is estimated using the PaR model. In addition to using PaR for evaluating PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 107 operating reserve cost, the PaR model is also used to estimate the costs associated with daily system balancing activities. These system balancing costs result from the unpredictable nature of load and wind generation on a day-ahead basis and can be characterized as system costs borne from committing generation resources against a forecast of load and wind generation and then dispatching generation resources under actual load and wind conditions as they occur in real time. Regulating Margin Requirements Consistent with the methodology developed in the Company’s 2012 WIS, and the discussion above, regulating margin requirements were derived from actual data on a 10-minute interval basis for both wind generation and load. The ramp reserve represents the minimal amount of flexible system capacity required to follow net load requirements without any error or deviation and with perfect foresight for following changes in load and wind generation from hour to hour. These amounts are as follows:  If system is ramping down: [(Net Area Load Hour H – Net Area Load Hour (H+1))/2]  If system is ramping up: [(Net Area Load Hour (H+1) – Net Area Load Hour H)/2] That is, the ramp reserve is half the absolute value of the difference between the net balancing area load at the top of one hour minus the net balancing load at the top of the prior hour. The ramp reserve for load and wind is calculated using the net load (load minus wind generation output) at the top of each hour. The ramp reserve required for wind is the difference between that for load and that for load and wind. As ramp reserves represent the system flexibility required to follow the system’s requirements without any uncertainty or error, the regulation reserve is necessary to cover uncertainty ever- present in power system operations. Very short-term fluctuations in weather, load patterns, wind generation output and other system conditions cause short term forecasts to change at all times. Therefore, system operators rely on regulation reserve to allow for the unpredictable changes between the time the schedule is made for the next hour and the arrival of the next hour, or the ability to follow net load. Also, these very same sources of instability are present throughout each hour, requiring flexibility to regulate the generation output to the myriad of ups and downs of customer demand, fluctuations in wind generation, and other system disturbances. To assess the regulation reserve requirements for PacifiCorp’s BAAs, the Company compared operational data to hypothetical forecasts as described below. Hypothetical Operational Forecasts Regulation reserve consists of two components: (1) regulating, which is developed using the 10- minute interval data, and (2) following, which is calculated using the same data but estimated on an hourly basis. Load data and wind generation data were applied to estimate reserve requirements for each month in the Study Term. The regulating calculation compares observed 10-minute interval load and wind generation to a 10-minute interval forecast, and following compares observed hourly averages to an average hourly forecast. Therefore, the regulation reserve requirements are composed of four component requirements, which, in turn, depend on differences between actual and expected needs. The four component requirements include: load following, wind following, load regulating, and wind regulating. The determination of these PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 108 reserve requirements began with the development of the expected following and regulating needs (hypothetical forecasts) of the four components, each discussed in turn below. Hypothetical Load Following Operational Forecast PacifiCorp maintains system balance by optimizing its operations to an hour-ahead load forecast every hour with changes in generation and market activity. This planning interval represents hourly changes in generation that are assessed roughly 20 minutes into each hour to meet a bottom-of-the-hour (i.e., 30 minutes after the hour) scheduling deadline. Taking into account the conditions of the present and the expected load and wind generation, PacifiCorp must schedule generation to meet demand with an expectation of how much higher or lower load may be. These activities are carried out by the group referred to as the real-time desk. PacifiCorp's real-time desk updates the load forecast for the upcoming hour 40 minutes prior to the start of that hour. This forecast is created by comparing the load in the current hour to the load of a prior similar-load-shaped day. The hour-to-hour change in load from the similar day and hours (the load difference or “delta”) is applied to the load for the current hour, and the sum is used as the forecast for the upcoming hour. For example, on a given Sunday, the PacifiCorp real-time desk operator may forecast hour-to-hour changes in load by referencing the hour-to- hour changes from the prior Sunday, which would be a similar-load-shaped day. If at 11:20 am, the hour-to-hour load change between 11:00 a.m. and 12:00 p.m. of the prior Sunday was five percent, the operator will use a five percent change from the current hour to be the upcoming hour’s load following forecast. For the calculation in this WIS, the hour-ahead load forecast used for calculating load following was modeled using the approximation described above with a shaping factor calculated using the day from one week prior, and applying a prior Sunday to shape any NERC holiday schedules. The differences observed between the actual hourly load and the load following forecasts comprised the load following deviations. Figure H.2 shows an illustrative example of a load following deviation in August 2013 using operational data from PACE. In this illustration, the delta between hours 11:00 a.m. and 12:00 p.m. from the prior week is applied to the actual load at 11:00 a.m. on the “current day” to produce the hypothetical forecast of the load for the 12:00 p.m. (“upcoming”) hour. That is, using the actual load at 11:00 a.m. (beginning of the purple line), the load forecast for the 12:00 p.m. hour is calculated by following the dashed red line that is parallel to the green line from the prior week. The forecasted load for the upcoming hour is the point on the blue line at 12:00 p.m. Since the actual load for the 12:00 p.m. hour (the point on the purple line at 12:00 p.m.) is higher than the forecast, the deviation (indicated by the black arrow) is calculated as the difference between the forecasted and the actual load for 12:00 p.m. This deviation is used to calculate the load following component reserve requirement for 12:00 p.m. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 109 Figure H.2 – Illustrative Load Following Forecast and Deviation Hypothetical Wind Following Operational Forecast The short term hourly operational wind forecast is based on the concept of persistence – using the instantaneous sample of the wind generation output at 20 minutes into the current hour as the forecast for the upcoming hour, and balancing the system to that forecast. For the calculation in this WIS, the hour-ahead wind generation forecast for the “upcoming” hour used the 20th minute output from the “current” hour. For example, if the wind generation is producing 300 MW at 9:20 p.m. in PACE, then it is assumed that 300 MW will be generated between 10:00 p.m. and 11:00 p.m., that same day. The difference between the hourly average of the six 10-minute wind generation readings and the wind generation forecast comprised the wind following deviation for that hour. Figure H.3 shows an illustrative example of a wind following deviation in July 2013 using operational data from PACE. In this illustration, the wind generation output at 9:20 p.m. (within the “current” hour) is the hour-ahead forecast of the wind generation for the 10:00 p.m. hour (the “upcoming” hour). That is, following persistence scheduling, the wind following need for the 10:00 p.m. hour is calculated by following the dashed red line starting from the actual wind generation on the purple line at 9:20 p.m. for the entire 10:00 p.m. hour (blue line). Since the average of the actual wind generation during the 10:00 p.m. hour (dotted green line) is higher than the wind following forecast, the deviation (indicated by the black arrow) is calculated as the PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 110 difference between the wind following forecast and the actual wind generation for the 10:00 p.m. hour. This deviation is used to calculate the wind following component reserve requirement for 10:00 p.m. Figure H.3 – Illustrative Wind Following Forecast and Deviation Hypothetical Load Regulating Operational Forecast Separate from the variations in the hourly scheduled loads, the 10-minute load variability and uncertainty was analyzed by comparing the 10-minute actual load values to a line of intended schedule, represented by a line interpolated between the actual load at the top of the “current” hour and the hour-ahead forecasted load (the load following hypothetical forecast) at the bottom of the “upcoming” hour. The method approximates the real time operations process for each hour where, at the top of a given hour, the actual load is known, and a forecast for the next hour has been made. For the calculation in this WIS, a line joining the two points represented a ramp up or down expected within the given hour. The actual 10-minute load values were compared to the portion of this straight line from the “current” hour to produce a series of load regulating deviations at each 10-minute interval within the “current” hour. Figure H.4 shows an illustrative example of a load regulating deviation in November 2013 using operational data in PACW. In this illustration, the line of intended schedule is drawn from the actual load at 7:00 a.m. to the hour-ahead load forecast at 8:30 a.m. The portion of this line within the 7:00 a.m. hour becomes the load regulating forecast for that hour. That is, using the forecasted load for the 8:00 a.m. hour that was calculated for the load following hypothetical forecast, the line of intended schedule is calculated by following the dashed red line from the actual load at 7:00 a.m. (beginning of the purple line) to the point in the hour-ahead forecast PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 111 (green line) at 8:30 a.m. The six 10-minute deviations within the 7:00 a.m. hour (one of which is indicated by the black arrow) are the differences between the actual 10-minute load readings (purple line) and the line of intended schedule. These deviations are used to calculate the load regulating component reserve requirement for the six 10-minute intervals within the 7:00 a.m. hour. Figure H.4 – Illustrative Load Regulating Forecast and Deviation Hypothetical Wind Regulating Operational Forecast Similarly, the 10-minute wind generation variability and uncertainty was analyzed by comparing the 10-minute actual wind generation values to a line of intended schedule, represented by a line interpolated between the actual wind generation at the top of the “current” hour and the hour- ahead forecasted wind generation (the wind following hypothetical forecast) at the bottom of the “upcoming” hour. For the calculation in this WIS, a line joining the two points represented a ramp up or down expected within the given hour. The actual 10-minute wind generation values were compared to the portion of this straight line from the “current” hour to produce a series of wind regulating deviations at each 10-minute interval within the “current” hour. Figure H.5 shows an illustrative example of a wind regulating deviation in July 2013 using operational data in PACE. In this illustration, the line of intended schedule is drawn from the actual wind generation at 2:00 p.m. to the hour-ahead wind forecast at 3:30 p.m. The portion of this line within the 2:00 p.m. hour becomes the wind regulating forecast for that hour. That is, using the forecasted wind generation for the 3:00 p.m. hour that was calculated for the wind following hypothetical forecast, the line of intended schedule is calculated by following the dashed red line from the actual wind generation at 2:00 p.m. (beginning of the purple line) to the point in the hour-ahead forecast (green line) at 3:30 p.m. The six 10-minute deviations within the PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 112 2:00 p.m. hour (one of which is indicated by the black arrow) are the differences between the actual 10-minute wind generation readings (purple line) and the line of intended schedule (red line). These deviations are used to calculate the wind regulating component reserve requirement for the six 10-minute intervals within the 2:00 p.m. hour. Figure H.5 – Illustrative Wind Regulating Forecast and Deviation Analysis of Deviations The deviations are calculated for each 10-minute interval in the Study Term and for each of the four components of regulation reserves (load following, wind following, load regulating, wind regulating). Across any given hourly time interval, the six 10-minute intervals within each hour have a common following deviation, but different regulating deviations. For example, considering load deviations only, if the load forecast for a given hour was 150 MW below the actual load realized in that hour, then a load following deviation of -150 MW would be recorded for all six of the 10-minute periods within that hour. However, as the load regulating forecast and the actual load recorded in each 10-minute interval vary, the deviations for load regulating vary. The same holds true for wind following and wind regulating deviations, in that the following deviation is recorded as equal for the hour, and the regulating deviation varies each 10-minute interval. Since the recorded deviations represent the amount of unpredictable variation on the electrical system, the key question becomes how much regulation reserve to hold in order to cover the deviations, thereby maintaining system reliability. The deviations are analyzed by separating the deviations into bins by their characteristic forecasts for each month in the Study Term. The bins are defined by every 5th percentile of recorded forecasts, creating 20 bins for the deviations in each month for each component hypothetical operational forecast. In other words, each month of the Study Term has 20 bins of load following deviations, 20 bins of load regulating deviations, and the same for wind following and wind regulating. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 113 As an example, Table H.6 depicts the calculation of percentiles (every five percent) among the load regulating forecasts for June 2013 using PACE operational data. For the month, the load ranged from 4,521 MW to 8,587 MW. A load regulating forecast for a load at 4,892 MW represents the fifth percentile of the forecasts for that month. Any forecast below that value will be in Bin 20, along with the respective deviations recorded for those time intervals. Any forecast values between 4,892 MW and 5,005 MW will place the deviation for that particular forecast in Bin 19. Table H.6 – Percentiles Dividing the June 2013 East Load Regulating Forecasts into 20 Bins Bin Number Percentile Load Forecast MAX 8,587 1 0.95 7,869 2 0.90 7,475 3 0.85 7,220 4 0.80 6,984 5 0.75 6,807 6 0.70 6,621 7 0.65 6,482 8 0.60 6,383 9 0.55 6,285 10 0.50 6,158 11 0.45 6,023 12 0.40 5,850 13 0.35 5,720 14 0.30 5,568 15 0.25 5,404 16 0.20 5,275 17 0.15 5,134 18 0.10 5,005 19 0.05 4,892 20 MIN 4,521 Table H.7 depicts an example of how the data are assigned into bins based on the level of forecasted load, following the definition of the bins in Table H.6. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 114 Table H.7 – Recorded Interval Load Regulating Forecasts and their Respective Deviations for June 2013 Operational Data from PACE Date / Time Load Regulation Forecast Load Regulation Deviation Bin Assignment 06/01/2013 6:00 4,755 88 20 06/01/2013 6:10 4,706 -67 20 06/01/2013 6:20 4,746 -13 20 06/01/2013 6:30 4,786 -36 20 06/01/2013 6:40 4,826 -26 20 06/01/2013 6:50 4,866 -46 20 06/01/2013 7:00 4,905 -46 19 06/01/2013 7:10 4,984 4 19 06/01/2013 7:20 5,016 -8 18 06/01/2013 7:30 5,048 -10 18 06/01/2013 7:40 5,081 16 18 06/01/2013 7:50 5,113 31 18 06/01/2013 8:00 5,145 12 17 06/01/2013 8:10 5,158 16 17 06/01/2013 8:20 5,182 -22 17 06/01/2013 8:30 5,207 -6 17 06/01/2013 8:40 5,231 4 17 06/01/2013 8:50 5,256 18 17 06/01/2013 9:00 5,280 10 16 06/01/2013 9:10 5,278 -30 16 06/01/2013 9:20 5,287 11 16 06/01/2013 9:30 5,295 2 16 06/01/2013 9:40 5,303 25 16 06/01/2013 9:50 5,311 -4 16 The binned approach prevents over-assignment of reserves in different system states, owing to certain characteristics of load and wind generation. For example, when the balancing area load is near the lowest value for any particular day, it is highly unlikely the load deviation will require substantial down reserves to maintain balance because load will typically drop only so far. Similarly, when the load is near the peak of the load values in a month, it is likely to go only a little higher, but could drop substantially at any time. Similarly for wind, when wind generation output is at the peak value for a system, there will not be a deviation taking the wind value above that peak. In other words, the directional nature of reserve requirements can change greatly by the state of the load or wind output. At high load or wind generation states, there is not likely to be a significant need for reserves covering a surprise increase in those values. Similarly, at the lowest states, there is not likely to be a need for the direction of reserves covering a significant shortfall in load or wind generation. Figure H.6 shows a distribution of deviations gathered in Bin 14 for forecast load levels between 5,569 MW and 5,720 MW in June 2013. All of the deviations fall between -170 MW and +370 MW. Such deviations would need to be met by resources on the system in order to maintain the balance of load and resources. That is, when actual load is 170 MW lower than expected, there needs to be additional resources that are capable of being dispatched down, and when actual load is 370 MW higher than expected, there needs to be additional resources that are capable of being dispatched up to cover the increases in load. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 115 Figure H.6 – Histogram of Deviations Occurring About a June 2013 PACE Load Regulating Forecast between 5,568 MW and 5,720 MW (Bin 14) Up and down deviations must be met by operating reserves. To determine the amount of reserves required for load or wind generation levels in a bin, a tolerance level is applied to exclude deviation outliers. The bin tolerance level represents a percentage of component deviations intended to be covered by the associated component reserve. In the absence of an industry standard which articulates an acceptable level of tolerance, the Company must choose a guideline that provides both cost-effective and adequate reserves. These two criteria work against each other, whereby assigning an overly-stringent tolerance level will lead to unreasonably high wind integration costs, while an overly-lax tolerance level incurs penalties for violating compliance standards. Two relevant standards, CPS1 and BAAL, address the reliability of control area frequency and error. The compliance standard for CPS1 (rolling 12-month average of area frequency) is 100%, while the minimum compliance standard for BAAL is a 30- minute response. Working within these bounds and considering the requirement to maintain adequate, cost-effective reserves, the Company plans to a three-standard deviation (99.7 percent) tolerance in the calculation of component reserves, which are subsequently used to inform the need for regulating margin reserves in operations. In doing so, the Company strikes a balance between planning for as much deviation as allowable while managing costs, uncertainty, adequacy and reliability. Despite exclusion of extreme deviations with the use of the 99.7 percent tolerance, the Company’s system operators are expected to meet reserve requirements without exception. The binned approach is applied on a monthly basis, and results in the four component forecast values (load following, wind following, load regulating, wind regulating) for each 10-minute interval of the Study Period. The component forecasts and reserve requirements are then applied PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 116 back to the operational data to develop summary level information for regulation reserve requirements, using the back casting procedure described below. Back Casting Given the development of component reserve requirements that are dependent upon a given system state, reserve requirements were assigned to each 10-minute interval in the Study Term according to their respective hypothetical operational forecasts to simulate the component reserves values as they would have happened in real-time operations. Doing so results in a total reserve requirement for each interval informed by the data. To perform the back casts, component reserve requirements calculated from the bin analysis described above are first turned into reference tables. Table H.8 shows a sample (June 2013, PACE) reference table for load and wind following reserves at varying levels of forecasted load and wind generation, and Table H.9 shows a sample (June 2013, PACE) reference table for load and wind regulating reserves at varying forecast levels. Table H.8 – Sample Reference Table for East Load and Wind Following Component Reserves (MW) Bin Up Reserve (MW) Load Forecast (MW) Down Reserve (MW) Up Reserve (MW) Wind Forecast (MW) Down Reserve (MW) 266 10000 283 358 5000 157 1 266 7841 283 358 1061 157 2 250 7528 192 348 940 213 3 200 7220 285 512 839 205 4 315 7005 294 298 755 290 5 262 6804 334 356 698 207 6 150 6626 321 198 627 231 7 280 6506 260 239 571 375 8 191 6381 212 332 502 308 9 147 6265 135 238 438 284 10 273 6168 99 195 395 374 11 237 6017 168 163 355 172 12 199 5859 338 166 302 241 13 279 5719 295 115 262 264 14 124 5574 151 114 226 203 15 87 5406 195 101 197 287 16 144 5264 171 84 163 326 17 179 5125 98 90 122 225 18 102 4991 86 44 78 242 19 87 4870 73 35 47 288 20 290 4505 63 41 -7 81 290 0 63 41 -7 81 PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 117 Table H.9 – Sample Reference Table for East Load and Wind Regulating Component Reserves Bin Up Reserve (MW) Load Forecast (MW) Down Reserve (MW) Up Reserve (MW) Wind Forecast (MW) Down Reserve (MW) 177 10000 261 373 10000 173 1 177 7869 261 373 1070 173 2 254 7475 183 459 935 228 3 161 7220 189 297 827 203 4 255 6984 222 277 762 306 5 271 6807 271 393 695 277 6 327 6621 253 233 628 219 7 232 6482 213 305 562 372 8 182 6383 164 279 508 225 9 179 6285 143 177 440 233 10 210 6158 158 172 394 406 11 258 6023 260 131 351 145 12 225 5850 448 134 305 168 13 237 5720 431 144 264 224 14 149 5568 353 112 229 158 15 163 5404 231 85 196 279 16 153 5275 104 74 162 494 17 96 5134 125 76 116 240 18 69 5005 111 44 82 94 19 51 4892 97 38 46 154 20 179 4521 87 21 -7 112 179 0 87 21 -7 112 Each of the relationships recorded in the table is then applied to hypothetical operational forecasts. Building on the reference tables above, the hypothetical operational forecasts described in the previously sections were used to calculate a reserve requirement for each interval of historical operational data. This is clarified in the example outlined below. Application to Component Reserves For each time interval in the Study Term, component forecasts developed from the hypothetical forecasts are used, in conjunction with Table H.8 and Table H.9, to derive a recommended reserve requirement informed by the load and wind generation conditions. This process can be explained with an example using the tables shown above and hypothetical operational forecasts from June 2013 operational data for PACE. Table H.10 illustrates the outcome of the process for the load following and regulating components. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 118 Table H.10 – Load Forecasts and Component Reserve Requirement Data for Hour-ending 11:00 a.m. June 1, 2013 in PACE East Time Actual Load (10-min Avg) MW Actual Load (Hourly Avg) MW Following Forecast Load MW Load Following Up Reserves Specified by Tolerance Level MW Load Following Down Reserves Specified by Toleranc e Level MW Regulating Load Forecast MW Load Regulatin g Up Reserves Specified by Tolerance Level MW Load Regulatin g Down Reserves Specified by Tolerance Level MW 06/01/2013 10:00 5,337 5,395 5,344 144 171 5,319 153 104 06/01/2013 10:10 5,383 5,395 5,344 144 171 5,350 153 104 06/01/2013 10:20 5,386 5,395 5,344 144 171 5,363 153 104 06/01/2013 10:30 5,403 5,395 5,344 144 171 5,375 153 104 06/01/2013 10:40 5,433 5,395 5,344 144 171 5,388 153 104 06/01/2013 10:50 5,428 5,395 5,344 144 171 5,401 153 104 The load following forecast for this particular hour (hour ending 11:00 a.m.) is 5,344 MW, which designates reserve requirements from Bin 16 as depicted (with shading for emphasis) in Table H.8. Because the 5,344 MW load following forecast falls between 5,264 MW and 5,406 MW, the value from the higher bin, 144 MW, as opposed to 87 MW, is assigned for this period. Note the same following forecast is applied to each interval in the hour for the purpose of developing reserve requirements. The first 10 minutes of the hour exhibits a load regulating forecast of 5,319 MW, which designates reserve requirements from Table H.9, Bin 16. Note that the load regulating forecast changes every 10 minutes, and as a result, the load regulating component reserve requirement can change very ten minutes as well-although, this is not observed in the sample data shown above. A similar process is followed for wind reserves using Table H.11. Table H.11 – Interval Wind Forecasts and Component Reserve Requirement Data for Hour-ending 11 a.m. June 1, 2013 in PACE East Time Actual Wind (10- min Avg) Actual Wind (Hourly Avg) Following Forecast Wind: Wind Follow Up Reserves Specified by Tolerance Level Wind Follow Down Reserves Specified by Tolerance Level East Wind Regulating Forecast: Wind Regulating Up Reserves Specified by Tolerance Level: Wind Regulatin g Down Reserves Specified by Tolerance Level: 06/01/2013 10:00 190 217 207 101 287 219 85 279 06/01/2013 10:10 208 217 207 101 287 193 74 494 06/01/2013 10:20 212 217 207 101 287 195 74 494 06/01/2013 10:30 231 217 207 101 287 198 85 279 06/01/2013 10:40 234 217 207 101 287 200 85 279 06/01/2013 10:50 226 217 207 101 287 203 85 279 The wind following forecast for this particular hour (hour ending 11:00 a.m.) is 207 MW, which designates reserve requirements from Bin 15 under wind forecasts as depicted in Table H.8. Note the following forecast is applied to each interval in the hour for developing reserve requirements. Meanwhile, the regulating forecast changes every 10 minutes. The first 10 minutes of the hour PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 119 exhibits a wind regulating forecast of 219 MW, which designates reserve requirements from Bin 15 as depicted in Table H.9. Similar to load, the wind regulating forecast changes every 10 minutes, and as a result, the wind regulating component reserve requirement may do so as well. In this particular case, the second interval’s forecast (193 MW) shifts the wind regulating component reserve requirement from Bin 15 into Bin 16, per Table H.9, and the component reserve requirement changes accordingly. The assignment of component reserves using component hypothetical operational forecasts as described above is replicated for each 10-minute interval for the entire Study Term. The load following reserves, wind following reserves, load regulating reserves, and wind regulating reserves are then combined into following reserves and regulating reserves. Given that the four component reserves are to cover different deviations between actual and forecast values, they are not additive. In addition, as discussed in the Company’s 2012 WIS report, the deviations of load and wind are not correlated.33 Therefore, for each time interval, the wind and load reserve requirements are combined using the root-sum-of-squares (RSS) calculation in each direction (up and down). The combined results are then adjusted as the appropriate system L10 is subtracted and the ramp added to obtain the final result: , where i represents a 10-minute time interval. Assuming the ramp reserve for the east at 10:00 a.m. is 50 MW, and drawing from the first 10-minute interval in the example in Table H.10 and Table H.11. Load Regulatingi = 153 MW Wind Regulatingi = 85 MW Load Followingi = 144 MW Wind Followingi = 101 MW East System L10 = 48 MW East Rampi = 50 MW, The regulating margin for 10:00 a.m. is determined as: 153 85 144 101 48 50 251 In this manner, the component reserve requirements are used to calculate an overall reserve requirement for each 10-minute interval of the Study Term. A similar calculation is also made for the regulating margin pertaining only to the variability and uncertainty of load, while assuming zero reserves for the wind components. The incremental reserves assigned to wind generation are calculated as the difference between the total regulating margin requirement and the load-only regulating margin requirement. 33 The discussion starts on page 111 of Appendix H in Volume II of the Company’s 2012 IRP report: http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/Pacifi Corp-2013IRP_Vol2-Appendices_4-30-13.pdf PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 120 Application of Regulating Margin Reserves in Operations The methodology for estimating regulating margin requirements described above subsequently informs the projected regulating margin needs in operations. PacifiCorp applies the data from the reserve tables, as depicted in Table H.8 and Table H.9, to derive regulating margin requirements within its energy trading system, which is used to manage PacifiCorp’s electricity and natural gas physical positions. As such, the regulating margin requirements derived as part of this wind integration study are used when PacifiCorp schedules system resources to cost effectively and reliably meet customer loads. In operations, scheduling system resources to meet regulating margin requirements ensures that PacifiCorp can meet the BAAL reliability standard. This standard is tied to real-time system frequency, and as this frequency fluctuates, real-time operators use regulating margin reserves to maintain or correct frequency deviations within the allowable 30-minute period, 100% of the time. Determination of Wind Integration Costs Wind integration costs reflect production costs associated with additional reserve requirements to integrate wind in order to maintain reliability of the system, and additional costs incurred with daily system balancing that is influenced by the unpredictable nature of wind generation on a day-ahead basis. To characterize how wind generation affects regulating margin costs and system balancing costs, PacifiCorp utilizes the Planning and Risk (PaR) model and applies the regulating margin requirements calculated by the method detailed in the section above. The PaR model simulates production costs of a system by committing and dispatching resources to meet system load. For this study, PacifiCorp developed seven different PaR simulations. These simulations isolate wind integration costs associated with regulating margin reserves and system balancing practice. The former reflects wind integration costs that arise from short-term variability (within the hour and hour ahead) in wind generation and the latter reflects integration costs that arise from errors in forecasting wind generation on a day-ahead basis. The seven PaR simulations used in the WIS are summarized in Table H.12. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 121 Table H.12 – Wind Integration Cost Simulations in PaR The first two simulations are used to determine operating reserve wind integration costs in forward planning timeframes. The approach uses “P50”, or expected, wind generation profiles and forecasted loads that are applicable to 2015. 34 Simulation 1 includes only the load regulating margin reserves. Simulation 2 includes regulating margin reserves for both load and wind, while keeping other inputs unchanged. The difference in production costs between the two simulations determines the cost of additional reserves to integrate wind, or the intra-hour wind integration cost. The remaining five simulations support the calculation of system balancing costs related to committing resources based on day-ahead forecasted wind generation and load. These simulations were run assuming operation in the 2015 calendar year, applying 2013 load and wind data. This calculation method combines the benefits of using actual system data with current forward price curves pertinent to calculating the costs for wind integration service on a forward basis, as well as the current resource portfolio.35 PacifiCorp resources used in the simulations are based upon the 2013 IRP Update resource portfolio.36 Determining system balancing costs requires a comparison between production costs with day- ahead information as inputs and production costs with actual information as inputs. 2013 was the most recent year with the availability of these two types of data. Day-ahead wind generation forecasts for all owned and contracted wind resources were collected from the Company’s wind forecast service provider, DNV GL.37 For 2012 and 2013, DNV GL provided data sets for the historical day-ahead wind forecasts. The day-ahead load forecast was provided by the 34 P50 signifies the probability exceedance level for the annual wind production forecast; at P50 generation is expected to exceed the assumed generation levels half the time and to fall below the assumed generation levels half the time. 35 The Study uses the December 31, 2013 official forward price curve (OFPC). 36 The 2013 Integrated Resource Update report, filed with the state utility commissions on March 31, 2014 is available for download from PacifiCorp’s IRP Web page using the following hyperlink: http://www.pacificorp.com/es/irp.html 37 This is the same service provider as used by the Company previously, Garrad Hassan. Garrad Hassan is now part of DNV GL. PaR Model Simulation Forward Term Load Wind Profile Incremental Reserve Da -ahead Forecast Error Comments Regulating Margin Reserve Cost Runs 1 2015 2015 Load Forecast Expected Profile Load None 2 2015 2015 Load Forecast Expected Profile Load and Wind None Regulating Margin Cost = System Cost from PaR Simulation 2 less System Cost from PaR Simulation 1 System Balancing Cost Runs 3 2015 2013 Day-ahead Forecast 2013 Day-ahead Forecast Yes None Commit units based on day-ahead load forecast, and day-ahead wind forecast 4 2015 2013 Actual 2013 Actual Yes For Load and Wind Apply commitment from Simulation 3 5 2015 2013 Actual 2013 Day-ahead Forecast Yes None Commit units based on actual Load, and day-ahead wind forecast 6 2015 2013 Actual 2013 Actual Yes For Wind Apply commitment from Simulation 5 7 2015 2013 Actual 2013 Actual Yes None Commit units based on actual Load, and actual wind forecast Load System Balancing Cost = System Cost from PaR Simulation 4, which uses the unit commitment from Simulation 3 based on day-ahead forecast load (and day-ahead wind) less System Cost from PaR Simulation 6, which uses the unit commitement from Simulation 5 based on actual load (and day-ahead wind) Wind System Balancing Cost = System Cost from PaR Simulation 6, which uses the unit commitment from Simulation 5 based on day-ahdead wind (and actual load) less System Cost from PaR Simulation 7, which commits units based on actual wind (and actual load) PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 122 Company’s load forecasting department. There are five PaR simulations to estimate daily system balancing wind integration costs, labeled as Simulations 3 through 7. In this phase of the analysis, PacifiCorp generation assets were committed consistent with a day-ahead forecast of wind and load, but dispatched against actual wind and load. To simulate this operational behavior, the five additional PaR simulations included the incremental reserves from Simulation 2 and the unit commitment states associated with simulating the portfolio with the day-ahead forecasts. Load system balancing costs capture the difference between committing resources based on a day-ahead load forecast and committing resources based on actual load, while keeping inputs for wind generation unchanged. Similarly, wind system balancing costs capture the difference between committing resources based on day-ahead wind generation forecasts and committing resources based on actual wind generation, while keeping inputs for load unchanged. Simulation 3 determines the resource commitment for load system balancing and Simulation 5 determines the resource commitment for wind system balancing. The difference in production costs between Simulations 4 and 6 is the load system balancing cost due to committing resources using imperfect foresight on load. The difference in production cost between Simulations 6 and 7 is the wind system balancing cost due to committing resources using imperfect foresight on wind generation. Table H.12 above is a revision from what was presented in the 2012 WIS. The revision was made to remove the impact of volume changes between day-ahead forecasts and actuals on production costs. Table H.13 lists the simulations performed in the 2012 WIS, which shows that wind system balancing costs were determined based on the change in production costs between Simulation 5 and Simulation 4. The wind system balancing costs are captured by committing resources based on a day-ahead forecast of wind generation, while operating the resources based on actual wind generation. However, between Simulation 4 and Simulation 5, the volume of wind generation is different. As a result, the production cost of Simulation 5 is impacted by changes in wind generation. Using the approach adopted in the 2014 WIS as discussed above isolates system balancing integration costs to changes unit commitment. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 123 Table H.13 – Wind Integration Cost Simulations in PaR, 2012 WIS Also different from the 2012 WIS, the regulating margin reserves are input to the PaR model on an hourly basis, after being reduced for the estimated benefits of participating in the EIM, as discussed in more detail below. Table H.14 shows the intra-hour and inter-hour wind integration costs from the 2014 WIS. Table H.14 – 2014 Wind Integration Costs, $/MWh 2014 WIS (2015$) Intra-hour Reserve $2.35 Inter-hour/System Balancing $0.71 Total Wind Integration $3.06 In the 2015 IRP process, the System Optimizer (SO) model uses the 2014 WIS results to develop a cost for wind generation services. Once candidate resource portfolios are developed using the SO model, the PaR model is used to evaluate the risk profiles of the portfolios in meeting load obligations, including incremental operating reserve needs. Therefore, when performing IRP risk analysis using PaR, specific operating reserve requirements consistent with this wind study are used. Sensitivity Studies The Company performed several sensitivity scenarios to address recommendations from the TRC in its review of PacifiCorp’s 2012 WIS. Each is discussed in turn below. Modeling Regulating Margin on a Monthly Basis As shown in Table H.10 and Table H.11, the component reserves and the total reserves are determined on a 10-minute interval basis. In the 2012 WIS, PacifiCorp calculated reserve requirements on a monthly basis by averaging the data for all 10-minute intervals in a month and PaR Model Simulation Forward Term Load Wind Profile Incremental Reserve Da -ahead Forecast Error Regulating Margin Reserve Cost Runs 1 2015 2015 Load Forecast Expected Profile No None 2 2015 2015 Load Forecast Expected Profile Yes None Regulating Margin Cost = System Cost from PaR Simulation 2 less System Cost from PaR Simulation 1 System Balancing Cost Runs 3 2015 2013 Day-ahead Forecast 2013 Day-ahead Forecast Yes None 4 2015 2013 Actual 2013 Day-ahead Forecast Yes For Load 5 2015 2013 Actual 2013 Actual Yes For Load and Wind Load System Balancing Cost = System Cost from PaR simulation 4 (which uses the unit commitment from Simulation 3) less system cost from PaR simulation 3 Wind System Balancing Cost = System Cost from PaR simulation 5 (which uses the unit commitment from Simulation 4) less system cost from PaR simulation 4 PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 124 applying these monthly reserve requirements in PaR as a constant requirement in all hours during a month. The TRC recommended that the reserve requirements could be modeled on an hourly basis to reflect the timing differences of reserves. In calculating wind integration costs for the 2014 WIS, the PacifiCorp modeled hourly reserve requirements as recommended by the TRC. Table H.15 compares wind integration costs from the 2012 WIS with wind integration costs from the 2014 WIS calculated using both monthly and hourly reserve requirements as inputs to the PaR model. Table H.15 – Comparison of Wind Integration Costs Calculated Using Monthly and Hourly Reserve Requirements as Inputs to PaR, ($/MWh) 2012 WIS Monthly Reserves (2012$) 2014 WIS Hourly Reserves (2015$) 2014 WIS Monthly Reserves (2015$) Intra-hour Reserve $2.19 $2.35 $1.66 Inter-hour/System Balancing $0.36 $0.71 $0.74 Total Wind Integration $2.55 $3.06 $2.40 Compared to the 2012 WIS intra-hour reserve cost, the 2014 WIS intra-hour reserve cost is lower when reserves are modeled on a monthly basis in PaR. This is primarily due to the addition of a the Lake Side 2 combined-cycle plant, which can be used to cost effectively meet regulating margin requirements. Without Lake Side 2, the intra-hour reserve costs for the 2014 WIS Monthly Reserve sensitivity would increase from $1.66/MWh to $2.65/MWh. As compared to the 2012 WIS, which reported wind integration costs using monthly reserve data, the increase in cost is primarily due to increases in the market price for electricity and natural gas. Table H.16 compares the natural gas and electricity price assumptions used in the 2012 WIS to those used in the 2014 WIS. Table H.16 – Average Natural Gas and Electricity Prices Used in the 2012 and 2014 Wind Integration Studies Study Palo Verde High Load Hour Power ($/MWh) Palo Verde Low Load Hour Power ($/MWh) Opal Natural Gas ($/MMBtu) 2012 WIS $37.05 $25.74 $3.43 2014 WIS $39.13 $29.31 $3.88 When modeling reserves on an hourly basis in PaR, the intra-hour reserve cost is higher than when modeling reserves on a monthly basis. This is due to more reserves being shifted from relatively lower-priced hours to relatively higher-priced hours. Figure H.7 shows the average profiles of wind regulating margin reserves from 2013. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 125 Figure H.7 – Average Hourly Wind Reserves for 2013, MW Separating Regulating and Following Reserves In its review of the 2012 WIS, the TRC recommended treating categories of reserves differently by separating the component reserves of regulating, following and ramping. That is, instead of modeling regulating margin as: , The TRC recommendation requires calculating regulating reserves and following reserves using two separate calculations: , . Because regulating reserves are more restrictive than following reserves (fewer units can be used to meet regulating reserve requirements), the L10 adjustment is applied to the regulating reserve calculation. Ramp reserves can be met with similar types of resources as following reserves, and therefore, are combined with following reserves. The impact of separating the component reserves as outlined above is to increase the total reserve requirement required on PacifiCorp’s system. Table H.17 shows the total reserve requirement when the separately calculated regulating and following reserves are summed as compared to the total reserves combined using one RSS equation. The total reserve requirement, 0 20 40 60 80 100 120 140 160 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 MW Hour East West PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 126 when calculated separately, is over 30% higher than the reserve requirement calculated from a single RSS equation. This is a significant increase in the amount of regulation reserves that is inconsistent with how the Company’s resources are operated and dispatched. As a result, PacifiCorp did not evaluate this sensitivity in PaR. Table H.17 – Total Load and Wind Monthly Reserves, Separating Regulating and Following Reserves (MW) Combined Regulating Following Total West East West East West East West East Jan 238 400 107 196 211 354 318 550 Feb 212 363 100 182 187 318 287 500 Mar 219 357 97 179 202 313 299 492 Apr 240 422 123 224 208 362 331 586 May 192 400 84 205 180 348 264 553 Jun 183 462 70 240 179 393 249 633 Jul 219 427 88 180 206 391 294 572 Aug 220 428 90 188 206 388 296 576 Sep 210 392 100 171 188 361 287 533 Oct 153 335 75 159 131 301 206 461 Nov 301 438 165 228 249 375 414 603 Dec 274 433 122 216 251 375 373 592 Energy Imbalance Market (EIM) EIM is an energy balancing market that optimizes generator dispatch between PacifiCorp and the CAISO every five minutes via the existing real-time dispatch market functionality. PacifiCorp and the CAISO began a phased implementation of the EIM on October 1, 2014, when EIM was activated to allow the systems that will operate the market to interact under realistic conditions, allowing PacifiCorp to submit load schedules and bid resources into the EIM and allowing the CAISO to use its automated system to generate dispatch signals for resources on PacifiCorp’s control areas. The EIM is expected to be fully operational November 1, 2014. Once EIM becomes fully operational, PacifiCorp must provide sufficient flexible reserve capacity to ensure it is not leaning on other participating balancing authorities in the EIM for reserves. The intent of the EIM is that each participant in the market has sufficient capacity to meet its needs absent the EIM, net of a CAISO calculated reserves diversity benefit. In this manner, PacifiCorp must hold the same amount of regulating reserve under the EIM as it did prior to the EIM, but for a calculated diversity benefit.38 Figure H.8 illustrates this process. 38 Under the EIM, base schedules are due 75 minutes prior to the hour of delivery. The base schedules can be adjusted at 55 minutes and 40 minutes prior to the delivery hour in response to CAISO sufficiency tests. This is consistent with pre-EIM scheduling practices, in which schedules are set 40 minutes prior to the delivery hour. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 127 Figure H.8 – Energy Imbalance Market The CAISO will calculate the diversity benefit by first calculating the reserve requirement for each individual EIM participant and then by comparing the sum of those requirements to the reserve requirement for the entire EIM area. The latter amount is expected to be less than the sum due to the portfolio diversification effect of load and variable energy resource (wind and solar) variations. The CAISO will then allocate the diversity benefit among all the EIM participants. Finally, PacifiCorp will reduce its regulating reserve requirement by its allocation of diversity benefit. In its 2013 report, Energy and Environmental Economics (E3) estimated the following benefits of the EIM system implementation:39 - PacifiCorp could see a 19 to 103 MW reduction in regulating reserves, depending on the level of bi-directional transmission intertie made available to EIM; - Interregional dispatch savings: Five-minute dispatch efficiency will reduce “transactional friction” (e.g., transmission charges) and alleviate structural impediments currently preventing trade between the two systems; - Intraregional dispatch savings: PacifiCorp generators will dispatch more efficiently through the CAISO’s automated system (nodal dispatch software), including benefits from more efficient transmission utilization; - Reduced flexibility reserves by aggregating the two systems’ load, wind, and solar variability and forecast errors; - Reduced renewable energy curtailment by allowing BAAs to export or reduce imports of renewable generation when it would otherwise need to be curtailed. Based on the E3 study, the relationship between the benefit in reducing regulating reserve requirements and the transfer capability of the intertie is shown in Table H.18. 39 http://www.caiso.com/Documents/PacifiCorp-ISOEnergyImbalanceMarketBenefits.pdf PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 128 Table H.18 – Estimated Reduction in PacifiCorp’s Regulating Margin Due to EIM Transfer Capability (MW) Reduction in Flexible Reserves (MW) 100 19 400 78 800 103 Given that the transfer capacity in this WIS is assumed to be approximately 330 MW, through owned and contracted rights, the reduction in regulating reserve is assumed to be approximately 65 MW. This benefit is applied to reduce the regulating margin on PacifiCorp’s west BAA because the current connection between PacifiCorp and CAISO is limited to the west only. Table H.19 summarizes the impact of estimated EIM regulating reserve benefits assuming monthly application of reserves in PaR to be comparable to how the 2012 WIS wind integration costs were calculated. The sensitivity shows that EIM regulating reserve benefits reduce wind integration costs by approximately $0.21/MWh. Table H.19 – Wind Integration Cost with and without EIM Benefit, $/MWh 2012 WIS (2012$) 2014 WIS With EIM Benefits (2015$) 2014 WIS Without EIM Benefits (2015$) Intra-hour Reserve Cost $2.19 $1.66 $1.87 Inter-hour/System Balancing Cost $0.36 $0.74 $0.74 Total Wind Integration Cost $2.55 $2.40 $2.61 Summary The 2014 WIS determines the additional reserve requirement, which is incremental to the mandated contingency reserve requirement, needed to maintain moment-to-moment system balancing between load and generation while integrating wind resources into PacifiCorp’s system. The 2014 WIS also estimates the cost of holding these incremental reserves on its system. PacifiCorp implemented the same methodology developed in the 2012 WIS for calculating regulating reserves for its 2014 WIS, and implemented recommendations from the TRC to implement hourly reserve inputs when determining wind integration costs using PaR. Also consistent with TRC recommendations, PacifiCorp further incorporated regulation reserve benefits associated with EIM in its wind integration costs. Table H.20 compares the results of the 2014 WIS total reserves to those calculated in the 2012 WIS. PACIFICORP – 2015 IRP APPENDIX H – WIND INTEGRATION 129 Table H.20 – Regulating Margin Requirements Calculated for PacifiCorp’s System (MW) Year Reserve Component West BAA East BAA Ramp Combined 2011 (2012 WIS) Load-Only Regulating Reserves 99 176 119 394 Incremental Wind Reserves 50 126 9 185 Total Reserves 149 302 128 579 2012 Load-Only Regulating Reserves 95 186 119 400 Incremental Wind Reserves 71 123 11 206 Total Reserves 166 309 130 606 2013 (2013 WIS) Load-Only Regulating Reserves 119 203 119 441 Incremental Wind Reserves 51 123 12 186 Total Reserves 169 326 131 626 The anticipated implementation of EIM with the CAISO is expected to reduce PacifiCorp’s reserve requirements due to the diversification of resource portfolios between the two entities. PacifiCorp estimated the benefit of EIM regulating reserve benefits based on a study from E3. The assumed benefits reduce regulating reserves in PacifiCorp’s west BAA by approximately 65 MW from the regulating reserves shown in the table above, which lowers wind integration costs by approximately $0.21/MWh. Two categories of wind integration costs are estimated using the Planning and Risk (PaR) model: one for meeting intra-hour reserve requirements, and one for inter-hour system balancing. Table H.21 compares 2014 wind integration costs, inclusive of estimated EIM benefits, to those published in the 2012 WIS. Table H.21 – 2014 WIS Wind Integration Costs as Compared to 2012 WIS, $/MWh 2012 WIS (2012$) 2014 WIS (2015$) Intra-hour Reserve $2.19 $2.35 Inter-hour/System Balancing $0.36 $0.71 Total Wind Integration $2.55 $3.06 The 2014 WIS results are applied to the 2015 IRP portfolio development process as a cost for wind generation resources. Once candidate resource portfolios are developed using the SO model, the PaR model is used to evaluate portfolio risks. After resource portfolios are developed using the SO model, the PaR model is used to evaluate the risk profiles of the portfolios in meeting load obligations, including incremental operating reserve needs. Therefore, when performing IRP risk analysis using PaR, specific operating reserve requirements consistent with the 2014 WIS are used. Date: December 22, 2014 To: PacifiCorp From: 2014 Wind Integration Study Technical Review Committee (TRC) Subject: PacifiCorp 2014 Wind Integration Study Technical Memo Background The purpose of the PacifiCorp 2012 wind integration study as identified by Pacificorp in the Introduction to the 2015 IRP, Appendix H – Draft Wind Integration Study, is to estimate the operating reserves required to both maintain PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation (NERC) reliability standards. PacifiCorp must provide sufficient operating reserves to meet NERC’s balancing authority area control error limit (BAL-001-2) at all times, incremental to contingency reserves, which PacifiCorp maintains to comply with NERC standard BAL-002-WECC-2.1, Apart from disturbance events that are addressed through contingency reserves, these incremental operating reserves are necessary to maintain area control error3 (ACE), due to sources outside direct operator control including intra-hour changes in load demand and wind generation, within required parameters. The wind integration study estimates the operating reserve volume required to manage load and wind generation variation in PacifiCorp’s Balancing Authority Areas (BAAs) and estimates the incremental cost of these operating reserves. PacifiCorp currently serves 1.8 million customers across 136,000 square miles in six western states. According to a company fact sheet available at http://www.pacificorp.com/content/dam/pacificorp/doc/About_Us/Company_Overview/PC-FactSheet- Final_Web.pdf, PacifiCorp’s generating plants have a net capacity of 10,595 MW, including about 1,900 1 NERC Standard BAL-001-2: http://www.nerc.com/files/BAL-001-2.pdf 2 NERC Standard BAL-002-WECC-2 (http://www.nerc.com/files/BAL-002-WECC-2.pdf), which became effective October 1, 2014, replaced NERC Standard BAL-STD-002, which was in effect at the time of this study. 3 “Area Control Error” is defined in the NERC glossary here: http://www.nerc.com/pa/stand/glossary of terms/glossary_of_terms.pdf MW of owned and contracted wind capacity, which provides approximately 8% of PacifiCorp’s annual energy. PacifiCorp operates two BAAs in WECC, referenced as PACE (PacifiCorp East) and PACW (PacifiCorp West). The BAAs are interconnected by a limited amount of transmission, and the two BAAs are operated independently at the present time, so wind generation in each BAA is balanced independently.4 PacifiCorp has experienced continued wind growth in each BAA, and has been requested to update its wind integration study as part of its IRP. The total amount of wind capacity in PacifiCorp’s BAAs, which was included in the 2014 wind integration study, was 2,544 MW. TRC Process The Utility Variable-Generation Integration Group (UVIG) has encouraged the formation of a Technical Review Committee (TRC) to offer constructive input and feedback on wind integration studies conducted by industry partners for over 10 years. The TRC is generally formed from a group of people who have some knowledge and expertise in these types of studies, can bring insights gained in previous work, have an interest in seeing the studies conducted using the best available data and methods, and who will stay actively engaged throughout the process. Over time, the UVIG has developed a set of principles which is used to guide the work of the TRC. A modified version of these principles was used in the conduct of this study, and the same version was used for the conduct of the TRC process for the 2012 wind integration study. A copy is included as an attachment to this memo. The composition of the TRC for the 2014 PacifiCorp study was as follows:  Andrea Coon - Director, Western Renewable Energy Generation Information System (WREGIS) for the Western Electricity Coordinating Council (WECC)  Matt Hunsaker - Manager, Operations for the Western Electricity Coordinating Council (WECC)  Michael Milligan – Principal Researcher for the Transmission and Grid Integration Team at the National Renewable Energy Laboratory (NREL)  J. Charles Smith - Executive Director, Utility Variable-Generation Integration Group (UVIG)  Robert Zavadil - Executive Vice President of Power Systems Consulting, EnerNex The TRC was provided with a study presentation in July of 2014, and met by teleconference on 2 occasions during the course of the study, which was completed in November 2014. PacifiCorp provided presentations on the status and results of the work on the teleconferences, with periodic updates 4 PacifiCorp and the CAISO began operating an energy imbalance market (EIM) on Oct. 1, 2014, which will likely make wind integration somewhat easier. With the EIM, there would seem to be more impetus for this policy to be reviewed and potentially revised going forward. The TRC recommends that this topic be explored in future work. during the course of the study, and engaged with the TRC in a robust discussion throughout the work. The teleconferences were followed up with further clarifications and responses to requests for additional information. While the conclusions appear justified by the results of the study, the TRC review should not be interpreted as a substitute for the usual PUC review process. Introduction The Company should be acknowledged for the diligent efforts it made in implementing the recommendations by the TRC from the 2012 wind integration study in the 2014 study, as summarized in Table H.1. For example, the company modeled the reserve requirements on an hourly basis in the production cost model, rather than on a monthly average basis; the regulating margin reserve volumes accounted for estimated benefits from PacifiCorp’s participation in the energy imbalance market (EIM) with the California Independent System Operator (CAISO); and a discussion on the selection of a 99.7% exceedance level when calculating regulation reserve needs was provided, including a description of how the WIS results inform the amount of regulation reserves planned for operations. Sensitivity studies were performed, including the modeling of the regulating reserves on a monthly basis, and demonstrating the impact of separating the reserves into different categories. The 2014 wind integration study report thoroughly documents the company’s analysis. As pointed out in the report, there is a small but meaningful difference in the integration costs between the 2012 study and the 2014 study. The 2012 value of $2.55/MWh of wind generation, using monthly reserves in PaR, is slightly less than the 2014 value of $3.06/MWh, using hourly reserves in the Planning and Risk (PaR) production cost model, with the major difference attributed to the modest increase in the cost of electricity and natural gas. When modeling reserves on an hourly basis in PaR, the intra-hour reserve cost is higher than when modeling reserves on a monthly basis. This is due to more reserves being shifted from relatively lower-priced hours to relatively higher-priced hours. Analytical Methodology  The first paragraph on p. 24 of the revised Appendix H, entitled "Application of Regulating Margin Reserves in Operations" is a critical aspect of this study, albeit a little late to the interactions between Pacificorp and the TRC. In effect, it means that the results of this study are and have been applied in operations, which is very unique in the universe of wind integration analysis since nearly all other studies are forward looking and utilize synthesized data and other assumptions. While this paragraph sufficiently addresses the points raised by the TRC in the late summer of 2014, it should receive more prominence in the report. A comparison of the interaction between the 2012 study methodology and PacifiCorp operations with the 2014 study methodology and Pacificorp operations should be included at the front of the document. Assumptions  The assumptions generally seem reasonable. PAC does a good job of laying out the process they use for the modeling and analysis. They have also provided discussion of the previous suggestions (from the 2012) study made by the TRC.  The report addresses the issue of the 99.7% coverage of variability, and says that the operators are expected to have sufficient reserves to cover all variability all of the time. It would be interesting to contrast the company’s policy of ensuring 100% reserve compliance with actual system performance. In the November TRC call there was some helpful discussion on this issue. One item discussed was that using 99.7% provides some margin of error in case a lower value, such as 95%, is used in the study but insufficient if the actual variability of wind/load were to increase. It would be nice to see this discussion reflected in the report, which would provide some additional justification for the 99.7 percentile. The reason this point is raised is to magnify the point that PAC makes in the report; that there is a tradeoff between economics and reliability. Holding the system to an extremely high effective CPS performance will be somewhat costly, and it is not clear what impact this is having on wind integration costs.  The use of actual historical wind production data is excellent, and something that many studies are unable to do. This means that the PAC study is somewhat unique and PAC is to be commended for doing this work. At the same time, the report provides some illumination on the difficulties in using actual data, because data recovery rates can compromise the time series. PAC has done a good job in analyzing and correcting these inevitable data gaps, and this should not have a significant impact on the study results. Results  Table H.15 documents a comparison of the monthly versus hourly reserve modeling, and shows that a constant monthly reserve is less costly than reserves modeled on an hourly basis. The explanation provided is useful, but may leave out some factors such as non-linearity in reserve supply curve. In addition, the shifting of reserves from lower price hours to higher price hours only seems to apply to the East area, as the West area exhibits the opposite characteristic. Discussion and Conclusions  Table H.17 shows that the total reserves increase with consideration of regulation and following separately. It should be noted that while the arithmetic sum of the reserves does increase, it would not necessarily lead to higher costs as some of the following reserve could be obtained from non-spinning and quick-start resources which cost little to have on standby for such purpose.  Based on the information provided by PacifiCorp, the methodology used in the wind integration study appears to be reasonable. Based on the draft study report, the findings and conclusions appear sound. The findings appear to be useful to inform the Integrated Resource Planning process. Recommendations for Future Work Wind Integration modeling presented is unique in how it is integrated with the operating process at PacifiCorp. There are some sensitivity studies which could be done to shed additional light on the results and provide some useful insights:  Future work should explore balancing area cooperation between PACE and PACW under the EIM framework.  Regulating margin implies reserve capacity available on very short notice (ten minute or less). The ramping and following reserve categories do not all require fast response. Future sensitivity studies could be done to compare the results from PaR to use of the RSS formula.  It might be useful to perform some additional sensitivities on natural gas price. For example, integration costs would be expected to increase with gas prices, yet at higher gas prices PAC would be getting a larger benefit from wind energy.  A sensitivity analysis with carbon tax assumptions could also provide some useful insight and results. Concurrence provided by: Andrea Coon – Director of WREGIS, WECC Matt Hunsaker - Manager, Operations, WECC Michael Milligan - Principal Researcher, Transmission and Grid Integration Team, NREL J. Charles Smith - Executive Director, UVIG Robert Zavadil - Executive Vice President, EnerNex PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 135 APPENDIX I – PLANNING RESERVE MARGIN STUDY Introduction The planning reserve margin (PRM), measured as a percentage of coincident system peak load, is a parameter used in resource planning to ensure there are adequate resources to meet forecasted load over time. PacifiCorp selects a PRM for use in its resource planning by studying the relationship between cost and reliability among ten different PRM levels, accounting for variability and uncertainty in load and generation resources.40 Costs include capital and run-rate fixed costs for new resources required to achieve ten different PRM levels, ranging from 11 percent to 20 percent, along with system production costs (fuel and non-fuel variable operating costs, contract costs, and market purchases). In analyzing reliability, PacifiCorp performed a stochastic loss of load study using the Planning and Risk (PaR) production cost simulation model to calculate the following reliability metrics for each PRM level:  Expected Unserved Energy (EUE): Measured in gigawatt-hours (GWh), EUE reports the expected (mean) amount of load that exceeds available resources over the course of a given year. EUE measures the magnitude of reliability events, but does not measure frequency or duration.  Loss of Load Hours (LOLH): LOLH is a count of the expected (mean) number of hours in which load exceeds available resources over the course of a given year. A LOLH of 2.4 hours per year equates to one day in 10 years, a common reliability target in the industry. LOLH measures the duration of reliability events, but does not measure frequency or magnitude.  Loss of Load Events (LOLE): LOLE is a count of the expected (mean) number of reliability events over the course of a given year. A LOLE of 0.1 events per year equates to one event in 10 years, a common reliability target in the industry. LOLE measures the frequency of reliability events, but does not measure magnitude or duration. PacifiCorp’s loss of load study results reflect its participation in the Northwest Power Pool (NWPP) reserve sharing agreement. This agreement allows a participant to receive energy from other participants within the first hour of a contingency event, defined as an event when there is an unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch, or other electrical element. PacifiCorp’s participation in the NWPP reserve sharing agreement improves reliability at a given PRM level. Upon evaluating the relationship between cost and reliability in its PRM study, PacifiCorp will continue to use a 13 percent target PRM in its resource planning. Methodology Figure I.1 shows the workflow used in PacifiCorp’s PRM study. The four basic modeling steps in the workflow include: (1) using the System Optimizer (SO) model, produce resource portfolios among eleven different PRM levels ranging between 10 percent and 20 percent; (2) using the Planning and Risk model (PaR), produce reliability metrics for each resource portfolio; 40 Costs and reliability metrics are calculated for eleven different PRM levels, ranging from 10 percent to 20 percent. Comparative analysis among each PRM is performed for 10 different PRM levels by comparing the cost and reliability results from PRM levels ranging between 11 percent and 20 percent to those from the 10 percent PRM. PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 136 (3) using PaR, produce system variable costs for each resource portfolio; (4) calculate the incremental cost of reliability among PRM levels analyzed. Figure I.1 – Workflow for Planning Reserve Margin Study Development of Resource Portfolios The SO model is used to produce resource portoflios assuming PRM levels ranging between 10 percent and 20 percent. The SO model optimizes expansion resources over a 20-year planning horizon to meet peak load inclusive of the PRM applicable to each case. As the PRM level is increased from 10 percent to 20 percent, additional resources are added to the portfolio. Resource options used in this step of the workflow include demand side management (DSM), gas-fired combined cycle combustion turbines (CCCT), and gas-fired simple cycle combustion turbines (SCCT). Front office transactions (FOTs) are not considered as a resource expansion option in this phase of the workflow. FOTs are proxy resources used in the IRP portfolio development process that represent firm forward short-term market purchases for summer on-peak delivery, which coincides with the time of year and time of day in which PacifiCorp observes its coincident system peak load. These proxy resources are a reasonable representation of firm market purchases when performing comparative analysis of different resource portfolios to arrive at a System Optimizer Model PaR Production Costs PaR Reliability Incremental Cost of Reliability PRM PRM Stochastic Parameters for Load and Generation Stochastic Parameters for Load, Generation, Market Prices Resource Portfolios (Expansion Resources) Reliability Metrics Production Costs Capital & Run-rate Fixed Costs PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 137 preferred portfolio in the IRP. However, given the seasonal and intra-day pattern of these proxy resource options, they are not as well suited for a loss of load study that evaluates reliability metrics across all hours in a given year. The contribution of firm market purchases to reliability, up to transmission and market depth limits that are identical for all scenarios, are accounted for in the loss of load study by allowing system balancing hourly purchases in the subsequent workflow step where reliability metrics are produced using PaR. Upfront capital and run-rate fixed costs from each portfolio are recorded and used later in the workflow where the relationship between cost and reliability is analyzd. Resources from each portfolio are used in the subsequent workflow steps where reliability metrics and production costs are produced in PaR. Development of Reliability Metrics PaR is used to produce reliability metrics for each of the resource portfolios developed assuming PRM levels ranging between 10 percent and 20 percent. PaR is a production cost simulation model, configured to represent PacifiCorp’s integrated system, that uses Monte Carlo random sampling of stochastic variables to produce a distribution of system operation. For this step in the workflow, reliability metrics are produced from a 500-iteration PaR simulation with Monte Carlow draws of stochastic variables that affect system reliability—load, hydro generation, and thermal unit outages. As discussed above, system balancing hourly purchases are enabled to capture the contribution of firm market purchases to system reliability. The PaR reliability studies are used to report instances where load exceeds available resources, including system balancing hourly purchases. Reported EUE measures the stochastic mean volume of instances where load exceeds available resources, and is mesasured in GWh. EUE measures the magnitude of reliability events. Reported LOLH is a count of the stochastic mean hours in which load exceeds available resources. LOLH measures the duration of reliability events. Reported LOLE is a count of the stochastic mean events in which load exceeds available resources. LOLE is a measure of the frequency of reliability events. Each of the reliability metrics described above is adjusted to account for PacifiCorp’s participation in the NWPP reserve sharing agreement, which allows a participant to receive energy from other participants within the first hour of a contingency event. The NWPP adjustments are made to EUE by reducing the stochastic mean volume of instances where load exceeds available resources for the first hour of a reliability event. For example, if the stochastic mean volume of EUE for a reliability event is 120 MWh, equal to 40 MWh in three consecutive hours, then the adjusted EUE is 80 MWh after removing the first hour of the event. Using this same example, LOLH would be adjusted from three to two hours, and LOLE would not be adjusted. The LOLE is only adjusted inasmuch as a given reliability event has a one hour duration. Development of System Variable Costs In addition to completing PaR runs to develop reliability metrics, PaR is also used to produce system variable operating costs for each of the resource portfolios developed assuming PRM levels ranging between 10 percent and 20 percent. For the system variable cost PaR runs, Monte Carlo random sampling of stochastic variables is expanded to include natural gas and wholesale market prices in addition to the stochastic variables for load, hydro generation, and thermal unit outages. Including market prices as a stochastic variable is important for this step of the PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 138 workflow because of their influence the economic dispatch of system resources, the cost of system balancing purchases, and revenues from system balancing sales. The stochastic mean of system variable costs is added to the upfront capital and run-rate fixed costs from each portfolio so that total portfolio costs are captured for each PRM level. Calculating the Incremental Cost of Reliability Using 2017 as the reference year, the cost of reliability is calculated as the difference in fixed and variable system costs at each PRM level relative to total costs at a 10 percent PRM. The incremental cost of reliability is calculated by dividing the cost of reliability by the difference in EUE at each PRM level relative to EUE at 10 percent PRM. This calculation yields an incremental cost per megawatt-hour (MWh) of EUE at PRM levels raninging between 11 percent and 20 percent. Results Resource Portfolios Table I.1 shows new resources added to the portfolio at PRM levels ranging between 10 percent and 20 percent. Each portfolio includes a 420 megawatt (MW) CCCT. New SCCT resource capacity totals 976 MW at the 10 percent PRM, rising to 1,996 MW at a 20 percent PRM. DSM resource additions range between 1,010 MW and 1,107 MW (between 358 MW and 424 MW during system peak hours). As the PRM is increased, system capacity is largely met with additional SCCT resources. Because new SCCT resources are added in blocks indicative of a typical plant size (i.e. the model cannot add a 2 MW SCCT plant), the addition of new DSM resources does not always increase with each sequential increase in the PRM. Table I.1 – Expansion Resources Additions by PRM PRM (%) DSM SCCT (MW) CCCT (MW) Total at System Peak (MW) Maximum (MW) Capacity at System Peak (MW) 10 1,029 372 976 420 1,768 11 1,017 363 1,157 420 1,940 12 1,020 365 1,259 420 2,045 13 1,032 375 1,259 420 2,055 14 1,017 363 1,440 420 2,224 15 1,043 384 1,440 420 2,244 16 1,010 358 1,602 420 2,380 17 1,065 397 1,612 420 2,428 18 1,017 363 1,793 420 2,576 19 1,107 424 1,793 420 2,637 20 1,096 416 1,996 420 2,832 Reliability Metrics Table I.2 shows EUE, LOLH, and LOLE reliability results before and after adjusting these reliability metrics for PacifiCorp’s participation in the NWPP reserve sharing agreement. Each of the reliability metrics generally improve as the PRM increases and after accounting for benefits associated with PacifiCorp’s participation in the NWPP reserve sharing agreement. After PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 139 accounting for its participation in the NWPP reserve sharing agreement, all PRM levels meet a one day in ten year planning criteria (LOLH at or above 2.4), and PRM levels of between 15 and 16 percent meet a one event in ten year planning criteria (LOLE at or above 0.1). Table I.2 – Expected Reliability Metrics by PRM Before NWPP Adjustment After NWPP Adjustment PRM (%) EUE (GWh/yr) LOLH (Hours/yr) LOLE (Events/yr) EUE (GWh/yr) LOLH (Hours/yr) LOLE (Events/yr) 10 301 2.60 0.87 200 1.73 0.48 11 183 2.03 0.74 116 1.29 0.41 12 197 1.78 0.50 141 1.27 0.29 13 122 1.51 0.43 87 1.08 0.29 14 84 1.24 0.35 60 0.89 0.25 15 98 1.19 0.30 73 0.89 0.22 16 32 0.34 0.20 13 0.13 0.04 17 68 0.46 0.18 41 0.28 0.07 18 17 0.30 0.12 10 0.18 0.05 19 17 0.40 0.18 9 0.22 0.08 20 13 0.27 0.12 7 0.15 0.04 The reliability metrics do not montonically improve with each incremental increase in the PRM. This is influenced by the physical location of new resources within PacifiCorp’s system at varying PRM levels and the ability of these resources to serve load in all load pockets when Monte Carlo sampling is applied to load, hydro generation, and thermal unit outages. Considering that the reliability metrics are measuring very small magnitudes of change among the different PRM levels, the PaR outputs are fit to a logarithmic function to report the overall trend in reliability improvements as the PRM level increases. Table I.3 shows the fitted EUE, LOLH, and LOLE results. Figure I.2, Figure I.3 and Figure I.4 show a plot of the fitted trend for EUE, LOLH, and LOLE, respectively, after accounting for PacifiCorp’s participation in the NWPP reserve sharing agreement. Table I.3 – Fitted Reliability Metrics by PRM Before NWPP Adjustment After NWPP Adjustment PRM (%) EUE (GWh/yr) LOLH (Hours/yr) LOLE (Events/yr) EUE (GWh/yr) LOLH (Hours/yr) LOLE (Events/yr) 10 294 2.78 0.90 198 1.88 0.52 11 211 2.05 0.66 142 1.38 0.38 12 162 1.62 0.53 109 1.09 0.30 13 127 1.32 0.43 86 0.88 0.24 14 101 1.08 0.36 67 0.72 0.20 15 79 0.89 0.30 53 0.59 0.16 16 60 0.73 0.25 40 0.48 0.13 17 44 0.59 0.20 29 0.38 0.10 18 30 0.46 0.16 20 0.30 0.08 19 18 0.35 0.13 11 0.22 0.06 20 6 0.25 0.10 3 0.15 0.04 PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 140 Figure I.2 – Expected and Fitted Relationship of EUE to PRM Figure I.3 – Expected and Fitted Relationship of LOLH to PRM y = -81.27ln(x) + 198.27 R² = 0.9191 0 20 40 60 80 100 120 140 160 180 200 10 11 12 13 14 15 16 17 18 19 20 EU E ( G W h ) PRM (%) EUE ln (EUE) y = -0.721ln(x) + 1.8837 R² = 0.8878 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 10 11 12 13 14 15 16 17 18 19 20 LO L H ( H o u r ) PRM (%) LOLH ln (LOLH) PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 141 Figure I.4 – Simulated Relationship of Loss of Load Episode to PRM System Costs For the 2017 reference year, Table I.4 shows the stochastic mean of system variable costs and the upfront capital and run-rate fixed costs, including the cost of new DSM resources, for each portfolio developed at PRM levels ranging between 10 percent and 20 percent. The fixed costs associated with these new resource additions drive total costs higher as PRM levels increase. DSM run-rate costs increase most substantially once the PRM level exceeds 18 percent, indicating that incremental DSM resource selections for portfolios developed at the 19 percent and 20 percent PRM levels were taken from higher cost resources in the DSM supply curve. Table I.4 – System Variable, Up-front Capital, and Run-rate Fixed Costs by PRM PRM (%) System Variable Costs ($ thousands) DSM Run-rate Costs ($ thousands) Up-front Capital & Run-rate Fixed Costs ($ thousands) Total Cost ($ thousands) 10 1,292,361 34,498 237,119 $1,563,978 11 1,292,341 32,177 256,251 $1,580,769 12 1,288,956 32,838 276,790 $1,598,584 13 1,287,921 34,919 275,976 $1,598,816 14 1,289,097 32,181 295,108 $1,616,386 15 1,287,021 38,644 295,108 $1,620,773 16 1,289,396 30,544 314,025 $1,633,965 17 1,284,925 44,903 314,133 $1,643,961 18 1,289,300 32,177 333,265 $1,654,742 19 1,284,132 143,492 334,144 $1,761,768 20 1,283,763 141,192 363,042 $1,787,997 y = -0.201ln(x) + 0.5222 R² = 0.9149 0.00 0.10 0.20 0.30 0.40 0.50 0.60 10 11 12 13 14 15 16 17 18 19 20 LO L E ( E v e n t s / Y e a r ) PRM (%) LOLE ln (LOLE) PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 142 Incremental Cost of Reliability Table I.5 shows the incremental cost of reliability at PRM levels ranging between 11 percent and 20 percent. Figure I.5 depicts this same information graphically. These results show the incremental cost of reliability rises as PRM levels increase from 15 percent and 18 percent, and increase dramatically at PRM levels above 18 percent. The incremental cost of reliability does not vary significantly at PRM levels at or below 15 percent. Table I.5 – Incremental Cost of Reliability by PRM PRM (%) Reduction in Fitted EUE from EUE at 10% PRM After NWPP Adjustment (GWh) Reduction in Total System Cost from Cost at 10% PRM ($ thousands) Incremental Cost of EUE Relative to 10% PRM ($/MWh of EUE) 11 56 $16,791 $298 12 89 $34,606 $388 13 113 $34,838 $309 14 131 $52,408 $401 15 146 $56,795 $390 16 158 $69,987 $443 17 169 $79,983 $473 18 179 $90,764 $508 19 187 $197,790 $1,057 20 195 $224,019 $1,150 Figure I.5 – Incremental Cost of Reliability by PRM 0 100 200 300 400 500 600 700 800 900 11 12 13 14 15 16 17 18 19 20 ($ / M W h o f E U E ) PRM ($) PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 143 Conclusion Upon evaluating the relationship between cost and reliability in the PRM study, PacifiCorp will continue to use a 13 percent target PRM in its resource planning. A PRM below 13 percent would not sufficiently cover the need to carry short-term operating reserve needs (contingency and regulating margin) and longer-term uncertainties such as extended outages and changes in customer load.41 A PRM above 15 percent improves reliability above a one event in ten year planning level, though with a 125 percent to 370 percent increase in the incremental cost per megawatt-hour of reduced EUE when compared to a 13 percent PRM. With these considerations, the selected 13 percent PRM level ensures PacifiCorp can reliably meet customer loads while maintaining operating reserves, with a planning criteria that meets one day in 10 year planning targets, at the lowest reasonable cost. 41 PacifiCorp must hold approximately 6% of its resources in reserve to meet contingency reserve requirements and an estimated additional 4.5% to 5.5% of its resources in reserve, depending upon system conditions at the time of peak load, as regulating margin. This sums to 10.5% to 11.5% of operating reserves before even considering longer- term uncertainties such as extended outages (transmission or generation) and customer load growth. PACIFICORP – 2015 IRP APPENDIX I –PLANNING RESERVE MARGIN STUDY 144 PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 145 APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION Introduction The Utah Commission, in its 2008 IRP acknowledgment order, directed the Company to conduct two analyses pertaining to the Company’s ability to support reliance on market purchases: Additionally, we direct the Company to include an analysis of the adequacy of the western power market to support the volumes of purchases on which the Company expects to rely. We concur with the Office [of Consumer Services], the WECC is a reasonable source for this evaluation. We direct the Company to identify whether customers or shareholders will be expected to bear the risks associated with its reliance on the wholesale market. Finally, we direct the Company to discuss methods to augment the Company’s stochastic analysis of this issue in an IRP public input meeting for inclusion in the next IRP or IRP update.42 To fulfill the first requirement, PacifiCorp evaluated the Western Electricity Coordinating Council (WECC) Power Supply Assessment (PSA) reports to glean trends and conclusions from the supporting analysis. This evaluation, along with a discussion on risk allocation associated with reliance on market purchases, is provided below. As part of this evaluation, the Company also reviewed the status of resource adequacy assessments prepared for the Pacific Northwest by the Pacific Northwest Resource Adequacy Forum. Western Electricity Coordinating Council Resource Adequacy Assessment The WECC 2014 PSA shows a planning reserve margin (PRM) calculated as a percentage of resources (generation and transfers) and load, and is the percentage of capacity above demand. The PRM indicates that there are sufficient resources when the PRM is equal to or greater than the target planning reserve margin. The 2014 PSA shows WECC not needing additional resources throughout the entire period of their study, which ends in 2024 (see Figure J.1). Prior to the 2014 PSA report, WECC utilized eight sub regions in calculating and reporting reserve margins. For the 2014 PSA report, WECC reduced the sub region count from eight to four, with a substantial change in the balancing authority areas (BAA) that make up each sub region. Prior to 2014, PacifiCorp’s western BAA was in the “Northwest” sub region, while PacifiCorp’s eastern BAA was in the “Basin” sub region. In the 2014 PSA report, both of PacifiCorp’s BAA’s are now in the “Northwest Power Pool” (NWPP) region. As a result, comparison to prior year PSA only available on a WECC basis, as none of the prior eight sub regions are comparable to the current four sub regions. In WECC PSAs, the region and sub region target reserve margins are calculated using a building block methodology created by WECC. As such, they do not reflect a criteria-based margin determination process and do not reflect any balancing authority or load serving entity level 42 Public Service Commission of Utah, PacifiCorp 2008 Integrated Resource Plan, Report and Order, Docket No. 09-2035-01, p. 30. PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 146 requirements that may have been established through other processes (e.g., state regulatory authorities). They are not intended to supplant any of those requirements. The WECC building block methodology is comprised of four elements43: 1. Contingency Reserves – An additional amount of operating reserves sufficient to reduce area control error to zero following loss of generating capacity, which would result from the most severe single contingency. 2. Regulating Reserves – The amount of reserves sufficient to provide normal regulating margin. The regulating component of this guideline was calculated using data provided in WECC’s annual loads and resources data request responses. 3. Additional Forced Outages – Reserves for additional forced outages beyond what might be covered by operating reserves in order to cover second contingencies are calculated using the forced outage data supplied to WECC through the loads and resources data request responses. Ten years of data are averaged to calculate both a summer (July) and winter (December) forced outage rate. The same forced outage rate is used for all balancing authorities in WECC when calculating the building block margin. 4. Temperature Adders – Using historic temperature data for up to 20 years, the annual maximum and minimum temperature for each balancing authority’s area was identified. That data was used to calculate the average maximum (summer) and minimum (winter) temperature and the associated standard deviation. As seen in Figure J.1, the 2014 PSA shows the WECC as having a positive power supply margin (PSM) in all years. The PSM is a measure of a region’s ability to meet total load requirements, including its target reserve margin. As such, a PSM of zero or more indicates that demand plus the target reserve margin was met. 43 Further details of building block elements can be found on the WECC website at the following location: https://www.wecc.biz/Reliability/2014LAR_MethodsAssumptions.pdf PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 147 Figure J.1 – WECC Forecasted Power Supply Margins, 2007 to 2014 Note: WECC Power Supply Assessments include Class 1 Planned Resources Only In the 2012 PSA, the WECC study showed a deficit beginning in 2021. For the 2014 PSA there is no deficit period. Figure J.2 shows the difference between the 2014 and 2012 PSA studies. For most years the load forecasts (net internal demand) decreased, while capacity resources increased substantially. The target reserve margins change from year to year, though for the most part are not a major contributor to the year on year PSA deviations. PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 148 Figure J.2 – 2014 less 2012 WECC PSA Table J.1 shows the target summer planning reserve margin calculated in the 2014 WECC PSA report, along with the forecasted yearly results. These results are based on the following elements:  Generation (existing as of December 31, 2013, as well as that under construction);  Adjustments for scheduled maintenance/inoperable generation;  Hydro energy under adverse water conditions; and  Demand forecasts, both firm and non-firm. The 2014 WECC power reserve margin results show that there is not a resource need through 2024 whereas the 2012 PSA projected a resource need in 2020. Table J.1 – 2012 WECC Forecasted Planning Reserve Margins Northwest Power Pool (NWPP) is a winter peaking WECC sub region comprised of Washington, Oregon, Idaho, Montana, Nevada, Utah, western Wyoming, Alberta, British Columbia and the -5,000 0 5,000 10,000 15,000 20,000 2015 2016 2017 2018 2019 2020 2021 2022 Me g a w a t t s Capacity Resources Net Internal Demand Target Reserve Margin Subregion Target Reserve Margin 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 NWPP 15.5%33.6% 32.1% 303.7% 27.3% 27.1% 26.8% 26.6% 25.3% 21.3% 17.7% RMRG 13.2%41.7% 58.3% 63.7% 59.6% 53.0% 48.4% 28.4% 13.3% 13.4% 13.3% SRSG 14.1%31.8% 38.3% 31.1% 28.2% 21.0% 17.0% 15.1% 14.2% 14.2% 14.1% CA/MX 15.0%15.3% 16.0% 15.9% 15.4% 15.4% 15.3% 15.3% 15.2% 15.1% 15.1% WECC Total 14.7%27.3% 28.9% 27.6% 25.3% 23.8% 22.7% 21.1% 19.4% 17.6% 16.0% Summer; Existing and Class 1 ResourcesPlanning Reserve Margin PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 149 Balancing Authority of Northern California. The target summer reserve margin for this region is 15.5%, which is well below the region’s forecasted planning reserve margin for 2015-2024. Market depth refers to a market’s ability to accept individual transactions without a perceptible change in market price. While different from market liquidity44 the two are linked in that a deep market tends to be a liquid market. Electricity market depth is a function of the number of economic agents, market period, generating capacity, transmission capability, transparency, and institutional and/or physical constraints. Based on the 2014 PSA, WECC maintains a positive power supply margin (PSM) through 2024. All of the WECC’s sub regions also are forecasted to maintain sufficient PSM through 2024. In total, known market transactions, generation resources, load requirements, and the optimization of transfers within WECC show adequate market depth to maintain target reserve margins for several years. Pacific Northwest Resource Adequacy Forum’s Adequacy Assessment The Pacific Northwest Resource Adequacy Forum issued resource adequacy standards in April 2008, which were subsequently adopted by the Northwest Power and Conservation Council. The standard calls for assessments three and five years out, conducted every year, and including only existing resources and planned resources that are already sited and licensed. In a May 2014 report, the Forum concluded that the likelihood of a shortfall between the region’s winter power supply and forecasted load growth 5 years out had decreased from 6.6 percent to 6 percent.45 This means that the region will still have to acquire additional resources in the winter period in order to maintain an adequate power supply46, a finding that supports acquisition actions currently being taken by regional utilities. Between 2017 and 2019, the region’s electricity loads, net of planned energy efficiency savings, are expected to grow by about 130 average megawatts or about a 0.6 percent annual rate. Since the last assessment, 667 megawatts of new thermal capacity and 267 megawatts of new wind capacity have been added. There are a host of solutions which would get the targeted loss of load probability down to five percent. Adding 400 MWs of dispatchable generation by 2019 would suffice, as would reducing annual load by 300 average megawatts. WECC’s 2014 PSA shows a combination of lowering loads and increasing supply in future years. Customer versus Shareholder Risk Allocation Market purchase costs are reflected in rates. Consequently, customers bear the price risk of the Company’s reliance on a given level of market purchases. However, customers also bear the cost impact of the Company's decision to build or acquire resources if those resources exceed market alternatives and result in an increase in rates. These offsetting risks stress the need for robust IRP analysis, efficient RFPs and ability to capture opportunistic procurement opportunities when they arise. 44 Market liquidity refers to having ready and willing buyers and sellers for large transactions. 45 Pacific Northwest Power Supply Adequacy Assessment for 2017, at https://www.nwcouncil.org/energy/powersupply/2014-04/ 46 A five percent loss of load probability has been deemed, by the Pacific Northwest Power Council, as the maximum tolerable level. PACIFICORP – 2015 IRP APPENDIX J – WESTERN RESOURCE ADEQUACY EVALUATION 150 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 151 APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS Portfolio Case Build Tables This section provides the System Optimizer portfolio build tables for each of the case scenarios as described in the portfolio development section of Chapter 7. There are 30 core cases. The different cases were run under one of three Regional Haze scenarios. Table K.1 – Core Case Study Reference Guide Case Reg. Haze [1] 111(d) Def. [2] 111(d) Strat. [3] CO2 Price Class 2 DSM [4] FOTs 1st Year of New Thermal C01-R Ref None None None Base Base 2028 C01-1 1 None None None Base Base 2024 C01-2 2 None None None Base Base 2024 C02-1 1 1 A None Base Base 2024 C02-2 2 1 A None Base Base 2024 C03-1 1 1 B None Base+ Base 2028 C03-2 2 1 B None Base+ Base 2025 C04-1 1 1 C None Base+ Base 2028 C04-2 2 1 C None Base+ Base 2025 C05-1 1 2 A None Base Base 2024 C05-2 2 2 A None Base Base 2024 C05-3 3 2 A None Base Base 2028 C05a-1 1 2 A None Base Base 2024 C05b-1 1 2 A None Base Base 2024 C05a-2 2 2 A None Base Base 2024 C05a-3 3 2 A None Base Base 2028 C05a-3Q 3 2 A None Base Base 2028 C05b-3 3 2 A None Base Base 2028 C06-1 1 2 B None Base+ Base 2028 C06-2 2 2 B None Base+ Base 2025 C07-1 1 2 C None Base+ Base 2028 C07-2 2 2 C None Base+ Base 2025 C09-1 1 2 A None Base Limited 2022 C09-2 2 2 A None Base Limited 2022 C11-1 1 2 A None Accelerated Base 2024 C11-2 2 2 A None Accelerated Base 2024 C12-1 1 3a None None Base Base 2024 C12-2 2 3a None None Base Base 2024 C13-1 1 3b None None Base Base 2023 C13-2 2 3b None None Base Base 2023 C14-1 1 2 A Yes Base Base 2024 C14-2 2 2 A Yes Base Base 2024 C14a-1 1 2 A Yes Base Base 2022 C14a-2 2 2 A Yes Base Base 2022 [1] Regional Haze assumptions are defined in the Core Case Fact Sheet for each case. [2] 1 = 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation; 2 = 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation and retail customers; 3a = 111(d) implemented as a mass cap applicable to new and existing fossil resources in PacifiCorp’s system; 3b = 111(d) implemented as a mass cap applicable to existing fossil resources in PacifiCorp’s system [3] A = cost-effective energy efficiency, fossil re-dispatch before adding new renewables; B = increased energy efficiency, fossil re- PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 152 dispatch before adding new renewables; C = increased energy efficiency, new renewables before fossil re-dispatch [4] Base = base Class 2 DSM achievable potential supply curves; Base+ = base Class 2 DSM achievable potential supply curves with forced selections of approximately 1.5% of retail sales; Accelerated = accelerated Class 2 DSM achievable potential supply curves Table K.2 – Sensitivity Case Study Reference Guide Case Description Reg. Haze[1] 111(d) Strat. [2] CO2 Price Class 2 DSM [3] 1st Year of New Thermal S-01 Low Load 1 A None Base 2028 S-02 High Load 1 A None Base 2020 S-03 1-in-20 Load 1 A None Base 2019 S-04 Low DG 1 A None Base 2024 S-05 High DG 1 A None Base 2027 S-06 Pumped Storage 1 A None Base 2028 S-07 Energy Gateway 2 1 C None Base+ 2028 S-08 Energy Gateway 5 1 C None Base+ 2028 S-09 PTC Extension 1 A None Base 2024 S-10_ECA East BAA 3 A None Base 2028 S-10_WCA West BAA 3 A None Base 2020 S-10_System Benchmark System 3 A None Base 2028 S-11 111(d) and High CO2 Price 1 A High Base 2024 S-12 Stakeholder Solar Cost Assumptions 1 A None Base 2027 S-13 Compressed Air Storage 1 A None Base 2027 S-14 Class 3 DSM 1 A None Base 2024 S-15 Restricted 111(d) Attributes 1 A None Base 2020 [1] Regional Haze assumptions are defined in the Core Case Fact Sheet for each case. [2] A = cost-effective energy efficiency, fossil re-dispatch before adding new renewables; C = increased energy efficiency, new renewables before fossil re-dispatch [3] Base = base Class 2 DSM achievable potential supply curves; Base+ = base Class 2 DSM achievable potential supply curves with forced selections of approximately 1.5% of retail sales; Additional notes: All Sensitivities incorporate: 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation and retail customers; PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 153 Table K.3 – East-Side Resource Name and Description Resource List Detailed Description CCCT - DJohns - F 1x1 Combine Cycle Combustion Turbine F-Machine 1x1 with Duct Firing - Dave Johnston Brownfield CCCT - DJohns - F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing - Dave Johnston Brownfield CCCT - DJohns - G 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing - Dave Johnston Brownfield CCCT - DJohns - G 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing - Dave Johnston Brownfield CCCT - DJohns - J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing - Dave Johnston Brownfield CCCT - Goshen - F 1x1 Combine Cycle Combustion Turbine F-Machine 1x1 with Duct Firing - West Box Elder, Utah Area CCCT - Goshen - G 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing - West Box Elder, Utah Area CCCT - Goshen - J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing - West Box Elder, Utah Area CCCT - Hunter - F 1x1 Combine Cycle Combustion Turbine F-Machine 1x1 with Duct Firing - Hunter Plant Brownfield CCCT - Hunter - F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing - Hunter Plant Brownfield CCCT - Hunter - G 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing - Hunter Plant Brownfield CCCT - Hunter - G 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing - Hunter Plant Brownfield CCCT - Hunter - J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing - Hunter Plant Brownfield CCCT - Huntington - F 1x1 Combine Cycle Combustion Turbine F-Machine 1x1 with Duct Firing - Huntington Plant Brownfield CCCT - Huntington - F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing - Huntington Plant Brownfield CCCT - Huntington - G 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing - Huntington Plant Brownfield CCCT - Huntington - G 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing - Huntington Plant Brownfield CCCT - Huntington - J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing - Huntington Plant Brownfield CCCT - Naughton - J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing - Naughton Plant Brownfield CCCT F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing CCCT FD 1x1 Combine Cycle Combustion Turbine F-Machine 1x1 with Duct Firing CCCT GH 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing CCCT GH 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing CCCT J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing IC Aero UT Inter-cooled Simple Cycle Combustion Turbine Aero - Utah IC Aero WYNE Inter-cooled Simple Cycle Combustion Turbine Aero - Wyoming NE IC Aero WYSW Inter-cooled Simple Cycle Combustion Turbine Aero - Wyoming SW SCCT Aero UT Simple Cycle Combustion Turbine Aero - Utah SCCT Aero WYNE Simple Cycle Combustion Turbine Aero - Wyoming NE SCCT Frame ID Simple Cycle Combustion Turbine Frame - West Box Elder, Utah Area SCCT Frame UT Simple Cycle Combustion Turbine Frame - Utah SCCT Frame WYNE Simple Cycle Combustion Turbine Frame - Wyoming NE SCCT Frame WYSW Simple Cycle Combustion Turbine Frame - Wyoming SW Battery Storage - East Battery Storage – East CAES - East Compressed Air Energy Storage Fly Wheel - East Fly Wheel – East PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 154 Resource List Detailed Description Pump Storage - East Pump Storage – East Reciprocating Engine - East Reciprocating Engine Modular-Nuclear-East Small Modular Reactor x 12 Nuclear Nuclear - East Advanced Fission Nuclear Fuel Cell - East Fuel Cell – East Wind, DJohnston, 43 Wind, Wyoming After DJ Retirement, 43% Capacity Factor Wind, GO, 31 Wind, Goshen Idaho, 31% Capacity Factor Wind, UT, 31 Wind, Utah, 31% Capacity Factor Wind, WYAE, 43 Wind, Wyoming Aeolius, 43% Capacity Factor Utility Solar - PV - East Utility Solar, Utah - Photovoltaic DSM, Class 1, ID-Curtail DSM Class 1, Curtailment - Idaho DSM, Class 1, ID-DLC-RES DSM Class 1, Direct Load Control-Residential - Idaho DSM, Class 1, ID-Irrigate DSM Class 1, Direct Load Control-Irrigation - Idaho DSM, Class 1, UT-Curtail DSM Class 1, Curtailment - Utah DSM, Class 1, UT-DLC-RES DSM Class 1, Direct Load Control-Residential - Utah DSM, Class 1, UT-Irrigate DSM Class 1, Direct Load Control-Irrigation - Utah DSM, Class 1, WY-Curtail DSM Class 1, Curtailment - Wyoming DSM, Class 1, WY-DLC-RES DSM Class 1, Direct Load Control-Residential - Wyoming DSM, Class 1, WY-Irrigate DSM Class 1, Direct Load Control-Irrigation - Wyoming DSM, Class 3, ID-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - Idaho DSM, Class 3, ID-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - Idaho DSM, Class 3, ID-Irrigate Price DSM Class 3, Irrigation Pricing - Idaho DSM, Class 3, ID-Res Price DSM Class 3, Residential Pricing - Idaho DSM, Class 3, UT-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - Utah DSM, Class 3, UT-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - Utah DSM, Class 3, UT-Irrigate Price DSM Class 3, Irrigation Pricing - Utah DSM, Class 3, UT-Res Price DSM Class 3, Residential Pricing - Utah DSM, Class 3, WY-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - Wyoming DSM, Class 3, WY-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - Wyoming DSM, Class 3, WY-Irrigate Price DSM Class 3, Irrigation Pricing - Wyoming DSM, Class 3, WY-Res Price DSM Class 3, Residential Pricing - Wyoming DSM, Class 2, ID DSM, Class 2, Idaho DSM, Class 2, UT DSM, Class 2, Utah DSM, Class 2, WY DSM, Class 2, Wyoming FOT Mona Q3 Front Office Transaction - 3rd Quarter HLH Product - Mona PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 155 Table K.4 – West-Side Resource Name and Description Resource List Detailed Description CCCT F 2x1 Combine Cycle Combustion Turbine F-Machine 2x1 with Duct Firing CCCT GH 1x1 Combine Cycle Combustion Turbine GH-Machine 1x1 with Duct Firing CCCT GH 2x1 Combine Cycle Combustion Turbine GH-Machine 2x1 with Duct Firing CCCT J 1x1 Combine Cycle Combustion Turbine J-Machine 1x1 with Duct Firing IC Aero WV Inter-cooled Simple Cycle Combustion Turbine Aero - Willamette Valley IC Aero WW Inter-cooled Simple Cycle Combustion Turbine Aero - Walla Walla IC Aero PO Inter-cooled Simple Cycle Combustion Turbine Aero - Portland IC Aero SO-CAL Inter-cooled Simple Cycle Combustion Turbine Aero - Southern Oregon SCCT Aero PO Simple Cycle Combustion Turbine Aero - Portland SCCT Aero WV Simple Cycle Combustion Turbine Aero - Willamette Valley SCCT Aero WW Simple Cycle Combustion Turbine Aero - Walla Walla SCCT Frame WW Simple Cycle Combustion Turbine Frame - Walla Walla Fly Wheel Fly Wheel Battery Storage Battery Storage Pump Storage Pump Storage Utility Solar - PV Utility Solar - Photovoltaic OR Solar (Util Cap Standard & Cust Incentive Prgm) OR Solar (Utility Solar Capacity Standard & Customer Incentive Program) Wind, YK, 29 Wind, Arlington, OR, 29% Capacity Factor Wind, WW, 29 Wind, Walla Walla, 29% Capacity Factor DSM, Class 1, CA-Curtail DSM Class 1, Curtailment - California DSM, Class 1, CA-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - California DSM, Class 1, CA-DLC-RES DSM Class 1, Direct Load Control-Residential - California DSM, Class 1, OR-Curtail DSM Class 1, Curtailment - Oregon DSM, Class 1, OR-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - Oregon DSM, Class 1, OR-DLC-RES DSM Class 1, Direct Load Control-Residential - Oregon DSM, Class 1, WA-Curtail DSM Class 1, Curtailment - Washington DSM, Class 1, WA-DLC-IRR DSM Class 1, Direct Load Control-Irrigation - Washington DSM, Class 1, WA-DLC-RES DSM Class 1, Direct Load Control-Residential - Washington DSM, Class 3, CA-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - California DSM, Class 3, CA-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - California DSM, Class 3, CA-Irrigate Price DSM Class 3, Irrigation Pricing - California DSM, Class 3, CA-Res Price DSM Class 3, Residential Pricing - California DSM, Class 3, OR-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - Oregon DSM, Class 3, OR-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - Oregon DSM, Class 3, OR-Irrigate Price DSM Class 3, Irrigation Pricing - Oregon PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 156 Resource List Detailed Description DSM, Class 3, OR-Res Price DSM Class 3, Residential Pricing - Oregon DSM, Class 3, WA-C&I Pricing DSM Class 3, Commercial & Industrial Pricing - Washington DSM, Class 3, WA-C&I Demand Buyback DSM Class 3, Commercial & Industrial Demand Buyback - Washington DSM, Class 3, WA-Irrigate Price DSM Class 3, Irrigation Pricing - Washington DSM, Class 3, WA-Res Price DSM Class 3, Residential Pricing - Washington DSM, Class 2, CA DSM, Class 2, California DSM, Class 2, OR DSM, Class 2, Oregon DSM, Class 2, WA DSM, Class 2, Washington FOT COB Flat Front Office Transaction – Annual Flat Product - COB FOT COB Q3 Front Office Transaction - 3rd Quarter HLH Product - COB FOT MidColumbia Flat Front Office Transaction - Annual Flat Product - Mid Columbia FOT MidColumbia Q3 Front Office Transaction - 3rd Quarter HLH Product - Mid Columbia FOT MidColumbia Q3 - 2 Front Office Transaction - 3rd Quarter HLH Product - Mid Columbia FOT NOB Q3 Front Office Transaction - 3rd Quarter HLH Product - Nevada Oregon Border FOT COB - Jan Front Office Transaction - January HLH Product - COB FOT MidColumbia - Jan Front Office Transaction - January HLH Product - Mid Columbia FOT MidColumbia - Jan - 2 Front Office Transaction - January HLH Product - Mid Columbia FOT NOB - Jan Front Office Transaction - January HLH Product - Nevada Oregon Border PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 157 Table K.5 – Core Case System Optimizer Results Case PVRR ($M) Cumulative CO2 Emissions (Thousand Short Tons) C01-R 26,828 969,315 C01-1 26,683 897,452 C02-1 27,787 825,935 C03-1 28,889 809,295 C04-1 29,310 865,036 C05-1 26,646 890,106 C05a-1 26,591 879,838 C05b-1 26,649 885,644 C06-1 27,930 875,231 C07-1 28,516 873,897 C09-1 26,809 895,314 C11-1 26,649 889,635 C12-1 26,655 862,398 C13-1 26,902 839,068 C14-1 39,442 812,401 C14a-1 39,304 762,475 C01-2 27,254 849,333 C02-2 28,313 781,935 C03-2 29,509 767,859 C04-2 29,913 822,396 C05-2 27,177 845,522 C05a-2 27,240 832,613 C06-2 28,549 832,553 C07-2 29,115 830,308 C09-2 27,454 850,072 C11-2 27,175 844,736 C12-2 27,241 821,818 C13-2 27,360 807,512 C14-2 39,584 772,949 C14a-2 39,347 747,893 C05-3 26,615 920,441 C05a-3 26,578 906,487 C05a-3Q, Preferred Portfolio 26,591 903,937 C05b-3 26,649 912,759 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 158 Table K.6 – Sensitivity Case System Optimizer Results Sensitivity PVRR ($M) Cumulative CO2 Emissions (Thousand Short Tons) S-01 24,715 865,610 S-02 28,334 914,156 S-03 27,709 892,507 S-04 26,885 895,085 S-05 26,016 878,263 S-06 27,094 881,487 S-07 29,227 876,749 S-08 29,977 871,943 S-09 26,443 886,173 S-10_ECA 19,672 667,684 S-10_System 26,480 905,154 S-10_WCA 8,129 250,205 S-11 45,091 642,166 S-12 26,029 878,261 S-13 27,046 882,676 S-14 26,602 887,261 S-15 27,057 882,840 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 159 Table K.7 – Core Cases, Detailed Capacity Expansion Portfolios Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (218) - - - - - - - (218) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - - - - - - - - - - - - - Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - - 401 - 401 CCCT - Utah-S - F 2x1 - - - - - - - - - - - - - - - - - 635 - - - 635 Total CCCT - - - - - - - - - - - - - 423 - 313 - 635 - 401 - 1,772 Wind, DJohnston, 43 - - - - - - - - - - - - - 25 - - - - - - - 25 Total Wind - - - - - - - - - - - - - 25 - - - - - - - 25 Utility Solar - PV - East - - - - - - - - 238 - - - - - - - - - - - 238 238 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - 20.0 - - - - - 20.0 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 57.8 - - - - - 57.8 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - 16.5 - - - - - 16.5 DSM, Class 1 Total - - - - - - - - - - - - - - - 94.2 - - - - - 94.2 DSM, Class 2, ID 4 4 5 5 5 4 4 4 6 6 5 5 5 5 5 5 4 4 4 4 47 93 DSM, Class 2, UT 69 78 84 86 92 80 86 93 99 105 85 85 84 84 83 77 66 65 63 64 871 1,626 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 14 14 16 15 16 14 15 15 15 122 270 DSM, Class 2 Total 79 90 99 102 111 97 103 112 120 127 103 104 104 105 103 97 84 84 82 83 1,040 1,989 FOT Mona Q3 - - - - - - - - - - - - - 137 75 295 295 75 175 143 - 60 West Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - 10.6 - - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 15.6 - - 10.6 - - - 10.6 - - - - 19.0 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 2 2 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 24 22 22 22 23 22 21 20 20 19 19 303 512 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 7 7 98 182 DSM, Class 2 Total 54 50 47 44 42 38 36 36 36 36 32 33 32 34 33 30 29 29 27 27 418 724 FOT COB Q3 - 92 148 113 181 224 - - - - - - - 268 196 268 268 72 268 268 76 118 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 279 312 257 250 266 287 321 375 375 375 375 375 375 375 320 335 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (760) - (694) (77) - (358) - Annual Additions, Long Term Resources 133 147 146 146 153 135 139 151 409 163 134 147 136 586 136 546 113 748 110 511 Annual Additions, Short Term Resources 727 967 1,023 988 1,056 1,099 779 812 757 750 766 787 821 1,280 1,146 1,438 1,438 1,022 1,318 1,286 Total Annual Additions 860 1,114 1,169 1,134 1,209 1,234 918 964 1,166 913 900 934 957 1,866 1,282 1,984 1,552 1,770 1,428 1,797 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C01-R PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 160 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - - - 423 - - - 846 Total CCCT - - - - - - - - - - - - - 736 - 423 - 423 824 - - 2,406 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - - 25.9 - 25.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - - - 19.0 - 19.0 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 45.0 - 45.0 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 88 DSM, Class 2, UT 69 78 84 86 92 80 84 87 89 90 73 73 74 75 75 72 71 73 71 73 839 1,568 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 15 16 16 17 121 266 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 92 94 93 90 91 93 91 94 1,004 1,922 FOT Mona Q3 - - - - 11 - - 127 112 - 83 131 203 44 75 175 170 75 75 300 25 79 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - - - - 454 - - 454 CCCT - WillamValcc - J 1x1 - - - - - - - - - 477 - - - - - - - - - - 477 477 Total CCCT - - - - - - - - - 477 - - - - - - - - 454 - 477 932 Wind, YK, 29 - - - - - - - - 24 - - - - - - - - - - - 24 24 Total Wind - - - - - - - - 24 - - - - - - - - - - - 24 24 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 28 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 21 21 21 21 20 20 20 19 19 302 505 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 9 8 8 8 8 7 97 178 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 30 30 31 29 29 29 28 28 415 711 FOT COB Q3 - 93 149 114 268 261 - 268 268 264 268 268 268 209 54 268 268 155 230 268 169 197 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 314 375 375 375 375 375 375 375 375 375 375 375 375 375 354 365 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 145 146 152 314 137 146 173 623 120 121 122 861 124 542 120 545 1,397 167 Annual Additions, Short Term Resources 727 968 1,024 989 1,153 1,136 814 1,270 1,255 1,139 1,226 1,274 1,346 1,128 1,004 1,318 1,312 1,105 1,180 1,443 Total Annual Additions 859 1,115 1,170 1,135 1,306 1,450 951 1,416 1,427 1,762 1,346 1,395 1,469 1,989 1,128 1,860 1,432 1,650 2,577 1,610 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C01-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 161 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - 423 - - 423 - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - 401 - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - F 2x1 - - - - - - - - - 635 - - - - - - - - - - 635 635 Total CCCT - - - - - - - - - 635 423 - - 423 - - 401 - 736 635 635 3,253 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - - - - 215 - - - - - - - - - - - 215 215 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - 12.9 - - 7.0 - - 4.6 - - 24.6 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - 6.5 - - - - - 6.5 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - 3.5 - - 13.0 - - - - - 16.5 DSM, Class 1 Total - - - - - - - - - - - - 16.5 - - 26.5 - - 4.6 - - 47.6 DSM, Class 2, ID 4 4 5 5 5 4 5 5 6 6 5 5 5 5 5 4 4 4 4 4 48 95 DSM, Class 2, UT 69 78 84 86 97 86 97 104 106 105 85 85 84 84 81 75 74 73 72 64 911 1,687 DSM, Class 2, WY 7 8 10 12 14 12 13 15 15 17 14 14 15 15 15 15 15 16 17 15 123 274 DSM, Class 2 Total 80 90 99 102 116 102 115 124 127 128 104 104 104 104 101 95 94 93 93 83 1,082 2,056 FOT Mona Q3 - - - - - 33 - 146 47 - 219 256 300 254 49 300 111 103 300 75 23 110 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - 454 - - - - - 454 CCCT - WillamValcc - J 1x1 - - - - - - - - - - - - - - 477 - - - - - - 477 Total CCCT - - - - - - - - - - - - - - 477 454 - - - - - 932 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 10.6 - - - - - - - - - 10.6 21.2 DSM, Class 1, OR-Irrigate - - - - 5.0 - - - - - - - - - - - - - - - 5.0 5.0 DSM, Class 1 Total - - - - 5.0 - - - - 10.6 10.6 - - - - - - - - - 15.6 26.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 2 2 1 1 1 1 1 1 1 17 30 DSM, Class 2, OR 44 39 35 32 29 27 25 26 25 24 22 22 23 22 21 21 20 21 20 18 306 514 DSM, Class 2, WA 9 10 10 10 11 9 10 10 11 11 9 9 10 9 9 8 8 8 8 7 100 184 DSM, Class 2 Total 54 50 47 45 42 38 36 37 37 36 33 33 34 32 31 30 29 30 28 26 422 729 Battery Storage - West - 1 - - - - - - 1 - - - - - - - - - - - 2 2 FOT COB Q3 - 91 146 111 266 268 - 268 268 106 268 268 268 268 264 268 99 268 268 226 152 199 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 226 375 375 375 375 375 343 375 375 375 375 375 375 375 375 375 375 375 375 375 357 366 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 134 148 146 147 163 165 151 161 379 809 570 137 154 559 609 606 524 123 862 744 Annual Additions, Short Term Resources 726 966 1,021 986 1,141 1,176 843 1,289 1,189 981 1,362 1,399 1,443 1,397 1,187 1,443 1,084 1,246 1,443 1,176 Total Annual Additions 860 1,114 1,168 1,133 1,304 1,341 994 1,450 1,569 1,790 1,932 1,536 1,597 1,955 1,797 2,049 1,608 1,369 2,305 1,920 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C01-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 162 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,481 - 423 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 86 DSM, Class 2, UT 69 78 84 86 92 81 84 87 89 90 73 73 72 72 70 66 65 65 63 64 839 1,522 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 15 15 15 121 260 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 90 90 88 84 84 84 82 83 1,004 1,868 FOT Mona Q3 - - - - 10 - - - 21 - 44 75 75 44 - 75 44 75 - 275 3 37 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - 282 - - - - - - - - 37 - - - - 282 319 Total Wind - - - - - - 282 - - - - - - - - 37 - - - - 282 319 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 28 DSM, Class 2, OR 44 39 36 33 29 27 25 25 23 23 21 21 21 21 20 19 20 20 19 19 303 503 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 8 8 8 8 7 7 97 177 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 30 30 29 28 29 29 27 27 415 708 FOT COB Q3 - 93 149 114 268 121 - 186 149 102 142 148 222 38 - 198 218 7 - - 118 108 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 107 375 375 375 375 375 375 375 337 375 375 375 331 375 333 350 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 152 719 419 147 155 569 124 131 121 857 117 572 123 513 1,590 110 Annual Additions, Short Term Resources 727 968 1,024 989 1,153 996 607 1,061 1,046 977 1,061 1,098 1,172 957 837 1,148 1,137 957 831 1,150 Total Annual Additions 860 1,114 1,170 1,135 1,305 1,715 1,026 1,208 1,200 1,546 1,184 1,229 1,293 1,814 954 1,720 1,261 1,470 2,421 1,259 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C02-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 163 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - 635 - - - 635 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - 423 - - - - - - - 423 846 Total CCCT - - - - - - - - - 423 846 - 423 - 635 401 - - 1,270 - 423 3,998 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 9 - - - - - - 106 115 Wind, WYAE, 43 - - - - - - - - - - - - - - - 12 - - - - - 12 Total Wind - - - - - 106 - - - - - - - 9 - 12 - - - - 106 127 Utility Solar - PV - East - - - - - 118 - - - - - - - - - - - 36 - - 118 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 86 90 94 93 75 79 80 80 79 73 72 75 70 71 852 1,605 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 121 272 DSM, Class 2 Total 79 90 99 102 111 97 103 108 114 115 92 97 99 99 98 92 93 96 91 92 1,019 1,967 FOT Mona Q3 - - - - 9 - - - 37 - 75 75 - 44 - 75 44 111 60 300 5 41 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, YK, 29 - - - - - - 190 - - - - - - - - 10 - - - - 190 200 Total Wind - - - - - - 190 - - - - - - - - 10 - - - - 190 200 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 36 33 29 27 25 25 23 23 22 22 22 22 22 21 21 21 20 20 303 514 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 32 32 32 32 32 30 30 30 28 29 417 725 FOT COB Q3 - 93 148 113 268 123 - 206 149 215 169 200 - 254 - 174 187 268 - 70 131 132 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 129 375 375 375 375 375 347 375 308 375 375 375 375 375 336 350 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 147 146 147 153 764 329 149 160 573 973 140 554 141 765 545 133 162 1,389 121 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 998 629 1,081 1,062 1,090 1,119 1,150 847 1,173 808 1,124 1,106 1,254 935 1,245 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,761 958 1,230 1,221 1,663 2,092 1,290 1,401 1,313 1,573 1,669 1,239 1,415 2,324 1,366 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C02-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 164 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 313 - 423 - 401 1,269 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 21 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 142 142 155 138 143 154 157 157 132 147 148 149 146 132 130 130 129 128 1,357 2,728 FOT Mona Q3 - - - - - - - - - - 44 44 44 63 44 128 75 75 75 - - 30 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - - - - - - 144 - - - - - 144 Total Wind - - - - - - - - - - - - - - - 144 - - - - - 144 Utility Solar - PV - West - - - - - 332 - - - - - - - - - - - - - - 332 332 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 5.0 10.6 - 10.6 - - - - 10.6 - - - 19.0 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 48 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 50 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 100 19 136 - - - - 185 186 169 188 268 112 268 268 44 92 - 53 106 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 335 78 375 316 375 375 375 375 375 375 375 375 375 375 233 321 341 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 226 221 229 718 208 221 225 229 185 210 201 516 196 745 186 576 1,440 805 Annual Additions, Short Term Resources 727 968 975 894 1,011 835 578 875 816 1,060 1,105 1,088 1,107 1,206 1,031 1,271 1,218 994 1,042 733 Total Annual Additions 859 1,115 1,200 1,116 1,240 1,553 786 1,096 1,041 1,289 1,290 1,299 1,308 1,721 1,228 2,016 1,404 1,570 2,482 1,538 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C03-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 165 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - 423 - - - - - 846 Total CCCT - - - - - - - - - - 846 - - 423 - 824 - - 1,371 - - 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 21 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 142 142 154 138 143 154 157 157 132 147 148 149 146 131 131 130 129 129 1,357 2,728 FOT Mona Q3 - - - - - - - - - 17 44 75 44 44 86 44 44 75 - 171 2 32 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - - - - - - 140 - - - - - 140 Total Wind - - - - - - - - - - - - - - - 140 - - - - - 140 Utility Solar - PV - West - - - - - 337 - - - - - - - - - - - - - - 337 337 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - - - - - - 10.6 - - - 10.6 21.2 DSM, Class 1, OR-DLC-RES - - - - - - - 3.7 - - - - 4.5 - - - - - - - 3.7 8.2 DSM, Class 1, OR-Irrigate - - - - - - - - - - - 3.4 - - - 5.0 - - - - - 8.4 DSM, Class 1 Total - - - - - - - 3.7 - 10.6 - 3.4 4.5 - - 5.0 10.6 - - - 14.3 37.8 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 48 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 51 46 45 45 42 42 661 1,145 Battery Storage - West - - - - - - - - 3 - - 1 - - - - - - - - 3 4 FOT COB Q3 - 93 100 19 136 - - - - 268 233 192 237 146 268 196 142 238 - - 62 113 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 333 76 373 316 375 375 375 375 375 375 375 375 375 269 375 320 342 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 226 222 228 723 208 222 223 229 1,031 204 206 625 196 1,146 187 175 1,542 171 Annual Additions, Short Term Resources 727 968 975 894 1,011 833 576 873 816 1,160 1,152 1,142 1,156 1,065 1,229 1,115 1,061 1,188 769 1,046 Total Annual Additions 859 1,115 1,200 1,115 1,240 1,556 784 1,095 1,039 1,388 2,183 1,346 1,361 1,690 1,425 2,261 1,248 1,363 2,312 1,217 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C03-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 166 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 313 - 423 - 401 1,269 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Wind, GO, 31 - - - - - - - - - - 33 166 115 142 121 - - - - - - 577 Total Wind - - - - - 25 - - - - 33 166 115 142 121 - - - - - 25 602 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 7 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 21 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 142 142 155 138 143 154 157 157 132 147 148 149 146 132 130 130 129 128 1,357 2,728 FOT Mona Q3 - - - - - - - - - - - - - 14 - 44 33 - - - - 5 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, WW, 29 - - - - - - - 91 78 229 202 - - - - - - - - - 398 600 Wind, YK, 29 - - - - - - 334 66 - - - - - - - - - - - - 400 400 Total Wind - - - - - - 334 157 78 229 202 - - - - - - - - - 798 1,000 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - 10.6 - - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - - 3.7 - - - - - - - - - - 3.7 3.7 DSM, Class 1, OR-Irrigate - - - - - - - - - - - - - - 5.0 - - - - - - 5.0 DSM, Class 1 Total - - - - - - - 10.6 - 3.7 - 10.6 - - 5.0 - 10.6 - - - 14.4 40.5 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 48 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 51 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 100 19 136 - - - - - - - - - - 42 - - - - 35 20 FOT MidColumbia Q3 400 400 400 400 400 400 373 400 400 400 400 400 400 400 400 400 400 400 400 323 397 395 FOT MidColumbia Q3 - 2 227 375 375 375 375 310 - 225 152 348 340 301 303 369 187 375 375 184 232 - 276 271 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 226 222 229 791 542 386 298 451 420 376 316 658 322 601 186 576 1,440 805 Annual Additions, Short Term Resources 727 968 975 894 1,011 810 473 725 652 848 840 801 803 883 687 961 908 684 732 423 Total Annual Additions 859 1,115 1,200 1,116 1,240 1,600 1,015 1,111 950 1,299 1,260 1,177 1,120 1,540 1,009 1,562 1,094 1,260 2,172 1,228 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C04-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 167 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - 423 - - - - - 846 Total CCCT - - - - - - - - - - 846 - - 423 - 824 - - 1,371 - - 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Wind, GO, 31 - - - - - - - - - - 33 166 115 142 121 - - - - - - 577 Total Wind - - - - - 25 - - - - 33 166 115 142 121 - - - - - 25 602 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 7 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 114 111 122 109 112 122 124 123 104 119 121 121 118 105 104 102 102 101 1,083 2,179 DSM, Class 2, WY 6 8 18 20 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 142 142 154 138 143 154 157 157 132 146 148 149 146 132 131 129 129 128 1,357 2,728 FOT Mona Q3 - - - - - - - - - - 8 - - - 9 - - 6 - - - 1 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, WW, 29 - - - - - - - 91 78 229 202 - - - - - - - - - 398 600 Wind, YK, 29 - - - - - - 334 66 - - - - - - - - - - - - 400 400 Total Wind - - - - - - 334 157 78 229 202 - - - - - - - - - 798 1,000 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - 0.3 5.0 8.7 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - 1.4 15.6 41.5 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 48 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 50 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 100 19 137 - - - - 72 - - - - - - - - - - 42 21 FOT MidColumbia Q3 400 400 400 400 400 400 373 400 400 400 400 400 400 400 400 400 400 400 363 400 397 397 FOT MidColumbia Q3 - 2 227 375 375 375 375 310 - 232 148 375 375 344 347 236 375 309 254 375 - 238 279 282 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 225 221 228 791 542 380 308 447 1,270 376 316 767 317 1,001 187 175 1,543 172 Annual Additions, Short Term Resources 727 968 975 894 1,012 810 473 732 648 947 883 844 847 736 884 809 754 881 463 738 Total Annual Additions 859 1,115 1,200 1,116 1,240 1,601 1,015 1,111 956 1,395 2,152 1,220 1,163 1,504 1,201 1,810 941 1,056 2,006 910 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C04-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 168 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,481 - 423 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 86 DSM, Class 2, UT 69 78 84 86 92 81 84 88 89 90 73 73 72 72 70 66 65 65 63 64 840 1,522 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 15 15 15 121 260 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 90 90 88 84 84 84 82 83 1,004 1,869 FOT Mona Q3 - - - - 11 - - 125 110 35 118 156 229 44 44 214 203 75 63 291 28 86 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - 27 - - - - - - - - - - 27 27 Total Wind - - - - - - - - - 27 - - - - - - - - - - 27 27 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - 0.3 5.0 8.7 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - 1.4 15.6 41.5 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 28 DSM, Class 2, OR 44 39 35 32 29 28 25 25 23 23 21 21 21 21 20 20 20 20 19 19 303 503 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 8 8 8 8 7 7 97 177 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 30 30 29 29 29 29 27 27 416 709 FOT COB Q3 - 93 149 114 268 261 - 268 268 268 268 268 268 238 118 268 268 216 102 191 169 195 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 314 375 375 375 375 375 375 375 375 375 375 375 375 375 354 365 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 146 146 152 314 137 147 155 596 124 131 121 857 117 536 123 513 1,590 111 Annual Additions, Short Term Resources 727 968 1,024 989 1,153 1,136 814 1,268 1,252 1,178 1,261 1,299 1,372 1,157 1,037 1,356 1,346 1,166 1,040 1,357 Total Annual Additions 859 1,115 1,170 1,135 1,306 1,450 951 1,415 1,407 1,773 1,385 1,430 1,493 2,014 1,155 1,893 1,469 1,679 2,630 1,468 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 169 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - 635 - - - 635 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - 423 - - - - - - - 423 846 Total CCCT - - - - - - - - - 423 846 - 423 - 635 401 - - 1,270 - 423 3,998 Wind, DJohnston, 43 - - - - - 106 - - - 12 - - - 9 - - - - - - 118 127 Total Wind - - - - - 106 - - - 12 - - - 9 - - - - - - 118 127 Utility Solar - PV - East - - - - - - - - 58 - - - - - - - - 36 - - 58 94 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - 4.0 - - - 4.0 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - 9.0 - - - 9.0 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 5 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 84 90 91 97 78 81 83 84 81 75 75 75 69 71 851 1,622 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 14 15 15 16 16 17 17 17 121 272 DSM, Class 2 Total 79 90 99 102 111 97 102 108 110 118 96 99 101 104 101 95 95 96 90 92 1,017 1,985 FOT Mona Q3 - - - - 10 37 - 168 129 154 180 210 44 227 - 177 157 294 81 300 50 108 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 35 32 29 28 25 25 23 23 22 22 22 22 22 21 21 21 20 20 303 514 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 32 32 32 32 32 30 30 30 28 28 417 724 FOT COB Q3 - 93 149 113 268 268 - 268 268 268 268 268 128 268 116 268 268 268 163 255 169 198 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 358 375 375 375 375 375 375 375 375 375 375 375 375 375 358 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 146 146 153 241 138 149 215 588 977 141 556 145 768 526 136 171 1,388 120 Annual Additions, Short Term Resources 727 968 1,024 988 1,153 1,180 858 1,311 1,272 1,297 1,322 1,353 1,047 1,370 991 1,320 1,300 1,437 1,119 1,430 Total Annual Additions 859 1,114 1,170 1,135 1,305 1,422 996 1,460 1,487 1,885 2,299 1,494 1,603 1,514 1,759 1,846 1,436 1,608 2,507 1,550 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 170 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,481 - 423 3,464 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 86 DSM, Class 2, UT 69 78 84 86 92 81 84 87 89 90 73 73 74 72 70 66 65 65 63 64 840 1,523 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 15 15 15 121 260 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 92 90 88 84 84 84 82 83 1,005 1,870 FOT Mona Q3 - - - - 10 53 - 179 169 101 184 222 294 79 44 277 267 86 75 300 51 117 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - 10.6 - - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - - 5.0 - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 10.6 5.0 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 24 23 21 21 22 21 21 20 20 20 19 19 303 506 DSM, Class 2, WA 8 9 10 10 10 9 10 10 11 11 9 9 9 9 8 8 8 8 7 7 97 177 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 32 30 31 29 29 29 27 27 416 712 FOT COB Q3 - 93 149 113 268 268 - 268 268 268 268 268 268 268 182 268 268 268 148 242 169 207 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 374 375 375 375 375 375 375 375 375 375 375 375 375 375 360 368 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 152 135 137 153 149 569 124 131 124 857 118 536 123 513 1,595 110 Annual Additions, Short Term Resources 727 968 1,024 988 1,153 1,196 874 1,322 1,312 1,244 1,327 1,365 1,437 1,221 1,101 1,420 1,410 1,229 1,098 1,417 Total Annual Additions 860 1,114 1,170 1,135 1,305 1,330 1,011 1,475 1,461 1,812 1,451 1,496 1,560 2,078 1,219 1,956 1,533 1,743 2,694 1,527 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05a-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 171 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,481 - 423 3,464 Wind, DJohnston, 43 - - - - - - - - - - - - - 13 - - - - - - - 13 Wind, WYAE, 43 - - - - - - - - - - - - - 12 - - - - - - - 12 Total Wind - - - - - - - - - - - - - 25 - - - - - - - 25 Utility Solar - PV - East - - - - - - - - - - - - - 154 - - - - - - - 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 86 DSM, Class 2, UT 69 78 84 86 92 81 84 88 89 90 73 73 72 72 70 66 65 65 63 64 840 1,522 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 15 15 15 121 260 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 90 90 88 84 84 84 82 83 1,005 1,869 FOT Mona Q3 - - - - 10 53 - 185 169 101 184 222 295 44 44 146 135 75 44 225 52 97 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - - - - 277 - - - - - - - 277 Total Wind - - - - - - - - - - - - - 277 - - - - - - - 277 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 28 DSM, Class 2, OR 44 39 36 33 29 27 25 25 23 23 21 21 21 21 20 20 20 20 19 19 303 503 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 8 8 8 8 7 7 97 177 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 31 30 29 29 29 29 27 27 415 709 FOT COB Q3 - 93 149 114 268 268 - 268 268 268 268 268 268 170 50 268 268 148 53 191 170 182 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 374 375 375 375 375 375 375 375 375 375 375 375 375 375 360 368 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 152 135 137 147 155 569 124 131 121 1,313 117 536 123 513 1,590 110 Annual Additions, Short Term Resources 727 968 1,024 989 1,153 1,196 874 1,328 1,312 1,244 1,327 1,365 1,438 1,089 969 1,289 1,278 1,098 972 1,291 Total Annual Additions 860 1,114 1,170 1,135 1,305 1,330 1,011 1,475 1,467 1,813 1,451 1,496 1,559 2,402 1,086 1,825 1,402 1,611 2,562 1,401 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05b-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 172 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - 635 - - - 635 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - 423 - - - - - - - 423 846 Total CCCT - - - - - - - - - 423 846 - 423 - 635 401 - - 1,270 - 423 3,998 Wind, DJohnston, 43 - - - - - - - - - - - - - 9 - - - - - - - 9 Total Wind - - - - - - - - - - - - - 9 - - - - - - - 9 Utility Solar - PV - East - - - - - - - - - - - - - - - - - 62 - - - 62 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - 11.2 - - - 11.2 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - 10.0 - - - 10.0 DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - 3.1 - - - - 3.1 DSM, Class 1 Total - - - - - - - - - - - - - - - - 3.1 26.1 - - - 29.1 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 5 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 86 90 91 93 78 81 84 84 81 75 76 74 69 69 849 1,620 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 16 16 16 16 16 122 272 DSM, Class 2 Total 79 90 99 102 111 97 103 108 110 115 96 99 103 104 101 95 96 95 89 89 1,015 1,983 FOT Mona Q3 - - - - 9 52 - 181 163 192 218 248 44 263 21 214 190 300 75 300 60 124 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 36 32 29 27 25 25 23 24 22 22 22 22 22 21 21 21 20 19 304 515 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 36 32 32 32 32 32 30 30 30 28 28 418 725 FOT COB Q3 - 93 148 113 268 268 - 268 268 268 268 268 165 268 131 268 268 268 175 263 169 202 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 371 375 375 375 375 375 375 375 375 375 375 375 375 375 360 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 147 146 146 153 135 139 149 157 574 977 141 558 145 768 526 140 214 1,387 117 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 1,195 871 1,324 1,306 1,335 1,361 1,391 1,084 1,406 1,027 1,357 1,333 1,443 1,125 1,438 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,329 1,010 1,473 1,463 1,909 2,338 1,533 1,642 1,551 1,796 1,883 1,473 1,657 2,512 1,555 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05a-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 173 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 635 - - 2,217 Wind, DJohnston, 43 - - - - - - - - - - - - - - - - - - - 25 - 25 Total Wind - - - - - - - - - - - - - - - - - - - 25 - 25 Utility Solar - PV - East - - - - - - - - - - - - - - - - - 100 - 54 - 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 5 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 85 90 94 93 75 81 80 80 79 73 72 73 73 71 851 1,607 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 121 271 DSM, Class 2 Total 79 90 99 102 111 97 102 108 113 115 92 99 99 99 98 92 93 94 94 92 1,017 1,969 FOT Mona Q3 - - - - - - - - - - - - - 185 57 144 126 300 300 300 - 71 West Expansion Resources Wind, YK, 29 - - - - - - - - 261 - - - - - - - - - - - 261 261 Total Wind - - - - - - - - 261 - - - - - - - - - - - 261 261 Utility Solar - PV - West - - - - - - - - - - - - - - - - - - - 599 - 599 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - 3.7 - - - - - - - - - - - 3.7 3.7 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 3.7 10.6 3.4 10.6 - - - - 10.6 - - - 19.3 43.9 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 28 25 25 23 23 21 22 22 22 21 21 21 21 20 19 303 512 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 30 30 28 28 417 721 FOT COB Q3 - 93 149 113 178 220 - - - - - - - 268 268 268 268 219 173 263 75 124 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 274 307 227 182 263 293 360 375 375 375 375 375 375 375 309 332 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 133 146 146 146 153 135 138 149 414 160 126 141 130 555 129 1,282 133 224 757 798 Annual Additions, Short Term Resources 727 968 1,024 988 1,053 1,095 774 807 727 682 763 793 860 1,328 1,200 1,287 1,269 1,394 1,348 1,438 Total Annual Additions 859 1,114 1,170 1,135 1,205 1,230 913 956 1,141 842 889 935 990 1,883 1,329 2,569 1,403 1,618 2,106 2,236 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05-3 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 174 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 635 - - 2,217 Wind, DJohnston, 43 - - - - - - - - - - - - - - - - - - - 26 - 26 Total Wind - - - - - - - - - - - - - - - - - - - 26 - 26 Utility Solar - PV - East - - - - - - - - - - - - - - - - - 100 - 54 - 154 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - - 25.9 - 25.9 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - - - 19.0 - 19.0 DSM, Class 1 Total - - - - - - - - - - - - - - - - - 4.9 - 45.0 - 49.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 5 4 4 46 92 DSM, Class 2, UT 69 78 84 86 94 83 86 90 91 93 81 81 84 84 81 75 76 75 73 73 852 1,634 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 122 273 DSM, Class 2 Total 79 90 99 102 113 99 103 108 111 115 99 99 103 104 101 95 96 96 94 94 1,020 1,999 FOT Mona Q3 - - - - - - - - - - - - 44 248 117 191 182 300 300 300 - 84 West Expansion Resources Utility Solar - PV - West - - - - - - - - - - - - - - - - - - - 584 - 584 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - 10.6 - - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - - - - - - 5.0 5.0 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - - 10.6 - - - - 15.6 36.8 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 33 29 27 25 25 23 24 22 22 22 22 21 21 21 21 20 20 304 514 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 50 47 44 42 38 36 36 36 36 32 32 32 32 32 30 30 30 28 28 418 724 FOT COB Q3 - 93 148 113 176 217 - - - - - - 7 268 268 268 268 268 222 268 75 129 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 226 375 375 375 375 375 271 303 289 254 333 363 375 375 375 375 375 375 375 375 322 346 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 133 147 146 147 155 137 139 149 157 151 130 141 135 559 132 1,295 126 231 757 831 Annual Additions, Short Term Resources 726 968 1,023 988 1,051 1,092 771 803 789 754 833 863 926 1,391 1,260 1,334 1,325 1,443 1,397 1,443 Total Annual Additions 860 1,114 1,169 1,134 1,205 1,228 910 952 946 905 963 1,005 1,061 1,950 1,392 2,629 1,451 1,674 2,154 2,274 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05a-3 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 175 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 635 - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 635 635 - 2,852 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 5 4 45 90 DSM, Class 2, UT 69 78 84 86 92 81 84 90 91 93 75 76 80 80 77 75 72 72 73 70 847 1,596 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 121 271 DSM, Class 2 Total 79 90 99 102 111 97 101 108 110 114 92 94 99 99 97 94 93 92 94 92 1,012 1,958 FOT Mona Q3 - - - - - - - - - - - - - 161 44 110 104 268 300 74 - 53 West Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - 10.6 - - - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - - - - - - 5.0 5.0 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - 10.6 - - - - - 15.6 36.8 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 33 29 27 25 25 23 23 21 22 22 22 21 21 20 21 20 20 303 511 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 29 30 28 28 417 721 FOT COB Q3 - 62 29 - 60 104 - - - - - - - 268 248 268 268 268 185 138 26 95 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 370 375 375 269 291 261 254 271 292 335 375 375 375 375 375 375 375 317 335 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 133 146 146 146 153 135 137 149 157 149 123 137 130 555 139 1,284 122 122 762 755 Annual Additions, Short Term Resources 727 937 904 870 935 979 769 791 761 754 771 792 835 1,304 1,167 1,253 1,247 1,411 1,360 1,087 Total Annual Additions 860 1,084 1,050 1,016 1,088 1,113 906 941 917 903 893 928 965 1,859 1,305 2,537 1,369 1,533 2,123 1,841 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05a-3Q Preferred Portfolio PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 176 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 635 - - 2,217 Wind, DJohnston, 43 - - - - - - - - - - - - - - - - - - - 25 - 25 Total Wind - - - - - - - - - - - - - - - - - - - 25 - 25 Utility Solar - PV - East - - - - - - - - - - - - - - - - - 100 - 54 - 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 85 90 94 93 75 81 80 80 79 73 72 71 73 71 851 1,605 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 121 271 DSM, Class 2 Total 79 90 99 102 111 97 102 108 114 115 92 99 99 99 98 92 93 92 94 92 1,017 1,967 FOT Mona Q3 - - - - - - - - - - - - 44 139 44 98 80 217 300 300 - 61 West Expansion Resources Wind, WW, 29 - - - - - - - - - - - - - 48 - - - - - - - 48 Wind, YK, 29 - - - - - - - - - - - - - 400 - - - - - - - 400 Total Wind - - - - - - - - - - - - - 448 - - - - - - - 448 Utility Solar - PV - West - - - - - - - - - - - - - - - - - - - 599 - 599 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - 0.3 5.0 8.7 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - 0.3 15.6 40.5 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 28 25 25 23 23 21 22 22 22 21 21 21 21 20 19 303 511 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 30 30 28 28 417 721 FOT COB Q3 - 93 149 113 178 220 - - - - - - 15 268 235 268 268 257 129 218 75 121 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 274 307 291 255 337 367 375 375 375 375 375 375 375 375 323 347 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 133 146 146 146 153 135 138 149 160 150 126 141 130 1,003 129 1,282 133 222 757 799 Annual Additions, Short Term Resources 727 968 1,024 988 1,053 1,095 774 807 791 755 837 867 934 1,282 1,154 1,241 1,223 1,350 1,304 1,393 Total Annual Additions 859 1,114 1,170 1,135 1,205 1,230 913 956 950 905 963 1,009 1,064 2,285 1,283 2,523 1,357 1,572 2,061 2,192 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C05b-3 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 177 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 313 - 423 - 401 1,269 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - - - 150 - - - - - - - - - - - - 150 150 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 20 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 143 142 154 138 143 154 157 157 132 147 148 149 146 132 130 130 129 128 1,357 2,728 FOT Mona Q3 - - - - - - - - - 32 77 61 79 178 44 278 225 76 300 8 3 68 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 5.0 10.6 - 10.6 - - - - 10.6 - - - 19.0 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 48 46 44 41 39 37 36 37 37 35 33 33 33 30 30 470 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 66 64 63 61 54 53 53 53 50 46 45 45 42 42 662 1,145 FOT COB Q3 - 93 100 19 137 131 - 116 57 268 268 268 268 268 228 268 268 193 17 - 92 148 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 192 375 375 375 375 375 375 375 375 375 375 375 375 375 342 358 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 226 221 229 232 209 371 225 229 186 210 201 516 196 601 186 576 1,440 805 Annual Additions, Short Term Resources 727 968 975 894 1,012 1,006 692 991 932 1,175 1,220 1,204 1,222 1,321 1,147 1,421 1,368 1,144 1,192 883 Total Annual Additions 859 1,115 1,200 1,116 1,240 1,237 901 1,362 1,156 1,404 1,405 1,414 1,424 1,837 1,343 2,022 1,554 1,720 2,632 1,688 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C06-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 178 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - 423 - - - - - 846 Total CCCT - - - - - - - - - - 846 - - 423 - 824 - - 1,371 - - 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - - - 150 - - - - - - - - - - - - 150 150 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 20 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 143 142 154 138 143 154 157 157 132 147 148 149 146 132 131 130 129 129 1,357 2,728 FOT Mona Q3 - - - - - - - - - 132 124 108 127 44 200 125 70 198 42 174 13 67 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 5.0 10.6 - 10.6 - - - - 10.6 - - - 19.0 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 49 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 51 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 99 19 136 130 - 116 57 268 268 268 268 260 268 268 268 268 - 145 92 160 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 192 375 375 375 375 375 375 375 375 375 375 375 375 375 342 358 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 226 221 229 232 208 371 225 229 1,031 210 201 625 196 1,001 187 175 1,548 170 Annual Additions, Short Term Resources 727 968 974 894 1,011 1,005 692 991 932 1,275 1,267 1,251 1,270 1,179 1,343 1,268 1,213 1,341 917 1,194 Total Annual Additions 859 1,115 1,200 1,115 1,240 1,237 900 1,362 1,157 1,504 2,299 1,462 1,471 1,804 1,540 2,269 1,400 1,515 2,464 1,364 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C06-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 179 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 313 - 423 - 401 1,269 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 111 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 21 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 143 142 154 138 143 154 157 157 132 147 148 149 146 132 130 130 129 128 1,357 2,728 FOT Mona Q3 - - - - - - - - - - 44 44 44 44 44 73 44 - 29 - - 18 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, WW, 29 - - - - - - - - - - - - - - - - 213 - - - - 213 Wind, YK, 29 - - - - - - 45 - - - - - - - - 225 130 - - - 45 400 Total Wind - - - - - - 45 - - - - - - - - 225 343 - - - 45 613 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - 3.4 - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - - 3.4 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 51 49 45 44 41 39 37 37 37 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 74 68 65 64 63 61 54 53 53 53 50 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 100 19 136 - - - - 152 153 137 155 254 80 268 161 - - - 50 85 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 310 42 338 273 375 375 375 375 375 375 375 375 357 375 95 307 326 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 226 221 229 791 253 223 230 218 186 210 201 516 196 829 529 576 1,440 805 Annual Additions, Short Term Resources 727 968 975 894 1,011 810 542 838 773 1,027 1,072 1,056 1,074 1,173 999 1,216 1,080 857 904 595 Total Annual Additions 859 1,115 1,200 1,115 1,240 1,601 795 1,061 1,004 1,246 1,257 1,266 1,276 1,689 1,195 2,045 1,609 1,432 2,344 1,401 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C07-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 180 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - 423 - - - - - 846 Total CCCT - - - - - - - - - - 846 - - 423 - 824 - - 1,371 - - 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 8 8 7 7 7 6 6 6 6 6 82 149 DSM, Class 2, UT 69 78 115 112 122 109 112 122 124 123 105 119 121 121 118 105 104 102 102 101 1,083 2,180 DSM, Class 2, WY 6 8 18 21 23 21 22 23 24 25 20 20 20 21 21 20 21 21 21 22 192 399 DSM, Class 2 Total 79 90 142 142 154 138 143 154 157 157 132 147 148 149 146 131 131 130 129 129 1,357 2,729 FOT Mona Q3 - - - - - - - - - - 74 75 44 44 44 44 28 75 - 139 - 28 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, YK, 29 - - - - - - 91 - - - - - - - - 14 78 - - - 91 183 Total Wind - - - - - - 91 - - - - - - - - 14 78 - - - 91 183 Utility Solar - PV - West - - - - - 405 - - - - - - - - - - - - - - 405 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 21.2 - - - - - - 10.6 - - - 21.2 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 3.4 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 5.0 3.4 21.2 - - - - - - 10.6 - - - 29.6 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 3 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 60 58 50 48 45 44 41 39 37 37 36 37 35 33 33 33 30 30 469 809 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 164 285 DSM, Class 2 Total 54 49 83 80 73 68 65 64 63 61 54 53 53 53 51 46 45 45 42 42 661 1,145 FOT COB Q3 - 93 100 18 136 - - - - 227 145 138 188 97 262 183 126 206 - - 57 96 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 310 31 327 269 375 375 375 375 375 375 375 375 375 237 375 304 333 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 226 222 228 791 299 223 223 240 1,031 200 201 625 196 1,015 265 175 1,543 170 Annual Additions, Short Term Resources 727 968 975 893 1,011 810 531 827 769 1,102 1,094 1,088 1,107 1,016 1,181 1,102 1,029 1,156 737 1,014 Total Annual Additions 859 1,115 1,200 1,116 1,239 1,600 830 1,050 992 1,342 2,125 1,288 1,308 1,642 1,377 2,117 1,294 1,331 2,280 1,185 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C07-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 181 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - 423 - - - - - - - - - - - 423 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423 CCCT - Utah-S - J 1x1 - - - - - - - 423 - - - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - 423 423 - - - - 313 - 824 - - 1,058 423 846 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - 1 - 25 26 Total Wind - - - - - 25 - - - - - - - - - - - - 1 - 25 26 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, ID-Irrigate - - - - 3.5 - - - - - - - - - - - - - 21.1 - 3.5 24.6 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1, UT-Irrigate - - - - 10.1 - - - - - - - - - - - - - 6.4 - 10.1 16.5 DSM, Class 1 Total - - - - 13.5 - - - - - - - - - - - - - 32.4 - 13.5 46.0 DSM, Class 2, ID 4 6 6 6 7 4 4 4 5 5 5 5 5 5 5 4 4 5 5 4 51 98 DSM, Class 2, UT 83 93 100 102 110 85 86 90 93 97 81 81 84 84 81 75 75 75 74 73 938 1,719 DSM, Class 2, WY 7 9 10 13 15 12 13 14 15 16 13 13 14 15 15 15 16 16 17 17 125 276 DSM, Class 2 Total 94 107 116 120 132 101 103 108 113 118 99 99 103 104 100 95 95 96 95 94 1,114 2,094 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - 21 - - - - - - - - - - - - 21 21 Total Wind - - - - - - - 21 - - - - - - - - - - - - 21 21 Utility Solar - PV - West - - - - - - - - - - - - - - - - - - 421 - - 421 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - 21.2 - - - - - - - - - - - 10.6 - - - 21.2 31.8 DSM, Class 1, OR-Irrigate - - - - 5.0 - - - - - - - - - - 3.4 - - - - 5.0 8.4 DSM, Class 1 Total - - - - 26.2 - - - - - - - - - - 3.4 10.6 - - - 26.2 40.2 DSM, Class 2, CA 2 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 18 31 DSM, Class 2, OR 44 40 37 34 31 27 25 25 24 23 22 22 22 22 21 21 21 21 21 20 309 520 DSM, Class 2, WA 9 10 11 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 102 186 DSM, Class 2 Total 55 52 50 47 45 38 36 36 36 35 32 32 32 32 31 30 30 30 30 28 428 737 FOT COB Q3 - 67 108 58 265 245 - 4 - - - 42 105 248 117 73 54 214 268 208 75 104 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 214 375 375 375 375 375 338 375 340 334 375 375 375 375 375 375 375 375 375 375 348 361 FOT NOB Q3 100 100 100 100 - - - - - - - - - - - - - - - - 40 20 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 149 166 165 167 216 318 139 588 572 153 130 131 136 449 132 952 136 126 1,638 545 Annual Additions, Short Term Resources 714 942 983 933 1,040 1,020 738 779 740 734 775 817 880 1,023 892 848 829 989 1,043 983 Total Annual Additions 863 1,107 1,149 1,100 1,257 1,338 877 1,367 1,312 888 905 948 1,015 1,472 1,024 1,801 965 1,115 2,680 1,528 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C09-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 182 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - 423 - - 423 - - - - - - - - - 423 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - 635 - 635 - - - - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 423 - - - - - - - - - 423 846 Total CCCT - - - - - - - 423 - 423 846 - - 635 - 635 - - 1,137 - 846 4,099 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - 1 25 26 Total Wind - - - - - 25 - - - - - - - - - - - - - 1 25 26 Utility Solar - PV - East - - - - - 144 - - - - - - - - - - - 1 - 9 144 154 DSM, Class 1, ID-Irrigate - - - - 3.5 - - - - - - - - - - - - 11.2 - 11.3 3.5 25.9 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 10.0 - 10.0 DSM, Class 1, UT-Irrigate - - - - 10.1 - - - - - - - - - - - - 6.4 - 2.5 10.1 19.0 DSM, Class 1 Total - - - - 13.5 - - - - - - - - - - - - 17.6 - 23.8 13.5 54.9 DSM, Class 2, ID 4 6 6 6 7 4 4 4 5 5 5 5 5 5 5 4 4 5 5 4 51 98 DSM, Class 2, UT 83 93 100 102 110 85 86 90 91 93 79 81 84 84 81 76 76 76 73 76 931 1,716 DSM, Class 2, WY 7 9 10 13 15 12 13 14 15 16 13 13 14 15 15 16 16 17 17 17 124 277 DSM, Class 2 Total 94 107 116 120 132 101 103 108 110 114 97 99 103 104 101 96 96 97 94 98 1,106 2,091 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - 39 - - - - - - - - - - 39 39 Total Wind - - - - - - - - - 39 - - - - - - - - - - 39 39 Utility Solar - PV - West - - - - - - - - - - - - - - - - - 124 - 384 - 508 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - 21.2 - - - - - - - - - - - 10.6 - - - 21.2 31.8 DSM, Class 1, OR-Irrigate - - - - 5.0 - - - - - - - - - - 3.4 - - - - 5.0 8.4 DSM, Class 1 Total - - - - 26.2 - - - - - - - - - - 3.4 10.6 - - - 26.2 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 17 31 DSM, Class 2, OR 44 40 37 34 31 27 25 25 24 23 22 22 22 22 22 21 21 23 20 21 309 524 DSM, Class 2, WA 9 10 11 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 8 102 186 DSM, Class 2 Total 55 52 50 47 45 38 36 36 36 35 32 32 32 33 32 30 30 32 28 30 428 741 FOT COB Q3 - 67 108 58 266 249 - 13 7 27 54 95 158 8 216 247 234 268 118 268 79 123 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 214 375 375 375 375 375 338 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365 FOT NOB Q3 100 100 100 100 - - - - - - - - - - - - - - - - 40 20 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 149 166 165 167 216 308 139 567 146 612 975 131 136 772 134 765 137 272 1,260 546 Annual Additions, Short Term Resources 714 942 983 933 1,041 1,024 738 788 782 802 829 870 933 783 991 1,022 1,009 1,043 893 1,043 Total Annual Additions 863 1,107 1,149 1,100 1,257 1,332 877 1,356 928 1,413 1,804 1,001 1,069 1,555 1,125 1,786 1,146 1,315 2,153 1,588 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C09-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 183 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 635 - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - 423 - - - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,058 635 423 3,676 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 5 5 5 4 4 5 5 5 4 4 4 4 3 46 87 DSM, Class 2, UT 69 81 87 91 102 89 89 91 89 87 74 75 80 79 77 71 69 67 65 57 875 1,587 DSM, Class 2, WY 6 10 11 13 15 13 14 15 15 16 13 13 13 14 14 14 15 15 15 13 128 268 DSM, Class 2 Total 79 95 103 109 122 106 108 110 109 107 91 92 98 98 95 89 87 86 84 74 1,049 1,942 FOT Mona Q3 - - - - - - - 52 32 - 53 94 168 44 44 146 152 75 282 75 8 61 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - 4 - - - - - - - - - - 4 4 Total Wind - - - - - - - - - 4 - - - - - - - - - - 4 4 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - 10.6 - - - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - - - - - - 5.0 5.0 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - 10.6 - - - - - 15.6 36.8 DSM, Class 2, CA 1 2 2 2 2 2 2 2 2 1 1 1 1 1 1 1 1 1 1 1 17 29 DSM, Class 2, OR 44 40 39 39 38 37 35 32 31 28 17 16 14 14 12 11 10 10 10 10 361 483 DSM, Class 2, WA 8 9 10 10 11 9 10 10 10 9 8 8 8 8 8 7 6 6 6 5 97 169 DSM, Class 2 Total 54 51 51 51 52 48 46 43 42 39 26 25 23 23 21 19 18 18 17 16 475 682 FOT COB Q3 - 87 134 88 237 207 - 268 268 231 268 268 268 177 48 268 268 171 208 163 152 181 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 248 375 375 375 375 375 375 375 375 375 375 375 375 375 348 361 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 153 154 160 174 333 154 158 161 573 117 128 121 857 127 531 105 504 1,164 725 Annual Additions, Short Term Resources 727 962 1,009 963 1,112 1,082 748 1,195 1,175 1,106 1,196 1,237 1,311 1,096 967 1,289 1,295 1,121 1,366 1,113 Total Annual Additions 859 1,114 1,163 1,123 1,286 1,414 902 1,353 1,336 1,679 1,313 1,365 1,432 1,953 1,093 1,820 1,400 1,625 2,530 1,838 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C11-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 184 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - 635 - - - 635 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - 423 - - - - - - 423 846 Total CCCT - - - - - - - - - 423 846 - - 423 635 401 - - 1,270 - 423 3,998 Wind, DJohnston, 43 - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Total Wind - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Utility Solar - PV - East - - - - - - - - - 34 - - - - - - - - - 26 34 60 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - 11.2 - 6.0 - 17.1 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - 10.0 - 2.5 - 12.5 DSM, Class 1 Total - - - - - - - - - - - - - - - - - 26.1 - 8.5 - 34.6 DSM, Class 2, ID 4 4 5 5 6 4 4 5 5 5 4 5 5 5 5 4 4 4 4 4 46 90 DSM, Class 2, UT 69 81 87 95 102 89 89 91 95 92 81 81 80 80 77 71 69 69 64 66 890 1,626 DSM, Class 2, WY 6 10 11 13 15 13 14 15 15 16 13 13 14 15 15 15 15 15 15 15 128 274 DSM, Class 2 Total 79 95 103 113 122 106 108 110 115 113 98 99 99 99 97 90 88 88 83 85 1,064 1,990 FOT Mona Q3 - - - - - - - 97 79 80 106 142 215 179 - 154 148 300 75 300 26 94 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - 3.7 - - - - - - - - - - - 3.7 3.7 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 - - 5.0 - - - - - - - - - 3.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 3.7 10.6 5.0 10.6 - - - - 10.6 - - - 17.7 43.9 DSM, Class 2, CA 1 2 2 2 2 2 2 2 2 2 1 1 1 1 2 1 1 1 1 1 17 30 DSM, Class 2, OR 44 40 39 39 39 37 35 32 31 28 17 16 14 14 12 11 11 11 10 11 362 486 DSM, Class 2, WA 8 9 10 10 11 10 10 10 10 9 9 9 8 8 8 7 6 6 6 6 98 170 DSM, Class 2 Total 54 51 51 51 52 48 46 43 42 39 27 26 23 23 21 19 18 19 17 17 476 686 FOT COB Q3 - 87 134 86 235 250 - 268 268 268 268 268 268 268 80 268 268 262 182 263 160 199 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 291 375 375 375 375 375 375 375 375 375 375 375 375 375 352 363 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 153 154 164 175 260 154 156 160 640 976 135 122 546 752 510 117 133 1,370 136 Annual Additions, Short Term Resources 727 962 1,009 961 1,110 1,125 791 1,240 1,222 1,223 1,249 1,285 1,358 1,322 955 1,297 1,291 1,437 1,132 1,438 Total Annual Additions 859 1,114 1,163 1,125 1,285 1,385 945 1,396 1,382 1,864 2,225 1,420 1,480 1,868 1,707 1,806 1,408 1,570 2,502 1,574 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C11-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 185 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - 313 - 627 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - - 1,036 313 423 2,932 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 13 - - - - 16 - 106 135 Total Wind - - - - - 106 - - - - - - - 13 - - - - 16 - 106 135 Utility Solar - PV - East - - - - - - - - 63 - - - - - - - - - - - 63 63 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - 11.2 - - - 11.2 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - 3.5 - - - 3.5 DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - 16.2 - - - 16.2 DSM, Class 1 Total - - - - - - - - - - - - - - - - - 35.8 - - - 35.8 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 4 4 45 90 DSM, Class 2, UT 69 78 84 86 92 80 84 90 91 90 78 81 80 84 81 75 74 73 63 64 843 1,596 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 14 15 15 15 16 15 15 121 267 DSM, Class 2 Total 79 90 99 102 111 97 101 108 110 111 95 99 98 103 100 95 94 94 82 83 1,009 1,952 FOT Mona Q3 - - - - 10 38 - 168 128 60 132 162 229 44 44 178 165 300 300 300 40 113 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - - - - 454 - - 454 Total CCCT - - - - - - - - - - - - - - - - - - 454 - - 454 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - 10.6 10.6 - - - - - - - - 10.6 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - 4.5 - - - - 4.5 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - 3.4 - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 10.6 10.6 - - 3.4 - 4.5 - - - 15.6 44.7 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 21 22 22 21 20 21 21 18 19 302 507 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 7 7 98 180 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 32 32 31 30 30 30 27 27 416 716 FOT COB Q3 - 93 148 113 268 268 - 268 268 268 268 268 268 225 91 268 268 258 122 160 169 194 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 359 375 375 375 375 375 375 375 375 375 375 375 375 375 359 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 153 241 137 149 220 569 137 140 130 884 135 547 128 160 1,615 423 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 1,181 859 1,311 1,271 1,203 1,275 1,305 1,372 1,144 1,010 1,321 1,308 1,433 1,297 1,335 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,421 996 1,461 1,491 1,772 1,411 1,445 1,502 2,028 1,146 1,868 1,437 1,592 2,912 1,758 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C12-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 186 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - 423 423 - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 423 - - - - - - - - - 423 846 Total CCCT - - - - - - - - - 423 423 - - - 423 423 - 401 635 423 423 3,151 Wind, DJohnston, 43 - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Total Wind - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Utility Solar - PV - East - - - - - - - - - 55 - - - - - - - - - - 55 55 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - 24.6 - - 24.6 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 28.4 - - 28.4 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - - 16.5 - - 16.5 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 69.4 - - 69.4 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 5 4 45 91 DSM, Class 2, UT 69 78 84 86 92 80 86 90 91 94 81 81 84 84 81 75 74 73 73 66 849 1,621 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 15 16 17 15 122 270 DSM, Class 2 Total 79 90 99 102 111 97 103 108 110 115 99 99 102 104 101 95 94 94 94 86 1,015 1,982 FOT Mona Q3 - - - - 9 38 - 168 146 152 202 181 245 151 75 300 300 300 300 300 51 143 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - 454 - - - - - - - - - - 454 CCCT - WillamValcc - J 1x1 - - - - - - - - - - - - - 477 - - - - - - - 477 Total CCCT - - - - - - - - - - 454 - - 477 - - - - - - - 932 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - 10.6 - - - - - - - - - 10.6 21.2 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 15.6 - 10.6 - - - - - - - - - 19.0 29.6 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 22 22 22 21 20 20 21 20 19 302 509 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 180 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 29 30 28 27 416 718 FOT COB Q3 - 93 148 113 268 268 - 268 268 268 207 268 268 268 182 268 260 71 264 211 169 198 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 357 375 375 375 375 375 375 375 375 375 375 375 375 375 358 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 146 146 146 153 241 139 148 162 649 1,017 131 134 613 555 547 123 525 827 535 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 1,180 857 1,311 1,289 1,294 1,284 1,324 1,388 1,294 1,132 1,443 1,435 1,246 1,439 1,386 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,421 996 1,459 1,451 1,943 2,301 1,455 1,522 1,908 1,687 1,990 1,558 1,771 2,266 1,921 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C12-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 187 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - - - 423 - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-S - F 2x1 - - - - - - - - - - - - - - - 635 - - - - - 635 Total CCCT - - - - - - - - - - - - - 313 - 635 - 423 824 - - 2,195 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - 0 - - - - - - 154 154 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - - 25.9 - 25.9 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - - - - - 12.5 - 12.5 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 38.4 - 38.4 DSM, Class 2, ID 4 4 5 5 5 4 4 5 6 6 5 5 5 5 5 4 4 4 4 4 47 92 DSM, Class 2, UT 69 78 84 86 92 83 86 90 98 101 81 85 84 84 75 72 71 73 71 73 865 1,633 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 14 15 16 16 17 122 270 DSM, Class 2 Total 79 90 99 102 111 99 103 109 118 123 99 103 103 104 94 90 91 93 91 94 1,034 1,995 FOT Mona Q3 - - - - 9 - - 114 - - 75 94 157 300 175 273 268 300 300 278 12 117 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - - - - 454 454 - 909 CCCT - WillamValcc - J 1x1 - - - - - - - - 477 - - - - - - - - - - - 477 477 Total CCCT - - - - - - - - 477 - - - - - - - - - 454 454 477 1,386 Wind, YK, 29 - - - - - - - 22 - - - - - - - - - - - - 22 22 Total Wind - - - - - - - 22 - - - - - - - - - - - - 22 22 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - - - - - - 5.0 5.0 DSM, Class 1 Total - - - - - - - 5.0 - - - - - - - - - - - - 5.0 5.0 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 22 22 22 22 20 19 19 19 18 18 302 503 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 8 8 8 8 7 7 98 179 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 32 32 32 32 29 28 28 28 27 26 417 710 FOT COB Q3 - 93 148 113 268 258 - 268 - 245 249 268 268 268 268 268 268 30 105 - 139 169 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 310 375 328 375 375 375 375 375 375 375 375 375 375 375 349 362 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 147 146 146 153 316 139 172 632 158 130 135 135 450 123 753 119 544 1,396 613 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 1,133 810 1,257 828 1,120 1,199 1,237 1,300 1,443 1,318 1,416 1,411 1,205 1,280 1,153 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,449 949 1,429 1,459 1,278 1,330 1,372 1,435 1,892 1,441 2,170 1,530 1,748 2,676 1,766 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C13-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 188 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Huntington - J 1x1 - - - - - - - - - - 423 - - 423 - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423 CCCT - Utah-S - J 1x1 - - - - - - - - 423 423 - - - - - - - - - - 846 846 Total CCCT - - - - - - - - 423 423 423 - - 423 - 401 - - 635 423 846 3,151 Wind, DJohnston, 43 - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Total Wind - - - - - 106 - - - 21 - - - - - - - - - - 127 127 Utility Solar - PV - East - - - - - - - - - 55 - - - - - - - - - - 55 55 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - 11.2 - - 13.4 - - 24.6 DSM, Class 1, UT-Irrigate - - - - - - - - - - - - - - - 6.6 - - 9.9 - - 16.5 DSM, Class 1 Total - - - - - - - - - - - - - - - 17.8 - - 23.3 - - 41.0 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 46 92 DSM, Class 2, UT 69 78 84 86 92 83 86 93 95 105 85 85 84 84 81 75 74 73 71 64 870 1,645 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 16 15 16 17 15 122 271 DSM, Class 2 Total 79 90 99 102 111 99 103 112 115 127 103 103 104 104 101 95 94 93 92 83 1,038 2,008 FOT Mona Q3 - - - - 9 36 - 151 - - 147 184 247 200 44 300 292 300 300 300 20 126 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources CCCT - SOregonCal - J 1x1 - - - - - - - - - - - - - - - - - 454 - - - 454 CCCT - WillamValcc - J 1x1 - - - - - - - - - - - - - - 477 - - - - - - 477 Total CCCT - - - - - - - - - - - - - - 477 - - 454 - - - 932 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - 10.6 - 10.6 - - - - - - - - - - 21.2 21.2 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - 3.4 - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 15.6 - 14.0 - - - - - - - - - - 29.6 29.6 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 2 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 22 22 22 22 22 21 20 20 20 19 302 511 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 50 47 44 42 38 36 36 36 35 32 32 32 32 33 30 29 29 28 27 417 722 FOT COB Q3 - 92 148 113 268 268 - 268 39 21 268 268 268 268 214 268 268 26 268 217 122 177 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 355 375 375 375 375 375 375 375 375 375 375 375 375 375 358 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 133 147 146 146 153 243 139 164 574 675 557 135 136 559 611 544 123 577 778 533 Annual Additions, Short Term Resources 727 967 1,023 988 1,152 1,178 855 1,294 914 896 1,290 1,327 1,390 1,343 1,133 1,443 1,435 1,201 1,443 1,392 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,421 994 1,458 1,488 1,571 1,847 1,462 1,526 1,902 1,744 1,987 1,558 1,777 2,221 1,925 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C13-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 189 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - - - 423 - - - - - - - - - - 423 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 Total CCCT - - - - - - - - - 423 - - - - - 401 - - 313 - 423 1,137 Modular-Nuclear-East - - - - - - - - - - - - - - - - 1,037 - 1,037 518 - 2,592 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 326 - - - - 17 - 106 449 Wind, UT, 31 - - - - - - - - - - - - - - - 250 - - - - - 250 Total Wind - - - - - 106 - - - - - - - 326 - 250 - - 17 - 106 699 Utility Solar - PV - East - - - - - - - - - - - - 599 151 - - - - - - - 750 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 5 5 6 6 7 5 6 6 6 6 5 6 6 5 5 5 5 4 4 4 57 107 DSM, Class 2, UT 75 84 98 99 107 95 101 106 108 108 88 87 87 87 84 78 77 76 74 74 981 1,790 DSM, Class 2, WY 7 9 11 14 16 14 15 16 17 18 15 15 15 16 16 16 16 17 17 17 137 298 DSM, Class 2 Total 87 98 114 119 129 114 122 128 131 132 108 108 108 108 105 99 98 97 95 95 1,174 2,195 FOT Mona Q3 - - - - - - - 61 26 - 44 44 69 188 44 294 - - - - 9 38 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - - - - - - 151 - - - - - 151 Total Wind - - - - - - - - - - - - - - - 151 - - - - - 151 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - 10.6 - - - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - - - - - 0.3 5.0 5.3 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - 10.6 - - - - 1.4 15.6 38.1 DSM, Class 2, CA 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 1 1 2 2 19 34 DSM, Class 2, OR 44 40 39 36 32 31 28 30 29 28 26 26 25 25 29 29 23 29 27 27 338 602 DSM, Class 2, WA 9 11 12 11 12 10 11 11 12 12 10 10 10 10 10 8 8 8 8 8 113 202 DSM, Class 2 Total 55 52 53 50 47 43 41 44 43 42 37 37 37 37 40 39 32 38 37 36 469 839 FOT COB Q3 - 80 122 72 221 233 - 268 268 207 233 255 69 268 264 268 - - - - 147 141 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 221 375 375 375 375 375 269 375 375 375 375 375 375 375 375 375 252 256 266 288 349 340 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 142 157 167 168 176 264 163 176 184 597 145 156 743 622 156 939 1,167 135 1,504 651 Annual Additions, Short Term Resources 721 955 997 947 1,096 1,108 769 1,204 1,169 1,082 1,152 1,174 1,012 1,331 1,183 1,437 752 756 766 788 Total Annual Additions 863 1,113 1,164 1,115 1,272 1,372 932 1,380 1,353 1,679 1,297 1,330 1,756 1,953 1,339 2,376 1,919 891 2,270 1,439 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C14-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 190 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - - - - 846 - - - - - - - - - - 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - - - - - - 423 423 Total CCCT - - - - - - - - - 423 846 - - - - 401 - - 313 - 423 1,983 IC Aero WYD - - - - - - - - - - - - - - - - - - 83 - - 83 Modular-Nuclear-East - - - - - - - - - - - - - - - - 1,037 - 518 518 - 2,074 Wind, DJohnston, 43 - - - - - 106 - - - 106 - - - 220 - - - - 17 - 212 449 Wind, WYAE, 43 - - - - - - - - - - - - - - - 299 - - 426 2 - 727 Total Wind - - - - - 106 - - - 106 - - - 220 - 299 - - 443 2 212 1,176 Utility Solar - PV - East - - - - - - - - - - - - 431 146 - - - - - - - 577 DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 45.8 - - 45.8 DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 5.0 - - 5.0 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 50.8 - - 50.8 DSM, Class 2, ID 5 5 6 6 7 5 6 6 6 6 6 6 6 5 5 5 5 4 4 4 57 107 DSM, Class 2, UT 75 91 98 100 110 98 101 106 109 108 88 87 87 87 84 78 77 76 74 74 996 1,806 DSM, Class 2, WY 7 9 11 14 16 14 15 17 17 18 15 15 16 16 16 16 16 17 17 17 137 300 DSM, Class 2 Total 87 106 114 119 132 117 122 128 132 133 108 108 108 108 105 99 98 97 95 95 1,191 2,213 FOT Mona Q3 - - - - - - - 49 12 10 44 46 75 176 299 299 - - - - 7 50 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, WW, 29 - - - - - - - - - - - - - - - 314 - - - - - 314 Wind, YK, 29 - - - - - - - - - - - - - - - 400 - - - - - 400 Total Wind - - - - - - - - - - - - - - - 714 - - - - - 714 Utility Solar - PV - West - - - - - - - - - - - - - - 225 307 - - - - - 532 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - 10.6 - - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - 0.3 5.0 8.7 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - 10.6 - - - 1.4 15.6 41.5 DSM, Class 2, CA 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 1 1 2 2 19 35 DSM, Class 2, OR 45 40 39 36 32 31 29 30 29 28 26 26 32 32 32 29 23 29 27 27 338 620 DSM, Class 2, WA 9 10 12 11 12 11 11 11 12 12 10 10 10 10 10 8 8 8 8 8 113 203 DSM, Class 2 Total 56 52 53 50 47 43 41 44 43 42 37 37 44 44 43 39 33 38 37 36 470 858 FOT COB Q3 - 74 115 65 211 222 - 268 268 268 249 268 137 268 268 268 - - - - 149 147 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 220 375 375 375 375 375 257 375 375 375 375 375 375 375 375 375 20 108 109 115 348 304 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (460) (728) - - (220) (359) (694) (77) - (956) - Annual Additions, Long Term Resources 143 165 167 169 179 267 163 177 186 704 994 156 583 519 374 1,869 1,167 135 1,540 653 Annual Additions, Short Term Resources 720 949 990 940 1,086 1,097 757 1,192 1,155 1,153 1,168 1,189 1,087 1,319 1,442 1,442 520 608 609 615 Total Annual Additions 863 1,113 1,157 1,109 1,265 1,363 920 1,368 1,341 1,857 2,162 1,345 1,669 1,837 1,815 3,311 1,687 743 2,149 1,268 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C14-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 191 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 1 (Coal Early Retirement/Conversions)- - - - - - (418) - - - - - - - - - - - - - (418) (418) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Hunter 3 (Coal Early Retirement/Conversions)- - - - - - - - - (471) - - - - - - - - - - (471) (471) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - 423 - - - - - - - - - - - - 423 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-S - J 1x1 - - - - - - - - - 846 - - - - - - - - - - 846 846 Total CCCT - - - - - - - 423 - 846 - - - - - 401 - - 313 - 1,269 1,983 Modular-Nuclear-East - - - - - - - - - - - - - - - - 1,555 - 1,037 - - 2,592 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 326 - - - - 17 - 106 449 Total Wind - - - - - 106 - - - - - - - 326 - - - - 17 - 106 449 Utility Solar - PV - East - - - - - - - - - - - 82 72 - - - - - - - - 154 DSM, Class 2, ID 5 5 6 6 7 5 6 6 6 7 6 6 6 5 5 5 5 4 4 4 58 108 DSM, Class 2, UT 75 91 98 102 110 98 101 106 109 108 88 87 87 87 84 78 77 76 74 74 998 1,807 DSM, Class 2, WY 7 9 11 14 16 14 15 17 17 18 15 15 16 16 16 16 16 17 17 17 137 300 DSM, Class 2 Total 87 106 114 121 132 117 122 128 132 133 108 108 108 108 105 99 98 97 95 95 1,193 2,215 FOT Mona Q3 - - - - - - 4 68 31 16 82 73 102 294 155 300 - - - - 12 56 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, WW, 29 - - - - - - - - - - - - - - - 426 - - - - - 426 Wind, YK, 29 - - - - - - - - - - - - - 166 - 234 - - - - - 400 Total Wind - - - - - - - - - - - - - 166 - 660 - - - - - 826 Utility Solar - PV - West - - - - - - - - - - - - - 405 - 32 - - - - - 437 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - 10.6 - - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - 0.3 5.0 8.7 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - 10.6 - - - 1.4 15.6 41.5 DSM, Class 2, CA 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 1 1 2 1 19 35 DSM, Class 2, OR 45 40 39 36 32 31 30 30 29 28 26 26 32 32 32 29 23 23 27 27 340 616 DSM, Class 2, WA 9 11 12 11 12 11 11 11 12 12 10 10 10 10 10 8 8 8 8 8 113 203 DSM, Class 2 Total 56 52 53 50 47 43 43 44 43 42 37 37 44 44 43 39 32 33 37 36 472 854 FOT COB Q3 - 73 115 63 210 220 268 268 268 268 268 268 268 268 268 268 - - - - 175 168 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 330 336 351 373 400 390 FOT MidColumbia Q3 - 2 220 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 - - - - 360 292 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - (418) (450) - (825) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 143 165 167 171 179 267 165 599 186 1,021 148 238 224 1,050 149 1,242 1,685 130 1,499 133 Annual Additions, Short Term Resources 720 948 990 938 1,085 1,095 1,147 1,211 1,174 1,159 1,225 1,216 1,245 1,437 1,298 1,443 430 436 451 473 Total Annual Additions 863 1,113 1,157 1,109 1,264 1,362 1,311 1,810 1,360 2,180 1,373 1,454 1,468 2,487 1,447 2,685 2,115 566 1,950 606 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C14a-1 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 192 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 1 (Coal Early Retirement/Conversions)- - - - - - (418) - - - - - - - - - - - - - (418) (418) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - (269) - - - - - - - - - - (269) Hunter 3 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - (467) - - - - (467) Huntington 1 (Coal Early Retirement/Conversions)- - - - - - - - - - (459) - - - - - - - - - - (459) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 (Coal Early Retirement/Conversions - - - - - - - - - (106) - - - - - - - - - - (106) (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Wyodak (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (268) - - (268) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - 423 - - 423 - - - - - - - - - 423 846 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - 635 - - - - - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 423 - - - - - - - - - 423 846 Total CCCT - - - - - - - 423 - 423 846 - - - 635 401 - - 313 - 846 3,041 IC Aero WYD - - - - - - - - - - - - - - - - - - 166 - - 166 Modular-Nuclear-East - - - - - - - - - - - - - - - - 1,555 - 518 - - 2,074 Wind, DJohnston, 43 - - - - - 106 - - - 106 - - - 220 - - - - 17 - 212 449 Wind, WYAE, 43 - - - - - - - - - - - - - - - - - - 174 2 - 176 Total Wind - - - - - 106 - - - 106 - - - 220 - - - - 191 2 212 625 Utility Solar - PV - East - - - - - - - - - - - - 154 - - - - - - - - 154 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 5.0 - 5.0 DSM, Class 1, WY-Curtail - - - - - - - - - - - - - - - - - - 45.8 - - 45.8 DSM, Class 1, WY-DLC-RES - - - - - - - - - - - - - - - - - - 5.0 - - 5.0 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 50.8 5.0 - 55.8 DSM, Class 2, ID 5 5 6 6 7 5 6 6 6 7 6 6 6 5 5 5 5 5 5 4 58 109 DSM, Class 2, UT 75 91 98 102 110 98 101 106 109 108 88 87 87 87 84 78 77 76 74 74 998 1,807 DSM, Class 2, WY 7 9 11 14 16 14 15 17 17 18 15 15 16 16 16 16 16 17 17 17 138 300 DSM, Class 2 Total 87 106 114 121 132 117 122 128 132 133 108 108 108 108 105 99 98 97 96 96 1,194 2,216 FOT Mona Q3 - - - - - - 2 66 30 27 65 63 61 298 44 237 - - - - 13 45 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - (359) - - - - - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - - - - 26 - - - - - - - 26 Total Wind - - - - - - - - - - - - - 26 - - - - - - - 26 Utility Solar - PV - West - - - - - - - - - - - - - 125 - - - - - - - 125 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 1 1 2 2 19 35 DSM, Class 2, OR 45 40 39 36 33 31 31 30 29 28 26 26 33 32 29 29 23 29 27 27 342 622 DSM, Class 2, WA 9 11 12 11 12 11 11 12 12 12 10 10 10 10 10 8 8 8 8 8 114 204 DSM, Class 2 Total 56 53 53 50 48 43 44 44 43 42 37 37 45 45 40 39 32 38 37 36 475 861 FOT COB Q3 - 73 115 63 209 219 268 268 268 268 245 268 268 268 137 268 - - - - 175 160 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 220 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 228 232 247 265 360 341 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - (418) (450) - (460) (728) - - (220) (359) (694) (544) - (956) - Annual Additions, Long Term Resources 143 166 167 171 180 267 166 600 186 704 995 156 307 524 780 538 1,696 135 1,371 139 Annual Additions, Short Term Resources 720 948 990 938 1,084 1,094 1,145 1,209 1,173 1,170 1,185 1,206 1,204 1,441 1,056 1,380 728 732 747 765 Total Annual Additions 863 1,114 1,157 1,109 1,264 1,361 1,311 1,809 1,358 1,874 2,179 1,362 1,511 1,964 1,836 1,918 2,423 867 2,118 903 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case C14a-2 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 193 Table K.8 – Sensitivity Cases, Detailed Capacity Expansion Portfolios Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 313 - 846 - - 1,247 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 4 4 44 88 DSM, Class 2, UT 69 78 84 86 92 81 84 90 94 93 77 81 80 80 70 66 65 65 63 64 850 1,560 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 14 15 14 14 14 15 15 15 121 262 DSM, Class 2 Total 79 90 99 102 111 97 101 108 113 114 94 99 98 99 88 84 84 84 82 83 1,015 1,910 FOT Mona Q3 - - - - - - - - - - 54 82 125 252 104 64 44 146 300 75 - 62 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - 21 - - - - - - - - - - - - - 21 21 Total Wind - - - - - - 21 - - - - - - - - - - - - - 21 21 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - - - - - - - - 10.6 - - - - 10.6 DSM, Class 1, OR-Irrigate - - - - - - - - - - - 3.4 - - - 5.0 - - - - - 8.4 DSM, Class 1 Total - - - - - - - - - - - 3.4 - - - 5.0 10.6 - - - - 19.0 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 24 23 21 22 22 22 20 19 19 20 19 19 303 505 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 8 7 8 8 7 7 98 178 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 29 28 28 29 27 27 417 712 FOT COB Q3 - - - - - - - - - 266 268 268 268 268 268 221 211 268 195 140 27 132 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 122 297 328 168 317 276 214 374 359 375 375 375 375 375 375 375 375 375 375 375 283 329 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 153 314 158 144 149 149 125 134 130 445 117 963 122 113 1,356 745 Annual Additions, Short Term Resources 622 797 828 668 817 776 714 874 859 1,141 1,197 1,225 1,268 1,394 1,247 1,160 1,130 1,289 1,370 1,090 Total Annual Additions 755 943 974 814 969 1,090 872 1,019 1,009 1,290 1,322 1,359 1,398 1,840 1,364 2,123 1,252 1,402 2,727 1,834 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-01 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 194 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - 423 - - - - - - - - - - 423 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - 401 - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - 635 - - 635 - - 1,270 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423 CCCT - Utah-S - J 1x1 - - - - - 423 - - - - - - 423 - - - - - - - 423 846 Total CCCT - - - - - 423 - - - 423 - - 423 313 - 635 401 - 1,058 423 846 4,099 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 46 91 DSM, Class 2, UT 69 78 84 86 92 83 86 93 94 97 81 81 80 80 79 73 72 73 71 73 861 1,622 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 14 14 15 15 16 16 17 122 269 DSM, Class 2 Total 80 90 99 102 111 99 103 112 114 119 99 99 98 99 97 92 92 93 91 94 1,029 1,982 FOT Mona Q3 - - 20 12 203 - - 152 167 114 212 258 44 137 64 139 44 75 300 282 67 111 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - 24 - - - - - - - - - - - 24 24 Total Wind - - - - - - - - 24 - - - - - - - - - - - 24 24 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - - - 10.6 - - - 10.6 10.6 - - - - 31.8 DSM, Class 1, OR-Irrigate - - - - - - - - - 5.0 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - - - 5.0 3.4 10.6 - - - 10.6 10.6 - - - 5.0 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 24 23 22 22 22 22 21 20 20 21 20 19 303 511 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 99 181 DSM, Class 2 Total 54 50 47 45 42 38 36 36 36 35 32 32 32 32 31 29 29 30 28 28 418 721 FOT COB Q3 - 200 268 268 268 228 - 268 268 268 268 268 203 268 225 268 14 169 199 182 203 205 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 335 375 375 375 375 375 309 375 375 375 375 375 375 375 375 375 375 375 375 375 364 370 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 134 147 146 147 153 739 139 147 174 582 134 141 553 444 128 767 533 123 1,183 545 Annual Additions, Short Term Resources 835 1,075 1,163 1,155 1,346 1,103 809 1,295 1,310 1,257 1,355 1,401 1,122 1,280 1,163 1,281 933 1,119 1,374 1,339 Total Annual Additions 969 1,222 1,310 1,302 1,498 1,842 948 1,443 1,484 1,839 1,488 1,543 1,675 1,724 1,292 2,048 1,466 1,241 2,557 1,884 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-02 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 195 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - F 1x1 - - - - - - - 313 - - - - - - - - - - - - 313 313 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 1,270 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - 313 - 423 - - - 313 - 824 - - 1,693 - 736 3,567 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, ID-Irrigate - 3.5 - - - - - - - - - - - - - - - - - - 3.5 3.5 DSM, Class 1, UT-DLC-RES - 5.3 - - - - - - - - - - - - - - - - - - 5.3 5.3 DSM, Class 1, UT-Irrigate - 6.5 - - - - - - - - - - - - - - - - - - 6.5 6.5 DSM, Class 1 Total - 15.4 - - - - - - - - - - - - - - - - - - 15.4 15.4 DSM, Class 2, ID 8 9 6 6 7 5 4 4 5 5 5 5 5 5 5 4 4 4 4 4 59 104 DSM, Class 2, UT 127 136 100 102 109 93 86 90 91 93 78 81 80 80 81 75 74 75 73 64 1,026 1,786 DSM, Class 2, WY 12 15 10 12 15 12 13 14 15 16 13 13 14 14 15 15 15 16 17 15 136 283 DSM, Class 2 Total 147 160 116 120 130 111 103 108 110 114 95 99 98 99 100 94 94 96 94 83 1,220 2,172 Battery Storage - East - 8.0 - - - - - - - - - - - - - - - - - - 8 8 FOT Mona Q3 - 200 233 188 265 236 - 112 50 38 144 164 164 231 232 242 243 300 298 223 132 178 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources IC Aero WV - - - - 101 - - - - - - - - - - - - - - - 101 101 Wind, YK, 29 - - - - - - - 13 - - - - - - - - - - - - 13 13 Total Wind - - - - - - - 13 - - - - - - - - - - - - 13 13 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - 10.6 - - - - - - - - - - - - - - - - - 10.6 10.6 DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - 3.7 - - - - - 3.7 DSM, Class 1, OR-Irrigate - - - - - - - - - 3.4 - - - - - - - - - - 3.4 3.4 DSM, Class 1 Total - - 10.6 - - - - - - 3.4 - - - - - 3.7 - - - - 14.0 17.8 DSM, Class 2, CA 3 3 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 21 34 DSM, Class 2, OR 58 56 37 34 31 27 25 25 23 23 22 22 22 22 21 20 21 21 20 19 339 547 DSM, Class 2, WA 17 17 11 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 116 200 DSM, Class 2 Total 78 77 50 47 45 38 36 36 36 35 32 32 32 32 31 30 30 30 28 27 476 781 Battery Storage - West - 10 - - - - - - - - - - - - - - - - - - 10 10 Geothermal, Greenfield - West - 30 - - - - - - - - - - - - - - - - - - 30 30 FOT COB Q3 315 268 268 268 268 268 175 268 268 268 268 268 268 268 268 268 268 225 268 251 263 263 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 225 307 176 166 276 328 139 471 146 576 127 131 131 444 132 951 124 126 1,815 110 Annual Additions, Short Term Resources 1,190 1,343 1,376 1,331 1,408 1,379 1,050 1,255 1,193 1,181 1,287 1,307 1,307 1,374 1,374 1,385 1,386 1,400 1,441 1,349 Total Annual Additions 1,415 1,650 1,551 1,498 1,684 1,706 1,189 1,726 1,339 1,757 1,414 1,438 1,438 1,819 1,506 2,337 1,510 1,526 3,256 1,459 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-03 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 196 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - 423 - - - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 1,270 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - 423 - 313 - 824 - - 1,693 - 423 3,676 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - 4.9 - - - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 4 5 5 4 4 4 4 4 44 86 DSM, Class 2, UT 69 78 84 86 92 81 84 90 91 92 74 73 72 73 71 66 65 65 63 64 845 1,531 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 15 15 15 121 261 DSM, Class 2 Total 79 90 99 102 111 97 101 108 110 112 91 89 90 92 90 84 84 84 82 83 1,010 1,878 FOT Mona Q3 - - - - 15 - - 142 133 114 237 53 44 82 122 130 138 240 75 114 40 82 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - 27 - - - - - - - - - - 27 27 Total Wind - - - - - - - - - 27 - - - - - - - - - - 27 27 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - 10.6 - - - 1.1 10.6 32.9 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 3.4 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 5.0 3.4 10.6 - 10.6 - - - 10.6 - - - 1.1 19.0 41.3 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 23 23 21 21 21 21 20 20 20 20 19 19 303 504 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 8 8 8 8 7 7 98 178 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 30 30 30 29 29 29 27 27 417 710 FOT COB Q3 - 96 151 117 268 268 - 268 268 268 268 160 222 268 268 268 268 268 167 268 170 206 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 228 375 375 375 375 375 321 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 153 314 137 149 149 607 121 554 120 436 119 948 113 118 1,802 111 Annual Additions, Short Term Resources 728 971 1,026 992 1,158 1,143 821 1,285 1,276 1,257 1,380 1,088 1,141 1,225 1,265 1,273 1,281 1,383 1,117 1,257 Total Annual Additions 861 1,117 1,172 1,138 1,311 1,457 959 1,435 1,425 1,864 1,501 1,642 1,261 1,661 1,384 2,221 1,393 1,500 2,919 1,368 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-04 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 197 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - 423 - - - 846 Total CCCT - - - - - - - - - - - - 423 313 - 423 - 423 824 635 - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 87 DSM, Class 2, UT 69 78 84 86 92 81 84 88 89 90 73 73 74 73 71 68 71 71 69 64 840 1,546 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 14 16 16 15 121 263 DSM, Class 2 Total 79 90 99 102 111 97 101 106 108 111 90 90 92 92 90 86 90 91 89 83 1,005 1,896 FOT Mona Q3 - - - - - - - - 53 145 189 208 44 196 44 122 92 75 300 229 20 85 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - 27 - - - - - - - - - - 27 27 Total Wind - - - - - - - - - 27 - - - - - - - - - - 27 27 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - - - 10.6 - - - - - - - - - 10.6 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - 3.4 - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 5.0 - 3.4 - 10.6 - - - - - - - - 8.4 19.0 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 28 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 21 21 21 20 20 20 20 19 19 303 504 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 8 8 8 8 8 7 97 177 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 30 30 30 29 29 29 28 27 416 709 FOT COB Q3 - 71 139 90 252 185 - 230 268 268 268 268 239 268 140 268 268 221 204 103 150 187 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 224 375 375 375 375 375 262 375 375 375 375 375 375 375 375 375 375 375 375 375 349 362 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 153 314 137 147 144 176 120 131 545 436 119 538 119 542 940 745 Annual Additions, Short Term Resources 724 946 1,014 965 1,127 1,060 762 1,105 1,196 1,288 1,332 1,351 1,158 1,339 1,059 1,265 1,235 1,171 1,379 1,207 Total Annual Additions 857 1,092 1,160 1,111 1,280 1,373 899 1,252 1,340 1,464 1,452 1,482 1,704 1,775 1,179 1,803 1,353 1,713 2,319 1,952 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-05 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 198 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - - - - 423 - - 846 Total CCCT - - - - - - - - - - - - - 736 - 423 - - 1,882 - - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 12 - - - - - - - - - - - 142 - - 12 154 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 46 92 DSM, Class 2, UT 69 78 84 86 92 81 86 92 94 93 78 81 80 80 79 73 73 71 71 70 854 1,609 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 16 16 17 16 122 272 DSM, Class 2 Total 79 90 99 102 111 97 103 111 114 115 96 99 99 99 98 92 93 92 92 90 1,022 1,973 FOT Mona Q3 - - - - 9 43 - 171 101 21 100 130 196 44 44 156 139 300 34 209 34 85 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - 209 - - - - - - - - - - - 209 209 Total Wind - - - - - - - - 209 - - - - - - - - - - - 209 209 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 25 24 21 22 22 22 21 21 21 21 19 19 305 514 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 49 47 44 42 38 36 36 37 36 31 32 32 32 32 30 30 30 28 27 420 724 Pump Storage - West - - - - - - - - - 400 - - - - - - - - - - 400 400 FOT COB Q3 - 92 148 112 268 268 - 268 268 268 268 268 268 197 68 268 268 218 - 137 169 183 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 226 375 375 375 375 375 363 375 375 375 375 375 375 375 375 375 375 375 375 375 359 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 147 146 147 153 172 139 151 370 551 130 142 131 868 130 546 133 264 2,002 118 Annual Additions, Short Term Resources 726 967 1,023 987 1,152 1,186 863 1,314 1,244 1,164 1,243 1,273 1,339 1,116 987 1,299 1,282 1,393 909 1,221 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,358 1,002 1,465 1,614 1,715 1,373 1,415 1,470 1,984 1,117 1,845 1,415 1,657 2,910 1,339 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-06 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 199 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - - 401 - 401 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 313 - 1,269 - - 423 401 - 2,406 Wind, DJohnston, 43 - - - - - - - 25 - - - - - - - - - - - - 25 25 Wind, WYAE, 43 - - - - - - - 500 - - - - - - - - - - - - 500 500 Total Wind - - - - - - - 525 - - - - - - - - - - - - 525 525 Utility Solar - PV - East - - - - - - 108 - - - - - - - - - 23 - - - 108 131 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 7 7 7 7 7 6 6 6 6 6 81 148 DSM, Class 2, UT 69 78 112 110 122 108 112 116 124 123 99 119 119 121 118 104 103 101 101 100 1,073 2,157 DSM, Class 2, WY 6 8 18 20 23 21 22 23 24 25 19 20 20 21 20 20 20 21 21 21 189 392 DSM, Class 2 Total 79 90 139 139 154 138 143 148 157 157 126 146 146 149 145 130 130 128 128 127 1,343 2,697 FOT Mona Q3 - - - - - - - - - - 44 44 50 149 44 - - - 266 75 - 34 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources CCCT - Jbridger - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 Total CCCT - - - - - - - - - - - - - - - - - - 401 - - 401 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 - 10.6 - - - 10.6 - - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - 3.4 5.0 - - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - 3.4 5.0 - 10.6 - 10.6 - - - 10.6 - - - - 19.0 40.2 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 2 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 61 55 51 48 45 43 41 39 37 36 36 37 34 32 32 33 30 30 464 801 DSM, Class 2, WA 8 9 19 19 19 17 17 17 18 18 14 14 14 14 13 11 11 11 10 10 163 282 DSM, Class 2 Total 54 49 83 77 73 68 65 64 62 60 53 53 52 53 50 45 45 45 41 42 655 1,134 FOT COB Q3 - 93 102 25 143 142 - 72 18 262 268 253 268 268 200 - - - 20 139 86 114 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 192 375 375 375 375 375 375 375 375 170 149 223 375 375 342 329 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 223 216 227 205 318 742 219 228 179 209 198 515 195 1,455 198 173 993 569 Annual Additions, Short Term Resources 727 968 977 900 1,018 1,017 692 947 893 1,137 1,187 1,172 1,193 1,292 1,119 670 649 723 1,161 1,089 Total Annual Additions 859 1,115 1,200 1,117 1,246 1,222 1,010 1,689 1,112 1,365 1,366 1,381 1,391 1,807 1,314 2,125 847 896 2,154 1,658 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-07 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 200 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - - 635 - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - 423 - - 423 - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 423 423 - 736 635 - 2,640 Wind, WYAE, 43 - - - - - - - 383 365 - - - - - - 211 - - - - 748 959 Total Wind - - - - - - - 383 365 - - - - - - 211 - - - - 748 959 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 2, ID 4 4 10 10 10 9 9 9 9 9 7 7 7 7 7 6 6 6 6 6 81 148 DSM, Class 2, UT 69 78 112 108 122 108 112 119 124 123 99 119 119 121 118 104 103 101 101 100 1,074 2,158 DSM, Class 2, WY 6 8 18 20 22 21 22 23 24 25 19 20 20 21 21 20 20 21 21 21 189 392 DSM, Class 2 Total 79 90 139 138 154 138 143 150 156 157 126 146 146 149 145 130 130 128 128 127 1,344 2,698 FOT Mona Q3 - - - - - - - - - 3 44 44 48 57 44 131 - 75 75 - 0 26 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources CCCT - Jbridger - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 Total CCCT - - - - - - - - - - - - - - - - - - 401 - - 401 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - 10.6 10.6 10.6 - - - - - - - - 10.6 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - 4.5 - - - - 4.5 DSM, Class 1, OR-Irrigate - - - - - - - 8.4 - - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 8.4 - 10.6 10.6 10.6 - - - - 4.5 - - - 19.0 44.7 DSM, Class 2, CA 1 2 3 3 4 3 3 3 3 3 3 2 3 3 3 2 2 2 2 2 28 51 DSM, Class 2, OR 44 39 58 57 51 48 45 44 41 39 37 36 36 37 34 32 32 33 30 30 464 801 DSM, Class 2, WA 8 9 20 19 19 17 17 18 18 18 14 14 14 14 13 11 11 11 10 10 163 282 DSM, Class 2 Total 54 49 81 79 73 68 65 64 62 60 53 53 52 53 50 45 45 45 41 42 655 1,134 FOT COB Q3 - 93 103 26 144 143 - 130 26 268 266 250 268 268 108 268 - 36 189 - 93 129 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 195 375 375 375 375 375 375 375 375 375 358 375 375 331 342 356 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 132 146 221 217 227 205 207 606 583 228 189 209 198 624 195 809 602 174 1,311 803 Annual Additions, Short Term Resources 727 968 978 901 1,019 1,018 695 1,005 901 1,146 1,185 1,169 1,190 1,200 1,027 1,274 858 986 1,139 831 Total Annual Additions 859 1,115 1,199 1,118 1,247 1,223 902 1,610 1,485 1,374 1,374 1,379 1,389 1,825 1,222 2,084 1,460 1,159 2,450 1,635 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-08 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 201 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 1,270 - - 1,270 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - 423 - - - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 423 - 824 - - 1,583 - 423 3,253 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 326 - - - - 17 - 106 449 Wind, UT, 31 - - - - - - - 143 - - - - - - - - - - - - 143 143 Total Wind - - - - - 106 - 143 - - - - - 326 - - - - 17 - 249 592 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - - 3.5 - 3.5 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - 4.9 - - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - 4.9 3.5 - 8.5 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 4 4 5 5 5 4 4 4 4 4 44 87 DSM, Class 2, UT 69 78 84 86 92 81 84 88 89 90 74 73 74 74 77 72 72 73 71 71 840 1,570 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 13 14 14 14 15 16 16 17 121 266 DSM, Class 2 Total 79 90 99 102 111 97 101 106 109 111 91 90 92 92 96 90 92 93 91 92 1,005 1,923 FOT Mona Q3 - - - - 10 38 - 152 131 63 149 186 259 277 150 114 97 300 94 300 39 116 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 3.4 5.0 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 3.4 15.6 - - 10.6 - - - - 10.6 - - - 19.0 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 33 29 27 25 25 23 23 21 21 21 22 21 20 20 20 20 19 303 507 DSM, Class 2, WA 8 9 10 10 10 9 9 10 11 11 9 9 9 9 9 8 8 8 8 7 97 178 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 31 31 31 29 29 29 28 28 416 714 FOT COB Q3 - 93 149 113 268 268 - 268 268 268 268 268 268 268 268 268 268 228 166 267 169 212 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 359 375 375 375 375 375 375 375 375 375 375 375 375 375 359 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 146 146 146 152 241 137 289 160 569 121 131 123 873 127 943 131 122 1,725 123 Annual Additions, Short Term Resources 727 968 1,024 988 1,153 1,181 859 1,295 1,274 1,206 1,292 1,329 1,402 1,420 1,293 1,257 1,240 1,403 1,135 1,442 Total Annual Additions 860 1,114 1,170 1,135 1,305 1,422 996 1,584 1,434 1,775 1,413 1,461 1,524 2,293 1,420 2,200 1,372 1,525 2,859 1,566 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-09 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 202 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 1,058 - - 2,640 Utility Solar - PV - East - - - - - - - - - - - - - - - 3 - - - - - 3 DSM, Class 1, ID-Irrigate - 3.5 - - - - - - - - - - - - - 16.5 - - - - 3.5 20.0 DSM, Class 1, UT-Curtail - - 24.0 24.5 - - - - - - - - - - - - - - - - 48.5 48.5 DSM, Class 1, UT-DLC-RES - 5.3 6.5 6.6 - 13.3 - - - - - - - - - - 26.1 - - - 31.7 57.8 DSM, Class 1, UT-Irrigate - 6.5 - - - 3.5 - - - - - - - - - 6.4 - - - - 10.1 16.5 DSM, Class 1, WY-Curtail - - 13.0 13.2 - - - - - - - - - - - - - - - - 26.2 26.2 DSM, Class 1 Total - 15.4 43.5 44.2 - 16.8 - - - - - - - - - 22.9 26.1 - - - 119.9 168.9 DSM, Class 2, ID 8 9 6 6 7 5 4 4 5 6 5 5 5 5 5 5 5 4 4 4 60 107 DSM, Class 2, UT 127 136 106 105 108 96 86 93 98 105 85 85 84 84 81 77 76 73 63 64 1,060 1,831 DSM, Class 2, WY 13 15 11 13 14 13 13 14 15 16 13 13 14 15 15 16 16 16 15 15 138 286 DSM, Class 2 Total 148 160 123 124 129 114 103 112 118 127 103 103 104 104 102 97 97 93 82 83 1,258 2,225 Battery Storage - East - 8.0 - - - - - - - - - - - - - - - - - - 8 8 Geothermal, Greenfield - East - 30.0 - - - - - - - - - - - - - - - - - - 30.0 30.0 FOT Mona Q3 711 458 358 283 277 281 - - - - - - - 286 229 300 299 299 250 165 237 210 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 148 213 166 169 129 131 103 112 118 127 103 103 104 527 102 1,282 123 93 1,140 83 Annual Additions, Short Term Resources 711 458 358 283 277 281 - - - - - - - 286 229 300 299 299 250 165 Total Annual Additions 859 672 525 452 406 412 103 112 118 127 103 103 104 813 331 1,582 422 392 1,390 248 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-10_ECA PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 203 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year West Existing Plant Retirements/Conversions Chehalis (Thermal Early Retirement/Conversions)- - - - - (512) - - - - - - - - - - - - - - (512) (512) Expansion Resources IC Aero PO - - - - - 106 - - - - - - - - - - - - - - 106 106 IC Aero WV - - - - - - - - 101 - - - - - - - - - - - 101 101 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - 10.6 10.6 - - - 10.6 - - - - - - - - - - - - 31.8 31.8 DSM, Class 1, OR-DLC-RES - - - - - - - - - - - - - - - - - - 3.0 11.2 - 14.2 DSM, Class 1, OR-Irrigate - - - - 5.0 - - - - - - - - - - - - 3.4 - - 5.0 8.4 DSM, Class 1 Total - - 10.6 10.6 5.0 - - 10.6 - - - - - - - - - 3.4 3.0 11.2 36.8 54.4 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 21 22 22 21 20 20 20 19 19 302 507 DSM, Class 2, WA 8 9 10 10 10 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 97 179 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 31 32 32 32 29 29 29 28 28 415 715 Battery Storage - West - - 1 - 1 - - - - - - - - - - - - - - - 2 2 FOT Mid Columbia Flat - - - - - 38 125 202 29 57 72 114 119 117 137 197 189 196 192 233 45 101 FOT COB - Jan - - - - - 297 297 297 297 297 297 297 297 297 297 297 297 297 297 297 149 223 FOT MidColumbia - Jan 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia - Jan - 2 51 77 281 253 336 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 287 331 FOT NOB - Jan 100 76 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 98 99 Existing Plant Retirements/Conversions - - - - - (512) - - - - - - - - - - - - - - Annual Additions, Long Term Resources 54 56 58 55 48 144 36 47 136 35 31 31 32 32 32 29 29 33 31 39 Annual Additions, Short Term Resources 551 553 781 753 836 1,210 1,298 1,374 1,201 1,229 1,244 1,286 1,291 1,289 1,309 1,369 1,361 1,368 1,364 1,405 Total Annual Additions 605 609 839 807 884 1,354 1,333 1,421 1,338 1,264 1,275 1,317 1,322 1,321 1,340 1,399 1,390 1,401 1,395 1,444 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-10_WCA PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 204 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - (450) - - - - - (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - (330) - - - - - - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - 313 - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - - 423 - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 846 - - - - - 846 Total CCCT - - - - - - - - - - - - - 423 - 1,159 - - 635 423 - 2,640 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 84 90 91 93 75 80 80 80 79 73 73 73 73 71 847 1,603 DSM, Class 2, WY 6 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 15 16 17 17 121 271 DSM, Class 2 Total 79 90 99 102 111 97 101 108 110 115 92 98 98 99 98 92 93 94 94 92 1,013 1,964 FOT Mona Q3 - - - - - - - - - - - - - 184 56 144 138 300 300 300 - 71 West Expansion Resources Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 23 23 21 22 22 22 21 21 21 21 20 19 303 511 DSM, Class 2, WA 8 9 10 10 11 9 9 10 11 11 9 9 9 9 9 8 8 8 8 7 98 180 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 30 30 28 28 416 721 FOT COB Q3 - 62 29 - 60 104 - - - - - - - 268 268 268 268 268 223 165 25 99 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 370 375 375 160 198 196 162 248 290 357 375 375 375 375 375 375 375 281 317 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 - - - - - - - - - (762) - (1,144) (77) - (627) - Annual Additions, Long Term Resources 133 147 146 146 153 135 137 144 146 149 123 130 130 555 129 1,282 123 124 757 543 Annual Additions, Short Term Resources 727 937 904 870 935 979 660 698 696 662 748 790 857 1,327 1,199 1,287 1,280 1,443 1,398 1,340 Total Annual Additions 860 1,084 1,050 1,016 1,088 1,113 797 843 842 811 871 920 988 1,881 1,328 2,569 1,403 1,567 2,155 1,883 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-10_System PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 205 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - - - - - - 313 - - 313 CCCT - Huntington - J 1x1 - - - - - - - - - 423 - - - - - - - - - - 423 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - 401 - - - - - 401 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423 Total CCCT - - - - - - - - - 423 - - 423 - - 401 - - 313 - 423 1,560 Modular-Nuclear-East - - - - - - - - - - - - - - - - 3,110 - - - - 3,110 Wind, DJohnston, 43 - - - - - 106 - - - - - - - 326 - - - - 17 - 106 449 Wind, GO, 31 - - - - - - - - - - - - 426 69 18 - - 12 100 31 - 656 Wind, UT, 31 - - - - - - - - - - 250 - - - - - - - - - - 250 Wind, WYAE, 43 - - - - - - - - - - - - - 389 - - - - - - - 389 Total Wind - - - - - 106 - - - - 250 - 426 784 18 - - 12 117 31 106 1,744 Utility Solar - PV - East - - - - - - - - - 750 - - - - - - - - - - 750 750 DSM, Class 2, ID 5 5 6 6 7 6 6 6 7 7 6 6 6 5 5 5 5 5 5 5 60 111 DSM, Class 2, UT 80 91 100 101 110 99 103 107 109 109 89 89 88 88 85 79 78 77 76 75 1,009 1,835 DSM, Class 2, WY 8 9 12 14 16 15 15 17 18 19 15 15 16 16 16 16 16 17 17 17 141 303 DSM, Class 2 Total 92 106 117 121 132 119 124 130 134 134 110 110 110 110 107 101 100 99 97 97 1,209 2,250 FOT Mona Q3 - - - - - - - 27 - - - - - - - - - - - - 3 1 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Modular-Nuclear-West - - - - - - - - - - - - - - - - 518 - - - - 518 Wind, WW, 29 - - - - - - - - - - - - 38 376 33 92 - 18 - 10 - 567 Total Wind - - - - - - - - - - - - 38 376 33 92 - 18 - 10 - 567 Utility Solar - PV - West - - - - - - - - - - - 339 66 - - - - - - - - 405 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - 3.4 - - - - - - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - 3.4 10.6 - - - - 10.6 - - - 15.6 40.2 DSM, Class 2, CA 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 21 39 DSM, Class 2, OR 47 42 40 37 36 34 31 39 36 35 33 33 33 32 32 29 28 29 27 27 376 679 DSM, Class 2, WA 11 11 12 12 13 11 11 12 12 12 10 10 10 10 10 8 8 8 8 8 117 208 DSM, Class 2 Total 60 55 54 51 51 46 44 52 51 50 45 46 45 45 43 39 38 38 37 36 514 927 FOT COB Q3 - 67 106 53 198 206 - 268 254 - - - - - - - - - - - 115 58 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 - - - - 400 320 FOT MidColumbia Q3 - 2 215 375 375 375 375 375 248 375 375 264 293 193 88 5 15 156 - - - - 335 205 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - - 9 30 100 82 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 152 168 171 172 183 271 168 187 195 1,357 408 505 1,108 1,315 202 632 3,777 168 564 175 Annual Additions, Short Term Resources 715 942 981 928 1,073 1,081 748 1,170 1,129 764 793 693 588 505 515 656 - - 9 30 Total Annual Additions 866 1,110 1,152 1,100 1,256 1,353 917 1,357 1,325 2,121 1,201 1,199 1,696 1,820 716 1,288 3,777 168 574 205 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-11 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 206 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - 423 - - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - - - - 423 - 423 - - - 846 Total CCCT - - - - - - - - - - - - 423 313 - 423 - 423 824 - - 2,406 Wind, DJohnston, 43 - - - - - - - - - - - - - - - - - - - 26 - 26 Total Wind - - - - - - - - - - - - - - - - - - - 26 - 26 Utility Solar - PV - East - - - - - - - - - - - - - - - - - - - 154 - 154 DSM, Class 1, ID-Irrigate - - - - - - - - - - - - - - - - - - - 4.0 - 4.0 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 4.0 - 4.0 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 4 4 45 91 DSM, Class 2, UT 69 78 84 86 92 81 86 90 92 93 75 81 80 80 81 75 74 73 71 73 850 1,612 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 15 16 17 17 121 270 DSM, Class 2 Total 79 90 99 102 111 97 103 108 112 114 92 99 99 99 100 94 94 93 92 94 1,016 1,973 FOT Mona Q3 - - - - - - - 18 40 140 172 194 44 170 44 80 47 75 300 300 20 81 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - 259 - - - - - - - - 108 - 6 259 373 Total Wind - - - - - - - - 259 - - - - - - - - 108 - 6 259 373 Utility Solar - PV - West - - - - - - - - - - - - - - - - - - - 605 - 605 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - - - 10.6 - - - - - - - - - - 10.6 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 3.4 - - - - - - - - - - - 8.4 8.4 DSM, Class 1 Total - - - - - - - 5.0 3.4 - 10.6 - - - - - - - - - 8.4 19.0 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 35 32 29 27 25 25 23 23 21 22 22 22 21 20 20 21 20 19 303 510 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 181 DSM, Class 2 Total 54 50 47 44 42 38 36 36 36 35 31 32 32 32 31 30 29 30 28 28 417 720 FOT COB Q3 - 70 139 89 251 244 - 268 268 268 268 268 220 268 105 268 268 147 128 268 160 190 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 224 375 375 375 375 375 282 375 375 375 375 375 375 375 375 375 375 375 375 375 351 363 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 147 146 146 153 135 139 149 410 149 133 131 553 445 132 547 123 654 944 916 Annual Additions, Short Term Resources 724 945 1,014 964 1,126 1,119 782 1,161 1,183 1,283 1,315 1,336 1,139 1,312 1,024 1,223 1,190 1,097 1,303 1,443 Total Annual Additions 857 1,092 1,160 1,111 1,279 1,253 921 1,310 1,593 1,433 1,448 1,467 1,692 1,758 1,156 1,770 1,312 1,752 2,247 2,359 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-12 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 207 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - - - - 423 - - - - - 423 - - 846 Total CCCT - - - - - - - - - - - - 423 313 - 423 - 401 1,481 - - 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, UT-DLC-RES - - - - - - - - - - - - - - - - - - - 4.9 - 4.9 DSM, Class 1 Total - - - - - - - - - - - - - - - - - - - 4.9 - 4.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 5 5 5 5 5 5 4 4 4 4 4 45 90 DSM, Class 2, UT 69 78 84 86 92 81 84 90 94 93 75 77 80 80 77 73 66 65 66 69 850 1,577 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 14 15 15 16 121 266 DSM, Class 2 Total 79 90 99 102 111 97 101 108 113 115 92 95 99 99 97 92 84 84 85 89 1,016 1,933 CAES - East - - - - - - - - - 300.0 - - - - - - - - - - 300.0 300.0 FOT Mona Q3 - - - - 9 - - 122 103 119 197 229 44 73 44 255 244 143 75 300 35 98 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - - - - 29 - - - - - - - - - - 29 Total Wind - - - - - - - - - - 29 - - - - - - - - - - 29 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Curtail - - - - - - - - 10.6 - - 10.6 - - - - 10.6 - - - 10.6 31.8 DSM, Class 1, OR-Irrigate - - - - - - - 5.0 - - - - - - - 3.4 - - - - 5.0 8.4 DSM, Class 1 Total - - - - - - - 5.0 10.6 - - 10.6 - - - 3.4 10.6 - - - 15.6 40.2 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 29 DSM, Class 2, OR 44 39 36 32 29 27 25 25 23 23 21 22 22 22 21 21 20 20 19 19 303 509 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 7 7 98 180 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 31 32 32 32 31 30 29 29 27 27 417 718 FOT COB Q3 - 93 148 113 268 260 - 268 268 268 268 268 150 268 169 268 268 189 128 212 169 194 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 227 375 375 375 375 375 313 375 375 375 375 375 375 375 375 375 375 375 375 375 354 364 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 147 146 146 153 314 137 149 160 450 153 138 553 445 128 548 124 513 1,593 122 Annual Additions, Short Term Resources 727 968 1,023 988 1,152 1,135 813 1,265 1,246 1,262 1,339 1,372 1,069 1,216 1,088 1,397 1,387 1,206 1,078 1,387 Total Annual Additions 860 1,114 1,169 1,134 1,305 1,449 950 1,415 1,405 1,711 1,492 1,510 1,622 1,661 1,216 1,946 1,511 1,720 2,671 1,508 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-13 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 208 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Coal Early Retirement/Conversions)- - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Coal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Coal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Coal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Coal Early Retirement/Conversions - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Coal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - - - 423 - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - - 401 - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 313 - 846 - - 1,459 - 423 3,041 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 108 - - - - - - - - - - - - - 46 108 154 DSM, Class 3, ID-C&I Pricing - - - - - - - - - - - - - - - - - - - 1.6 - 1.6 DSM, Class 3, ID-C&I Demand Buyback - - - - - - - - - - - - - - - - - - - 0.1 - 0.1 DSM, Class 3, ID-Irrigate Price - - - - - - - - - - - - - - - - - - - 1.8 - 1.8 DSM, Class 3, ID-Res Price - - - - - - - - - - - - - - - - - - - 2.7 - 2.7 DSM, Class 3, UT-C&I Pricing - - - - - - - 20.6 6.2 3.4 - - - - - - - 3.4 - 0.9 30.2 34.5 DSM, Class 3, UT-C&I Demand Buyback - - - - - - - - - - - - - - - - - - - 5.3 - 5.3 DSM, Class 3, UT-Irrigate Price - - - - - - - - - - - - - - - - - - - 0.8 - 0.8 DSM, Class 3, UT-Res Price - - - - - - - - - - - - - - - - - - - 69.4 - 69.4 DSM, Class 3, WY-C&I Pricing - - - - - - - 8.9 - 4.1 - - - - - - - - - 1.5 13.0 14.5 DSM, Class 3, WY-C&I Demand Buyback - - - - - - - - - - - - - - - - - - - 4.2 - 4.2 DSM, Class 3, WY-Irrigate Price - - - - - - - - - - - - - - - - - - - 0.3 - 0.3 DSM, Class 3, WY-Res Price - - - - - - - - - - - - - - - - - - - 9.7 - 9.7 DSM, Class 1 Total - - - - - - - 29.5 6.2 7.5 - - - - - - - 3.4 - 98.3 43.2 144.9 DSM, Class 2, ID 4 4 5 5 5 4 4 4 5 6 5 5 5 5 5 4 4 4 4 4 46 92 DSM, Class 2, UT 69 78 84 86 92 81 86 91 94 93 81 81 80 84 81 75 74 73 71 71 853 1,625 DSM, Class 2, WY 7 8 10 12 14 12 13 14 15 16 13 13 14 15 15 15 15 16 17 17 122 273 DSM, Class 2 Total 79 90 99 102 111 97 103 110 114 115 99 99 99 104 100 95 94 94 92 93 1,021 1,989 FOT Mona Q3 - - - - - - - 75 60 - 56 88 151 294 163 98 80 238 217 300 14 91 West Existing Plant Retirements/Conversions JimBridger 1 (Coal Early Retirement/Conversions)- - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Coal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (359) - - (359) Expansion Resources Wind, YK, 29 - - - - - - - 79 - - - - - - - - - - - - 79 79 Total Wind - - - - - - - 79 - - - - - - - - - - - - 79 79 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, OR-Irrigate - - - - - - - - - - 5.0 - 3.4 - - - - - - - - 8.4 DSM, Class 3, CA-C&I Pricing - - - - - - - - - - - - - - - - - - - 0.7 - 0.7 DSM, Class 3, CA-Irrigate Price - - - - - - - - - - - - - - - - - - - 0.7 - 0.7 DSM, Class 3, CA-Res Price - - - - - - - - - - - - - - - - - - - 1.6 - 1.6 DSM, Class 3, OR-C&I Pricing - - 7.4 - - - - 6.1 - - - - - - - - 3.0 - - 0.2 13.5 16.7 DSM, Class 3, OR-C&I Demand Buyback - - - - - - - - - - - - - - - - - - - 2.0 - 2.0 DSM, Class 3, OR-Irrigate Price - - - - - - - - - - - - - - - - - - - 1.7 - 1.7 DSM, Class 3, OR-Res Price - - - - - - - - - - - 8.1 - - - 5.7 6.4 - - 9.7 - 29.9 DSM, Class 3, WA-C&I Pricing - - - - - - - 4.0 - - - - - - - - - - - 1.1 4.0 5.1 DSM, Class 3, WA-C&I Demand Buyback - - - - - - - - - - - - - - - - - - - 0.5 - 0.5 DSM, Class 3, WA-Irrigate Price - - - - - - - - - - - - - - - - - - - 1.1 - 1.1 DSM, Class 3, WA-Res Price - - - - - - - - - - - - - - - - - - - 8.3 - 8.3 DSM, Class 1 Total - - 7.4 - - - - 10.1 - - 5.0 8.1 3.4 - - 5.7 9.4 - - 27.6 17.5 76.7 DSM, Class 2, CA 1 2 2 2 2 1 1 2 2 2 1 1 1 1 1 1 1 1 1 1 16 30 DSM, Class 2, OR 44 39 36 32 29 27 25 25 23 23 22 22 22 22 21 21 21 21 20 21 303 514 DSM, Class 2, WA 8 9 10 10 11 9 10 10 11 11 9 9 9 9 9 8 8 8 8 7 98 182 DSM, Class 2 Total 54 49 47 44 42 38 36 36 36 35 32 32 32 32 31 30 30 30 28 29 417 725 FOT COB Q3 - 93 141 105 268 268 - 268 268 249 268 268 268 268 268 268 268 268 175 259 166 212 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 226 375 375 375 375 375 321 375 375 375 375 375 375 375 375 375 375 375 375 375 355 365 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) - - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 133 147 154 146 153 268 139 265 156 580 136 139 135 449 132 977 133 127 1,579 294 Annual Additions, Short Term Resources 726 968 1,016 980 1,143 1,143 821 1,218 1,203 1,124 1,199 1,231 1,294 1,437 1,306 1,241 1,223 1,381 1,267 1,434 Total Annual Additions 860 1,114 1,169 1,127 1,296 1,411 960 1,483 1,359 1,705 1,334 1,370 1,429 1,886 1,438 2,218 1,357 1,509 2,846 1,728 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-14 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 209 Capacity (MW)Resource Totals 1/ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 10-year 20-year East Existing Plant Retirements/Conversions Hayden 1 - - - - - - - - - - - - - - - - (45) - - - - (45) Hayden 2 - - - - - - - - - - - - - - - - (33) - - - - (33) Hunter 2 (Thermal Early Retirement/Conversions)- - - - - - - - - - - - - - - - - - (269) - - (269) Huntington 2 (Thermal Early Retirement/Conversion - - - - - - - (450) - - - - - - - - - - - - (450) (450) Carbon 1 (Thermal Early Retirement/Conversions)(67) - - - - - - - - - - - - - - - - - - - (67) (67) Carbon 2 (Thermal Early Retirement/Conversions)(105) - - - - - - - - - - - - - - - - - - - (105) (105) Cholla 4 (Thermal Early Retirement/Conversions)- - - - - - - - - - (387) - - - - - - - - - - (387) DaveJohnston 1 (Thermal Early Retirement/Convers - - - - (106) - - - - - - - - - - - - - - - (106) (106) DaveJohnston 2 - - - - - - - - - - - - - (106) - - - - - - - (106) DaveJohnston 3 - - - - - - - - - - - - - (220) - - - - - - - (220) DaveJohnston 4 - - - - - - - - - - - - - - - - - - (330) - - (330) Naughton 1 - - - - - - - - - - - - - - - (156) - - - - - (156) Naughton 2 - - - - - - - - - - - - - - - (201) - - - - - (201) Naughton 3 (Thermal Early Retirement/Conversions)(50) - - (280) - - - - - - - - - - - - - - - - (330) (330) Gadsby 1-6 - - - - - - - - - - - - - - - - - - (358) - - (358) Coal Ret_AZ - Gas RePower - - - - - - - - - - 387 - - - - - - - - - - 387 Coal Ret_WY - Gas RePower - - - 337 - - - - - - - - - - - (337) - - - - 337 - Expansion Resources CCCT - DJohns - F 1x1 - - - - - - - - - - - - - 313 - - - - - - - 313 CCCT - DJohns - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Huntington - J 1x1 - - - - - - - - - - - - - 423 - - - - - - - 423 CCCT - Naughton - J 1x1 - - - - - - - - - - - - - - - - - 401 - - - 401 CCCT - Utah-N - F 2x1 - - - - - - - - - - - - - - - - - - 635 - - 635 CCCT - Utah-N - J 1x1 - - - - - - - - - - - - - - - - - - 423 - - 423 CCCT - Utah-S - J 1x1 - - - - - - - - - 423 - - - - - 423 - - - - 423 846 Total CCCT - - - - - - - - - 423 - - - 736 - 423 - 401 1,481 - 423 3,464 Wind, DJohnston, 43 - - - - - 25 - - - - - - - - - - - - - - 25 25 Total Wind - - - - - 25 - - - - - - - - - - - - - - 25 25 Utility Solar - PV - East - - - - - 154 - - - - - - - - - - - - - - 154 154 DSM, Class 1, ID-Irrigate - - - - - - - 8.8 - - - - 7.6 - - - - - - - 8.8 16.4 DSM, Class 1, UT-DLC-RES - - - - - - - 37.2 - - - - - - - - - - - 10.0 37.2 47.2 DSM, Class 1, UT-Irrigate - - - - - - - 13.2 - - - - - - - - - - - - 13.2 13.2 DSM, Class 1 Total - - - - - - - 59.2 - - - - 7.6 - - - - - - 10.0 59.2 76.7 DSM, Class 2, ID 4 4 5 6 7 5 6 6 6 6 5 5 5 4 5 4 4 4 4 4 54 99 DSM, Class 2, UT 80 89 96 102 108 96 100 104 106 105 85 85 86 72 70 65 65 63 62 64 985 1,701 DSM, Class 2, WY 7 9 10 12 14 13 14 16 15 17 14 15 15 14 14 14 14 15 15 15 127 271 DSM, Class 2 Total 90 102 111 119 129 114 120 126 127 128 104 105 106 90 88 83 84 82 81 83 1,167 2,070 FOT Mona Q3 - - - - - 261 - 283 262 173 247 274 293 77 - 276 275 95 - 255 98 139 West Existing Plant Retirements/Conversions JimBridger 1 (Thermal Early Retirement/Conversions - - - - - - - - - (354) - - - - - - - - - - (354) (354) JimBridger 2 (Thermal Early Retirement/Conversions - - - - - - - - - - - - - - - - - - (359) - - (359) Chehalis - - - - - (465) - - - - - - - - - - - - - - (465) (465) Expansion Resources IC Aero PO - - - - - 106 - - - - - - - - - - - - - - 106 106 Wind, YK, 29 - - - - - - - - - 27 - - - - - - - - - - 27 27 Total Wind - - - - - - - - - 27 - - - - - - - - - - 27 27 Oregon Solar Capacity Standard - 7 - - - - - - - - - - - - - - - - - - 7 7 DSM, Class 1, CA-Curtail - - - - - - - - - - - - - - - - - - - 1.0 - 1.0 DSM, Class 1, CA-DLC-RES - - - - - - - - - - - - - - - - - - - 2.6 - 2.6 DSM, Class 1, CA-Irrigate - - - - - - - 3.6 - - - - - - - - - - - 0.6 3.6 4.2 DSM, Class 1, OR-Curtail - - - - - - - 10.6 - - - - 21.2 - - - - - - 1.1 10.6 32.9 DSM, Class 1, OR-DLC-RES - - - - - - - - - - - 7.5 - - - - - - - 3.0 - 10.5 DSM, Class 1, OR-Irrigate - - - - - - - 8.4 - - - - - - - - - - - 0.3 8.4 8.7 DSM, Class 1, WA-Curtail - - - - - - - - - - - - 6.2 - - - - - 3.0 0.3 - 9.5 DSM, Class 1, WA-DLC-RES - - - - - - - - - - - - - - - - - - - 3.7 - 3.7 DSM, Class 1, WA-Irrigate - - - - - - - - - - - - 4.5 - - - - - - 0.6 - 5.1 DSM, Class 1 Total - - - - - - - 22.6 - - - 7.5 31.8 - - - - - 3.0 13.1 22.6 78.1 DSM, Class 2, CA 1 2 2 2 2 2 2 2 2 2 2 2 2 1 2 1 1 1 1 2 19 33 DSM, Class 2, OR 44 40 37 34 30 30 28 28 26 25 23 26 25 23 22 21 21 23 27 27 322 559 DSM, Class 2, WA 9 10 11 10 11 9 10 11 11 12 10 10 10 9 9 8 8 8 8 8 104 191 DSM, Class 2 Total 55 52 49 47 44 41 39 40 39 39 34 37 37 34 33 30 30 32 36 36 445 783 FOT COB Q3 - 73 118 69 219 268 229 268 268 268 268 268 268 268 234 268 268 268 261 268 178 221 FOT MidColumbia Q3 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 400 FOT MidColumbia Q3 - 2 217 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 375 359 367 FOT NOB Q3 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Existing Plant Retirements/Conversions (222) - - 57 (106) (465) - (450) - (354) - - - (326) - (694) (77) - (1,316) - Annual Additions, Long Term Resources 145 161 160 166 173 441 159 248 165 617 138 149 183 860 120 536 114 515 1,601 142 Annual Additions, Short Term Resources 717 948 993 944 1,094 1,404 1,104 1,426 1,405 1,316 1,390 1,417 1,436 1,220 1,109 1,419 1,418 1,238 1,136 1,398 Total Annual Additions 862 1,109 1,154 1,110 1,267 1,844 1,263 1,674 1,571 1,932 1,528 1,566 1,618 2,079 1,229 1,955 1,532 1,753 2,736 1,540 1/ Front office transaction amounts reflect one-year transaction periods, are not additive, and are reported as a 10/20-year annual average. Case S-15 PACIFICORP – 2015 IRP APPENDIX K – DETAIL CAPACITY EXPANSION RESULTS 210 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 211 APPENDIX L – STOCHASTIC PRODUCTION COST SIMULATION RESULTS Introduction This appendix reports additional results for the Monte Carlo production cost simulations conducted with the Planning and Risk (PaR) model for the core and sensitivity cases. These results supplement the data presented in Volume I Chapter 8 of the IRP document. The results presented include the following:  Screening of portfolios balancing costs and risk  Statistics of the stochastic simulation results  Components of portfolios’ present value revenue requirements (PVRR)  Energy-not-serve  Customer rate impact of portfolios in the final screen as compares with the preferred portfolio  Loss of load probability of the preferred portfolio The figures and tables in this appendix are the following for the core and sensitivity cases:  Figure L.1 through Figure L.6 – Stochastic Risk Profile under regional haze scenarios 1 and 2 by price scenario, Core Cases  Figure L.7 – Stochastic Risk Profile under regional haze scenarios 1 and 2 and medium gas plus high CO2 price  Table L.1 – Stochastic Mean PVRR ($m) by Price Scenario, Core Cases  Table L.2 – Stochastic Mean PVRR ($m) by Price Scenario, Sensitivity Cases  Table L.3 through Table L.6 – Stochastic Risk Results by price scenario, Core Cases  Table L.7 through Table L.9 – Stochastic Risk Results by price scenario, Sensitivity Cases  Table L.10 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Core Cases  Table L.11 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Sensitivity Cases  Table L.12 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Core Cases  Table L.13 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Sensitivity Cases  Table L.14 through Table L.17 – Average Annual Energy Not Served (2015 – 2034) by price scenario, Core Cases  Table L.18 through Table L.20 – Average Annual Energy Not Served (2015 – 2034) by price scenario, Sensitivity Cases  Table L.21 through Table L.24 – Portfolio PVRR Cost Components by price scenario, Core Cases  Table L.25 through Table L.27 – Portfolio PVRR Cost Components by price scenario, Sensitivity Cases  Table L.28 –10-year Average Incremental Customer Rate Impact ($m), Final Screen Portfolios  Table L.29 – Loss of Load Probability for a Major (> 25,000 MWh) July Event, Final Screen Portfolios, Base Price Curve  Table L.30 – Average Loss of Load Probability during Summer Peak, Final Screen Portfolios, PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 212 Figure L.1 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, Low Price Figure L.2 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, Base Price $17.5 $18.0 $18.5 $19.0 $19.5 $20.0 $20.5 $21.0 $25.5 $26.5 $27.5 $28.5 $29.5 $30.5Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenarios 1 and 3, Low Price C02-1 C03-1 C04-1 C05-1 C05a-1 C05b-1 C06-1 C07-1 C09-1 C11-1 C12-1 C13-1 C14-1 C14a-1 C05-3 C05a-3 C05b-3 $19.0 $19.5 $20.0 $20.5 $21.0 $21.5 $22.0 $22.5 $27.5 $28.0 $28.5 $29.0 $29.5 $30.0 $30.5 $31.0 Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenarios 1 and 3, Base Price C02-1 C03-1 C04-1 C05-1 C05a-1 C05b-1 C06-1 C07-1 C09-1 C11-1 C12-1 C13-1 C14-1 C14a-1 C05-3 C05a-3 C05b-3 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 213 Figure L.3 – Stochastic Risk Profile under Regional Haze Scenarios 1 and 3, High Price Figure L.4 – Stochastic Risk Profile under Regional Haze Scenario 2, Low Price $20.5 $21.0 $21.5 $22.0 $22.5 $23.0 $23.5 $24.0 $24.5 $29.0 $29.5 $30.0 $30.5 $31.0 $31.5 $32.0 $32.5 Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenarios 1 and 3, High Price C02-1 C03-1 C04-1 C05-1 C05a-1 C05b-1 C06-1 C07-1 C09-1 C11-1 C12-1 C13-1 C14-1 C14a-1 C05-3 C05a-3 C05b-3 $18.0 $18.5 $19.0 $19.5 $20.0 $20.5 $21.0 $26.0 $26.5 $27.0 $27.5 $28.0 $28.5 $29.0 $29.5 $30.0 Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenario 2, Low Price C02-2 C03-2 C04-2 C05-2 C05a-2 C06-2 C07-2 C09-2 C11-2 C12-2 C13-2 C14-2 C14a-2 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 214 Figure L.5 – Stochastic Risk Profile under Regional Haze Scenario 2, Base Price Figure L.6 – Stochastic Risk Profile under Regional Haze Scenario 2, High Price $19.5 $20.0 $20.5 $21.0 $21.5 $22.0 $22.5 $23.0 $28.0 $28.5 $29.0 $29.5 $30.0 $30.5 $31.0 $31.5 $32.0Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenario 2, Base Price C02-2 C03-2 C04-2 C05-2 C05a-2 C06-2 C07-2 C09-2 C11-2 C12-2 C13-2 C14-2 C14a-2 $21.5 $22.0 $22.5 $23.0 $23.5 $24.0 $24.5 $25.0 $25.5 $30.5 $31.0 $31.5 $32.0 $32.5 $33.0 $33.5Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) Regional Haze Scenario 2, High Price C02-2 C03-2 C04-2 C05-2 C05a-2 C05b-2 C06-2 C07-2 C09-2 C11-2 C12-2 C13-2 C14-2 C14a-2 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 215 Figure L.7 – Stochastic Risk Profile, High CO2 $38.0 $39.0 $40.0 $41.0 $42.0 $43.0 $44.0 $47.5 $48.0 $48.5 $49.0 $49.5 $50.0 $50.5 $51.0 $51.5 Up p e r T a i l M e a n P V R R L e s s F i x e d C o s t s ($ b i l l i o n ) Stochastic Mean PVRR($ billion) High CO2 C02-1 C03-1 C04-1 C05-1 C05a-1 C05b-1 C06-1 C07-1 C09-1 C11-1 C12-1 C13-1 C14-1 C14a-1 C02-2 C03-2 C04-2 C05-2 C05a-2 C06-2 C07-2 C09-2 C11-2 C12-2 C13-2 C14-2 C14a-2 C05-3 C05a-3 C05b-3 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 216 Table L.1 – Stochastic Mean PVRR ($m) by Price Scenario, Core Cases Case Low Base High High CO2 C01-R 26,888 27,990 29,347 50,810 C01-1 26,060 27,739 29,614 49,361 C02-1 26,798 28,350 30,096 49,234 C03-1 28,029 29,521 31,205 50,491 C04-1 29,534 30,856 32,379 51,042 C05-1 26,220 27,900 29,778 49,374 C05a-1 25,993 27,718 29,641 49,417 C05b-1 26,147 27,813 29,678 49,306 C06-1 27,710 29,278 31,043 50,612 C07-1 28,462 29,912 31,556 50,711 C09-1 26,435 28,049 29,865 49,142 C11-1 26,271 27,931 29,784 49,322 C12-1 26,115 27,801 29,690 49,343 C13-1 25,963 27,649 29,523 49,373 C14-1 27,627 28,900 30,464 48,497 C14a-1 28,012 29,675 31,604 47,750 C01-2 26,489 28,545 30,742 49,087 C02-2 27,154 29,088 31,161 48,858 C03-2 28,416 30,282 32,281 50,038 C04-2 29,908 31,601 33,439 50,592 C05-2 26,564 28,629 30,838 48,980 C05a-2 26,419 28,517 30,756 49,069 C06-2 28,077 30,023 32,106 50,143 C07-2 28,795 30,634 32,606 50,293 C09-2 26,827 28,831 30,976 48,895 C11-2 26,623 28,675 30,865 49,013 C12-2 26,477 28,557 30,771 49,161 C13-2 26,361 28,422 30,624 48,878 C14-2 28,229 29,841 31,686 48,100 C14a-2 27,824 29,825 32,025 47,531 C05-3 26,427 27,799 29,376 50,011 C05a-3 26,159 27,570 29,184 49,913 C05a-3Q Preferred Portfolio 26,090 27,500 29,086 49,616 C05b-3 26,361 27,736 29,319 49,940 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 217 Table L.2 – Stochastic Mean PVRR ($m) by Price Scenario, Sensitivity Cases Case Low Base High S-01 24,588 25,914 27,408 S-02 27,558 29,523 31,696 S-03 27,179 28,797 30,603 S-04 26,436 28,160 30,075 S-05 25,628 27,194 28,972 S-06 26,655 28,338 30,217 S-07 29,160 30,593 32,236 S-08 29,946 31,332 32,935 S-09 26,229 27,872 29,725 S-10_ECA 19,782 20,824 21,924 S-10_WCA 8,028 8,465 8,988 S-10_System 25,768 27,169 28,742 S-11 30,654 31,539 32,774 S-12 25,662 27,209 28,975 S-13 26,586 28,274 30,156 S-14 26,171 27,843 29,715 S-15 26,653 28,306 30,138 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 218 Table L.3 – Stochastic Risk Results, PVRR ($m), Core Cases, Low Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs C01-R 176 26,609 27,190 18,157 C01-1 207 25,750 26,433 18,280 C02-1 189 26,530 27,113 18,004 C03-1 194 27,779 28,357 20,157 C04-1 190 29,271 29,845 19,579 C05-1 205 25,933 26,554 18,486 C05a-1 216 25,686 26,368 18,673 C05b-1 197 25,883 26,480 18,498 C06-1 211 27,415 28,091 20,474 C07-1 193 28,198 28,782 20,007 C09-1 171 26,182 26,684 18,326 C11-1 196 25,997 26,589 18,546 C12-1 212 25,795 26,507 18,625 C13-1 204 25,676 26,343 18,375 C14-1 220 27,355 28,039 18,268 C14a-1 223 27,708 28,394 18,428 C01-2 255 26,138 26,901 18,929 C02-2 218 26,809 27,509 18,400 C03-2 226 28,111 28,822 20,469 C04-2 228 29,557 30,258 19,887 C05-2 239 26,216 26,937 18,905 C05a-2 251 26,095 26,765 19,099 C06-2 232 27,742 28,402 20,731 C07-2 225 28,480 29,130 20,361 C09-2 218 26,507 27,183 18,720 C11-2 263 26,231 27,131 19,169 C12-2 293 26,073 27,051 19,143 C13-2 227 25,995 26,705 18,842 C14-2 198 27,967 28,592 18,241 C14a-2 222 27,516 28,165 18,661 C05-3 202 26,125 26,799 18,303 C05a-3 182 25,883 26,442 18,377 C05a-3Q Preferred Portfolio 175 25,807 26,328 18,353 C05b-3 184 26,069 26,622 18,246 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 219 Table L.4 – Stochastic Risk Results, PVRR ($m), Core Cases, Base Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs C01-R 223 27,592 28,374 19,311 C01-1 264 27,322 28,195 20,042 C02-1 240 27,979 28,795 19,640 C03-1 244 29,181 29,964 21,731 C04-1 241 30,515 31,279 20,981 C05-1 256 27,500 28,363 20,235 C05a-1 269 27,304 28,221 20,470 C05b-1 246 27,452 28,255 20,248 C06-1 263 28,899 29,785 22,131 C07-1 243 29,563 30,350 21,539 C09-1 218 27,705 28,413 20,004 C11-1 246 27,558 28,374 20,288 C12-1 265 27,378 28,289 20,396 C13-1 260 27,258 28,096 20,145 C14-1 253 28,563 29,365 19,551 C14a-1 267 29,294 30,119 20,177 C01-2 304 28,106 29,003 21,045 C02-2 269 28,657 29,522 20,411 C03-2 273 29,893 30,762 22,399 C04-2 274 31,156 32,061 21,670 C05-2 285 28,162 29,100 21,070 C05a-2 298 28,102 28,962 21,289 C06-2 276 29,589 30,423 22,751 C07-2 273 30,226 31,024 22,262 C09-2 264 28,420 29,254 20,792 C11-2 307 28,181 29,251 21,268 C12-2 340 28,063 29,120 21,270 C13-2 279 27,966 28,864 21,001 C14-2 248 29,514 30,290 19,915 C14a-2 270 29,423 30,277 20,769 C05-3 252 27,379 28,257 19,738 C05a-3 231 27,191 27,934 19,842 C05a-3Q Preferred Portfolio 224 27,123 27,811 19,814 C05b-3 234 27,334 28,086 19,683 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 220 Table L.5 – Stochastic Risk Results, PVRR ($m), Core Cases, High Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs C01-R 287 28,846 29,785 20,743 C01-1 329 29,088 30,113 22,034 C02-1 302 29,623 30,594 21,463 C03-1 304 30,764 31,697 23,487 C04-1 300 31,939 32,870 22,574 C05-1 317 29,277 30,333 22,197 C05a-1 333 29,129 30,218 22,499 C05b-1 306 29,230 30,213 22,195 C06-1 324 30,573 31,614 23,995 C07-1 304 31,108 32,043 23,255 C09-1 278 29,421 30,311 21,887 C11-1 309 29,312 30,273 22,218 C12-1 329 29,165 30,229 22,358 C13-1 326 29,025 30,015 22,097 C14-1 298 30,055 30,984 21,131 C14a-1 318 31,143 32,105 22,171 C01-2 363 30,216 31,346 23,336 C02-2 330 30,651 31,687 22,577 C03-2 330 31,813 32,800 24,493 C04-2 331 32,906 34,000 23,601 C05-2 341 30,279 31,371 23,375 C05a-2 356 30,241 31,339 23,608 C06-2 332 31,592 32,648 24,914 C07-2 330 32,116 33,144 24,328 C09-2 319 30,486 31,525 23,020 C11-2 362 30,285 31,493 23,486 C12-2 397 30,194 31,381 23,522 C13-2 339 30,088 31,176 23,331 C14-2 307 31,259 32,225 21,850 C14a-2 326 31,540 32,604 23,072 C05-3 313 28,857 29,885 21,385 C05a-3 292 28,693 29,649 21,520 C05a-3Q Preferred Portfolio 284 28,625 29,537 21,452 C05b-3 297 28,830 29,781 21,330 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 221 Table L.6 – Stochastic Risk Results, PVRR ($m), Core Cases, High CO2 Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs C01-R 263 50,336 51,179 42,258 C01-1 297 48,859 49,877 41,802 C02-1 291 48,767 49,682 40,662 C03-1 275 50,084 50,894 42,790 C04-1 266 50,600 51,421 41,267 C05-1 303 48,893 49,891 41,902 C05a-1 316 48,915 49,968 42,350 C05b-1 286 48,826 49,703 41,848 C06-1 290 50,185 51,110 43,586 C07-1 273 50,260 51,206 42,457 C09-1 259 48,708 49,533 41,233 C11-1 289 48,830 49,789 41,834 C12-1 311 48,849 49,892 42,067 C13-1 303 48,960 49,949 42,027 C14-1 327 47,997 49,045 39,253 C14a-1 324 47,344 48,296 38,303 C01-2 332 48,596 49,704 41,712 C02-2 292 48,412 49,462 40,329 C03-2 294 49,639 50,613 42,332 C04-2 290 50,144 51,054 40,750 C05-2 303 48,424 49,532 41,523 C05a-2 339 48,569 49,610 41,985 C06-2 292 49,678 50,663 42,979 C07-2 294 49,861 50,832 42,067 C09-2 295 48,478 49,459 41,008 C11-2 336 48,485 49,665 41,740 C12-2 364 48,597 49,814 42,001 C13-2 289 48,377 49,353 41,516 C14-2 311 47,652 48,634 38,429 C14a-2 329 46,958 48,044 38,608 C05-3 294 49,530 50,522 42,095 C05a-3 274 49,463 50,381 42,357 C05a-3Q Preferred Portfolio 278 49,199 50,101 42,160 C05b-3 274 49,464 50,351 42,036 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 222 Table L.7 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, Low Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs S-01 171 24,358 24,874 17,109 S-02 197 27,278 27,854 19,342 S-03 161 26,970 27,437 18,792 S-04 199 26,144 26,768 18,581 S-05 196 25,368 25,976 18,119 S-06 229 26,335 27,129 18,695 S-07 187 28,905 29,449 19,855 S-08 198 29,689 30,325 19,837 S-09 217 25,917 26,617 18,571 S-10_ECA 272 19,456 20,276 13,809 S-10_WCA 128 7,854 8,256 5,941 S-10_System 162 25,535 25,989 17,959 S-11 181 30,375 30,969 17,116 S-12 209 25,375 26,047 18,180 S-13 204 26,294 26,907 18,567 S-14 199 25,893 26,498 18,517 S-15 206 26,347 26,976 18,649 Table L.8 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, Base Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs S-01 220 25,589 26,338 18,517 S-02 254 29,122 29,964 21,397 S-03 211 28,481 29,131 20,460 S-04 252 27,760 28,629 20,383 S-05 248 26,846 27,680 19,768 S-06 284 27,922 28,926 20,476 S-07 237 30,249 31,008 21,370 S-08 249 30,993 31,812 21,306 S-09 267 27,467 28,355 20,279 S-10_ECA 314 20,404 21,361 14,878 S-10_WCA 141 8,258 8,707 6,394 S-10_System 211 26,834 27,466 19,418 S-11 224 31,167 31,946 18,043 S-12 261 26,824 27,721 19,797 S-13 256 27,870 28,733 20,334 S-14 252 27,451 28,312 20,273 S-15 258 27,909 28,695 20,423 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 223 Table L.9 – Stochastic Risk Results, PVRR ($m), Sensitivity Cases, High Price Curve Case Standard Deviation 5th percentile 95th percentile Upper Tail (mean of 3 Highest) No Fixed Costs S-01 277 26,990 27,883 20,077 S-02 324 31,182 32,190 23,643 S-03 271 30,180 31,039 22,333 S-04 315 29,571 30,609 22,391 S-05 310 28,529 29,502 21,631 S-06 349 29,702 30,827 22,468 S-07 298 31,798 32,735 23,084 S-08 310 32,504 33,471 22,991 S-09 327 29,220 30,244 22,233 S-10_ECA 365 21,388 22,568 16,053 S-10_WCA 159 8,753 9,268 6,956 S-10_System 273 28,307 29,142 21,062 S-11 283 32,304 33,254 19,406 S-12 324 28,490 29,533 21,651 S-13 320 29,649 30,689 22,290 S-14 316 29,219 30,245 22,237 S-15 325 29,638 30,626 22,400 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 224 Table L.10 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Core Cases Case Low Base High High CO2 C01-R 28,248 29,408 30,837 53,369 C01-1 27,382 29,149 31,120 51,855 C02-1 28,154 29,790 31,626 51,718 C03-1 29,447 31,019 32,789 53,036 C04-1 31,026 32,420 34,023 53,613 C05-1 27,547 29,319 31,295 51,869 C05a-1 27,311 29,129 31,152 51,915 C05b-1 27,471 29,226 31,189 51,791 C06-1 29,114 30,768 32,624 53,167 C07-1 29,901 31,429 33,159 53,271 C09-1 27,769 29,469 31,381 51,619 C11-1 27,601 29,350 31,298 51,811 C12-1 27,440 29,215 31,201 51,838 C13-1 27,281 29,053 31,023 51,871 C14-1 29,029 30,368 32,013 50,950 C14a-1 29,432 31,181 33,209 50,164 C01-2 27,834 29,995 32,309 51,573 C02-2 28,529 30,564 32,746 51,332 C03-2 29,857 31,820 33,921 52,569 C04-2 31,421 33,204 35,139 53,145 C05-2 27,910 30,084 32,406 51,457 C05a-2 27,757 29,966 32,323 51,550 C06-2 29,498 31,544 33,738 52,677 C07-2 30,252 32,185 34,263 52,834 C09-2 28,187 30,293 32,552 51,368 C11-2 27,980 30,138 32,440 51,496 C12-2 27,830 30,013 32,340 51,652 C13-2 27,697 29,865 32,183 51,346 C14-2 29,659 31,356 33,297 50,532 C14a-2 29,232 31,339 33,655 49,933 C05-3 27,767 29,211 30,870 52,537 C05a-3 27,481 28,967 30,667 52,432 C05a-3Q Preferred Portfolio 27,406 28,890 30,563 52,121 C05b-3 27,692 29,140 30,808 52,458 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 225 Table L.11 – Stochastic Risk Adjusted PVRR ($m) by Price Scenario, Sensitivity Cases Case Low Base High S-01 25,832 27,231 28,803 S-02 28,951 31,021 33,305 S-03 28,551 30,253 32,155 S-04 27,774 29,592 31,606 S-05 26,926 28,578 30,447 S-06 28,011 29,784 31,759 S-07 30,633 32,144 33,873 S-08 31,463 32,923 34,609 S-09 27,560 29,289 31,238 S-10_ECA 20,796 21,892 23,052 S-10_WCA 8,441 8,901 9,451 S-10_System 27,067 28,542 30,199 S-11 32,203 33,137 34,437 S-12 26,964 28,595 30,451 S-13 27,931 29,710 31,691 S-14 27,496 29,259 31,228 S-15 28,002 29,741 31,670 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 226 Table L.12 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Core Cases Case Low Base High High CO2 C01-R 954,131 968,854 966,480 770,940 C01-1 884,900 891,716 887,700 749,180 C02-1 877,961 885,913 882,086 729,463 C03-1 865,727 873,288 869,936 733,376 C04-1 859,153 867,139 863,921 727,016 C05-1 882,521 889,576 885,516 736,826 C05a-1 884,354 891,521 887,442 741,484 C05b-1 885,615 892,956 889,002 739,289 C06-1 869,416 876,150 872,465 739,385 C07-1 865,338 872,280 868,916 734,375 C09-1 883,946 891,909 887,727 727,116 C11-1 881,361 888,468 883,908 734,810 C12-1 878,575 887,201 883,248 738,260 C13-1 880,500 889,921 886,142 751,840 C14-1 845,210 855,017 851,563 703,575 C14a-1 786,902 794,662 790,518 669,998 C01-2 833,847 839,679 835,188 721,516 C02-2 828,825 835,872 831,792 701,058 C03-2 819,487 825,881 821,982 701,549 C04-2 813,156 819,638 815,845 696,154 C05-2 833,961 840,153 835,753 709,547 C05a-2 836,923 843,280 838,861 713,725 C06-2 823,300 828,898 824,711 707,456 C07-2 819,570 825,263 821,324 702,313 C09-2 837,389 844,468 840,009 704,503 C11-2 832,417 838,547 833,673 709,203 C12-2 832,979 840,373 836,123 725,364 C13-2 831,714 840,321 836,068 714,659 C14-2 798,739 806,523 802,567 678,744 C14a-2 762,962 769,632 765,115 661,706 C05-3 920,425 929,133 925,789 767,434 C05a-3 920,690 929,808 926,533 766,421 C05a-3Q Preferred Portfolio 922,019 930,639 926,565 760,565 C05b-3 920,445 929,146 925,797 767,672 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 227 Table L.13 – Carbon Dioxide Emissions (Thousand Tons) by Price Scenario, Sensitivity Cases Case Low Base High S-01 854,947 862,891 860,285 S-02 906,398 913,399 908,198 S-03 883,328 891,064 886,684 S-04 886,590 893,822 889,722 S-05 872,672 879,615 875,786 S-06 879,179 885,555 881,575 S-07 867,801 875,603 872,134 S-08 865,604 873,525 870,110 S-09 875,527 882,938 878,961 S-10_ECA 664,332 671,039 667,937 S-10_WCA 235,827 240,945 242,142 S-10_System 923,536 928,931 924,459 S-11 815,094 827,344 824,962 S-12 873,102 879,784 875,867 S-13 878,753 885,215 881,317 S-14 880,406 887,152 883,024 S-15 869,631 876,787 873,126 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 228 Table L.14 – Average Annual Energy Not Served (2015 – 2034), Core Cases, Low Price Curve Case Average Annual Energy Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 (GWh) C01-R 59.2 79.5 C01-1 41.4 53.1 C02-1 57.1 79.4 C03-1 60.6 81.0 C04-1 60.0 80.6 C05-1 59.7 84.6 C05a-1 61.5 83.0 C05b-1 59.6 81.2 C06-1 62.4 85.3 C07-1 59.9 81.4 C09-1 55.3 78.4 C11-1 58.2 80.7 C12-1 64.2 84.9 C13-1 42.0 53.3 C14-1 76.1 55.0 C14a-1 76.0 98.8 C01-2 72.5 99.6 C02-2 80.5 113.9 C03-2 76.5 105.2 C04-2 78.3 103.7 C05-2 83.0 128.5 C05a-2 85.6 128.0 C06-2 78.5 109.2 C07-2 78.5 107.5 C09-2 73.6 107.3 C11-2 84.2 135.3 C12-2 84.3 127.3 C13-2 71.8 98.6 C14-2 78.6 96.0 C14a-2 75.0 96.7 C05-3 64.2 83.6 C05a-3 61.1 79.5 C05a-3Q Preferred Portfolio 58.9 80.2 C05b-3 62.8 80.4 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 229 Table L.15 – Average Annual Energy Not Served (2015 – 2034), Core Cases, Base Price Curve Case Average Annual Energy Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 (GWh) C01-R 60.2 80.0 C01-1 42.2 53.3 C02-1 58.0 79.7 C03-1 61.7 81.2 C04-1 61.0 80.7 C05-1 60.6 84.9 C05a-1 62.5 83.2 C05b-1 60.5 81.4 C06-1 63.6 85.4 C07-1 60.9 81.5 C09-1 55.9 78.6 C11-1 58.9 80.9 C12-1 65.2 85.4 C13-1 43.0 53.5 C14-1 76.7 54.3 C14a-1 77.0 99.3 C01-2 73.2 100.0 C02-2 81.4 114.2 C03-2 77.7 105.4 C04-2 79.4 103.9 C05-2 84.0 128.7 C05a-2 86.5 128.5 C06-2 79.9 109.6 C07-2 79.6 107.8 C09-2 74.1 107.6 C11-2 85.0 135.8 C12-2 85.7 127.6 C13-2 72.5 99.2 C14-2 79.8 96.2 C14a-2 75.7 96.9 C05-3 65.3 84.3 C05a-3 62.3 79.8 C05a-3Q Preferred Portfolio 59.8 80.5 C05b-3 64.0 80.7 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 230 Table L.16 – Average Annual Energy Not Served (2015 – 2034), Core Cases, High Price Curve Case Average Annual Energy Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 (GWh) C01-R 61.5 80.8 C01-1 43.5 53.8 C02-1 59.4 80.5 C03-1 63.3 82.1 C04-1 62.6 81.6 C05-1 62.2 85.8 C05a-1 64.2 84.0 C05b-1 62.2 82.2 C06-1 65.2 86.4 C07-1 62.6 82.4 C09-1 57.3 79.5 C11-1 60.3 81.6 C12-1 66.8 86.0 C13-1 44.3 54.2 C14-1 78.3 55.8 C14a-1 78.7 100.4 C01-2 74.7 100.5 C02-2 83.0 115.4 C03-2 79.4 106.3 C04-2 81.1 104.8 C05-2 85.7 129.9 C05a-2 88.3 129.6 C06-2 81.5 110.5 C07-2 81.3 108.9 C09-2 75.5 108.6 C11-2 86.7 136.7 C12-2 87.6 128.6 C13-2 74.0 100.1 C14-2 81.2 97.1 C14a-2 77.5 97.6 C05-3 66.8 85.3 C05a-3 63.7 80.7 C05a-3Q Preferred Portfolio 61.1 81.4 C05b-3 65.4 81.5 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 231 Table L.17 – Average Annual Energy Not Served (2015 – 2034), Core Cases, High CO2 Price Curve Case Average Annual Energy Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 (GWh) C01-R 61.9 79.4 C01-1 50.2 58.2 C02-1 61.0 83.3 C03-1 67.6 83.0 C04-1 68.1 83.5 C05-1 63.9 89.0 C05a-1 66.3 86.0 C05b-1 63.4 82.6 C06-1 69.0 87.7 C07-1 67.2 84.6 C09-1 57.7 80.0 C11-1 62.0 82.6 C12-1 72.3 88.7 C13-1 53.1 56.9 C14-1 97.9 61.5 C14a-1 99.7 121.0 C01-2 97.2 117.9 C02-2 101.4 132.5 C03-2 99.0 122.4 C04-2 100.7 122.1 C05-2 103.9 145.8 C05a-2 106.7 146.0 C06-2 100.4 127.9 C07-2 100.7 124.7 C09-2 94.3 125.3 C11-2 104.8 154.4 C12-2 111.4 144.9 C13-2 95.5 116.2 C14-2 93.9 111.7 C14a-2 94.1 113.8 C05-3 68.2 86.0 C05a-3 64.2 79.3 C05a-3Q Preferred Portfolio 60.8 80.1 C05b-3 66.8 80.3 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 232 Table L.18 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Low Price Curve Case Avera e Annual Ener Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 S-01 43.1 61.6 S-02 56.5 73.6 S-03 27.3 46.9 S-04 61.3 83.6 S-05 51.9 72.4 S-06 66.5 83.5 S-07 57.3 81.0 S-08 58.5 82.0 S-09 74.5 96.7 S-10_ECA 50.3 54.8 S-10_WCA 17.4 46.3 S-10_System 32.8 56.7 S-11 66.8 89.5 S-12 54.7 73.1 S-13 61.3 81.7 S-14 60.7 81.6 S-15 55.9 74.5 Table L.19 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Base Price Curve Case Avera e Annual Ener Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 S-01 43.9 61.8 S-02 57.2 73.9 S-03 27.4 46.9 S-04 62.1 83.8 S-05 52.8 72.4 S-06 67.8 83.9 S-07 58.3 81.1 S-08 59.5 82.1 S-09 75.6 97.1 S-10_ECA 51.2 54.8 S-10_WCA 17.1 46.1 S-10_System 33.4 57.1 S-11 67.3 90.1 S-12 55.8 73.3 S-13 62.2 82.0 S-14 61.6 82.0 S-15 56.3 74.2 PACIFICORP – 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 233 Table L.20 – Average Annual Energy Not Served (2015 – 2034), Sensitivity Cases, Price Curve Case Average Annual Energy Not Served, 2015-2034 (GWh) Upper Tail Mean Energy Not Served Cumulative Total, 2015-2034 S-01 45.2 62.3 S-02 58.8 74.5 S-03 28.4 47.4 S-04 63.8 84.8 S-05 54.3 73.4 S-06 69.7 84.5 S-07 59.8 81.8 S-08 60.8 82.8 S-09 77.3 98.1 S-10_ECA 52.3 54.8 S-10_WCA 17.4 46.3 S-10_System 34.2 57.4 S-11 68.5 91.0 S-12 57.3 74.1 S-13 63.7 82.8 S-14 63.1 82.8 S-15 57.3 74.5 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 235 Table L.21 – Portfolio PVRR ($m) Cost Components, Core Cases, Low Price Curve Case Thermal Fuel Variable O&M incl. FOT Emission Cost Long Term Contracts Renewables DSM System Balancing Sales System Balancing Purchases Capital and Fixed O&M Cost Total PVRR C01-R 13,671 1,487 0 908 1,901 800 (3,190) 2,202 9,109 26,888 C01-1 13,419 1,598 0 910 1,904 737 (2,943) 2,241 8,193 26,060 C02-1 13,251 1,480 0 911 1,927 728 (3,016) 2,314 9,205 26,798 C03-1 12,902 1,424 0 909 1,910 3,003 (2,910) 2,484 8,306 28,029 C04-1 12,775 1,283 0 909 1,976 3,003 (3,046) 2,244 10,391 29,534 C05-1 13,320 1,595 0 911 1,904 728 (2,894) 2,472 8,184 26,220 C05a-1 13,369 1,633 0 912 1,897 731 (2,867) 2,529 7,789 25,993 C05b-1 13,368 1,600 0 912 1,907 728 (2,938) 2,459 8,111 26,147 C06-1 12,954 1,499 0 910 1,902 3,008 (2,857) 2,582 7,713 27,710 C07-1 12,868 1,389 0 909 1,920 3,004 (2,952) 2,428 8,897 28,462 C09-1 13,399 1,414 0 912 1,905 949 (2,943) 2,330 8,469 26,436 C11-1 13,266 1,553 0 914 1,903 907 (2,894) 2,471 8,151 26,271 C12-1 13,299 1,610 0 911 1,910 763 (2,867) 2,532 7,955 26,115 C13-1 13,400 1,586 0 910 1,904 789 (2,911) 2,273 8,012 25,963 C14-1 12,559 1,617 0 910 1,935 1,120 (2,920) 2,502 9,904 27,627 C14a-1 12,470 1,728 0 914 1,943 1,155 (2,902) 2,587 10,118 28,012 C01-2 13,318 1,641 0 911 1,903 847 (2,878) 2,639 8,108 26,489 C02-2 13,267 1,546 0 910 1,930 777 (2,976) 2,515 9,184 27,154 C03-2 12,944 1,493 0 909 1,911 3,002 (2,899) 2,638 8,417 28,416 C04-2 12,810 1,350 0 909 1,976 2,994 (3,034) 2,425 10,478 29,908 C05-2 13,368 1,665 0 910 1,911 777 (2,872) 2,660 8,143 26,564 C05a-2 13,422 1,683 0 912 1,898 780 (2,859) 2,711 7,872 26,419 C06-2 13,010 1,570 0 910 1,903 3,003 (2,846) 2,729 7,800 28,077 C07-2 12,923 1,469 0 909 1,916 3,004 (2,925) 2,611 8,888 28,795 C09-2 13,464 1,477 0 913 1,905 944 (2,927) 2,500 8,552 26,828 C11-2 13,300 1,643 0 913 1,911 934 (2,863) 2,701 8,084 26,623 C12-2 13,388 1,694 0 911 1,911 774 (2,873) 2,669 8,003 26,478 C13-2 13,380 1,670 0 912 1,911 798 (2,869) 2,590 7,969 26,362 C14-2 12,534 1,632 0 910 1,958 1,152 (2,929) 2,546 10,426 28,229 C14a-2 12,676 1,764 0 914 1,931 1,163 (2,865) 2,623 9,618 27,824 C05-3 13,475 1,492 0 908 1,911 773 (3,010) 2,320 8,557 26,427 C05a-3 13,490 1,519 0 908 1,898 787 (2,953) 2,340 8,171 26,159 C05a-3Q Preferred Portfolio 13,525 1,463 0 903 1,938 764 (2,944) 2,327 8,115 26,090 C05b-3 13,472 1,492 0 908 1,909 774 (3,007) 2,318 8,495 26,361 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 236 Table L.22 – Portfolio PVRR ($m) Cost Components, Core Cases, Base Price Curve Case Thermal Fuel Variable O&M incl. FOT Emission Cost Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Capital and Fixed O&M Cost Total PVRR C01-R 15,171 1,616 0 912 1,901 800 (4,138) 2,618 9,109 27,990 C01-1 15,211 1,743 0 914 1,904 737 (3,760) 2,796 8,193 27,739 C02-1 14,998 1,605 0 916 1,927 728 (3,861) 2,833 9,205 28,350 C03-1 14,503 1,554 0 913 1,910 3,003 (3,727) 3,059 8,306 29,521 C04-1 14,348 1,389 0 912 1,975 3,003 (3,902) 2,739 10,391 30,856 C05-1 15,082 1,744 0 916 1,904 728 (3,705) 3,049 8,184 27,900 C05a-1 15,147 1,788 0 917 1,897 731 (3,670) 3,119 7,789 27,718 C05b-1 15,136 1,750 0 917 1,907 728 (3,760) 3,024 8,111 27,813 C06-1 14,563 1,644 0 913 1,902 3,008 (3,656) 3,191 7,713 29,278 C07-1 14,452 1,514 0 912 1,920 3,004 (3,775) 2,987 8,897 29,912 C09-1 15,194 1,522 0 919 1,905 949 (3,777) 2,868 8,469 28,049 C11-1 15,017 1,697 0 920 1,903 906 (3,706) 3,043 8,151 27,932 C12-1 15,075 1,762 0 916 1,910 763 (3,686) 3,105 7,955 27,801 C13-1 15,217 1,736 0 914 1,904 789 (3,745) 2,823 8,012 27,649 C14-1 14,022 1,754 0 915 1,936 1,120 (3,757) 3,007 9,904 28,900 C14a-1 14,234 1,866 0 921 1,943 1,155 (3,715) 3,153 10,118 29,675 C01-2 15,382 1,796 0 916 1,903 847 (3,672) 3,265 8,108 28,545 C02-2 15,341 1,674 0 915 1,930 777 (3,808) 3,074 9,184 29,088 C03-2 14,861 1,619 0 913 1,911 3,002 (3,705) 3,263 8,417 30,282 C04-2 14,685 1,452 0 912 1,976 2,994 (3,872) 2,976 10,478 31,601 C05-2 15,470 1,817 0 915 1,911 777 (3,673) 3,269 8,143 28,629 C05a-2 15,543 1,838 0 917 1,898 780 (3,656) 3,326 7,872 28,518 C06-2 14,940 1,710 0 913 1,903 3,003 (3,633) 3,387 7,800 30,023 C07-2 14,826 1,590 0 912 1,916 3,004 (3,732) 3,229 8,888 30,634 C09-2 15,609 1,588 0 919 1,906 944 (3,753) 3,067 8,552 28,831 C11-2 15,384 1,791 0 919 1,911 933 (3,661) 3,313 8,084 28,676 C12-2 15,509 1,851 0 916 1,911 774 (3,681) 3,274 8,003 28,557 C13-2 15,519 1,818 0 918 1,912 798 (3,693) 3,182 7,969 28,422 C14-2 14,270 1,768 0 915 1,958 1,152 (3,754) 3,107 10,426 29,841 C14a-2 14,727 1,903 0 921 1,931 1,163 (3,666) 3,229 9,618 29,826 C05-3 15,075 1,619 0 912 1,911 773 (3,861) 2,812 8,557 27,799 C05a-3 15,099 1,651 0 912 1,898 787 (3,794) 2,847 8,171 27,571 C05a-3Q Preferred Portfolio 15,129 1,586 0 904 2,010 764 (3,804) 2,797 8,115 27,500 C05b-3 15,071 1,620 0 912 1,909 774 (3,855) 2,810 8,495 27,736 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 237 Table L.23 – Portfolio PVRR ($m) Cost Components, Core Cases, High Price Curve Case Thermal Fuel Variable O&M incl. FOT Emission Cost Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Capital and Fixed O&M Cost Total PVRR C01-R 16,484 1,737 0 911 1,901 800 (4,965) 3,369 9,109 29,348 C01-1 16,797 1,885 0 914 1,904 737 (4,481) 3,665 8,193 29,614 C02-1 16,528 1,726 0 916 1,927 728 (4,605) 3,672 9,205 30,096 C03-1 15,929 1,671 0 913 1,910 3,003 (4,453) 3,925 8,306 31,205 C04-1 15,752 1,482 0 912 1,975 3,003 (4,667) 3,531 10,391 32,379 C05-1 16,630 1,886 0 916 1,904 728 (4,415) 3,946 8,184 29,778 C05a-1 16,710 1,937 0 917 1,897 731 (4,371) 4,032 7,789 29,641 C05b-1 16,691 1,894 0 917 1,907 728 (4,482) 3,913 8,111 29,678 C06-1 16,000 1,775 0 913 1,902 3,008 (4,361) 4,094 7,713 31,043 C07-1 15,872 1,626 0 912 1,920 3,004 (4,511) 3,836 8,897 31,556 C09-1 16,759 1,624 0 919 1,905 949 (4,502) 3,741 8,469 29,866 C11-1 16,512 1,831 0 920 1,903 905 (4,403) 3,966 8,151 29,784 C12-1 16,618 1,908 0 916 1,910 763 (4,391) 4,010 7,955 29,690 C13-1 16,795 1,876 0 914 1,903 789 (4,463) 3,696 8,012 29,523 C14-1 15,332 1,881 0 915 1,935 1,120 (4,481) 3,857 9,904 30,464 C14a-1 15,823 1,993 0 921 1,942 1,155 (4,419) 4,070 10,118 31,604 C01-2 17,176 1,941 0 916 1,903 847 (4,364) 4,215 8,108 30,742 C02-2 17,147 1,799 0 915 1,930 777 (4,538) 3,947 9,184 31,161 C03-2 16,540 1,737 0 913 1,911 3,002 (4,417) 4,179 8,417 32,281 C04-2 16,334 1,544 0 912 1,976 2,994 (4,622) 3,822 10,478 33,439 C05-2 17,303 1,962 0 915 1,911 777 (4,371) 4,197 8,143 30,838 C05a-2 17,387 1,986 0 917 1,898 780 (4,349) 4,264 7,872 30,756 C06-2 16,636 1,841 0 913 1,903 3,003 (4,326) 4,336 7,800 32,106 C07-2 16,499 1,703 0 912 1,916 3,004 (4,450) 4,132 8,888 32,606 C09-2 17,464 1,693 0 919 1,905 944 (4,470) 3,967 8,552 30,976 C11-2 17,160 1,932 0 920 1,911 932 (4,344) 4,271 8,084 30,865 C12-2 17,344 1,999 0 916 1,911 774 (4,379) 4,203 8,003 30,771 C13-2 17,347 1,960 0 918 1,911 798 (4,393) 4,113 7,969 30,624 C14-2 15,820 1,893 0 915 1,958 1,152 (4,474) 3,997 10,426 31,686 C14a-2 16,539 2,034 0 921 1,931 1,163 (4,356) 4,176 9,618 32,025 C05-3 16,481 1,740 0 912 1,911 773 (4,612) 3,614 8,557 29,376 C05a-3 16,510 1,776 0 912 1,898 787 (4,532) 3,663 8,171 29,184 C05a-3Q Preferred Portfolio 16,507 1,698 0 909 2,113 764 (4,579) 3,559 8,115 29,086 C05b-3 16,477 1,743 0 912 1,909 774 (4,606) 3,616 8,495 29,319 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 238 Table L.24 – Portfolio PVRR ($m) Cost Components, Core Cases, High CO2 Price Curve Case Thermal Fuel Variable O&M incl. FOT Emission Cost Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Capital and Fixed O&M Cost Total PVRR C01-R 15,444 2,118 16,568 923 1,901 800 (4,008) 7,953 9,109 50,810 C01-1 16,274 2,333 15,826 924 1,904 737 (4,159) 7,328 8,193 49,361 C02-1 15,983 2,108 15,095 924 1,927 728 (4,216) 7,481 9,205 49,234 C03-1 15,236 2,046 15,285 923 1,911 3,003 (4,051) 7,832 8,306 50,491 C04-1 15,079 1,752 15,027 923 1,976 3,003 (4,324) 7,215 10,391 51,042 C05-1 16,100 2,343 15,324 924 1,905 728 (3,997) 7,864 8,184 49,374 C05a-1 16,183 2,418 15,497 925 1,898 731 (3,959) 7,935 7,789 49,417 C05b-1 16,148 2,346 15,395 925 1,907 728 (4,034) 7,780 8,111 49,306 C06-1 15,331 2,199 15,462 924 1,902 3,008 (3,957) 8,030 7,713 50,612 C07-1 15,214 1,973 15,304 923 1,920 3,004 (4,158) 7,634 8,897 50,711 C09-1 16,320 1,968 14,978 925 1,905 949 (4,087) 7,714 8,469 49,142 C11-1 16,013 2,274 15,273 926 1,904 910 (4,002) 7,872 8,151 49,322 C12-1 16,060 2,382 15,431 924 1,911 763 (3,972) 7,890 7,955 49,343 C13-1 16,215 2,333 15,992 924 1,904 789 (4,121) 7,325 8,012 49,373 C14-1 14,656 2,265 13,942 924 1,936 1,120 (4,086) 7,836 9,904 48,497 C14a-1 15,354 2,361 12,787 925 1,943 1,155 (4,218) 7,325 10,118 47,750 C01-2 16,684 2,405 14,765 925 1,904 847 (4,144) 7,596 8,108 49,088 C02-2 16,610 2,191 14,011 924 1,931 777 (4,256) 7,487 9,184 48,858 C03-2 15,941 2,120 14,038 923 1,911 3,002 (4,119) 7,804 8,417 50,038 C04-2 15,772 1,824 13,820 923 1,977 2,994 (4,399) 7,205 10,478 50,592 C05-2 16,781 2,428 14,277 924 1,912 777 (4,068) 7,807 8,143 48,980 C05a-2 16,858 2,461 14,426 925 1,899 780 (4,043) 7,892 7,872 49,070 C06-2 16,052 2,273 14,213 924 1,903 3,003 (4,022) 7,998 7,800 50,143 C07-2 15,930 2,071 14,048 923 1,917 3,004 (4,191) 7,702 8,888 50,293 C09-2 17,023 2,041 14,108 925 1,906 944 (4,184) 7,580 8,552 48,895 C11-2 16,663 2,397 14,292 926 1,911 935 (4,058) 7,863 8,084 49,013 C12-2 16,891 2,486 14,942 924 1,912 774 (4,194) 7,424 8,003 49,161 C13-2 16,858 2,436 14,554 924 1,912 798 (4,117) 7,544 7,969 48,878 C14-2 15,309 2,266 12,999 924 1,958 1,152 (4,235) 7,302 10,426 48,100 C14a-2 16,027 2,416 12,470 925 1,931 1,163 (4,226) 7,207 9,618 47,531 C05-3 15,769 2,151 16,368 923 1,911 773 (4,138) 7,696 8,557 50,011 C05a-3 15,790 2,206 16,335 923 1,898 787 (4,036) 7,840 8,171 49,913 C05a-3Q Preferred Portfolio 15,750 2,099 16,121 919 2,175 764 (4,071) 7,743 8,115 49,616 C05b-3 15,771 2,152 16,374 923 1,909 774 (4,134) 7,676 8,495 49,940 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 239 Table L.25 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, Low Price Curve Case Thermal Fuel Variable O&M incl. FOT Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Transmission Capital and O&M Capital and Fixed O&M Cost Total PVRR S-01 12,648 1,429 905 1,904 758 (2,998) 2,079 0 7,864 24,588 S-02 13,961 1,686 919 1,905 789 (2,846) 2,535 0 8,609 27,558 S03 13,373 1,724 907 1,957 1,576 (3,054) 1,947 0 8,749 27,179 S-04 13,441 1,610 910 1,904 738 (2,904) 2,454 0 8,282 26,436 S-05 13,054 1,556 910 1,904 735 (2,902) 2,430 0 7,942 25,628 S-06 13,200 1,575 915 1,911 786 (2,863) 2,652 0 8,479 26,655 S-07 12,915 1,438 908 1,946 2,830 (2,935) 2,331 945 8,782 29,160 S-08 12,823 1,449 909 1,967 2,826 (2,943) 2,329 2,044 8,543 29,946 S-09 13,192 1,618 909 1,931 742 (2,878) 2,584 0 8,130 26,229 S-10_ECA 9,930 703 348 1,726 1,245 (2,073) 1,368 0 6,536 19,782 S-10_WCA 3,198 766 574 304 199 (635) 1,268 0 2,352 8,027 S-10_System 13,461 1,459 901 1,938 768 (2,973) 2,110 0 8,106 25,768 S-11 12,055 1,499 909 1,990 1,280 (3,044) 2,048 0 13,917 30,654 S-12 13,055 1,559 911 1,912 772 (2,946) 2,442 0 7,956 25,662 S-13 13,203 1,587 915 1,904 766 (2,846) 2,604 0 8,452 26,586 S-14 13,252 1,600 911 1,906 786 (2,887) 2,527 0 8,076 26,172 S-15 12,903 1,595 912 1,904 989 (2,762) 2,717 0 8,397 26,654 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 240 Table L.26 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, Base Price Curve Case Thermal Fuel Variable O&M incl. FOT Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Transmission Capital and O&M Capital and Fixed O&M Cost Total PVRR S-01 14,196 1,561 908 1,904 758 (3,850) 2,574 0 7,864 25,914 S-02 15,965 1,840 929 1,905 789 (3,642) 3,128 0 8,609 29,523 S03 15,157 1,899 912 1,957 1,576 (3,903) 2,449 0 8,749 28,797 S-04 15,257 1,759 916 1,904 738 (3,718) 3,021 0 8,282 28,160 S-05 14,701 1,705 914 1,904 735 (3,714) 3,008 0 7,942 27,194 S-06 14,901 1,725 919 1,911 786 (3,656) 3,273 0 8,479 28,338 S-07 14,528 1,564 912 1,946 2,830 (3,767) 2,853 945 8,782 30,593 S-08 14,395 1,583 912 1,967 2,826 (3,777) 2,839 2,044 8,543 31,332 S-09 14,914 1,774 914 1,931 742 (3,689) 3,155 0 8,130 27,872 S-10_ECA 11,282 733 352 1,796 1,245 (2,725) 1,604 0 6,536 20,824 S-10_WCA 3,426 916 574 304 199 (791) 1,484 0 2,352 8,465 S-10_System 14,993 1,579 901 2,010 768 (3,794) 2,606 0 8,106 27,169 S-11 13,403 1,596 914 1,990 1,280 (3,944) 2,382 0 13,917 31,539 S-12 14,695 1,705 915 1,912 772 (3,759) 3,014 0 7,956 27,209 S-13 14,908 1,739 921 1,904 766 (3,639) 3,223 0 8,452 28,274 S-14 14,977 1,750 916 1,906 786 (3,691) 3,122 0 8,076 27,844 S-15 14,511 1,758 917 1,904 989 (3,543) 3,373 0 8,397 28,307 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 241 Table L.27 – Portfolio PVRR ($m) Cost Components, Sensitivity Cases, High Price Curve Case Thermal Fuel Variable O&M incl. FOT Long Term Contracts Renewable DSM System Balancing Sales System Balancing Purchases Transmission Capital and O&M Capital and Fixed O&M Cost Total PVRR S-01 15,572 1,683 908 1,903 758 (4,615) 3,335 0 7,864 27,408 S-02 17,686 1,986 929 1,905 789 (4,314) 4,106 0 8,609 31,696 S03 16,701 2,062 917 1,958 1,576 (4,642) 3,283 0 8,749 30,603 S-04 16,849 1,903 916 1,904 738 (4,430) 3,913 0 8,282 30,075 S-05 16,165 1,846 914 1,904 735 (4,428) 3,894 0 7,942 28,972 S-06 16,410 1,867 919 1,911 786 (4,356) 4,201 0 8,479 30,217 S-07 15,959 1,683 912 1,946 2,830 (4,501) 3,681 945 8,782 32,236 S-08 15,792 1,707 912 1,967 2,826 (4,514) 3,658 2,044 8,543 32,935 S-09 16,431 1,923 914 1,931 742 (4,396) 4,050 0 8,130 29,725 S-10_ECA 12,495 742 356 1,903 1,245 (3,296) 1,943 0 6,536 21,924 S-10_WCA 3,548 1,054 574 304 199 (913) 1,869 0 2,352 8,987 S-10_System 16,325 1,689 906 2,114 768 (4,562) 3,397 0 8,106 28,742 S-11 14,620 1,679 914 1,990 1,280 (4,722) 3,095 0 13,917 32,774 S-12 16,155 1,846 915 1,912 772 (4,481) 3,900 0 7,956 28,975 S-13 16,418 1,883 924 1,904 766 (4,337) 4,146 0 8,452 30,156 S-14 16,497 1,894 917 1,906 786 (4,394) 4,034 0 8,076 29,716 S-15 15,922 1,917 917 1,904 989 (4,223) 4,316 0 8,397 30,139 PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 242 Table L.28 –10-year Average Incremental Customer Rate Impact ($m), Final Screen Portfolios Low Price Base Price High Price Average Case Difference from Preferred Portfolio Rank Difference from Preferred Portfolio Rank Difference from Preferred Portfolio Ran k Difference from Preferred Portfolio Ran k C05a-3Q, Preferred Portfolio 0.0 1 0.0 1 0.0 1 0.0 1 C05-1 8.9 6 16.2 7 24.7 7 16.6 7 C05-3 10.9 7 10.2 4 9.7 4 10.3 4 C05a-3 0.1 2 0.3 2 0.7 2 0.4 2 C05b-1 4.0 4 11.8 6 20.8 6 12.2 6 C05b-3 0.9 3 1.0 3 1.5 3 1.1 3 C09-1 15.1 8 21.4 8 29.0 8 21.8 8 C13-1 4.1 5 11.6 5 20.1 5 11.9 5 Table L.29 – Loss of Load Probability for a Major (> 25,000 MWh) July Event, Final Screen Portfolios, Base Price Curve Year C05a-3Q, Preferred Portfolio C05-1 C05-3 C05a-3 C05b-1 C05b-3 C09-1 C13-1 2015 0% 0% 0% 0% 0% 0% 0% 0% 2016 24% 24% 24% 24% 24% 24% 24% 24% 2017 28% 28% 28% 28% 28% 28% 28% 28% 2018 2% 2% 2% 2% 4% 2% 2% 2% 2019 0% 0% 0% 0% 0% 0% 0% 0% 2020 36% 36% 36% 36% 36% 36% 40% 36% 2021 18% 18% 18% 18% 18% 18% 22% 18% 2022 36% 50% 36% 36% 50% 36% 38% 50% 2023 40% 44% 40% 40% 44% 40% 40% 2% 2024 4% 4% 4% 4% 6% 4% 4% 0% 2025 32% 40% 34% 34% 40% 34% 32% 12% 2026 44% 46% 44% 44% 46% 44% 44% 6% 2027 48% 50% 48% 48% 50% 48% 48% 8% 2028 48% 46% 58% 50% 44% 50% 44% 2% 2029 12% 12% 22% 12% 8% 14% 8% 2% 2030 6% 10% 6% 8% 6% 8% 6% 2% 2031 56% 56% 56% 54% 56% 54% 56% 6% 2032 56% 58% 56% 56% 54% 56% 54% 6% 2033 56% 52% 56% 56% 50% 56% 54% 24% 2034 64% 64% 66% 64% 64% 68% 64% 16% PACIFICORP - 2015 IRP APPENDIX L – STOCHASTIC SIMULATION RESULTS 243 Table L.30 – Average Loss of Load Probability during Summer Peak, Final Screen Portfolios, Base Price Curve Average for operating years 2015 through 2024 Event Size (MWh) C05a-3Q, Preferred Portfolio C05-1 C05-3 C05a-3 C05b-1 C05b-3 C09-1 C13-1 > 0 100% 100% 100% 100% 100% 100% 100% 100% > 1,000 100% 99% 100% 100% 99% 100% 100% 98% > 10,000 50% 52% 51% 51% 52% 51% 52% 44% > 25,000 19% 21% 19% 19% 21% 19% 20% 16% > 50,000 1% 1% 1% 1% 2% 1% 1% 1% > 100,000 0% 0% 0% 0% 0% 0% 0% 0% > 500,000 0% 0% 0% 0% 0% 0% 0% 0% Average for operating years 2015 through 2034 Event Size (MWh) C05a-3Q, Preferred Portfolio C05-1 C05-3 C05a-3 C05b-1 C05b-3 C09-1 C13-1 > 0 100% 100% 100% 100% 100% 100% 100% 100% > 1,000 99% 99% 99% 99% 99% 100% 99% 98% > 10,000 64% 65% 65% 64% 65% 64% 64% 40% > 25,000 31% 32% 32% 31% 31% 31% 30% 12% > 50,000 5% 6% 7% 5% 6% 6% 4% 2% > 100,000 1% 1% 1% 1% 1% 1% 0% 1% > 500,000 0% 0% 0% 0% 0% 0% 0% 0% > 1,000,000 0% 0% 0% 0% 0% 0% 0% 0% PacifiCorp – 2015 IRP Appendix M - Case Fact Sheets - 245 - Case Overview APPENDIX M – CASE STUDY FACT SHEETS Case Fact Sheet Overview This appendix documents the 2015 Integrated Resource Plan modeling assumptions used for the Core Case studies and the Sensitivity Case studies. The Core Fact sheets were provided to the public to further discussion at the November 14, 2014 Public Input Meeting. These aided in the discussion during the public process and provided details beyond the high level summary tables. Sensitivities were discussed extensively at the January and February meetings. Those fact sheets are included following the Core Fact sheets. Case Fact Sheets - Overview - 246 - Case Overview Core Case Fact Sheets The following Core Case Fact sheets summarize key assumptions and portfolio results for each portfolio being developed for the 2015 IRP. All cases produce resource portfolios capable of meeting state renewable portfolio standard requirements. Similarly, in addition to the specific 111(d) and Regional Haze compliance requirements specified for each case, all cases include costs to meet known and assumed compliance obligations for Mercury and Air Toxics (MATS), coal combustion residuals (CCR) under subtitle D of RCRA, cooling water intake structures under §316(b) of the Clean Water Act, and effluent guidelines. Quick Reference Guide Case Reg. Haze [1] 111(d) Def. [2] 111(d) Strat. [3] CO2 Price Class 2 DSM [4] FOTs 1st Year of New Thermal SO PVRR w/o Trans. ($m) SO PVRR w/ Trans. ($m) C01-R Ref None None None Base Base 2028 $26,822 $26,828 C01-1 1 None None None Base Base 2024 $26,647 $26,683 C01-2 2 None None None Base Base 2024 $27,233 $27,254 C02-1 1 1 A None Base Base 2024 $27,693 $27,787 C02-2 2 1 A None Base Base 2024 $28,213 $28,313 C03-1 1 1 B None Base+ Base 2028 $28,835 $28,889 C03-2 2 1 B None Base+ Base 2025 $29,447 $29,509 C04-1 1 1 C None Base+ Base 2028 $29,111 $29,310 C04-2 2 1 C None Base+ Base 2025 $29,706 $29,913 C05-1 1 2 A None Base Base 2024 $26,603 $26,646 C05-2 2 2 A None Base Base 2024 $27,127 $27,177 C05-3 3 2 A None Base Base 2028 $26,569 $26,615 C05a-1 1 2 A None Base Base 2024 $26,566 $26,591 C05b-1 1 2 A None Base Base 2024 $26,605 $26,649 C05a-2 2 2 A None Base Base 2024 $27,190 $27,240 C05a-3 3 2 A None Base Base 2028 $26,560 $26,578 C05a-3Q 3 2 A None Base Base 2028 $26,570 $26,591 C05b-3 3 2 A None Base Base 2028 $26,604 $26,649 C06-1 1 2 B None Base+ Base 2028 $27,919 $27,930 C06-2 2 2 B None Base+ Base 2025 $28,530 $28,549 C07-1 1 2 C None Base+ Base 2028 $28,449 $28,516 C07-2 2 2 C None Base+ Base 2025 $29,028 $29,115 C09-1 1 2 A None Base Limited 2022 $26,764 $26,809 C09-2 2 2 A None Base Limited 2022 $27,361 $27,454 C11-1 1 2 A None Accelerated Base 2024 $26,612 $26,649 C11-2 2 2 A None Accelerated Base 2024 $27,124 $27,175 C12-1 1 3a None None Base Base 2024 $26,638 $26,655 C12-2 2 3a None None Base Base 2024 $27,215 $27,241 C13-1 1 3b None None Base Base 2023 $26,860 $26,902 C13-2 2 3b None None Base Base 2023 $27,340 $27,360 C14-1 1 2 A Yes Base Base 2024 $39,364 $39,442 C14-2 2 2 A Yes Base Base 2024 $39,342 $39,584 C14a-1 1 2 A Yes Base Base 2022 $39,229 $39,304 C14a-2 2 2 A Yes Base Base 2022 $39,271 $39,347 [1] Regional Haze assumptions are defined in the Core Case Fact Sheet for each case. [2] 1 = 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation; 2 = 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation and retail customers; 3a = 111(d) implemented as a mass cap applicable to new and existing fossil resources in PacifiCorp’s system; 3b = 111(d) implemented as a mass cap applicable to existing fossil resources in PacifiCorp’s system [3] A = cost-effective energy efficiency, fossil re-dispatch before adding new renewables; B = increased energy efficiency, fossil re-dispatch before adding new renewables; C = increased energy efficiency, new renewables before fossil re-dispatch [4] Base = base Class 2 DSM achievable potential supply curves; Base+ = base Class 2 DSM achievable potential supply curves with forced selections of approximately 1.5% of retail sales; Accelerated = accelerated Class 2 DSM achievable potential supply curves Case Fact Sheets - Overview - 247 - Case Overview Sensitivity Fact Sheets The following Sensitivity Fact sheets summarize key assumptions and portfolio results for each sensitivity being developed for the 2015 IRP. All sensitivities produce resource portfolios capable of meeting state renewable portfolio standard requirements. Similarly, in addition to the specific 111(d) and Regional Haze compliance requirements specified for each case, all cases include costs to meet known and assumed compliance obligations for Mercury and Air Toxics (MATS), coal combustion residuals (CCR) under subtitle D of RCRA, cooling water intake structures under §316(b) of the Clean Water Act, and effluent guidelines. Quick Reference Guide Case Description Reg. Haze[1] 111(d) Strat. [2] CO2 Price Class 2 DSM [3] 1st Year of New Thermal SO PVRR w/o Trans. ($m) SO PVRR w/ Trans. ($m) S-01 Low Load 1 A None Base 2028 $24,680 $24,715 S-02 High Load 1 A None Base 2020 $28,269 $28,334 S-03 1-in-20 Load 1 A None Base 2019 $27,529 $27,709 S-04 Low DG 1 A None Base 2024 $26,843 $26,885 S-05 High DG 1 A None Base 2027 $25,987 $26,016 S-06 Pumped Storage 1 A None Base 2028 $27,022 $27,094 S-07 Energy Gateway 2 1 C None Base+ 2028 $29,221 $29,227 S-08 Energy Gateway 5 1 C None Base+ 2028 $29,966 $29,977 S-09 PTC Extension 1 A None Base 2024 $26,416 $26,443 S-10_ECA East BAA 3 A None Base 2028 $19,377 $19,672 S-10_WCA West BAA 3 A None Base 2020 $8,096 $8,129 S-10_System Benchmark System 3 A None Base 2028 $26,460 $26,480 S-11 111(d) and High CO2 Price 1 A High Base 2024 $44,629 $45,091 S-12 Stakeholder Solar Cost Assumptions 1 A None Base 2027 $25,993 $26,029 S-13 Compressed Air Storage 1 A None Base 2027 $26,950 $27,046 S-14 Class 3 DSM 1 A None Base 2024 $26,565 $26,602 S-15 Restricted 111(d) Attributes 1 A None Base 2020 $26,985 $27,057 [1] Regional Haze assumptions are defined in the Core Case Fact Sheet for each case. [2] A = cost-effective energy efficiency, fossil re-dispatch before adding new renewables; C = increased energy efficiency, new renewables before fossil re-dispatch [3] Base = base Class 2 DSM achievable potential supply curves; Base+ = base Class 2 DSM achievable potential supply curves with forced selections of approximately 1.5% of retail sales; Additional notes: All Sensitivities incorporate: 111(d) emission rate targets applied to PacifiCorp’s system for states in which PacifiCorp has fossil generation and retail customers; Case: C01-R - 248 - Case C01-R CASE ASSUMPTIONS Description Case C01-R is a reference case that assumes known and potential future Regional Haze requirements for installation of selective catalytic reduction (SCR) without any future requirements to reduce CO2 emissions, whether through a CO2 price or 111(d) regulation. Federal CO2 Policy/Price Signal None. Forward Price Curve Case C01-R gas and power prices utilize medium natural gas price assumptions consistent with the Company’s September 30, 2014 OFPC through 2018 without incorporating 111(d) impacts. Post-2018 prices are followed by a 12-month blend that segues into a pure fundamentals forecast. Regional Haze C01-R Regional Haze assumptions are summarized in the following table. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 SCR by Dec 2017 Colstrip 3 SCR by Dec 2023 Coal Unit Description Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 SCR by Mar 2019, Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 SCR by Dec 2021 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 Huntington 2 SCR by Dec 2022 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak SCR by Mar 2019 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC Medium Gas No CO2 $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Medium Gas No CO2 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium Case: C01-R - 249 - Case C01-R Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,822 Transmission Upgrades $6 Total Cost $26,828 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown in the figure below. - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (3) (2) (1) - 1 2 3 4 5 6 7 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R Case: C01-1 - 250 - Case C01-1 CASE ASSUMPTIONS Description Case C01-1 is a reference case that, for planning purposes, assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. This case produces a portfolio without any future requirements to reduce CO2 emissions, whether through a CO2 price or 111(d) regulation. Federal CO2 Policy/Price Signal None. Forward Price Curve Case C01-1 gas and power prices utilize medium natural gas price assumptions consistent with the Company’s September 30, 2014 OFPC through 2018 without incorporating 111(d) impacts. Post-2018 prices are followed by a 12-month blend that segues into a pure fundamentals forecast. Regional Haze Case C01-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The following figure shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC Medium Gas No CO2 $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Medium Gas No CO2 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium Case: C01-1 - 251 - Case C01-1 Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,647 Transmission Integration $30 Transmission Reinforcement $6 Total Cost $26,683 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Case C01-R in the figure below. 111(d) Compliance Profiles Not applicable. - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 Case: C01-2 - 252 - Case C01-2 CASE ASSUMPTIONS Description Case C01-2 is a reference case that, for planning purposes, assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. This case produces a portfolio without any future requirements to reduce CO2 emissions, whether through a CO2 price or 111(d) regulation. Federal CO2 Policy/Price Signal None. Forward Price Curve Case C01-2 gas and power prices utilize medium natural gas price assumptions consistent with the Company’s September 30, 2014 OFPC through 2018 without incorporating 111(d) impacts. Post-2018 prices are followed by a 12-month blend that segues into a pure fundamentals forecast. Regional Haze Case C01-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 * SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC Medium Gas No CO2 $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Medium Gas No CO2 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium Case: C01-2 - 253 - Case C01-2 Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,233 Transmission Integration $11 Transmission Reinforcement $10 Total Cost $27,254 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Case C01-R in the figure below. 111(d) Compliance Profiles Not applicable. - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 Case: C02-1 - 254 - Case C02-1 CASE ASSUMPTIONS Description Case C02-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C02-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C02-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C02-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C02-1 - 255 - Case C02-1 Coal Unit Description Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,693 Transmission Integration $87 Transmission Reinforcement $6 Total Cost $27,787 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the following figure. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C02-1 - 256 - Case C02-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C02-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C02-1 - 257 - Case C02-1 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 500 1,000 1,500 2,000 2,500 PacifiCorp's Share of MTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,250 PacifiCorp's Share of COCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp's Share of AZCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal Case: C02-2 - 258 - Case C02-2 CASE ASSUMPTIONS Description Case C02-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C02-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C02-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C02-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C02-2 - 259 - Case C02-2 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $28,213 Transmission Integration $91 Transmission Reinforcement $10 Total Cost $28,313 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the following figure. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C02-2 - 260 - Case C02-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C02-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C02-2 - 261 - Case C02-2 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 500 1,000 1,500 2,000 2,500 PacifiCorp's Share of MTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,250 PacifiCorp's Share of COCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp's Share of AZCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal Case: C03-1 - 262 - Case C03-1 CASE ASSUMPTIONS Description Case C03-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and re-dispatch of fossil generation. New renewable resources are added after re-dispatch of fossil generation, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C03-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C03-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C03-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C03-1 - 263 - Case C03-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $28,835 Transmission Integration $48 Transmission Reinforcement $6 Total Cost $28,889 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C03-1 - 264 - Case C03-1 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C03-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C03-1 - 265 - Case C03-1 0 500 1,000 1,500 2,000 2,500 PacifiCorp's Share of MTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,250 PacifiCorp's Share of COCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal (250)02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp's Share of AZCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal Case: C03-2 - 266 - Case C03-2 CASE ASSUMPTIONS Description Case C03-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and re-dispatch of fossil generation. New renewable resources are added after re-dispatch of fossil generation, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C03-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C03-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C03-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C03-2 - 267 - Case C03-2 Coal Unit Description Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $29,447 Transmission Integration $53 Transmission Reinforcement $10 Total Cost $29,509 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C03-2 - 268 - Case C03-2 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C03-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C03-2 - 269 - Case C03-2 0 500 1,000 1,500 2,000 2,500 PacifiCorp's Share of MTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,250 PacifiCorp's Share of COCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp's Share of AZCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal Case: C04-1 - 270 - Case C04-1 CASE ASSUMPTIONS Description Case C04-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and renewable resource acquisition. Re-dispatch of fossil generation is implemented after adding new renewable resources, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C04-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Addition of new renewable resources, as required.  Re-dispatch of existing fossil generation, as required. Forward Price Curve Case C04-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C04-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C04-1 - 271 - Case C04-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $29,111 Transmission Integration $193 Transmission Reinforcement $6 Total Cost $29,310 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C04-1 - 272 - Case C04-1 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C04-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C04-1 - 273 - Case C04-1 0 500 1,000 1,500 2,000 2,500 PacifiCorp's Share of MTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,250 PacifiCorp's Share of COCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp's Share of AZCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Net RE Goal Case: C04-2 - 274 - Case C04-2 CASE ASSUMPTIONS Description Case C04-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and renewable resource acquisition. Re-dispatch of fossil generation is implemented after adding new renewable resources, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C04-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 MT 1,882 1,771 CO 1,159 1,108 AZ 753 702 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Addition of new renewable resources, as required.  Re-dispatch of existing fossil generation, as required. Forward Price Curve Case C04-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C04-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C04-2 - 275 - Case C04-2 Coal Unit Description Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $29,706 Transmission Integration $198 Transmission Reinforcement $10 Total Cost $29,913 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the following figure. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C04-2 - 276 - Case C04-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C04-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05-1 - 277 - Case C05-1 CASE ASSUMPTIONS Description Case C05-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05-1 - 278 - Case C05-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,603 Transmission Integration $36 Transmission Reinforcement $6 Total Cost $26,646 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05-1 - 279 - Case C05-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C05-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05-2 - 280 - Case C05-2 CASE ASSUMPTIONS Description Case C05-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05-2 - 281 - Case C05-2 Coal Unit Description Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,127 Transmission Integration $41 Transmission Reinforcement $10 Total Cost $27,177 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05-2 - 282 - Case C05-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C05-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05-3 - 283 - Case C05-3 CASE ASSUMPTIONS Description Case C05-3 is an alternative to Cases C05-1 and C05-2 incorporating a different assumption for assumed outcome for Regional Haze compliance outcomes. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes an alternative to the two Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05-3 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05-3 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05-3 reflects an alternative to Regional Haze Scenarios 1 and 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05-3 - 284 - Case C05-3 Coal Unit Description Huntington 2 Shut Down by Dec 2029 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,569 Transmission Integration $40 Transmission Reinforcement $6 Total Cost $26,615 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05-3 - 285 - Case C05-3 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R, C01-1 and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C01-2 C05-3 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05a-1 - 286 - Case C05a-1 CASE ASSUMPTIONS Description Case C05a-1 is an alternative to Case C05-1 that assumes future Oregon RPS requirements can be deferred with acquisition of unbundled Renewable Energy Credits (RECs) in the 2015-2019 timeframe. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05a-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05a-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05a-1 - 287 - Case C05a-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,566 Transmission Integration $19 Transmission Reinforcement $6 Total Cost $26,591 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05a-1 - 288 - Case C05a-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C05a-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05b-1 - 289 - Case C05b-1 Description Case C05b-1 is an alternative to Case C05-1 that delays building resources to meet Oregon RPS requirements until the balance of banked RECs is exhausted. This results in resource additions in 2028 to meet state requirements. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05b-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05b-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05b-1 - 290 - Case C05b-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,605 Transmission Integration $38 Transmission Reinforcement $6 Total Cost $26,649 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05b-1 - 291 - Case C05b-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R, C01-1 and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C01-2 C05b-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05a-2 - 292 - Case C05a-2 CASE ASSUMPTIONS Description Case C05a-2 is an alternative to Case C05-2 that assumes future Oregon RPS requirements can be deferred with acquisition of unbundled Renewable Energy Credits (RECs) in the 2015-2019 timeframe. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05a-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05a-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05a-2 - 293 - Case C05a-2 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,190 Transmission Integration $41 Transmission Reinforcement $10 Total Cost $27,240 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05a-2 - 294 - Case C05a-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C05a-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05a-3 - 295 - Case C05a-3 CASE ASSUMPTIONS Description Case C05a-3 is an alternative to Cases C05a-1 and C05a-2 that assumes future Oregon RPS requirements can be deferred with acquisition of unbundled Renewable Energy Credits (RECs) in the 2015-2019 timeframe and under a different assumption for assumed Regional Haze compliance outcomes. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes an alternative to the two Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-3 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05a-3 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05a-3 reflects an alternative to Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05a-3 - 296 - Case C05a-3 Coal Unit Description Huntington 2 Shut Down by Dec 2029 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,560 Transmission Integration $11 Transmission Reinforcement $6 Total Cost $26,578 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05a-3 - 297 - Case C05a-3 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R, C01-1, and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C01-2 C05a-3 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05a-3Q - 298 - Case C05a-3Q CASE ASSUMPTIONS Description Case C05a-3Q is an alternative to Cases C05a-3 that incorporates the most current information on executed QF contracts. This case assumes future Oregon RPS requirements can be deferred with acquisition of unbundled Renewable Energy Credits (RECs) in the 2015-2019 timeframe and under a different assumption for assumed Regional Haze compliance outcomes. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes an alternative to the two Regional Haze compliance scenarios reflecting potential inter- temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-3Q reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05a-3Q gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05a-3Q reflects an alternative to Regional Haze Scenarios 1 and 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05a-3Q - 299 - Case C05a-3Q Coal Unit Description Huntington 2 Shut Down by Dec 2029 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,570 Transmission Integration $14 Transmission Reinforcement $6 Total Cost $26,591 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05a-3Q - 300 - Case C05a-3Q System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R, C01-1, and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C01-2 C05a-3Q 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C05b-3 - 301 - Case C05b-3 CASE ASSUMPTIONS Description Case C05b-3 is an alternative to Case C05a-3 that delays building resources to meet Oregon RPS requirements until the balance of banked RECs is exhausted. This results in resource additions in 2028 to meet state requirements. The case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re- dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes an alternative to the two Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C05a-3 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C05b-3 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C05b-3 reflects an alternative to Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C05b-3 - 302 - Case C05b-3 Coal Unit Description Huntington 2 Shut Down by Dec 2029 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,604 Transmission Integration $38 Transmission Reinforcement $6 Total Cost $26,649 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C05b-3 - 303 - Case C05b-3 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R, C01-1, and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C01-2 C05b-3 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C06-1 - 304 - Case C06-1 CASE ASSUMPTIONS Description Case C06-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and re-dispatch of fossil generation. New renewable resources are added after re- dispatch of fossil generation, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C06-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C06-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C06-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C06-1 - 305 - Case C06-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 * SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,919 Transmission Integration $5 Transmission Reinforcement $6 Total Cost $27,930 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C06-1 - 306 - Case C06-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C06-1 (250)02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C06-2 - 307 - Case C06-2 CASE ASSUMPTIONS Description Case C06-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and re-dispatch of fossil generation. New renewable resources are added after re- dispatch of fossil generation, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C06-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C06-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C06-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C06-2 - 308 - Case C06-2 Coal Unit Description Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $28,530 Transmission Integration $10 Transmission Reinforcement $10 Total Cost $28,549 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C06-2 - 309 - Case C06-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C06-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C07-1 - 310 - Case C07-1 CASE ASSUMPTIONS Description Case C07-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation and has retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and renewable resource acquisition. Re-dispatch of fossil generation is implemented after adding new renewable resources, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C07-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Addition of new renewable resources, as required.  Re-dispatch of existing fossil generation, as required. Forward Price Curve Case C07-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C07-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C07-1 - 311 - Case C07-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $28,449 Transmission Integration $60 Transmission Reinforcement $6 Total Cost $28,516 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C07-1 - 312 - Case C07-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C07-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C07-2 - 313 - Case C07-2 CASE ASSUMPTIONS Description Case C07-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp owns fossil generation and has retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency, increased energy efficiency acquisition, and renewable resource acquisition. Re-dispatch of fossil generation is implemented after adding new renewable resources, as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C07-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative selection of energy efficiency beginning 2017 up to 1.5% of retail sales.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Addition of new renewable resources, as required.  Re-dispatch of existing fossil generation, as required. Forward Price Curve Case C07-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C07-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C07-2 - 314 - Case C07-2 Coal Unit Description Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Additional energy efficiency beyond economic selections, up to 1.5% of retail sales, is forced into the resource portfolio. Class 2 resources that are not selected or forced in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $29,028 Transmission Integration $78 Transmission Reinforcement $10 Total Cost $29,115 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C07-2 - 315 - Case C07-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C07-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C09-1 - 316 - Case C09-1 CASE ASSUMPTIONS Description Case C09-1 is a variant of Case C05-1 in which the acquisition of front office transactions (FOTs) is eliminated at Mona (300 MW) and NOB (100 MW) beginning 2019. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C09-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C09-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C09-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C09-1 - 317 - Case C09-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,764 Transmission Integration $39 Transmission Reinforcement $6 Total Cost $26,809 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C09-1 - 318 - Case C09-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C09-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C09-2 - 319 - Case C09-2 CASE ASSUMPTIONS Description Case C09-2 is a variant of Case C05-2 in which the acquisition of front office transactions (FOTs) is eliminated at Mona (300 MW) and NOB (100 MW) beginning 2019. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C09-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C09-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C09-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C09-2 - 320 - Case C09-2 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,361 Transmission Integration $83 Transmission Reinforcement $10 Total Cost $27,454 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C09-2 - 321 - Case C09-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C09-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C11-1 - 322 - Case C11-1 CASE ASSUMPTIONS Description Case C11-1 is a variant of Case C05-1 in which accelerated Class 2 DSM supply curves are used in developing the resource portfolio. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter- temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C11-1 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C11-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C11-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C11-1 - 323 - Case C11-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Accelerated case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Accelerated achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,606 Transmission Integration $35 Transmission Reinforcement $6 Total Cost $26,649 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Acc. Class 2 DSM Cumulative Achievable Potential UT ORWAWYIDCABase Achiev. Potential - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C11-1 - 324 - Case C11-1 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C11-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C11-2 - 325 - Case C11-2 CASE ASSUMPTIONS Description Case C11-2 is a variant of Case C05-2 in which accelerated Class 2 DSM supply curves are used in developing the resource portfolio. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter- temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C11-2 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Case C11-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C11-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C11-2 - 326 - Case C11-2 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 * SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Accelerated case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Accelerated achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,124 Transmission Integration $41 Transmission Reinforcement $10 Total Cost $27,175 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Acc. Class 2 DSM Cumulative Achievable Potential UT ORWAWYIDCABase Achiev. Potential - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C11-2 - 327 - Case C11-2 System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C11-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C12-1 - 328 - Case C12-1 CASE ASSUMPTIONS Description Case C12-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission goals in all states in which PacifiCorp has fossil generation. The 111(d) emission goals are implemented as a mass cap applied to new and existing fossil generation. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C12-1 reflects EPA’s proposed 111(d) rule applied as a mass cap applicable to all new and existing fossil generation beginning 2020. No additional CO2 price signal is applied to this case. The figure below shows the mass cap applied to this case. Forward Price Curve Case C12-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C12-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 0 10 20 30 40 50 60 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n s C O 2 Mass Cap Applied to New and Existing Fossil Generation $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C12-1 - 329 - Case C12-1 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,638 Transmission Integration $10 Transmission Reinforcement $6 Total Cost $26,655 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C12-1 - 330 - Case C12-1 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles Not applicable. (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C12-1 Case: C12-2 - 331 - Case C12-2 CASE ASSUMPTIONS Description Case C12-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission goals in all states in which PacifiCorp has fossil generation. The 111(d) emission goals are implemented as a mass cap applied to new and existing fossil generation. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C12-2 reflects EPA’s proposed 111(d) rule applied as a mass cap applicable to all new and existing fossil generation beginning 2020. No additional CO2 price signal is applied to this case. The figure below shows the mass cap applied to this case. Forward Price Curve Case C12-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C12-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 0 10 20 30 40 50 60 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n s C O 2 Mass Cap Applied to New and Existing Fossil Generation $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C12-2 - 332 - Case C12-2 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 * SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,215 Transmission Integration $15 Transmission Reinforcement $10 Total Cost $27,241 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Case: C12-2 - 333 - Case C12-2 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles Not applicable. (6.00) (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C12-2 Case: C13-1 - 334 - Case C13-1 CASE ASSUMPTIONS Description Case C13-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission goals in all states in which PacifiCorp has fossil generation. The 111(d) emission goals are implemented as a mass cap applied to existing fossil generation. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C13-1 reflects EPA’s proposed 111(d) rule applied as a mass cap applicable to existing fossil generation beginning 2020. No additional CO2 price signal is applied to this case. The figure below shows the mass cap applied to this case. Forward Price Curve Case C13-1 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C13-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. 0 10 20 30 40 50 60 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n s C O 2 Mass Cap Applied to Existing Fossil Generation $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C13-1 - 335 - Case C13-1 Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,860 Transmission Integration $36 Transmission Reinforcement $6 Total Cost $26,902 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement Case: C13-1 - 336 - Case C13-1 111(d) Compliance Profiles Not applicable. 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C13-1 Case: C13-2 - 337 - Case C13-2 CASE ASSUMPTIONS Description Case C13-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission goals in all states in which PacifiCorp has fossil generation. The 111(d) emission goals are implemented as a mass cap applied to existing fossil generation. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C13-2 reflects EPA’s proposed 111(d) rule applied as a mass cap applicable to existing fossil generation beginning 2020. No additional CO2 price signal is applied to this case. The figure below shows the mass cap applied to this case. Forward Price Curve Case C13-2 gas and power prices reflect medium natural gas prices and regional compliance with EPA’s proposed 111(d) rule as implemented in the Company’s September 2014 official forward price curve (OFPC). Regional Haze Case C13-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. 0 10 20 30 40 50 60 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n s C O 2 Mass Cap Applied to Existing Fossil Generation $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Case: C13-2 - 338 - Case C13-2 Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,340 Transmission Integration $11 Transmission Reinforcement $10 Total Cost $27,360 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement Case: C13-2 - 339 - Case C13-2 111(d) Compliance Profiles Not applicable. 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C13-2 Case: C14-1 - 340 - Case C14-1 CASE ASSUMPTIONS Description Case C14-1 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. This case also includes a CO2 price signal beginning 2020 at approximately $22/ton rising to nearly $76/ton by 2034. For 111(d) compliance purposes, the compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C14-1 reflects EPA’s proposed 111(d) rule with an additional CO2 price signal beginning 2020. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. The CO2 price signal applied to this case is summarized in the following figure, with prices start at about $22/ton in 2020 rising to nearly $76/ton by 2034. Forward Price Curve C14-1 gas and power prices reflect medium natural gas prices adjusted for increased electric power sector demand with a national CO2 price signal applicable to the case. Power prices include the assumed CO2 price signal as an incremental dispatch cost for all fossil generation. The figures below summarize C14-1 gas and power prices alongside the Company’s September 2014 official forward price curve (OFPC). $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ t o n Nominal Federal CO2 Prices Medium $- $2 $4 $6 $8 $10 $12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC 111(d) + CO2 Price Case: C14-1 - 341 - Case C14-1 Regional Haze Case C14-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. $- $20 $40 $60 $80 $100 $120 $140 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC 111(d) + CO2 Price 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Case: C14-1 - 342 - Case C14-1 Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $39,364 Transmission Integration $70 Transmission Reinforcement $7 Total Cost $39,442 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C14-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C14-1 - 343 - Case C14-1 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C14-2 - 344 - Case C14-2 CASE ASSUMPTIONS Description Case C14-2 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. This case also includes a CO2 price signal beginning 2020 at approximately $22/ton rising to nearly $76/ton by 2034. For 111(d) compliance purposes, the compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C14-2 reflects EPA’s proposed 111(d) rule with an additional CO2 price signal beginning 2020. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. The CO2 price signal applied to this case is summarized in the following figure, with prices start at about $22/ton in 2020 rising to nearly $76/ton by 2034. Forward Price Curve C14-2 gas and power prices reflect medium natural gas prices adjusted for increased electric power sector demand with a national CO2 price signal applicable to the case. Power prices include the assumed CO2 price signal as an incremental dispatch cost for all fossil generation. The figures below summarize C14-2 gas and power prices alongside the Company’s September 2014 official forward price curve (OFPC). $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ t o n Nominal Federal CO2 Prices Medium $- $2 $4 $6 $8 $10 $12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC 111(d) + CO2 Price Case: C14-2 - 345 - Case C14-2 Regional Haze Case C14-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The figure below shows the medium system coincident peak load forecast applicable to this case before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. $- $20 $40 $60 $80 $100 $120 $140 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC 111(d) + CO2 Price 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Case: C14-2 - 346 - Case C14-2 PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $39,342 Transmission Integration $230 Transmission Reinforcement $13 Total Cost $39,584 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 12 13 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C14-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C14-2 - 347 - Case C14-2 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C14a-1 - 348 - Case C14a-1 CASE ASSUMPTIONS Description Case C14a-1 is an alternative to Case C14-1 in which endogenous coal unit retirements for coal units not already assumed to retire early for Regional Haze compliance purposes is allowed. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. This case also includes a CO2 price signal beginning 2020 at approximately $22/ton rising to nearly $76/ton by 2034. For 111(d) compliance purposes, the compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C14a-1 reflects EPA’s proposed 111(d) rule with an additional CO2 price signal beginning 2020. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. The CO2 price signal applied to this case is summarized in the following figure, with prices start at about $22/ton in 2020 rising to nearly $76/ton by 2034. Forward Price Curve C14a-1 gas and power prices reflect medium natural gas prices adjusted for increased electric power sector demand with a national CO2 price signal applicable to the case. Power prices include the assumed CO2 price signal as an incremental dispatch cost for all fossil generation. The figures below summarize C14a-1 gas and power prices alongside the Company’s September 2014 official forward price curve (OFPC). $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ t o n Nominal Federal CO2 Prices Medium $- $2 $4 $6 $8 $10 $12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC 111(d) + CO2 Price Case: C14a-1 - 349 - Case C14a-1 Regional Haze Case C14a-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. $- $20 $40 $60 $80 $100 $120 $140 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC 111(d) + CO2 Price 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Case: C14a-1 - 350 - Case C14a-1 Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $39,229 Transmission Integration $69 Transmission Reinforcement $7 Total Cost $39,304 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-1 in the following figure. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-1 C14a-1 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case: C14a-1 - 351 - Case C14a-1 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case C14a-2 - 352 - Case C14a-2 CASE ASSUMPTIONS Description Case C14a-2 is an alternative to Case C14-2 in which endogenous coal unit retirements for coal units not already assumed to retire early for Regional Haze compliance purposes is allowed. This case produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. This case also includes a CO2 price signal beginning 2020 at approximately $22/ton rising to nearly $76/ton by 2034. For 111(d) compliance purposes, the compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes one of two different Regional Haze compliance scenarios reflecting potential inter-temporal and fleet trade-off compliance outcomes. Federal CO2 Policy/Price Signal C14a-2 reflects EPA’s proposed 111(d) rule with an additional CO2 price signal beginning 2020. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. The CO2 price signal applied to this case is summarized in the following figure, with prices start at about $22/ton in 2020 rising to nearly $76/ton by 2034. Forward Price Curve C14a-2 gas and power prices reflect medium natural gas prices adjusted for increased electric power sector demand with a national CO2 price signal applicable to the case. Power prices include the assumed CO2 price signal as an incremental dispatch cost for all fossil generation. The figures below summarize C14a-2 gas and power prices alongside the Company’s September 2014 official forward price curve (OFPC). $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ t o n Nominal Federal CO2 Prices Medium $- $2 $4 $6 $8 $10 $12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC 111(d) + CO2 Price Case C14a-2 - 353 - Case C14a-2 Regional Haze Case C14a-2 reflects Regional Haze Scenario 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Mar 2019 Dave Johnson 2 Shut Down Dec 2023 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down Dec 2024 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down Dec 2024 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2028 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2032 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. Energy Efficiency (Class 2 DSM) This case uses base supply curves with economic resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized in the following figure. $- $20 $40 $60 $80 $100 $120 $140 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC 111(d) + CO2 Price 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Case C14a-2 - 354 - Case C14a-2 Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized in the following figure. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $39,271 Transmission Integration $69 Transmission Reinforcement $7 Total Cost $39,347 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C01-R and C01-2 in the following figure. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (6) (5) (4) (3) (2) (1) - 1 2 3 4 5 6 7 8 9 10 11 12 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C01-R C01-2 C14a-2 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Case C14a-2 - 355 - Case C14a-2 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal PacifiCorp – 2015 IRP Appendix M - Case Fact Sheets - 356 - Sensitivity Case Fact Sheets Sensitivity Case Fact Sheets S-01 – S-15 Sensitivity: S-01 (Low Load Forecast) February 26, 2015 - 357 - Sensitivity S-01 CASE ASSUMPTIONS Description Sensitivity S-01 assumes a low load forecast in producing a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter- temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-01 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-1 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-1 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-01 (Low Load Forecast) February 26, 2015 - 358 - Sensitivity S-01 Coal Unit Description Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 *SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast A low load forecast derived using low economic driver assumptions will be used. The figure below shows the change in system coincident peak as compared to the medium (base) load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $24,680 Transmission Integration $28 Transmission Reinforcement $6 Total Cost $24,715 -800 -600 -400 -200 0 200 400 600 800 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Change in Coincident System Peak Load Low - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-01 (Low Load Forecast) February 26, 2015 - 359 - Sensitivity S-01 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-01 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-01 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-02 (High Load Forecast) February 26, 2015 - 360 - Sensitivity S-02 CASE ASSUMPTIONS Description Sensitivity S-02 assumes a high load forecast in producing a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter- temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-02 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-2 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-2 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-02 (High Load Forecast) February 26, 2015 - 361 - Sensitivity S-02 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast A high load forecast derived using high economic drivers and high industrial load growth will be used. The figure below shows the change in system coincident peak as compared to the medium (base) load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $28,269 Transmission Integration $59 Transmission Reinforcement $6 Total Cost $28,334 -800 -600 -400 -200 0 200 400 600 800 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Change in Coincident System Peak Load High - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-02 (High Load Forecast) February 26, 2015 - 362 - Sensitivity S-02 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-02 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-02 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-03 (1 in 20 Load Forecast) February 26, 2015 - 363 - Sensitivity S-03 CASE ASSUMPTIONS Description Sensitivity S-03 assumes a 1-in-20 peak load forecast in producing a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter- temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-03 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-3 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-3 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-03 (1 in 20 Load Forecast) February 26, 2015 - 364 - Sensitivity S-03 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast A 1 in 20 load forecast reflecting the top peak producing weather over the past 20 years will be used. The figure below shows the change in system coincident peak as compared to the medium (base) load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,529 Transmission Integration $175 Transmission Reinforcement $6 Total Cost $27,709 -800 -600 -400 -200 0 200 400 600 800 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Change in Coincident System Peak Load 1 in 20 - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-03 (1 in 20 Load Forecast) February 26, 2015 - 365 - Sensitivity S-03 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-03 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-03 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-04 (Low Distributed Generation Forecast) February 26, 2015 - 366 - Sensitivity S-04 CASE ASSUMPTIONS Description Sensitivity S-04 assumes a low penetration of distributed generation (DG) in producing a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-04 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-4 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-4 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-04 (Low Distributed Generation Forecast) February 26, 2015 - 367 - Sensitivity S-04 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Low distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,843 Transmission Integration $36 Transmission Reinforcement $6 Total Cost $26,885 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Low Penetration Case UT OR WA WY ID CA Base Sensitivity: S-04 (Low Distributed Generation Forecast) February 26, 2015 - 368 - Sensitivity S-04 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-04 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-04 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-05 (High Distributed Generation Forecast) February 26, 2015 - 369 - Sensitivity S-05 CASE ASSUMPTIONS Description Sensitivity S-05 assumes a high penetration of distributed generation (DG) in producing a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-05 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-5 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-5 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-05 (High Distributed Generation Forecast) February 26, 2015 - 370 - Sensitivity S-05 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation High distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $25,987 Transmission Integration $22 Transmission Reinforcement $6 Total Cost $26,016 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 500 1,000 1,500 2,000 2,500 3,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -High Penetration Case UT OR WA WY ID CA Base Sensitivity: S-05 (High Distributed Generation Forecast) February 26, 2015 - 371 - Sensitivity S-05 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-05 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-05 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-06 (Pumped Storage) February 26, 2015 - 372 - Sensitivity S-06 CASE ASSUMPTIONS Description Sensitivity S-06 assumes construction of a 400 MW pumped storage facility on the Company’s west side. This facility replaced the need for a 423 MW CCT in 2024. As with the other cases this one produced a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-06 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-6 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-6 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-06 (Pumped Storage) February 26, 2015 - 373 - Sensitivity S-06 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $27,022 Transmission Integration $66 Transmission Reinforcement $6 Total Cost $27,094 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-06 (Pumped Storage) February 26, 2015 - 374 - Sensitivity S-06 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-06 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-06 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-07 (Energy Gateway 2) February 26, 2015 - 375 - Sensitivity S-07 CASE ASSUMPTIONS Description Sensitivity S-07 is one of two Energy Gateway sensitivities. This assumes construction of the following segments, and in-service dates; Segment C (2013), Segment D (2022), Segment G (2015). A portfolio was produced that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C07-1, a portfolio with a higher penetration of renewable resources. Federal CO2 Policy/Price Signal Sensitivity S-07 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-7 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-7 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-07 (Energy Gateway 2) February 26, 2015 - 376 - Sensitivity S-07 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost* without Transmission Upgrades $29,221 Transmission Integration $0 Transmission Reinforcement $6 Total Cost $29,227 *System costs incorporate EG-2 build out. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-07 (Energy Gateway 2) February 26, 2015 - 377 - Sensitivity S-07 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C07-1 and S-07 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C07-1 S-07 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-08 (Energy Gateway 5) February 26, 2015 - 378 - Sensitivity S-08 CASE ASSUMPTIONS Description Sensitivity S-08 is one of two Energy Gateway sensitivities. This assumes construction of the following segments, and in-service dates; Segment C (2013), Segment D (2022), Segment E (2024), Segment G (2015), Segment F (2023). A portfolio was produced that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C07-1, a portfolio with a higher penetration of renewable resources. Federal CO2 Policy/Price Signal Sensitivity S-08 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-8 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-8 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-08 (Energy Gateway 5) February 26, 2015 - 379 - Sensitivity S-08 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost* without Transmission Upgrades $29,966 Transmission Integration $5 Transmission Reinforcement $6 Total Cost $29,977 *System costs incorporate EG-5 build out. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-08 (Energy Gateway 5) February 26, 2015 - 380 - Sensitivity S-08 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C07-1 and S-08 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C07-1 S-08 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-09 (PTC Extension) February 26, 2015 - 381 - Sensitivity S-09 CASE ASSUMPTIONS Description Sensitivity S-09 assumes extension of the production tax credit (PTC) through the study period. The PTC starts at $2.30 per kilowatt-hour beginning in 2015 and escalates at inflation through 2034, as opposed to having expired at end of 2013. The portfolio produced meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-09 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-9 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-9 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-09 (PTC Extension) February 26, 2015 - 382 - Sensitivity S-09 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs continues in perpetuity at $2.30 per kilowatt-hour ($2015)  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,416 Transmission Integration $19 Transmission Reinforcement $7 Total Cost $26,443 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-09 (PTC Extension) February 26, 2015 - 383 - Sensitivity S-09 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-09 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-09 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-10 (Separate East/West BAAs) February 26, 2015 - 384 - Sensitivity S-10 CASE ASSUMPTIONS Description Sensitivity S-10 assumes separate balancing authority areas (BAA) for the Company’s East and West territory. Independent portfolios were developed for each area, focusing on summer peak needs in the East, and winter peak needs in the West. This sensitivity uses assumptions for Regional Haze scenario 3 as well as meeting all renewable and 111(d) requirements for both BAAs. A benchmark portfolio was also developed using the same assumptions, consistent with the draft preferred portfolio. The benchmark portfolio meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to each BAA relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. This sensitivity is a variant of Core Case C05-3. Federal CO2 Policy/Price Signal Sensitivity S-10 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-10 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-10 reflects Regional Haze Scenario 3 which is an alternative to Regional Haze Scenarios 1 and 2, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnson 1 Shut Down Dec 2027 Dave Johnson 2 Shut Down Dec 2027 Dave Johnson 3 Shut Down Dec 2027 Dave Johnson 4 Shut Down Dec 2027 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-10 (Separate East/West BAAs) February 26, 2015 - 385 - Sensitivity S-10 Hunter 2 Shut Down Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 SCR by Dec 2022 Huntington 2 Shut Down by Dec 2029 Jim Bridger 1 SCR by Dec 2022 Jim Bridger 2 SCR by Dec 2021 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) Cost East BAA West BAA East/West Total System Benchmark System Cost wo Transmission Upgrades $19,377 $8,096 $27,473 $26,460 Transmission Integration $289 $33 $322 $14 Transmission Reinforcement $6 $0 $6 $6 Total Cost $19,672 $8,129 $27,801 $26,480 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-10 (Separate East/West BAAs) February 26, 2015 - 386 - Sensitivity S-10 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figures below. Figures are included for the East and West as stand-alone BAAs, and the benchmark system portfolio. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown for the separate BAAs alongside those for the Benchmark System, and Case C05-3 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). East BAA (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW East BAA Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW West BAA Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW System Benchmark Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) East BAA West Baa C05a-3 Benchmark System 02505007501,0001,2501,5001,7502,0002,2502,5002,750 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-10 (Separate East/West BAAs) February 26, 2015 - 387 - Sensitivity S-10 West BAA Benchmark System 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 50100 150 200 250300 350 400 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-11 (111(d) and High CO2 Prices) February 26, 2015 - 388 - Sensitivity S-11 CASE ASSUMPTIONS Description Sensitivity S-11 produces a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. This case also includes a CO2 price signal beginning 2020 at approximately $22/ton rising to nearly $162/ton by 2034. For 111(d) compliance purposes, the compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 compliance reflecting potential inter- temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C14-1. Federal CO2 Policy/Price Signal Sensitivity S-11 reflects EPA’s proposed 111(d) rule with an additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-11 gas and power prices will utilize medium natural gas and high CO2 price assumptions. The graphs below summarize S-11 gas and power prices alongside those using medium natural gas prices as well as the electricity market price impacts of EPA’s proposed 111(d) rules. Federal CO2 Policy/Price Signal Sensitivity S-11 includes high CO2 prices starting in 2020 at $22.39/ton rising to nearly $162/ton by 2034. Regional Haze Sensitivity S-11 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, $- $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 $11 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC Medium Gas, 111(d) High CO2 $- $20 $40 $60 $80 $100 $120 $140 $160 $180 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Medium Gas, 111(d) High CO2 $- $20 $40 $60 $80 $100 $120 $140 $160 $180 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ t o n Nominal Federal CO2 Prices High Sensitivity: S-11 (111(d) and High CO2 Prices) February 26, 2015 - 389 - Sensitivity S-11 regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Sensitivity: S-11 (111(d) and High CO2 Prices) February 26, 2015 - 390 - Sensitivity S-11 PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $44,629 Transmission Integration $455 Transmission Reinforcement $7 Total Cost $45,091 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C14-1 and S-11 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 11.00 12.00 13.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C14-1 S-11 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WYCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UTCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-11 (111(d) and High CO2 Prices) February 26, 2015 - 391 - Sensitivity S-11 0 200 400 600 800 1,000 PacifiCorp Share of ORCompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal (200) 0 200 400 600 800 1,000 PacifiCorp Share of WACompliance Profile (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-12 (Stakeholder Solar Cost Assumptions) February 26, 2015 - 392 - Sensitivity S-12 CASE ASSUMPTIONS Description Sensitivity S-12 is based on recommendations from stakeholders. This sensitivity assumes that the costs of solar resources decrease linearly on real basis through the 20-year IRP study period, consistent with a “learning curve” approach. S-12 also assumes a high penetration of DG in line with the solar cost assumptions. As with the other cases this one produced a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re- dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-12 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-12 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-12 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-12 (Stakeholder Solar Cost Assumptions) February 26, 2015 - 393 - Sensitivity S-12 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation High distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $25,993 Transmission Integration $31 Transmission Reinforcement $6 Total Cost $26,029 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 500 1,000 1,500 2,000 2,500 3,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -High Penetration Case UT OR WA WY ID CA Base Sensitivity: S-12 (Stakeholder Solar Cost Assumptions) February 26, 2015 - 394 - Sensitivity S-12 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-12 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-12 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-13 (Compressed Air Storage) February 26, 2015 - 395 - Sensitivity S-13 CASE ASSUMPTIONS Description Sensitivity S-13 assumes construction of a 300 MW compressed air energy storage facility on the Company’s east side. This facility replaced the need for a 423 MW CCT in 2024. As with the other cases this one produced a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-13 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-13 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-13 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-13 (Compressed Air Storage) February 26, 2015 - 396 - Sensitivity S-13 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,950 Transmission Integration $90 Transmission Reinforcement $6 Total Cost $27,046 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-13 (Compressed Air Storage) February 26, 2015 - 397 - Sensitivity S-13 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-13 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re-dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-13 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of Uath Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-14 (Class 3 DSM) February 26, 2015 - 398 - Sensitivity S-14 CASE ASSUMPTIONS Description Sensitivity S-14 incorporates Class 3 DSM resource alternatives. As with the other cases this one produced a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of renewable energy and energy efficiency while prioritizing re-dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter- temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-14 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-14 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-14 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-14 (Class 3 DSM) February 26, 2015 - 399 - Sensitivity S-14 Huntington 1 Shut Down by Dec 2036 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. For this sensitivity, Class 3 DSM resources, which are generally considered non-firm due to the voluntary nature of customer response to price signals, will be considered firm resources. Only incremental potential is included in this sensitivity. To avoid overstating the capacity contribution of Class 3 DSM resources in this sensitivity, the potential for each Class 3 DSM product was adjusted for expected interactions among competing Class 1 and 3 DSM resource alternatives. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA Sensitivity: S-14 (Class 3 DSM) February 26, 2015 - 400 - Sensitivity S-14 PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,565 Transmission Integration $31 Transmission Reinforcement $6 Total Cost $26,602 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-14 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-14 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 250 500 750 1,000 1,250 1,500 1,750 PacifiCorp Share of UathCompliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-14 (Class 3 DSM) February 26, 2015 - 401 - Sensitivity S-14 0 200 400 600 800 1,000 PacifiCorp Share of Oregon Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 200 400 600 800 1,000 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal Sensitivity: S-15 (Restricted Allocation) February 26, 2015 - 402 - Sensitivity S-15 CASE ASSUMPTIONS Description Sensitivity S-15 assumes any renewable electric credits (RECs) used to meet state Renewable Portfolio Standards (RPS) will also be retired to meet EPA 111(d) compliance requirements. As with the other cases this one produced a portfolio that meets PacifiCorp’s share of state 111(d) emission rate goals in all states in which PacifiCorp has fossil generation and retail customers. The compliance strategy applied to this case relies on flexible allocation of non-RPS renewable energy and energy efficiency while prioritizing re- dispatch of fossil generation to achieve incremental emission rate reductions as required. For planning purposes, this case assumes Regional Haze Scenario 1 reflecting potential inter-temporal and fleet trade-off compliance outcomes. This sensitivity is a variant of Core Case C05-1. Federal CO2 Policy/Price Signal Sensitivity S-15 reflects EPA’s proposed 111(d) rule with no additional CO2 price signal. The table below summarizes the interim emission rate goal and the final emission rate target by state assumed to apply to PacifiCorp’s system. State Interim Goal (Avg. 2020-2029) (lb/MWh) Final Target (2030 & Beyond) (lb/MWh) WY 1,808 1,714 UT* 1,378 1,322 OR 407 372 WA 264 215 *EPA’s calculation of the target for UT treated PacifiCorp’s Lakeside 2 NGCC plant as an existing resource. The emission rate assumed for UT assumes Lake Side 2 is correctly classified as “under construction”. The 111(d) compliance strategy implemented for this case is summarized as follows:  Flexible allocation of system renewable resources and flexible allocation of cumulative energy efficiency savings beginning 2017 from ID and CA, where PacifiCorp does not own fossil generation.  Cumulative cost-effective selection of energy efficiency beginning 2017.  New NGCC generation in WY and UT (new NGCC resources are not allowed in OR, WA, and ID).  Re-dispatch of existing fossil generation, as required.  Addition of new renewable resources, as required. Forward Price Curve Sensitivity S-15 gas and power prices will utilize medium natural gas prices as well as market price impacts associated with EPA’s proposed 111(d) rules. These forecasts begin with the Company’s base September 30, 2014 official forward price curve. Regional Haze Sensitivity S-15 reflects Regional Haze Scenario 1, which assumes inter-temporal and fleet trade-off Regional Haze compliance outcomes as shown in the table below. This scenario is for planning purposes recognizing that agency, regulator, and joint owner perspectives on acceptability have not been determined. Coal Unit Description Carbon 1 Shut Down Apr 2015 Carbon 2 Shut Down Apr 2015 Cholla 4 Conversion by Jun 2025 Colstrip 3 SCR by Dec 2023 Colstrip 4 SCR by Dec 2022 Craig 1 SCR by Aug 2021 Craig 2 SCR by Jan 2018 Dave Johnston 1 Shut Down Mar 2019 Dave Johnston 2 Shut Down Dec 2027 Dave Johnston 3 Shut Down Dec 2027 Dave Johnston 4 Shut Down Dec 2032 Hayden 1 SCR by Jun 2015 Hayden 2 SCR by Jun 2016 Hunter 1 SCR by Dec 2021 Hunter 2 Shut Down by Dec 2032 Hunter 3 SCR by Dec 2024 Huntington 1 Shut Down by Dec 2036 $- $1 $2 $3 $4 $5 $6 $7 $8 $9 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M M B t u Nominal Average Annual Henry Hub Gas Prices Sep 2014 OFPC $- $10 $20 $30 $40 $50 $60 $70 $80 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 $/ M W h Nominal Average Annual Power Prices (Flat) Sep 2014 OFPC Sensitivity: S-15 (Restricted Allocation) February 26, 2015 - 403 - Sensitivity S-15 Huntington 2 Shut Down by Dec 2021 Jim Bridger 1 Shut Down by Dec 2023 Jim Bridger 2 Shut Down by Dec 2032 Jim Bridger 3 SCR by Dec 2015 Jim Bridger 4 SCR by Dec 2016 Naughton 1 Shut Down by Dec 2029 Naughton 2 Shut Down by Dec 2029 Naughton 3 Conversion by Jun 2018; Shut Down by Dec 2029 Wyodak Shut Down by Dec 2039 SCR = selective catalytic reduction Federal Tax Incentives  PTCs expire end of 2013  ITC of 30% expire end of 2016, thereafter it continues in perpetuity at 10%. Load Forecast The medium load forecast will be used. The figure below shows the system coincident peak load forecast before accounting for any potential contribution from DSM or distributed generation resources. Energy Efficiency (Class 2 DSM) Base case supply curves and ramp rates with resource selections up to the achievable potential. Class 2 resources that are not selected in any given year are not available for selection in future years. Achievable potential by state and year are summarized below. Distributed Generation Base case distributed generation penetration is assumed in all states. Distributed generation by state and year are summarized below. PORTFOLIO SUMMARY System Optimizer PVRR ($m) System Cost without Transmission Upgrades $26,985 Transmission Integration $66 Transmission Reinforcement $6 Total Cost $27,057 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000 13,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Coincident System Peak Load Medium - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Class 2 DSM Cumulative Achievable Potential UT OR WA WY ID CA - 100 200 300 400 500 600 700 800 900 1,000 20 1 3 20 1 4 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 MW Distributed Generation -Base PenetrationCase UT OR WA WY ID CA Sensitivity: S-15 (Restricted Allocation) February 26, 2015 - 404 - Sensitivity S-15 Resource Portfolio Cumulative changes to the resource portfolio (new resource additions and resource retirements), represented as nameplate capacity, are summarized in the figure below. System CO2 Emissions (System Optimizer) System CO2 emissions from System Optimizer are shown alongside those from Cases C05-1 and S-15 in the figure below. 111(d) Compliance Profiles The following figures summarize how compliance with state emission rate goals is achieved. The sum of each stacked bar represents the fossil emission rate. The net final rate represents the fossil rate after accounting for the emission rate impacts of new thermal (new NGCC units or nuclear, as applicable), re- dispatch of fossil units, energy efficiency (EE), and allocated renewable energy (RE). (5.00) (4.00) (3.00) (2.00) (1.00) - 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 GW Cumulative Nameplate Capacity DSM FOTs GasRenewableGas Conversion OtherEarly Retirement End of Life Retirement 0 10 20 30 40 50 60 20 1 5 20 1 6 20 1 7 20 1 8 20 1 9 20 2 0 20 2 1 20 2 2 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 Mi l l i o n T o n System CO2 Emissions (System Optimizer) C05-1 S-15 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WyomingCompliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of Wyoming Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 02505007501,0001,2501,5001,7502,0002,2502,500 PacifiCorp Share of WyomingCompliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal 0 50 100 150200 250 300 350 400 PacifiCorp Share of Washington Compliance Path (lb/MWh) Net Final Rate New Thermal Redispatch EE Allocated RE Goal PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 405 APPENDIX N – 2014 WIND AND SOLAR CAPACITY CONTRIBUTION STUDY Introduction The capacity contribution of wind and solar resources, represented as a percentage of resource capacity, is a measure of the ability for these resources to reliably meet demand. For purposes of this report, PacifiCorp defines the peak capacity contribution of wind and solar resources as the availability among hours with the highest loss of load probability (LOLP). PacifiCorp calculated peak capacity contribution values for wind and solar resources using the capacity factor approximation method (CF Method) as outlined in a 2012 report produced by the National Renewable Energy Laboratory (NREL Report)47. The capacity contribution of wind and solar resources affects PacifiCorp’s resource planning activities. PacifiCorp conducts its resource planning to ensure there is sufficient capacity on its system to meet its load obligation at the time of system coincident peak inclusive of a planning reserve margin. To ensure resource adequacy is maintained over time, all resource portfolios evaluated in the integrated resource plan (IRP) have sufficient capacity to meet PacifiCorp’s net coincident peak load obligation inclusive of a planning reserve margin throughout a 20-year planning horizon. Consequently, planning for the coincident peak drives the amount and timing of new resources, while resource cost and performance metrics among a wide range of different resource alternatives drive the types of resources that can be chosen to minimize portfolio costs and risks. PacifiCorp derives its planning reserve margin from a LOLP study. The study evaluates the relationship between reliability across all hours in a given year, accounting for variability and uncertainty in load and generation resources, and the cost of planning for system resources at varying levels of planning reserve margin. In this way, PacifiCorp’s planning reserve margin LOLP study is the mechanism used to transform hourly reliability metrics into a resource adequacy target at the time of system coincident peak. This same LOLP study was utilized for calculating the peak capacity contribution using the CF Method. Table N.1 summarizes the peak capacity contribution results for PacifiCorp’s east and west balancing authority areas (BAAs). Table N.1 – Peak Capacity Contribution Values for Wind and Solar East BAA West BAA Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV Capacity Contribution Percentage 14.5% 34.1% 39.1% 25.4% 32.2% 36.7% 47 Madaeni, S. H.; Sioshansi, R.; and Denholm, P. “Comparison of Capacity Value Methods for Photovoltaics in the Western United States.” NREL/TP-6A20-54704, Denver, CO: National Renewable Energy Laboratory, July 2012 (NREL Report). http://www.nrel.gov/docs/fy12osti/54704.pdf PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 406 Methodology The NREL Report summarizes several methods for estimating the capacity value of renewable resources that are broadly categorized into two classes: 1) reliability-based methods that are computationally intensive; and 2) approximation methods that use simplified calculations to approximate reliability-based results. The NREL Report references a study from Milligan and Parsons that evaluated capacity factor approximation methods, which use capacity factor data among varying sets of hours, relative to the more computationally intensive reliability-based effective load carrying capability (ELCC) metric. As discussed in the NREL Report, the CF Method was found to be the most dependable technique in deriving capacity contribution values that approximate those developed using the ELCC Method. As described in the NREL Report, the CF Method “considers the capacity factor of a generator over a subset of periods during which the system faces a high risk of an outage event.” When using the CF Method, hourly LOLP is calculated and then weighting factors are obtained by dividing each hour’s LOLP by the total LOLP over the period. These weighting factors are then applied to the contemporaneous hourly capacity factors for a wind or solar resource to produce a weighted average capacity contribution value. The weighting factors based on LOLP are defined as: ∑ where wi is the weight in hour i, LOLPi is the LOLP in hour i, and T is the number of hours in the study period, which is 8,760 hours for the current study. These weights are then used to calculate the weighted average capacity factor as an approximation of the capacity contribution as: , where Ci is the capacity factor of the resource in hour i, and CV is the weighted capacity value of the resource. To determine the capacity contribution using the CF method, PacifiCorp implemented the following two steps: 1. A 500-iteration hourly Monte Carlo simulation of PacifiCorp’s system was produced using the Planning and Risk (PaR) model to simulate the dispatch of the Company’s system for a sample year (calendar year 2017). This PaR study is based on the Company’s 2015 IRP planning reserve margin study using a 13% target planning reserve margin level. The LOLP for each hour in the year is calculated by counting the number of iterations in an hour in which system load could not be met with available resources and dividing by 500 (the total number iterations). For example, if in hour 9 on January 12th there are two iterations with Energy Not Served (ENS) out of a total of 500 iterations, then the LOLP for that hour would be 0.4%.48 48 0.4% = 2 / 500. PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 407 2. Weighting factors were determined based upon the LOLP in each hour divided by the sum of LOLP among all hours. In the example noted above, the sum of LOLP among all hours is 143%.49 The weighting factor for hour 9 on January 12th would be 0.2797%.50 The hourly weighting factors are then applied to the capacity factors of wind and solar resources in the corresponding hours to determine the weighted capacity contribution value in those hours. Extending the example noted, if a resource has a capacity factor of 41.0% in hour 9 on January 12th, its weighted annual capacity contribution for that hour would be 0.1146%.51 Results Table N.2 summarizes the resulting annual capacity contribution using the CF Method described above as compared to capacity contribution values assumed in the 2013 IRP.52 In implementing the CF Method, PacifiCorp used actual wind generation data from wind resources operating in its system to derive hourly wind capacity factor inputs. For solar resources, PacifiCorp used hourly generation profiles, differentiated between single axis tracking and fixed tilt projects, from a feasibility study developed by Black and Veatch. A representative profile for Milford County, Utah was used to calculate East BAA solar capacity contribution values, and a representative profile for Lakeview County, Oregon was used to calculate West BAA solar capacity contribution values. Table N.2 – Peak Capacity Contribution Values for Wind and Solar East BAA West BAA Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV CF Method Results 14.5% 34.1% 39.1% 25.4% 32.2% 36.7% 2013 IRP Results 4.2% 13.6% n/a 4.2% 13.6% n/a Figure N.1 presents daily average LOLP results from the PaR simulation, which shows that loss of load events are most likely to occur during the spring, when maintenance is often planned, and during peak load months, which occur in the summer and the winter. 49 For each hour, the hourly LOLP is calculated as the number of iterations with ENS divided by the total of 500 iterations. There are 715 ENS iteration-hours out of total of 8,760 hours. As a result, the sum of LOLP is 715 / 500 = 143%. 50 0.2797% = 0.4% / 143%, or simply 0.2797% = 2 / 715. 51 0.1146% = 0.2797% x 41.0%. 52 In its 2013 IRP, PacifiCorp estimated capacity contribution values for wind and solar resources by evaluating capacity factors for wind and solar resources at a 90% probability level among the top 100 load hours in a given year. PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 408 Figure N.1 – Daily LOLP Figure N.2 presents the relationship between monthly capacity factors among wind and solar resources (primary y-axis) and average monthly LOLP from the PaR simulation (secondary y- axis) in PacifiCorp’s CF Method analysis. As noted above, the average monthly LOLP is most prominent in April (spring maintenance period), summer (July peak loads), and winter (when loads are high). Figure N.2 – Monthly Resource Capacity Factors as Compared to LOLP Figure N.3 through Figure N.5 present the hourly distribution of capacity factors among wind and solar resources (primary y-axis) as compared to the hourly distribution of LOLP (secondary y-axis) for a typical day in the months of April, July, and December, respectively. Among a typical day in April, LOLP events peak during morning and evening ramp periods when generating units are transitioning between on-peak and off-peak operation. Among a typical day 0.00% 0.05% 0.10% 0.15% 0.20% 0.25% 0.30% 0.35% 0.40% Pe r c e n t a g e 0.00% 0.01% 0.02% 0.03% 0.04% 0.05% 0.06% 0.07% 0.08% 0% 10% 20% 30% 40% 50% 60% 1 2 3 4 5 6 7 8 9 10 11 12 Lo s s o f L o a d P r o b a b i l i t y Ca p a c i t y F a c t o r Month Wind, West Wind, East Potential Solar, Single Tracking, Utah Potential Solar, Fixed Tilt, Utah Loss of Load Probability PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 409 in July, LOLP events peak during higher load hours and during the evening ramp. In December, LOLP events peak during higher load evening hours. Figure N.3 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in April Figure N.4 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in July 0.00% 0.02% 0.04% 0.06% 0.08% 0.10% 0.12% 0.14% 0.16% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Lo s s o f L o a d P r o b a b i l i t y Ca p a c i t y F a c t o r Hour Wind, West Wind, East Potential Solar, Single Tracking, Utah Potential Solar, Fixed Tilt, Utah Loss of Load Probability 0.00% 0.02% 0.04% 0.06% 0.08% 0.10% 0.12% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Lo s s o f L o a d P r o b a b i l i t y Ca p a c i t y F a c t o r Hour Wind, West Wind, East Potential Solar, Single Tracking, Utah Potential Solar, Fixed Tilt, Utah Loss of Load Probability PACIFICORP – 2015 IRP APPENDIX N – WIND AND SOLAR CAPACITY CONTRIBUTION STUDY 410 Figure N.5 – Hourly Resource Capacity Factors as Compared to LOLP for an Average Day in December Conclusion PacifiCorp conducts its resource planning by ensuring there is sufficient capacity on its system to meet its net load obligation at the time of system coincident peak inclusive of a planning reserve margin. The peak capacity contribution of wind and solar resources, represented as a percentage of resource capacity, is the weighted average capacity factor of these resources at the time when the load cannot be met with available resources. The peak capacity contribution values developed using the CF Method are based on a LOLP study that aligns with PacifiCorp’s 13% planning reserve margin, and therefore, the values represent the expected contribution that wind and solar resources make toward achieving PacifiCorp’s target resource planning criteria. 0.00% 0.02% 0.04% 0.06% 0.08% 0.10% 0.12% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Lo s s o f L o a d P r o b a b i l i t y Ca p a c i t y F a c t o r Hour Wind, West Wind, East Potential Solar, Single Tracking, Utah Potential Solar, Fixed Tilt, Utah Loss of Load Probability PACIFICORP – 2015 IRP APPENDIX O – DISTRIBUTED GENERATION STUDY 411 APPENDIX O – DISTRIBUTED GENERATION RESOURCE ASSESSMENT STUDY Introduction Navigant Consulting, Inc. prepared this Distributed Generation Resource Assessment for Long- term Planning Study on behalf of PacifiCorp. A key objective of this research is to assist PacifiCorp in developing distributed generation resource penetration forecasts to support its 2015 IRP. The purpose of this study is to project the level of distributed resources PacifiCorp’s customers might install over the next twenty years. PACIFICORP – 2015 IRP APPENDIX O – DISTRIBUTED GENERATION STUDY 412 Distributed Generation Resource Assessment for Long-Term Planning Study Supply Curve Support Prepared for: PacifiCorp Prepared by: Karin Corfee Graham Stevens Shalom Goffri June 9, 2014 Navigant Consulting, Inc. One Market Street Spear Street Tower, Suite 1200 San Francisco, CA 94105 415.356.7100 www.navigant.com Reference No.: 171094 Page i Table of Contents Executive Summary ................................................................................................................... v Key Findings ................................................................................................................................................. vii 1. Introduction ......................................................................................................................... 1-1 1.1 Methodology ......................................................................................................................................... 1-2 1.2 Report Organization ............................................................................................................................. 1-3 2. DG Technology Definitions ............................................................................................. 2-1 2.1 What is a “Distributed Generation” Source? .................................................................................... 2-1 2.1.1 Size Limits for this Study ....................................................................................................... 2-1 2.1.2 Determination of Applicable Technologies ......................................................................... 2-2 2.1.3 Solar DG Technology Definition ........................................................................................... 2-3 2.1.4 Small Distributed Wind Technology Definition ................................................................. 2-5 2.1.5 Small Scale Hydro Technology Definition ........................................................................... 2-7 2.1.6 CHP Reciprocating Engines Technology Definition ........................................................ 2-10 2.1.7 CHP Microturbine Technology Definition ........................................................................ 2-14 3. Resource Cost & Performance Assumptions ................................................................. 3-1 3.1 Photovoltaic ........................................................................................................................................... 3-1 3.1.1 Performance ............................................................................................................................. 3-1 3.1.2 Cost ........................................................................................................................................... 3-3 3.2 Small-Scale Wind .................................................................................................................................. 3-5 3.2.1 Performance ............................................................................................................................. 3-5 3.2.2 Cost ........................................................................................................................................... 3-5 3.3 Small-Scale Hydro ................................................................................................................................ 3-6 3.3.1 Performance ............................................................................................................................. 3-6 3.3.2 Cost ........................................................................................................................................... 3-7 3.4 CHP Reciprocating Engines ................................................................................................................ 3-8 3.4.1 Performance ............................................................................................................................. 3-8 3.4.2 Cost ........................................................................................................................................... 3-8 3.5 CHP Micro-turbines ............................................................................................................................. 3-9 3.5.1 Performance ............................................................................................................................. 3-9 3.5.2 Cost ........................................................................................................................................... 3-9 4. DG Market Potential and Barriers ................................................................................... 4-1 4.1 Incentives ............................................................................................................................................... 4-1 4.1.1 Federal Incentives ................................................................................................................... 4-1 4.1.2 State Incentives ........................................................................................................................ 4-1 4.1.3 Rebate Incentives ..................................................................................................................... 4-3 4.2 Market Barriers to DG Penetration ..................................................................................................... 4-4 Page ii 4.2.1 Technical Barriers .................................................................................................................... 4-4 4.2.2 Economic Barriers ................................................................................................................... 4-5 4.2.3 Legal / Regulatory Barriers .................................................................................................... 4-6 4.2.4 Institutional Barriers ............................................................................................................... 4-6 5. Methodology to Develop 2015 IRP DG Penetration Forecasts .................................. 5-1 5.1 Market Penetration Approach............................................................................................................. 5-1 5.1.1 Assess Technical Potential ..................................................................................................... 5-1 5.1.2 Simple Payback........................................................................................................................ 5-7 5.1.3 Payback Acceptance Curves .................................................................................................. 5-9 5.1.4 Market Penetration Curves .................................................................................................... 5-9 5.1.5 Scenarios ................................................................................................................................. 5-13 6. Results ................................................................................................................................... 6-1 6.1 Technical Potential ................................................................................................................................ 6-1 6.2 Overall Scenario Results ...................................................................................................................... 6-2 6.3 Results by State ..................................................................................................................................... 6-5 6.4 Results by Technology ....................................................................................................................... 6-15 Appendix A. Glossary ........................................................................................................... A-1 Appendix B. Summary Table of Results ........................................................................... B-2 Page iii List of Figures and Tables Figures: Figure 1-1. PacifiCorp Service Territory ............................................................................................................... vi Figure 1-2. Technical Potential Results ................................................................................................................ vii Figure 1-3. Distributed Generation Supply Curve Results, Base Case ...........................................................viii Figure 1-4. Low and High Penetration Scenario Results .................................................................................... ix Figure 1-1. PacifiCorp Service Territory ............................................................................................................. 1-2 Figure 2-1. Solar Technology Types .................................................................................................................... 2-3 Figure 2-2. PV System Applications .................................................................................................................... 2-4 Figure 2-3. Wind Turbine Examples ................................................................................................................... 2-5 Figure 2-4. U.S. SWT Sales, by Market Segment (2007-2012) ........................................................................... 2-7 Figure 2-5. Small Hydro Definition ..................................................................................................................... 2-8 Figure 2-6. Small Hydro Sizes .............................................................................................................................. 2-9 Figure 2-7. Example Small Hydro Sites, Turbines ............................................................................................ 2-9 Figure 2-8. Residential CHP Schematic ............................................................................................................ 2-11 Figure 2-9. Typical Commercial CHP System Components .......................................................................... 2-11 Figure 2-10. Reciprocating Engine Cutaway .................................................................................................... 2-12 Figure 2-11. Diesel/Gas-Fired DG Technology Applications......................................................................... 2-13 Figure 2-12. Reciprocating Engine Sizes and Fuels Used ............................................................................... 2-13 Figure 2-13. Microturbine Schematic ................................................................................................................ 2-14 Figure 2-14. Example Micro-turbines (Capstone Turbine Corporation) ...................................................... 2-14 Figure 3-1. Example Solar Panels: Mono-crystalline and Poly-crystalline ................................................... 3-1 Figure 3-2. Typical Crystalline Solar Cell Cross Section .................................................................................. 3-2 Figure 3-3. Example Solar Module Power Warranty ........................................................................................ 3-2 Figure 3-4. Photovoltaic Module Price Trends. ................................................................................................. 3-4 Figure 3-5. Hydropower project capacity factors in the Clean Development Mechanism .......................... 3-6 Figure 4-1. Net Metering Policies in the U.S. ..................................................................................................... 4-6 Figure 4-2. US Benchmark Interest Rate ............................................................................................................. 4-7 Figure 5-1. US Wind Resource Map .................................................................................................................... 5-6 Figure 5-2. Payback Acceptance Curves ............................................................................................................. 5-9 Figure 5-3. Fisher-Pry Market Penetration Dynamics .................................................................................... 5-11 Figure 5-4. DG Market Penetration Curves Used ........................................................................................... 5-12 Figure 6-1. Technical Potential Results ............................................................................................................... 6-1 Figure 6-2. Base Case Results ............................................................................................................................... 6-2 Figure 6-3. Low Penetration Scenario Results ................................................................................................... 6-3 Figure 6-4. High Penetration Scenario Results .................................................................................................. 6-4 Figure 6-5. Utah Base Case Results ..................................................................................................................... 6-5 Figure 6-6. Utah Residential PV Market Drivers ............................................................................................... 6-7 Figure 6-7. Utah Small Commercial PV Market Drivers .................................................................................. 6-8 Figure 6-8. Utah Near-Term PV Projections ...................................................................................................... 6-9 Figure 6-9. California Base Case Results .......................................................................................................... 6-10 Figure 6-10. Idaho Base Case Results ................................................................................................................ 6-11 Page iv Figure 6-11. Oregon Base Case Results ............................................................................................................. 6-12 Figure 6-12. Washington Base Case Results ..................................................................................................... 6-13 Figure 6-13. Wyoming Base Case Results ........................................................................................................ 6-14 Figure 6-14. Reciprocating Engines Base Case Results ................................................................................... 6-15 Figure 6-15. Micro-turbines Base Case Results ................................................................................................ 6-16 Figure 6-16. Small Hydro Base Case Results ................................................................................................... 6-17 Figure 6-17. Photovoltaics Base Case Results .................................................................................................. 6-18 Figure 6-18. Photovoltaics Residential Base Case Results .............................................................................. 6-19 Figure 6-19. Photovoltaic Commercial Base Case Results ............................................................................. 6-20 Figure 6-20. Small Wind Base Case Results ..................................................................................................... 6-21 Figure 6-21. Small Wind Residential Results ................................................................................................... 6-22 Figure 6-22. Small Wind Commercial Results ................................................................................................. 6-23 Tables: Table 2-1. PacifiCorp Net Metering Limits ........................................................................................................ 2-1 Table 2-2. Applicable DG Technologies ............................................................................................................. 2-2 Table 2-3. Common Applications for Small Wind Systems ............................................................................. 2-6 Table 3-1. PV Installation and Maintenance Cost Assumptions ..................................................................... 3-3 Table 3-2. Small Scale Wind Cost Assumptions ................................................................................................ 3-5 Table 3-3. Small Scale Hydro Cost Assumptions .............................................................................................. 3-7 Table 3-4. CHP Reciprocating Engines Cost Assumptions .............................................................................. 3-8 Table 3-5. CHP Microturbine Cost Assumptions .............................................................................................. 3-9 Table 4-1. State Tax Incentives ............................................................................................................................. 4-2 Table 4-2. Rebate Incentives ................................................................................................................................. 4-3 Table 5-1. CHP Technical Potential ..................................................................................................................... 5-2 Table 5-2. CHP Install Base .................................................................................................................................. 5-3 Table 5-3. Small Hydro Technical Potential Results ......................................................................................... 5-4 Table 5-4. PV System Size per Customer Class Example (Utah) ..................................................................... 5-5 Table 5-5. Utah PV Technical Potential............................................................................................................... 5-5 Table 5-6. Small Wind Technical Potential Results ........................................................................................... 5-7 Table 5-7. Residential Tax Rates .......................................................................................................................... 5-8 Table 5-8. Commercial Tax Rate .......................................................................................................................... 5-8 Table 5-9. Scenario Variable Modifications ...................................................................................................... 5-13 Page v Disclaimer This report was prepared by Navigant Consulting, Inc. exclusively for the benefit and use of PacifiCorp and/or its affiliates or subsidiaries. The work presented in this report represents our best efforts and judgments based on the information available at the time this report was prepared. Navigant Consulting, Inc. is not responsible for the reader’s use of, or reliance upon, the report, nor any decisions based on the report. NAVIGANT CONSULTING, INC. MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESSED OR IMPLIED. Readers of this report are advised that they assume all liabilities incurred by them, or third parties, as a result of their reliance on this report, or the data, information, findings and opinions contained in this report. June 9, 2014 Page vi Executive Summary Navigant Consulting, Inc. (Navigant) prepared this Distributed Generation Resource Assessment for Long-term Planning Study on behalf of PacifiCorp. A key objective of this research is to assist PacifiCorp in developing distributed generation resource penetration forecasts to support its 2015 Integrated Resource Plan (IRP). The purpose of this study is to project the level of distributed resources PacifiCorp’s customers might install over the next twenty years. Navigant evaluated five Distributed Generation resources in detail in this report: 1. Photovoltaic (Solar) 2. Small Scale Wind 3. Small Scale Hydro 4. Combined Heat and Power Reciprocating Engines 5. Combined Heat and Power Micro-turbines Other technologies were excluded as they were: 1) analyzed elsewhere for the IRP; 2) are too large to be considered “Distributed” resources; or 3) are not economically viable on a large scale. Project sizes were restricted to be less than the size limits of the relevant state net metering regulation, i.e. less than 2 MW in Oregon and Utah; <1 MW in CA; <100 kW in ID and WA; and <25 kW in WY. Distributed generation technical potential and market penetration was estimated by technology and by geography, i.e. the portion of the individual states that are in PacifiCorp’s service territory, including parts of California, Idaho, Oregon, Utah, Washington, and Wyoming (Figure 1-1). Figure 1-1. PacifiCorp Service Territory1 1 http://www.pacificorp.com/content/dam/pacificorp/doc/About_Us/Company_Overview/Service_Area_Map.pdf Page vii Key Findings Using public data sources for costs and technology performance, Navigant conducted a Fisher-Pry2 payback analysis to determine market penetration for DG technologies. This was done for individual residential and commercial customers of PacifiCorp by rate class. Navigant estimates approximately 10 GW of technical potential in PacifiCorp’s territory. As displayed in Figure 1-2, PV technology represents the highest technical potential across the five technologies examined. Figure 1-2. Technical Potential Results The main body of the report contains results by state, technology, and sector. 2 Fisher-Pry are researchers who studied the economics of “S-curves”, which describe how quickly products penetrate the market. They codified their findings based on payback period, which measures how long it takes to recoup initial high first costs with energy savings over time. Page viii Our overall results reflect our base case market penetration analysis, and we found that the near term outlook is roughly 50 MW in 2019 and reaches 900 MW by 2034, the end of the IRP period (Figure 1-3). Figure 1-3. Distributed Generation Supply Curve Results, Base Case Page ix In the low and high penetration cases, 33 MW and 95MW penetration is achieved by 2019, rapidly expanding thereafter to achieve 290 and 2630 MW of penetration in 2034, respectively (Figure 1-4). Figure 1-4. Low and High Penetration Scenario Results Page 1-1 1. Introduction Navigant Consulting, Inc. (Navigant) prepared this Distributed Generation Resource Assessment for Long-term Planning Study on behalf of PacifiCorp. A key objective of this research is to assist PacifiCorp in developing distributed generation resource penetration forecasts to support its 2015 Integrated Resource Plan (IRP). The purpose of this study is to project the level of distributed resources PacifiCorp’s customers will install over the next 20 years. Navigant evaluated five distributed generation resources in detail in this report: 1. Photovoltaic (Solar) 2. Small Scale Wind 3. Small Scale Hydro 4. Combined Heat and Power Reciprocating Engines 5. Combined Heat and Power Micro-turbines Other technologies were excluded as they were: 1) analyzed elsewhere for the IRP; 2) are too large to be considered “Distributed” resources; or 3) are not economically viable on a large scale. Project sizes were restricted to be less than the size limits of the relevant state net metering regulation, i.e. less than 2 MW in Oregon and Utah; <1 MW in CA; <100 kW in ID and WA; and <25 kW in WY. Distributed generation technical potential and market penetration was estimated by technology and by geography, i.e. the portion of the individual states that are in PacifiCorp’s service territory, including parts of California, Idaho, Oregon, Utah, Washington, and Wyoming (Figure 1-1). Page 1-2 Figure 1-1. PacifiCorp Service Territory3 1.1 Methodology In assessing the technical and market potential of each distributed generation (DG) resource and opportunity in PacifiCorp’s service area, the study considered a number of key factors, including: • Technology maturity, costs, & future cost improvements • Industry practices, current and expected • Net metering policies • Tax incentives • Utility rebates • O&M costs • Historical performance, and expected performance improvements • Availability of DG resources • Consumer behavior and market penetration 3 http://www.pacificorp.com/content/dam/pacificorp/doc/About_Us/Company_Overview/Service_Area_Map.pdf Page 1-3 Using public data sources for costs and technology performance, Navigant conducted a Fisher-Pry4 payback analysis to determine market penetration for DG technologies. This was done for individual residential and commercial customers of PacifiCorp by rate class. A five-step process was used to determine the IRP penetration scenarios for DG resources: 1. Assess a Technology’s Technical Potential: Technical potential is the amount of a technology that can be physically installed without considering economics. 2. Calculate First Year Simple Payback Period for Each Year of Analysis: From past work in projecting the penetration of new technologies, Navigant has found that Simple Payback Period is the best indicator of uptake. Navigant used all relevant federal, state, and utility incentives in its calculation of paybacks, including their expiration dates. 3. Project Ultimate Adoption Using Payback Acceptance Curves: Payback Acceptance Curves estimate what percentage of a market will ultimately adopt a technology, but do not factor in how long adoption will take. 4. Project Market Penetration Using Market Penetration Curves: Market penetration curves factor in market and technology characteristics to project how long adoption will take. 5. Project Market Penetration under Different Scenarios. In addition to the Base Case scenario, a High and Low Case scenarios were evaluated that used different 20-year average cost assumptions, performance assumptions, and electricity rate assumptions. Navigant examined the cost of electricity from the customer perspective, called “levelized cost of energy” (LCOE). A LCOE calculation takes total installation costs, incentives, annual costs such as maintenance and financing costs, and system energy output, and calculates a net present value $/kWh for electricity which can be compared to current retail prices. A simple payback calculation involves the same analysis conducted for year 1, and calculates the first year costs divided by first year energy savings to see how long it will take for the investment to pay for itself. Navigant has used LCOE and payback analyses to examine consumer decisions as to whether purchase of distributed resources makes economic sense for these customers, and then projects DG penetration based on these analyses. 1.2 Report Organization The remainder of this report is organized as follows: • Distribution Generation Technology Definitions • Resource Cost & Performance Assumptions • DG Market Potential and Barriers • Market Barriers to DG • Methodology to Develop 2015 DG Penetration Forecasts 4 Fisher-Pry are researchers who studied the economics of “S-curves”, which describe how quickly products penetrate the market. They codified their findings based on payback period, which measures how long it takes to recoup initial high first costs with energy savings over time. Page 1-4 • Results • Appendix A: Glossary. Page 2-1 2. DG Technology Definitions 2.1 What is a “Distributed Generation” Source? Distributed generation (DG) sources provide on-site energy generation and are generally of relatively small size, usually no larger than the amount of power used at a particular location. 2.1.1 Size Limits for this Study For this study, the DG resources must meet the size requirements for net metering for the six states of PacifiCorp’s service territory, as installations that take into account net metering benefits are likely to be most economical. These size requirements are generally less than 2 MW, per Table 2-1 below. Table 2-1. PacifiCorp Net Metering Limits 5 CA6 university/local government 7 PUC/energy/DistGen/netmetering. htm 8 residential 25 kW res / small commercial 85% avoided cost rate for all others net/env/nmcg.html 9 residential Admin R. 860-039; OR Admin R. 860-022-0075 10 residential 25 kW residential • commercial • Large commercial/ industrial with demand charges choose between avoided cost rate or alternative http://energy.utah.gov/funding- incentives/ 11 12 5 The NEM credit for DG generation used to nullify or offset purchases from the utility. 6 http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm 7 The rate block of the energy component of retail rates that the DG customer is able to avoid paying as a result of each kWh of DG production to which NEM applies. 8 http://www.rockymountainpower.net/env/nmcg.html 9 OR Revised Statues 757.300; Or Admin R. 860-039; OR Admin R. 860-022-0075 10 http://www.energy.utah.gov/renewable_energy/renewable_incentives.... 11 Rev. Code Wash. § 80.60 Page 2-2 Net Metering applies to all DG technologies under consideration, with the possible exception of combined heat and power (CHP), as notated in Column 3 of Table 2-1. 2.1.2 Determination of Applicable Technologies Technologies considered for this study include commercialized technologies that are generally installed in system sizes smaller than the net metering limits designated in Table 2-1, with a focus on technologies that are achieving market penetration in PacifiCorp’s service territory (namely solar and wind). Table 2-2 below lists potentially applicable technologies, which ones were included (those in grey), and the reasons why a number of technologies were not included at this time. Note, future IRP’s may include consideration of more technologies, especially those upon the cusp of commercialization (such as fuel cells), but resource constraints excluded them at present. Nevertheless, we believe we have captured the major trends and DG technologies that will impact PacifiCorp over the next decade, as newer technologies will take a long time to overcome commercialization challenges and significantly penetrate the market. Table 2-2. Applicable DG Technologies Distributed Generation Technology 2013 Net Meter this DG Study? Comment Photovoltaic ~94% Yes Highest level of DG market penetration Small Scale Wind ~6% Yes Yes CHP [Identified in 2013 IRP CHP Memo] Yes No Turbine sizes generally larger than 2 MW Fuel Cells No No Large scale, does not apply to DG Anaerobic Digester (AD) No Similarly, AD is not generally economic on a small scale Solar Hot Water [see 2013 IRP SHW Memo ] No 12 http://psc.state.wy.us/ Page 2-3 2.1.3 Solar DG Technology Definition There are primarily two methods of converting sunlight into electricity: solar electric (photovoltaic), and solar thermal. These are depicted below in Figure 2-1. Figure 2-1. Solar Technology Types Solar thermal technologies, which concentrate energy to raise the temperature of a heat transfer fluid, usually require system sizes of 50MW or higher to be economical, so we have excluded them from further consideration. Commercialized solar electric technologies include crystalline silicon (~90% of the market), and thin film (~10% of the market). Other solar technologies include concentrating photovoltaics (CPV), and photovoltaics with tracking. For purposes of this study, we define photovoltaics to be crystalline or thin film module technologies that are mounted at either a fixed angle (usually 30-45 degrees) to a pitched roof, or mounted at a fixed angle (usually 5-10 degrees) on a flat rooftop, as most “less than 2 MW” applications are typically rooftop mounted. Concentrating photovoltaic technologies are currently uneconomic, with little market penetration, and tracking technologies are used mostly on large-scale fields (>2 MW project scale). Photovoltaics can be used at many system sizes and voltages, sometimes called applications (see Figure 2-2 below). For purposes of this study, we are considering grid-connected applications only, as PacifiCorp is interested in the distributed resources that will impact future resource decisions, and off- grid applications are by definition not connected to PacifiCorp’s electrical grid. In addition, we exclude large central/substation applications that operate at transmission voltages because these projects are Page 2-4 almost all done at larger than 2 MW scale, the net metering limit. This excludes a few large industrial rate consumers from this study. Figure 2-2. PV System Applications Page 2-5 2.1.4 Small Distributed Wind Technology Definition13 Wind technologies produce electricity by using a tower to hold up a multi-bladed structure. Wind spins the blades and generated power in a wind turbine. Sizes can range from very large structure (100’s of feet tall), to much smaller (10s of feet tall), as shown in Figure 2-3. Figure 2-3. Wind Turbine Examples Large Med Small Small Small wind systems are most commonly defined as those with rated nameplate capacities between 1 kW and 100 kW; however, some groups include small wind turbines (SWT) of up to 500 kW in that category. For purposes of keeping power classes consistent when comparing historical and forecast annual installed data, Navigant uses the range of SWTs less than 100kW, unless otherwise noted. The primary focus of this report is on-grid-connected systems, as these systems will impact PacifiCorp’s future load. A small wind system consists of, as necessary, a turbine, tower, inverter, wiring, and foundation, and these systems can be used for both grid-tied and off-grid applications. Micro-wind is a subset of the small wind classification and is generally defined as turbines of less than 1 kW in capacity. These units are typically used in off-grid applications such as battery charging, providing electricity on sailboats and recreational vehicles, and for pumping water on farms and ranches. We consider micro-wind applications to be a part of the small wind residential segment. Community wind is another distributed wind category; it is typically a larger-scale project that includes one or several medium- to large-scale turbines to create a small wind farm with total capacity in the range of 1 MW to 20 MW. In this arrangement, the wind farm is at least majority-owned by the end users. Community wind projects in Minnesota and Iowa, for example, have utilized 1 MW-plus turbines. For comparison, community wind installations made up approximately 5.6% of total U.S. installed wind capacity in 2010 and 6.7% in 2011. However, because community wind projects tend to be on the large size, over the above net meter limits, these projects are considered to be part of the large wind market, and are not considered DG. 13 Note, this section is taken from “Small Wind Power: Demand Drivers, Market Barriers, Technology Issues, Competitive Landscape, and Global Market”, a Navigant Research report, 1Q 2013, by Dexter Gauntlett and Mackinnon Lawrence. Page 2-6 Overall, small wind represents far less than 1% of U.S. annual installed wind capacity. Small wind turbines (SWT) are classified as either horizontal-axis or vertical-axis. Horizontal-axis wind turbines (HAWTs) must be installed at a height of 60 ft. to 150 ft. (usually on a tower) in order to access sufficient unhindered wind to be efficient. They can also be installed atop tall buildings. Unlike HAWTs, vertical- axis wind turbines (VAWTs) are designed to utilize more turbulent wind patterns such as those found in urban areas [an example of this type of turbine is shown at the far right of Figure 2-3]. VAWTs are associated with rooftop installations and are sometimes integrated into a building’s architecture. In general, VAWTs are much less efficient than HAWTs, but the actual output of any turbine depends on wind conditions at the site. Most experts agree that, in light of their economics and energy output, urban SWTs have yet to constitute a viable or sustainable market – at least with current designs. Table 2-3 illustrates common SWT applications based on turbine size. For this study, only the on-grid applications in blue are being modeled and considered further. Table 2-3. Common Applications for Small Wind Systems Rated System Power Wind-diesel Wind hybrid Wind home system < 1 kW X X X X X X X X X X X 1 kW- 7 kW X X X X X X X X X X X X X X 7 - 50 kW X X X X X X X X X X 50 - 100 kW X X X X X Small wind applications Sa i l b o a t s Si g n a l i n g St r e e t l a m p Re m o t e h o u s e s Fa r m s Wa t e r Pu m p i n g Se a w a t e r D e s a l i n a t i o n Vi l l a g e P o w e r Mi n i -gr i d St r e e t L a m p Bu i l d i n g R o o f t o p Dw e l l i n g s Pu b l i c C e n t e r s Ca r P a r k i n g In d u s t r i a l Fa r m s Off-grid Another picture of how SWT size varies with application is shown in Figure 2-4 from a recent market survey conducted by Pacific Northwest Laboratory in 2013. Off-grid small turbines tend to be .1-.9 kW in size; residential turbine sizes vary from 1-10 kW, mimicking residential loads; and commercial small wind markets use a broader 11-100 kW in turbine sizes. Note, also that the total small wind capacity additions for the country in 2012 was ~54 MW, which is relatively low compared to the over 13000 MW amount of total wind power installed in the US in 201214. 14 2012 Wind Technologies Market Report, US Department of Energy and Lawrence Berkeley Livermore Laboratory. Page 2-7 Figure 2-4. U.S. SWT Sales, by Market Segment (2007-2012)15 2.1.5 Small Scale Hydro Technology Definition In assessing hydro potential, Navigant references a number of U.S. Department of Energy (DOE) reports that inventory the potential for small- and large-scale hydro:` • “Assessment of Natural Stream Sites for Hydroelectric Dams in the Pacific Northwest Region”, Hall, Verdin, and Lee, March 2012, Idaho National Laboratory, INL/EXT-11-23130 • “Feasibility Assessment of the Water Energy Resources of the United States for New Low Power and Small Hydro Classes of Hydroelectric Plants”, US Department of Energy, DOE-ID-11263, January 2006 • “Water Energy Resources of the United States with Emphasis on Low Head/Low Power Resources”, US Department of Energy, DOE.UD-11111, April 2004 The 2012 report details data for the Pacific Northwest Region, which covers Oregon, Washington, Idaho; the older report in 2006 represents the best information available for Utah, Wyoming, and California. DOE has also posted GIS software on-line for these hydro resources, especially the Pacific Northwest, which has the highest technical potential. These reports define high power as > 1 MW, low power as < 1 MW, high-head as > 30 feet, and low head as < 30 feet. For the Pacific Northwest, we had access to the actual technical potential measurements by 15 2012 Market Report on Wind Technologies in Distributed Applications, Aug 2013, Pacific Northwest National Laboratory, Orrell et al. Page 2-8 site, so defined small hydro as less than 2 MW, the net metering limit, to be consistent with the rest of the study. As an example, Figure 2-5 shows the sites assessed in the Pacific Northwest, where each blue dot represents a potential site. The red zone below 2 MW represents our definition of small hydro for purposes of this study. It captures both high-head, low flow streams (i.e. large drops/waterfalls with small amounts of water), to low head, high flow streams (i.e. small drops with large amounts of water flowing), that each can add up to 2 MW of power produced annually. The studies examined estimated annual mean flow and power rates using state of the art digital elevation models and rainfall/weather records, and represent a maximum ideal power potential that may differ from specific site assessments that will include exact stream geometry, economic considerations, etc. Figure 2-5. Small Hydro Definition16 Figure 2-6 shows the hydraulic head vs. flow rates, and how these relate to conventional turbine designs, micro-hydro designs, and unconventional systems (ultra low head, kinetic energy turbines, etc.). Our study includes assessment of all of these technologies, as long as the estimated power produced annually is below 2 MW. Electric power is produced when water flows through a turbine, which spins a generator/alternator to generate electricity directly. See Figure 2-6 for an example site and a few representative turbine styles. 16 Figure 26, “Assessment of Natural Stream Sites for Hydroelectric Dams in the Pacific Northwest Region”, Douglas Hall, Kristine Verdin, Randy Lee, March 2012. Page 2-9 Figure 2-6. Small Hydro Sizes17 Figure 2-7. Example Small Hydro Sites, Turbines 17 Feasibility Assessment of the Water Energy Resources of the United States for New Low Power and Small Hydro Classes of Hydroelectric Plants, DOE-ID-11263, January 2006, US Department of Energy, page xviii. Page 2-10 2.1.6 CHP Reciprocating Engines Technology Definition In a combined heat and power application, a small CHP power source will burn a fuel to produce both electricity and heat. In many applications, the heat is transferred to water, and this hot water is then used to heat a building (or sets of buildings, in the case of college or business campuses). The heat transfer fluid can also be steam, heating the building via radiators. Finally, in a factory setting the heat generated can be used directly in industrial processes (such a furnaces, etc.) Figure 2-8 and Figure 2-9 show example schematics for these systems. Page 2-11 Figure 2-8. Residential CHP Schematic18 Figure 2-9. Typical Commercial CHP System Components19 The CHP source can be a large variety of possible devices; the most common on the market is an engine known as a “reciprocating engine.” As shown in Figure 2-10, a reciprocating engine is an internal combustion engine that uses pistons to turn a crankshaft that is connected to a generator used to produce electricity. Waste heat is extracted from the engine jacket and the exhaust gases to heat a building. This internal combustion engine is very similar to an automobile engine, but is typically somewhat larger. 18 http://www.forbes.com/sites/williampentland/2012/03/04/japan-moves-the-needle-on-micro-chp/ 19 www.atcogas.com Page 2-12 Figure 2-10. Reciprocating Engine Cutaway20 Navigant Research has done extensive surveys of diesel and gas-fired DG technology markets, and has found that ~80% of reciprocating engine sales are estimated to be for portable (i.e. for construction) and/or backup power applications21. For purposes of this study, these two applications are excluded because neither application would provide base-load power for PacifiCorp. Our main focus is therefore on the applications shown in Figure 2-11, namely base-load power applications and CHP applications. 20 a2dialog.wordpress.com 21 “Diesel Generator Sets: Distributed Reciprocating Engines for Portable, Standby, Prime, Continuous, and Cogeneration Applications”, 1Q2013, Dexter Gauntlett, Navigant Research. Page 2-13 Figure 2-11. Diesel/Gas-Fired DG Technology Applications Similar surveys show that reciprocating engines come in a large variety of sizes, and that natural gas fuels are typically in use ~ 11% of the time. We assume that diesel and gasoline fuels will be used in portable and/or remote backup situations, excluding these installations. Figure 2-12. Reciprocating Engine Sizes and Fuels Used Page 2-14 2.1.7 CHP Microturbine Technology Definition The definition for the microturbine category is equivalent to that for reciprocating engines above, except that the CHP source is a microturbine rather than a reciprocating engine. A schematic of this type of device is shown in Figure 2-13. Figure 2-13. Microturbine Schematic22 The microturbine uses natural gas to start a combustor, which drives a turbine. The turbine, in turn drives an AC generator and compressor, and the waste heat is exhausted to the user. The device therefore produces electrical power from the generator, and waste heat to the user. Emissions tend to be very low, allowing installation in locations with strict emissions controls, and they tend to have fewer moving parts than reciprocating engines, which they compete with directly in various applications. Navigant used the performance specifications of a typical microturbine design as profiled in various market reports23,24. Figure 2-14 shows one example offering. Figure 2-14. Example Micro-turbines (Capstone Turbine Corporation) 22 www.understandingchp.com 23 “Catalog of CHP Technologies”, U.S. Environmental Protection Agency, December 2008 24 “Combined Heat and Power: Policy Analysis and Market Assessment 2011-2030”, ICF, February 2012 Page 3-1 3. Resource Cost & Performance Assumptions 3.1 Photovoltaic 3.1.1 Performance Navigant has based its assessment of photovoltaic performance over time on manufacturer specification sheets and warranties. In general, solar panels are sized for either one or two man installation and handling, to allow them to fit them easily onto racks that are mounted onto rooftops, and that are of a weight and size for easy handling. For rooftop applications in particular, solar panels typically have an aluminum frame around the panel, to protect against accidental corner breakage and chipping of the front glass. Figure 3-1. Example Solar Panels: Mono-crystalline and Poly-crystalline The amount of power generated by the solar cell module depends on the particular material and configuration of the technology, as well as local sunlight conditions.25 Figure 3-2 illustrates a typical crystalline technology cross section, showing the grid pattern (the fine lines in Figure 3-1), and the various electrical components of the cell. Over time, manufacturers have improved material quality, 25 Navigant also factored in assumptions on single or dual axis tracking and the panel’s orientation. Page 3-2 material types, processes, and optics to generate slightly more power in the same area. For mature technologies, these gains have been on the order of .1% / year for mainstream commercial cells26. Figure 3-2. Typical Crystalline Solar Cell Cross Section A photovoltaic module will experience some slight amount of degradation over time, as the wires in the cells age and oxidation increases resistance, as differential thermal expansion ages the cells, etc. In the industry, it is an industry standard to offer a limited power output warranty which covers this degradation. An example warranty is shown in Figure 3-3. Figure 3-3. Example Solar Module Power Warranty In summary, we assume .1% efficiency gains over the next 20 years, mimicking solar technology performance over the last 20 years; and assume a .7% annual degradation rate in keeping with current module warranties that guarantee 80% power after 25 years. 26 Based on February Photon International’s annual survey of PV module specification sheets over the last twenty years. b) 25 Year Limited Power Output Warranty In addition, Trina Solar warrants that for a period of twenty-five years commencing on the Warranty Start Date loss of power output of the nominal power output specified in the relevant Product Data Sheet and measured at Standard Test Conditions (STC) for the Product(s) shall not exceed:  For Polycrystalline Products (as defined in Sec. 1 a): 2.5 % in the first year, thereafter 0.7% per year, ending with 80.7% in the 25th year after the Warranty Start Date,  For Monocrystalline Products (as defined in Sec. 1 b): 3.5 % in the first year, thereafter 0.68% per year, ending with 80.18% in the 25th year after the Warranty Start Date. Page 3-3 3.1.2 Cost Amalgamating a number of public sources of data regarding PV installed and maintenance costs with our own private sources and internal databases, we used the following assumptions and sources for these costs: Table 3-1. PV Installation and Maintenance Cost Assumptions DG Resource Units Sources Residential Commercial Installed Cost $/kWDC $4000 $3125 • • Photovoltaic System Pricing Trends: Historical, Recent, and Near - Term Fixed O&M $/kW-Yr $23 $25 • • Addressing Solar Photovoltaic Operations and Maintenance Challenges, 2010, EPRI • True South Renewables, Solar Plaza Module prices have come down dramatically over the last few decades, as the brown line shows in Figure 3-4. This has impacted system prices sharply, as module price has traditionally been ~50% of total system price. Page 3-4 Figure 3-4. Photovoltaic Module Price Trends27. In our base case, Navigant assumes that PV annual system installation cost reductions will continue at the same rate as has occurred over the last ten years. Plotting the data from the above graph, this equals 4.7% cost reduction annually for commercial installations, and slightly higher 5.3% cost reduction for residential installations. Note, a higher proportion of installation costs have become non-module costs (installation labor, design, permitting, etc.) recently, and the U.S. is a relatively immature market relative to scale regarding these non-module factors. Our expectation is that these non-module costs will start to mimic more mature markets such as Germany where costs are demonstrably lower28. However, costs likely cannot be reduced at such a relatively high rate forever. Navigant assumes that DOE’s modeled System Overnight Capital Cost will form a floor for future PV system prices, reaching 1.80 $/WpDC (commercial), and 2.10 $/WpDC (residential). For our high and low penetration cases, we vary these cost projections by +/- 10%. 27 Photovoltaic System Pricing Trends: Historical, Recent, and Near-Term Projections, 2013 Edition”,Feldman et al, NREL/LBNL, PR-6A20-60207 28 “Why are Residential PV Prices in Germany So Much Lower Than in the United States?” A Scoping Analysis”, Joachim Seel, Galen Barbose, and Ryan Wiser, Lawrence Berkeley National Laboratory, Feb 2013, sponsored by SunShot, US Department of Energy. Page 3-5 3.2 Small-Scale Wind 3.2.1 Performance Large-scale wind has dramatically improved system capacity factor over 10% over the last two decades29. This has reflected larger and larger turbine sizes, improvements in air flow modeling, blade angle control, indirect to direct drive innovations, etc. Small wind suffers from (a) size limitations, and (b) wind strength close to the earth tends to be much lower, Navigant assumes small wind system performance improvements will be roughly half of those achieved by its bigger cousins to reflect these factors and physical limits. We therefore assume that capacity factors will change from around 20% in 2013 to approximately 33% in 2034. 3.2.2 Cost The most recent public cost data that we could find regarding small wind installed cost and maintenance costs are shown in Table 3-2: Table 3-2. Small Scale Wind Cost Assumptions DG Resource Costs Units Baseline 2013 Sources Installed Cost (Residential) $/kW $6960 Capacity weighted average, "2012 Market Report on Wind Technologies in Distributed Applications." Pacific Northwest National Laboratory for U.S. DOE, August 2013. Commercial estimates based on reduced Installed Cost (Commercial) $5568 Fixed O&M $/kW-Yr $30 "2012 Market Report on Wind Technologies in Distributed Applications." Pacific Northwest National Laboratory for U.S. DOE, August The above capacity factor improvement is equivalent to a cost reduction potential of -2.5 % annual cost improvement over the next 20 years. If small wind gets to much larger scale than at present, then further cost reductions may be possible, but currently paybacks for this technology are very long, so this is less likely, and we therefore include this possibility as part of our high penetration scenario only. 21 “Recent Developments in the Levelized Cost of Energy from U.S. Wind Power Projects”, Wiser et al, Feb 2012, National Renewable Energy Laboratory / Lawrence Berkeley National Laboratory. Contract No DE-AC02- 05CH11231. Page 3-6 3.3 Small-Scale Hydro 3.3.1 Performance Hydropower project capacity factor can vary widely, as Figure 3-5 illustrates. Navigant assumes 50% capacity factor in the base case as typical30, using a band of +/- 5% to capture the variation in average project capacity factor as part of its low and high penetration scenarios. Figure 3-5. Hydropower project capacity factors in the Clean Development Mechanism31 30 This datapoint of 50% is echoed in three DOE potential studies referenced in section 2.1.7 . 31 Renewable Energy Technologies: Cost Analysis Series, Volume 1: Power Sector, Issue 3/5, Hydropower, June 2012, International Renewable Energy Agency, Figure 2.4, which references E. Branche, “Hydropower: the strongest performer in the CDM process, reflecting high quality of hydro in comparison to other renewable energy sources, EDF, Paris, 2011. Page 3-7 3.3.2 Cost Cost data for small scale hydro is found in Table 3-3, with the sources annotated. In keeping how other mature technologies are treated in the IRP, Navigant assumes no further future cost improvements for this technology. Table 3-3. Small Scale Hydro Cost Assumptions Small Scale Hydro DG Resource Units Baseline 2013 Sources Installed Cost $/kW $4000 Double average plant costs in "Quantifying the Value of Hydropower in the Electric Grid: Plant Cost Elements." Electric Power Research Institute, November 2011; this accounts for permitting/project Fixed O&M $/kW-Yr $52 Renewable Energy Technologies: Cost Analysis Series. "Hydropower." International Renewable Energy Page 3-8 3.4 CHP Reciprocating Engines 3.4.1 Performance Reciprocating internal combustion engines are a widespread and well-known technology. There are several varieties of stationary engine available for power generation market applications and duty cycles. Reciprocating engines for power generation are available in a range of sized from several kilowatts to over 5 MW. We used an electric heat rate of 11,000 Btu/kWh corresponding to electrical efficiencies around 30%-33%. 3.4.2 Cost The latest cost data for CHP reciprocating engines is shown in Table 3-4. Table 3-4. CHP Reciprocating Engines Cost Assumptions CHP Reciprocating Engines DG Resource Costs Units Baseline 2013 Sources Installed Cost $/kW $2325 Combined Heat and Power: Policy Analysis and Market Assessment 2011-2030, ICF International; Catalog of CHP Technologies, U.S. Environmental Protection Agency and Combined Heat and Power Partnership; Annual Cost Reductions % -1.4% 20% by 2030; "Combined Heat and Power: Policy Analysis AND 2011-2030 Market Assessment." ICF International, Inc., February Variable O&M $/MWh $19 Catalog of CHP Technologies, 2008, U.S. Environmental Protection Agency Fuel Cost $/MWh $77 [UT] Example State: UT; Electric Heat Rate: 11,000 BTU/kWh; Fuel Cost: ~$6.90/MMbtu*. Note, Page 3-9 3.5 CHP Micro-turbines 3.5.1 Performance Micro-turbines are small electricity generators that burn gaseous and liquid fuels to create high-speed rotation that turns an electrical generator. The capacity for micro-turbines available and in development is generally from 30 to 250 kilowatts (kW). We assumed electric heat rate around 14,800 Btu/kWh used which corresponds to a thermal to electric efficiency around 23%-25%. The electrical efficiency increases as the microturbine becomes larger.23,24 3.5.2 Cost Table 3-5 shows the latest cost data and assumptions for micro-turbines. Table 3-5. CHP Microturbine Cost Assumptions CHP Micro-turbines Resource Units 2013 Sources Installed Cost $/kW $2650 Combined Heat and Power: Policy Analysis and Market Assessment 2011-2030, ICF International; Catalog of CHP Technologies, U.S. Environmental Protection Agency and Combined Heat and Power Partnership; Annual Cost Reductions % -1.4% Analysis AND 2011-2030 Market Assessment." ICF International, Inc., February 2012. CEC-200- Variable O&M $/MWh $23.5 Catalog of CHP Technologies, 2008, U.S. Environmental Protection Agency Fuel Cost $/MWh $104 (UT) Fuel Cost: ~$6.90/MMbtu* Page 4-1 4. DG Market Potential and Barriers A number of DG resources are more expensive than grid electricity to the consumer on a levelized cost of energy basis. As a result, there are various forms of incentives that close the “grid parity gap” for some DG technologies. 4.1 Incentives 4.1.1 Federal Incentives A primary incentive, which Congress allows for wind and solar DG technologies, is the federal Business Energy Investment Tax Credit (ITC), which allows the owner of the system to claim a tax credit off a certain percentage of the installed price of these distributed generation resources.32 For example, for solar PV technologies the ITC is currently 30% of the overall installed system cost. This ITC for solar PV is set to reduce from 30% down 10% at the end of 2016. For CHP reciprocating engines and CHP microturbine technologies, the ITC for businesses is 10%. An equivalent personal credit is given for residential customers. For our base case analysis, Navigant presumes that aside from the expiration of the 30% ITC incentive down to 10% in 2017, current regulatory incentives will continue throughout the analysis period. In general, due to the uncertainties associated with varying political policy over time, Navigant does not attempt to predict whether or when particular policies will be enacted, and assumes that existing policy applies. Our base case therefore includes all current incentives, including expiration dates. Our high and low cases explicitly model potential changes in technology cost assumptions, technology performance assumptions, and future electricity rate assumptions, as discussed below. Policy changes that have equivalent payback impacts are therefore also modeled as part of our high and low scenarios. In other words, if the high penetration case includes 10% steeper cost reductions / year, and incentives are offered that are equivalent to this level of cost reduction, our high case includes this type of policy change (whether due to a policy change, or steeper cost reductions than expected). 4.1.2 State Incentives State incentives within PacifiCorp’s service territory that apply to the technologies under consideration in sizes < 2 MW are shown below in Table 4-1. 32 www.dsireusa.org Page 4-2 Table 4-1. State Tax Incentives33 Personal Tax Credit (residential) Corporate Tax Credit Sales Tax 40%/20%/20%/20% personal max over 4 years Wind: $2/kWh in first year, max $1500 commercial PV, wind systems: 10% of installed cost, up to As the table shows, there are a few state incentives that improve the payback and penetration of DG technologies beyond what is supported by the federal incentive. In particular, Oregon and Utah’s incentives significantly increase penetration. In general, depending on varying state goals and budgets, Navigant has observed that state incentives tend to complement or step up when federal incentives are reduced. Note as well that state incentives tend to be subject to varying budget restrictions over time and can therefore be somewhat volatile; this volatility can be lower for rate supported programs. 33 See http://www.dsireusa.org/summarytables/finre.cfm. Incentives and Rebates were examined as of 06/01/14; note that not all incentives listed on the website apply due to 2 MW size restrictions, alternate technologies, etc. Page 4-3 4.1.3 Rebate Incentives On top of state tax incentives, states or specific utilities within a state also offer rebates for DG installations. Typically these programs pay an up-front rebate to reduce the initial installation cost of the system, and are subject to strict budget limits. Rebate incentives that apply to PacifiCorp’s service territory are shown in Table 4-2: Table 4-2. Rebate Incentives Rebates34 CA Pacific Power PV Rebate Program: $1.13/Wp CEC-AC Res OR Oregon State Rebate Programs: Small Wind Incentive Program $5.00/kWh, up to 50% of installed cost Solar Electric Incentive Program $.75/WpDC (res) $1.00 /Wp (0-35 kW); .45-$1.00/Wp (35-200 kW) commercial $7500 max UT Rocky Mountain Power PV Rebate Program: $1.25->1.05/W-AC (res). $1.00->.80/W-AC (0-25kW); $.80->.60/W-AC (25-1000 kW) commercial Max: $5000 (res). $25,000 (0-25 kW). $800,000 (25-1000 kW) PacifiCorp is spending over $50 million from 2013-2017 in California and Utah, supporting DG technologies, and Oregon state’s rebate program is spending ~$2 million annually within PacifiCorp’s service territory. Given that these expenditures are rate-payer based, we assume the Oregon state rebate budget levels will extend throughout the IRP period as part of our base case. 34 See http://www.dsireusa.org/summarytables/finre.cfm. Incentives and Rebates were examined as of 06/01/14; note that not all incentives listed on the website apply due to 2 MW size restrictions, alternate technologies, expiring CSI budgets, etc. Page 4-4 4.2 Market Barriers to DG Penetration There are a number of market barriers to wider use of distributed resources in PacifiCorp’s service territory. These include technical, economic, regulatory/legal, and institutional barriers. Each of these barriers is discussed in turn. 4.2.1 Technical Barriers 4.2.1.1 Maximum DG Penetration Limits If DG sources are renewable, these usually have reduced availability / capacity factor when the resources is not available, and can also be highly variable. Because no widespread cost-effective energy storage solutions exist, backup power generation is needed when variable sources are suddenly unavailable (i.e., storms blocking the sun, or the wind dies down suddenly). This, in turn, can increase costs. From a technical perspective, a number of jurisdictions (Germany, Denmark, other utilities in the US35) have demonstrated that renewable sources can represent 20-30% of grid power without energy storage solutions. California is on target for reaching its 33% by 2020 renewable goal36, while many other states in PacifiCorp’s service territory have varying renewables penetration.. 4.2.1.2 Interconnection Standards Technical interconnection standards must be in place to ensure worker safety and grid reliability, and at the DG level these concerns have largely been addressed by standards such as IEEE 1547, which is concerned with voltage and frequency tolerances for distributed resources. Other technical codes and standards include ANSI C84 (voltage regulation), IEEE 1453 (flicker), IEEE 519 (harmonics), NFPA NEC / IEEE NESC (safety)37. However, as DG penetration levels increase to high levels (greater than 10%+), jurisdictions such as Germany have found that voltage control / ride-through can be an issue. Similarly, standards are a work in progress regarding advanced inverters and the grid support they can provide (reactive control, etc.). Finally, there is a lack of standards regarding utility two-way control of DG systems at high penetration levels. Two-way control, with attendant communication systems and higher costs, can allow the utility to turn off DG sources during periods of low load for better source/demand matching and dispatch. Standards bodies – IEEE, etc. – continue to make progress on defining these types of technical standards that will become more important should PacifiCorp face higher levels of DG market penetration. From a practical perspective, there is a plethora of different technical ways to interconnect DG equipment to the grid, and parts/schematic standardization is helpful to reduce maintenance costs (training, spare parts inventories, etc.) and improve safety. As DG penetration increases, we expect PacifiCorp to examine these issues as necessary with larger amounts of DG penetration. 35 On May 2013, Xcel Energy produced 60% of its power from wind. See http://www.xcelenergy.com/Environment/Renewable_Energy/Wind/Do_You_Know:_Wind 36 See http://www.energy.ca.gov/renewables/ 37 “Interconnection Standards for PV Systems: Where are we? Where are we going?”, Abraham Ellis, Sandia National Laboratory, Cedar Rapids, IA, Oct 2009. Page 4-5 4.2.2 Economic Barriers 4.2.2.1 Cost Barriers DG sources tend to be more expensive than conventional sources due to a number of effects: • Site Project Costs: Site project costs are spread out over smaller project sizes. For example, a 467 MW coal plant38 compared to a 100kW PV commercial roof installation. Because site project costs are relatively constant, these costs are higher for the DG installation. • Efficiency: DG sources tend to be less efficient than conventional sources (with CHP being the exception). Less power produced by a source leads to higher costs on a $/kWh basis. • Technology scale: As technologies move into mass production, equipment costs can come down dramatically; but until then, costs can be high, creating a barrier to market penetration. If a process is relatively slow, or expensive materials are used, this can result in high costs even at high scale. • DG Preferential Use: If DG is used preferentially over conventional sources, conventional source power costs can increase due to more start-stops, or less efficient operation. Each of these barriers is being address in the US market, varying by technology, and we therefore expect DG costs to come down over time, as shown above in our cost assumption for each technology. The US DOE is focusing research efforts on reducing soft costs, technical innovations can address efficiency gaps, and we expect many technologies to get to scale over the IRP period. 4.2.2.2 Resource Availability DG sources are dependent on the availability of their respective resources, especially from an economic perspective. For example, a CHP project needs a large enough local thermal load to be economically attractive. Similarly, a small scale hydro project needs to have adequate water flow annually to generate enough power to be viable and a small wind project needs high enough wind speed (typically class 3 or 4) to be viable.39 A solar project needs enough solar insolation to be worth developing in addition to appropriate rooftop orientation and rooftop area availability. 4.2.2.3 Trade Barriers/ Issues There have been recent trade actions that have impacted the US market for PV modules, one DG technology. The US and the EU have levied trade sanctions and tariffs on to Chinese PV panel producers, increasing module costs in the U.S. Conversely, Chinese government subsidies resulted in a large overcapacity of module factories in China, and this has reduced prices dramatically over the last 5 years, as well as driven a number of US manufacturers out of business. Trade issues can therefore be both a barrier as well as a spur to DG market growth. 38 A typical size for a coal plant (source: EIA) 39 Class 3 wind has annual wind speeds of 11.5-12.5 mph; class 4 is 12.5-13.4 mph. (http://rredc.nrel.gov/wind/pubs/atlas/tables/1-1T.html) Page 4-6 4.2.3 Legal / Regulatory Barriers 4.2.3.1 Net Metering All PacifiCorp states have approved net metering programs for DG as shown in Figure 4-1. The provisions of these programs vary by state. For customers owning DG, net metering can reduce the DG payback period, which may influence a customer’s investment decision. For customers leasing DG, it is uncertain whether and to what extent net metering has impacted the lease price offered to a customer and the total cost of a leasing customer’s total electric consumption. Figure 4-1. Net Metering Policies in the U.S.40 4.2.4 Institutional Barriers Institutional barriers include mis-matched incentives and financing barriers. 4.2.4.1 Mis-matched Incentives Typically, when a DG power source is purchased and installed, the benefits accrue directly to the customer rather than a utility. Utilities feel higher DG usage by customers as a drop in load and revenue, making it difficult for a utility to recover its fixed costs if actual sales in a 12-month period do not equal the forecast sales used in setting rates. 40 www.dsireusa.org Page 4-7 4.2.4.2 Financing Barriers As displayed in Figure 4-2, we are currently enjoying the lowest interest rates available in a generation. Figure 4-2. US Benchmark Interest Rate41 At some point, these interest rates may rise, significantly increasing the cost of financing DG projects, which typically have high up-front costs and use a loan and/or equity financing to enable projects to proceed. Countervailing this increasing interest rate possibility are trends regarding the risk premium for DG projects. As DG sources get to larger and larger scale from a financing perspective (i.e. deal size and bankability), the risk premium for these projects is likely to go down, especially for newer technologies. In particular, we are seeing solar projects shift from high equity content toward higher loan content, at correspondingly lower interest rates. Current incentives tend to rely on ITC incentives, which require a healthy tax equity market for larger- scale project financing. A recent barrier to larger DG projects occurred when the tax equity appetite shrank dramatically during the recent financial crisis, slowing DG market growth. Congress reacted by creating the Treasury Grant program in response, but this took some time to get set up and operational. 41 http://www.tradingeconomics.com/united-states/interest-rate Jan/13 Page 5-1 5. Methodology to Develop 2015 IRP DG Penetration Forecasts 5.1 Market Penetration Approach The following five-step process was used to determine the IRP penetration scenarios for DG resources: 1. Assess a Technology’s Technical Potential: Technical potential is the amount of a technology that can physically be installed without taking economics into account. 2. Calculate First Year Simple Payback Period for Each Year of Analysis: From past work in projecting the penetration of new technologies, Navigant has found that Simple Payback Period is the best indicator of uptake. Navigant used all relevant federal, state, and utility incentives in its calculation of paybacks, including their expiration dates. 3. Project Ultimate Adoption Using Payback Acceptance Curves: Payback Acceptance Curves estimate what percentage of a market will ultimately adopt a technology, but do not factor in how long adoption will take. 4. Project Actual Market Penetration Using Market Penetration Curves: Market penetration curves factor in market and technology characteristics to project how long adoption will take. 5. Project Market Penetration under Different Scenarios. In addition to the Base Case scenario, a High Penetration and a Low Penetration case were evaluated that used different 20-year average cost assumptions, performance assumptions, and electricity rate assumptions. Navigant examined the cost of electricity from the customer perspective, called “levelized cost of energy” (LCOE). A levelized cost of energy calculation takes total installation costs, incentives, annual costs such as maintenance and financing costs, and system energy output, and calculates a net present value $/kWh for electricity which can be compared to current retail prices. A simple payback calculation involves the same analysis conducted for year 1, and calculates the first year costs divided by first year savings to see how long it will take for the investment to pay for itself. Navigant has used LCOE and payback analyses to examine consumer decisions as to whether purchase of distributed resources makes economic sense for these customers, and then projects DG penetration based on these analyses. Each of these five steps is explained below. 5.1.1 Assess Technical Potential Each technology considered has its own characteristics and data sources that influenced how we assessed technical potential, which is the amount of a technology that can be physically installed within PacifiCorp’s service territory without taking economics into account. We consider each technology in the following subsections. 5.1.1.1 CHP (Reciprocating Engines and Micro-turbines) Technical Potential CHP technologies can substitute 1:1 for grid power. The technical potential is therefore the amount of power being used by applicable customer classes. In the case of CHP, market studies and our own work has shown that smaller installations are uneconomic, so our technical potential focused on large Page 5-2 commercial users. We multiplied the total number of large commercial customers times the minimum peak summer loads. For example, in Utah, large commercial class customers (schedule 8 electricity rates) number 274, and the minimum peak load for these customers is 661 kW, yielding a technical potential of 274 x 661 kW = 181 MW. Customer information and building load data was provided by PacifiCorp for each state. We then compared these technical potentials to a 2013 CHP national assessment, called “The Opportunity for CHP in the United States”42. This national assessment provides technical potential figures by state, so we multiplied their state estimates times PacifiCorp’s area coverage ratio to determine the studies assessment of CHP potential per this study. Table 5-1. CHP Technical Potential “The Opportunity for CHP in the United States” PacifiCorp Data State Potential 43 % PacifiCorp Coverage PacifiCorp Potential 2013 Customer x Load Potential (MW) 6456 7% 452 15 ID 211 11% 23 11 OR 657 22% 145 303 418 72% 301 181 WA 1052 4% 42 67 105 39% 41 135 In three states, WA, WY, and OR, the PacifiCorp data exceeded the figures from the national assessment. In these cases (shown in green) we reduced the technical potential to match the national study, which utilized more data regarding the availability of economic thermal loads; conversely, given the imprecision in the % coverage estimates, we conservatively used PacifiCorp’s data when it was lower than that assessed by the study (CA, ID, and UT). The difference in CA is especially stark, as PacifiCorp’s territory is mostly forested area with little large commercial activity. The bolded figures in Table 5-1 are the final technical potential used for each state. We also examined current CHP installations < 2 MW from available databases, and found a very low number of installations. In Table 5-2, the 2nd column shows the total number of reciprocating engine CHP projects since 1980 installed, with the number following the slash showing what proportion of these are less than 2 MW in size. 42 ICF International, Hedman et al, May 2013, for the American Gas Association 43 ibid, Table 7 (industrial 50-1000 kW + 1-5MW categories) + Table 8 Commercial (same categories), p32-33. Page 5-3 Table 5-2. CHP Install Base Combined Heat and Power National Database44 State Engine Installations (Total / < 2 MW) 1980-2013 Micro-turbine Installations [in MW] Given this very small installation base since 1980 within PacifiCorp’s territory, and summarizing, we conservatively used the minimum CHP technical potential from two sources, PacifiCorp’s customer data, and an area-ratio estimate from a national CHP study. 5.1.1.2 Small Hydro Technical Potential The detailed national small hydro studies conducted by the Department of Energy in 2004 to 2013, referenced in Section 2.1.5 formed the basis of our estimate of technical potential for small hydro. In the Pacific Northwest Basin, which covers WA, OR, ID, and WY, a very detailed stream by stream analysis was done in 2013, and DOE sent us this data directly. For these states we had detailed GIS PacifiCorp service territory data combined with detailed GIS data on each stream / water source. For each state, we subtracted out the streams that were not in PacifiCorp’s service territory, and summed the technical potentials. For the other two states, Utah and California, we relied on an older 2006 national analysis, and multiplied the given state figures time the area coverage for PacifiCorp within that state that are shown on Table 5-1 above. 44 http://www.eea-inc.com/chpdata. This ICF database is supported by the US Department of Energy and Oak Ridge National Laboratory. It was accessed 6/1/2014. Page 5-4 Table 5-3. Small Hydro Technical Potential Results State 2012 Small Hydro Potential (MW)45 32 99 161 62 156 28 5.1.1.3 Photovoltaic Technical Potential For photovoltaics, a similar approach was taken as the CHP technologies above. We assessed peak load from customer data records provided by PacifiCorp and multiplied by summer peak loads to determine technical potential for each customer class (i.e. rate schedule)46. Rate schedules and customer classes analyzed were chosen according to the following criteria: 1. Rate classes must represent significant revenue 2. Single customer contracts are excluded to preserve confidentiality 3. Partial requirements customers are generally large, over 1 MW, and are qualifying facilities under PURPA and therefore not net-metered customers. They have been excluded. 4. Transmission voltage customers were excluded, as PV projects at these voltage levels are likely to be large-scale PV fields, and exceed the 2 MW net metering limit We then compared this to the estimated maximum PV array available on the rooftop for an average member of this customer class; the available rooftop area in some cases limited technical potential (for large power users, sometimes sharply). Our assumption is that ground mount system sizes will be larger than the 2 MW net metering limit, and are therefore accounted for elsewhere in the IRP. To estimate maximum available PV array size, we multiplied a number of factors: • Average rooftop size, derived from PacifiCorp surveys on establishment square feet, divided by an average of two stories • Assumed PV access factor. Residential tilted rooftops have a 1 in 4 chance of facing south; commercial rooftop access factor is higher as rooftops are flat, but some shading occurs • Average PV Module Power density (W/Sq Ft). Derived from typical packing factor of 80% (accounting for maintenance footpaths, tilted racking, etc.) and 2013 manufacturer module power specification sheets 45 Note, average hydro technical potential is not likely to change annually 46 Note customer classes were chosen Page 5-5 An example of this system size calculation is shown for Utah in Table 5-4. Columns 2 through 4 were multiplied together to obtain column 5, and the minimum of the 2013 system size and the summer peak load is the output in the rightmost column. Table 5-4. PV System Size per Customer Class Example (Utah) 2103 Utah Customer Class (Rate Schedule) Maximum Available PV Array Size Peak Load One Average floor size PV Access Factor average PV Power 2013 system size 2013 Summer Peak Load Class System Size 17600 65% 12 137 1112.7 137 1258 25% 15 4.7 2.8 2.8 9600 65% 12 75 3.4 3.4 This output column of class system size was then multiplied by the number of customers to obtain technical potential per class. The commercial classes were then summed to show final residential and commercial technical potential for the state of Utah, as shown in Table 5-5. Table 5-5. Utah PV Technical Potential 2103 Utah Customer Class (Rate Schedule) System Number of Customers Potential per Residential 137 274 38 1580 Irrigation (10) 33.9 2784 94 Small Commercial (23) 3.4 82668 282 89.4 13072 1169 2.8 740189 2096 2100 Page 5-6 5.1.1.4 Small Wind For small wind, NREL publishes wind data in GIS format47. An example wind resource map is shown in Figure 5-1. Using PacifiCorp GIS service territory data, we excluded areas in each state outside of its service territory, and then proportionally determined the area within the territory that was Class 4 and above (i.e. the non-green area Figure 5-1 divided by total service area). Figure 5-1. US Wind Resource Map These proportions were multiplied by (the customer peak load) times (number of customers) to determine the technical potential for small wind within PacifiCorp’s service territory. A summary of the results is shown in Table 5-6. 47 http://www.nrel.gov/gis/data_wind.html Page 5-7 Table 5-6. Small Wind Technical Potential Results State % Class 4+ in service 48 Residential Commercial 5% .8 3.9 5.4% 10 6 8.4% 19 62 16% 48 116 8.4% 5 15 50.7% 62 139 Wyoming has the highest technical potential due to its very high wind; Utah is next because a large number of customers within Utah are PacifiCorp customers and it has relatively higher wind resources. 5.1.1.5 Technical Potential Over Time The previous subsections show how Navigant calculated technical potential in 2013. To project how technical potential will change over time (because of either more customers or larger loads per customer), Navigant escalated technical potentials at the same rate PacifiCorp projects its load will change over time. PacifiCorp provided Navigant with its load forecast through 2034. 5.1.2 Simple Payback For each customer class (rate schedule), technology, and state, Navigant calculates simple payback period using the following formula: Simple Payback Period = (Net Initial Costs)/(Net Annual Savings) Net Initial Costs = Installed Cost – Federal Incentives – Capacity Based Incentives*(1 – Tax Rate) Net Annual Savings = Annual Energy Bills Savings + (Performance Based Incentives – O&M Costs – Fuel Costs)*(1 – Tax Rate) • Federal tax credits can be taken against a system’s full value if other (i.e. utility or state supplied) capacity based or performance based incentives are considered taxable. • Navigant’s Market Penetration model calculates first year simple payback assuming new installations for each year of analysis. • For electric bills savings, Navigant conducted an 8760 hourly analysis to take into account actual rate schedules, actual output profiles, and demand charges. CHP performance and hydro performance assumptions are listed in the relevant performance / cost assumptions in section 3. PV performance and wind performance profiles were calculated for representative locations 48 The wind data this table is based on was last updated June 2012 Page 5-8 within each state based on the solar advisory model (which now also models wind). Building load profiles were provided by PacifiCorp, and were scaled to match the average electricity usage for each class based on billing data. • For thermal savings (if a CHP technology is chosen), the model examines at annual space heating loads and assume most of that is offset by CHP. Tax rates used are listed in Table 5-7. We used a tax calculator to estimate federal tax rates for median household incomes, and added this to state sales taxes and state income taxes to estimate a residential household tax rate for each state. Table 5-7. Residential Tax Rates Median Household Income ($$)49 Income Tax Rate as % of 50 2013 State Sales Tax51 State Income Tax52 2013 Residential Tax Rate $49,161 7% 0% 8% 14.7% $54,901 8% 4% 0% 11.8% To estimate commercial taxes, we added federal corporate taxes of 35% to state sales taxes, as shown in Table 5-8. Table 5-8. Commercial Tax Rate 2013 State Sales Tax Corporate Commercial 35% 6% 41% 7% 42% 49 http://www.deptofnumbers.com/income/. Latest available data is for 2012 50 www.calcxml.com 51 http://www.taxrates.com/state-rates 52 http://www.tax-rates.org/taxtables/income-tax-by-state Page 5-9 5.1.3 Payback Acceptance Curves For distributed resources, Navigant used the following payback acceptance curves to model market penetration of DG sources from the retail customer perspective: Figure 5-2. Payback Acceptance Curves These payback curves are based upon work for various utilities, federal government organizations, and state local organizations. They were developed from customer surveys, mining of historical program data, and industry interviews. Given a calculated payback, the curve predicts what ultimate level of market penetration of the technical potential is likely. For example, if the technical potential is 100MW, a 3 year commercial payback predicts that 15% of this, or 15MW, will be ultimately achieved over the long term. 5.1.4 Market Penetration Curves To determine the future DG market penetration within PacifiCorp’s territory, the team modeled the growth of DG technologies between now and 2034 for the IRP. The model is a Fisher-Pry-based technology adoption model that calculates the market growth of DG technologies. It uses a lowest-cost approach (to consumers) to develop expected market growth curves based on maximum achievable market penetration and market saturation time, as defined below.53 53 Michelfelder and Morrin, “Overview of New Product Diffusion Sales Forecasting Models” provides a summary of product diffusion models, including Fisher-Pry. Available: law.unh.edu/assets/images/uploads/pages/ipmanagement-new-product-diffusion-sales-forecasting-models.pdf 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0 2 4 6 8 10 12 14 Ul t i m a t e P e n e t r a t i o n [ % ] Payback Period (Years) Residential Commercial Industrial to unwillingness to change, mistrust of a new technology, incompatible building designs, etc. This is based upon Page 5-10 • Market Penetration – The percentage of a market that purchases or adopts a specific product or technology. The Fisher-Pry model estimates the achievable market penetration based on the simple payback period of the technology (per the curve show in Figure 5-2) • Market Saturation Time – The duration (in years) for a technology to increase market penetration from 10% to 90%. The Fisher-Pry model estimates market saturation time based on 12 different market input factors; those with the most substantial impact include: • Payback Period – Years required for the cumulative cost savings to equal or surpass the incremental first cost of equipment. • Market Risk – Risk associated with uncertainty and instability in the marketplace, which can be due to uncertainty over costs, industry viability, or even customer awareness, confidence, or brand reputation. An example of a high market risk environment is a jurisdiction lacking long- term, stable guarantees for incentives. • Technology Risk – Measures how well-proven and readily available the technology is. For example, technologies that are completely new to the industry are higher risk, whereas technologies that are only new to a specific market (or application) and have been proven elsewhere would be lower risk. • Government Regulation – Measure of government involvement in the market. A government stated goal is an example of low government involvement, whereas a government mandated minimum efficiency requirement is an example of high involvement, having a significant impact on the market. The model uses these factors to determine market growth instead of relying on individual assumptions about annual market growth for each technology or various supply and/or demand curves that may sometimes be used in market penetration modeling. With this approach, the model does not account for other more qualitative limiting market factors, such as the ability to train quality installers or manufacture equipment at a sufficient rate to meet the growth rates. Corporate sustainability, and other non-economic growth factors, are also not modeled. The model is an imitative model that uses equations developed from historical penetration rates of real products for over two decades. It has been validated in this industry via comparison to historical data for solar photovoltaics, a key focus of the study. The Fisher-Pry market growth curves have been developed and refined over time based on empirical adoption data for a wide range of technologies. Some of the original technologies used to develop the Fisher-Pry model include: water-based versus oil-based paints, plastic versus metal in cars, synthetic rubber for natural rubber, organic versus inorganic insecticides, and jet-engine aircraft for piston-engine aircraft.54 Figure 5-3 shows four example market growth curves from the model, each with different market saturation times (5, 10, 15, & 20 years) and increasing achievable market penetration. Although increased market penetration (reduced payback period) can go hand-in-hand with reduced saturation time, these plots are intended to illustrate that to reach near-term 54 Fisher, J. C. and R. H. Pry, "A Simple Substitution Model of Technological Change", Technological Forecasting and Social Change, 3 (March 1971), 75-88. Page 5-11 goals, reducing market saturation time is more important than maximizing the long-term achievable market penetration. However, with increased long-term maximum achievable penetration, it may be possible to achieve the same near-term market growth goals with a longer (and less burdensome) market saturation time. Figure 5-3. Fisher-Pry Market Penetration Dynamics The market penetration curves used in this study, Navigant assumed that the first year introduction occurred when the simple payback period was less than 25 years (per the payback acceptance curves used, this is the highest payback period that has any adoption. When the above payback period, market risk, technology risk, and government regulation factors above are analyzed, our general Fisher-Pry based method gives rise to the following market penetration curves used in this study: Page 5-12 Figure 5-4. DG Market Penetration Curves Used The model is designed to analyze the adoption of a single technology entering a market, and we assume that the DG market penetration analyzed for each technology is additive because the underlying resources limiting installations (sun, wind, hydro, high thermal loads) are generally mutually exclusive (wind tends to blow harder at night when the sun is not available, etc.), and because current levels of market penetration are relatively low—there are plenty of customers available for each technology. For future IRP efforts when market penetrations are higher, we recommend increasing accuracy by ratio-ing competing technologies by payback period to ensure no double-counting. Page 5-13 5.1.5 Scenarios Navigant analyzed three DG scenarios with its market penetration model, to capture the impact of major changes that could affect market penetration. For the low and high penetration cases, we varied technology costs, performance, and electricity rate assumptions per Table 5-9: Table 5-9. Scenario Variable Modifications Technology Costs Performance Electricity Rates Base Case • See section 3. • As modeled • Inflation rate per IRP Low DG Penetration • Hydro (mature): 0% • PV: 10% lower cost reduction/year • Other: 5% lower • 5% worse • -.5%/year, relative to the base case High DG Penetration • Hydro (mature): 2% cost reduction/year • PV: 10% steeper cost reduction/year • Other: 5% steeper cost reduction/year • Reciprocating Engines: 0% better (mature) • Micro-turbines: 2% better • Hydro: 5% better (reflecting wide performance distribution uncertainty) • PV/Wind: 1% better • +.5%/year, relative to the base case The primary driving variable is the amount of cost reduction expected over the next 20 years. Average technology performance assumptions are relatively constant, with a higher variability for hydro as project output is more variable and site specific. Finally, electricity rate changes are modeled in a relatively conservative band, reflecting the long-term stability of electricity rates in the United States. Note that these are all changes to the averages over 20 years, and we expect higher one- year or short term volatility on all of these variables, both up and down. However, when averaged over a long period of time for the 20-year IRP period, long-term trends show this level of variation. Page 6-1 6. Results 6.1 Technical Potential While technical potential results have been shared for most technologies in the last section, these are summarized by the following graph: Figure 6-1. Technical Potential Results As can be seen, the PV (both commercial and residential) technical potential is the highest of all the DG technologies evaluated. Total technical potential is ~10 GW, roughly equivalent to PacifiCorp’s peak summer loads. As indicated in the technical barriers section, it may be difficult for PacifiCorp to incorporate total levels of PV (both DG and large-scale fields) beyond 20-33% without economical energy storage. Page 6-2 6.2 Overall Scenario Results As shown in Figure 6-2, the near-term ten-year outlook is ~50 MW until 2021, when cost reduction and continued UT/OR incentives significantly improves payback and PV uptake increases dramatically, reaching 900 MW by 2034, the end of the IRP period. Figure 6-2. Base Case Results In the low penetration scenario, lower cost reduction than expected results in less short term market penetration, ~ 30 MW; the knee of the higher uptake curve is delayed until 2029 relative to the base case. Over the entire period, penetration is 275 MW by 2034, 60% lower than the base case. Page 6-3 Figure 6-3. Low Penetration Scenario Results Conversely, in the high penetration scenario, lower costs than expected over the long-term combined with continued UT incentives have the potential to increase DG penetration by 2034 to 2.6 GW from a customer economics perspective. 0 50 100 150 200 250 300 350 2013 2018 2023 2028 2033 Cu m u l a t i v e M a r k e t P r o j e c t i o n (M W ) PacifiCorp Distributed Generation Low Penetration Case Wind - Res Wind - Comm PV - Residential PV - Commercial Hydro CHP Micro Turbines CHP Recip Turbines • -.5% annual electricity rate escalation • Technology Costs 10% higher • 1% typical worse performance Page 6-4 Figure 6-4. High Penetration Scenario Results 0 500 1000 1500 2000 2500 3000 2013 2018 2023 2028 2033 Cu m u l a t i v e Ma r k e t P r o j e c t i o n (M W ) PacifiCorp Distributed Generation High Penetration Case Wind - Res Wind - Comm PV - Residential PV - Commercial Hydro CHP Micro Turbines CHP Recip Turbines • +.5% electricity rate escalation • Technology Costs 10% lower • 1% typical better performance Page 6-5 6.3 Results by State In this section, we present the results of the base case state by state: In Utah, assumed continued PV state incentives and continuing cost reductions spur the PV market, especially after medium term year 2021, and penetration is projected to increase to ~750 MW in the base case by 2034. Figure 6-5. Utah Base Case Results To illustrate the underlying drivers for this Utah result, which is large proportion of DG penetration for PacifiCorp overall, let us examine a bit more closely the cases of Residential PV and small commercial PV customers in Utah. Plotted in the figure below are the residential installation costs minus incentives – the out of pocket installation cost -- against the annual electric energy savings for Utah residential PV customers. On a secondary axis to the right, the payback period is also shown. The out of pocket installation costs drop in the next few years due to cost reduction, shoot back up in 2017 with the expiration of federal incentives, and continue coming down due to assumed cost reductions over time. The annual electric Page 6-6 savings increase gently due to modest performance improvements and load growth55. The payback period starts at 14 years in 2013, drops to 11 years by 2016, shoots back up to 14 years in 2017, and then, in year 2021, crosses the 10-year mark. At this point, penetration starts to increase (see lower graph). Even though the absolute levels of penetration are low (see Figure 5-2 for the payback curve), sizable market penetration in MW occurs because the residential market in Utah is relatively large. The small commercial PV market in Utah is similar, except that significant periods of <10 year paybacks occur much later (a blip in 2016, and then 2028+), and the overall market potential is much smaller. 55 Note, the calculations are assumed future average retail electricity rates, not variable costs which a customer can avoid. Page 6-7 Figure 6-6. Utah Residential PV Market Drivers Page 6-8 Figure 6-7. Utah Small Commercial PV Market Drivers Page 6-9 Figure 6-8. Utah Near-Term PV Projections If we zoom in a little and examine only the near-term and PV-only in Utah, as shown in Figure 6-8, the consumer economic model is projecting that the commercial portion of PacifiCorp’s PV Incentive program may not have a high enough incentive level to achieve 60 MW of PV penetration by 2017, but that residential installations, while capped at .5 MW annually in the incentive program, will partially compensate56. Note, as well, that commercial installations can be higher than projected due to corporate sustainability initiatives that are not captured in our economic model. For example, a single IKEA project last year in Utah of 1.5 MW quadrupled the total amount of commercial PV installations in Utah. Also, in 2016, we assume that the 30% federal Investment Tax Incentive will expire to 10%, leading to relatively flat installations for a few years until further cost reduction can compensate. The current program, as structured, does not compensate for this 20% projected increase in costs. 56 Note, there is a 12-18 month delay between program permit acceptance and actual installation that was factored in to our calculations of this incentive Page 6-10 In California, with much higher electricity rates and a small PacifiCorp rebate program, grid parity is closer than in other PacifiCorp states and payback periods are lower. However, overall penetration is limited because CA is a very low (>5%) proportion of PacifiCorp revenue. Residential penetration dominates, but at an overall lower level than in Utah. Figure 6-9. California Base Case Results Page 6-11 In Idaho, there is much larger commercial electricity use in PacifiCorp’s territory than residential. Accordingly, commercial PV is dominant, once PV prices reduce enough to achieve significant market penetration. Incentives are lower, so this transition occurs somewhat later than in other states, around 2023. Figure 6-10. Idaho Base Case Results Oregon has a much larger small hydro technical potential than other states, and achieves some hydro penetration. Wind and PV incentives, and good wind availability, spur penetration of these sources. Overall, penetration is lower than in Utah due to longer payback periods. Page 6-12 Figure 6-11. Oregon Base Case Results Page 6-13 Washington, with a relatively small PacifiCorp area, and rates that are somewhat lower, is projected to achieve up to 10 MW by 2034 in the base case. Figure 6-12. Washington Base Case Results Page 6-14 Wyoming is projected to achieve ~ 37 MW by 2034: Figure 6-13. Wyoming Base Case Results Page 6-15 6.4 Results by Technology Each technology is shown in turn. Non-construction and non-standby power reciprocating engines will mostly occur in OR, CA, ID, and UT. Negligible penetration is projected for WY and WA57. Figure 6-14. Reciprocating Engines Base Case Results 57 Hence these are not showing as series in Figure 36. Page 6-16 As a relatively more expensive cousin of reciprocating engines, lower levels of penetration are projected in fewer states. Installations are projected to occur primarily in CA, ID, and OR. Figure 6-15. Micro-turbines Base Case Results Page 6-17 Small levels of small hydro penetration are likely to occur in some states -- WY, WA, UT, and OR. WA, and UT have higher technical potential, leading to slightly more penetration; Oregon, with the highest technical potential, achieves ~5 MW of penetration when current incentives expire in 2017, with little penetration thereafter. Figure 6-16. Small Hydro Base Case Results Page 6-18 Due to higher residential electricity rates, and therefore lower payback periods, residential installations dominate PV projections, especially after 2022. Figure 6-17. Photovoltaics Base Case Results Page 6-19 As shown below and in the Utah results above, most of this dramatic residential growth after 2022 is projected to occur in Utah, with continued incentives and continued cost reduction lowering payback residential payback periods. Figure 6-18. Photovoltaics Residential Base Case Results Page 6-20 Commercial PV projections are much lower. Utah dominates due to higher incentives and its relatively large proportion of technical potential. Figure 6-19. Photovoltaic Commercial Base Case Results Page 6-21 Residential small wind installations are projected to be more economic than commercial: Figure 6-20. Small Wind Base Case Results Page 6-22 These are dominated by Oregon market penetration, which occurs largely due to an incentive that is projected to phase out by 2021. Figure 6-21. Small Wind Residential Results Page 6-23 Commercial small scale wind is projected to be much smaller, with long payback periods: Figure 6-22. Small Wind Commercial Results Page A-1 Appendix A. Glossary $/WpDC -- $/ peak watt DC. Solar modules produce DC power which is then converted to AC by an inverter CHP – Combined Heat and Power DG - Distributed Generation – electricity sources that are purchased by the consumer HAWT – Horizontal-axis wind turbine IRP – Integrated Resource Plan ITC – Investment Tax Credit LCOE – Levelized Cost of Energy, a measure of the cost of electricity in $/kWh MW – Mega-watt, a measure of power Net Meter – a regulation which allows the customer to feed excess power generated back into the grid O&M – Operations and Maintenance costs PV – Photovoltaic, or Solar, or Solar Electric (used interchangeably). A technology that generates electricity when a module is exposed to sunlight. PV Array – multiple PV modules grouped together to generate power PV Module – a 1-2 m2 solar component that can be readily handled by 1-2 people which generates DC electricity (like a battery) SWT – Small Wind Turbine Solar Electric – Photovoltaic Solar Thermal – an alternative PV technology which concentrates solar energy to raise the temperature of a heat transfer fluid VAWT – Vertical-axis wind turbine Page B-2 Appendix B. Summary Table of Results Base Case (MW Projected) 2015 2020 2025 2030 CA 9.8 11.4 21.5 36.3 ID 0.4 1.8 7.9 16.0 OR 5.3 15.5 24.0 36.7 UT 9.9 24.7 239.3 513.4 WA 0.1 0.4 2.6 6.1 WY 0.2 0.9 5.6 11.1 PACIFICORP – 2015 IRP APPENDIX P – ANAEROBIC DIGESTERS STUDY 495 APPENDIX P – ANAEROBIC DIGESTERS RESOURCE ASSESSMENT STUDY Introduction Harris Group Incorporated was engaged by PacifiCorp to assess the magnitude of the potential electrical power generation from dairy waste in the State of Washington. The purpose of the assessment is to evaluate the potential for inclusion of the dairy resource in PacifiCorp’s 2015 Integrated Resource Plan. PACIFICORP – 2015 IRP APPENDIX P – ANAEROBIC DIGESTERS STUDY 496 Anaerobic Digesters Resource Assessment for PacifiCorp Washington Service Territory Prepared for HARRIS GROUP INC. Report 80306 June 26, 2014 ANAEROBIC DIGESTERS RESOURCE ASSESSMENT PACIFICORP WASHINGTON SERVICE TERRITORY Table of Contents SECTION 1 – EXECUTIVE SUMMARY..................................................................................... 1 Introduction ................................................................................................................................. 1 Resource Assessment Overview ................................................................................................. 1 PacifiCorp Service Territory ....................................................................................................... 2 Washington Dairy Background .................................................................................................. 3 Observations and Conclusions .................................................................................................... 5 Section 2 – Digester Technology ............................................................................................ 5 Section 3 – Power Production Estimate .................................................................................. 5 Section 4 – Environmental and Regulatory ............................................................................ 6 Section 5 – Development Cost ................................................................................................ 6 Section 6 – Operating Costs .................................................................................................... 6 SECTION 2 – DIGESTER TECHNOLOGY ................................................................................. 7 Dairy Based Digester Design ...................................................................................................... 7 Manure Management .................................................................................................................. 9 Biogas Production ....................................................................................................................... 9 Biogas Conditioning ................................................................................................................. 10 Electrical Power Generation ..................................................................................................... 11 Engines and Prime Movers ................................................................................................... 11 Heat Recovery Systems ........................................................................................................ 11 Generators ............................................................................................................................. 11 Manure Effluent Management .................................................................................................. 11 Emission Control Systems ........................................................................................................ 12 SECTION 3 – POWER PRODUCTION ESTIMATE ................................................................. 13 Quantifying Energy Potential from Dairies in PacifiCorp’s WA State Territory ..................... 13 Required Parameters for Quantifying Energy Potential ........................................................... 13 Methodology ............................................................................................................................. 14 Results ....................................................................................................................................... 20 SECTION 4 – ENVIRONMENTAL AND REGULATORY ...................................................... 23 WA Solid Waste Permitting ..................................................................................................... 23 WA Water Permitting ............................................................................................................... 23 WA Air Permitting .................................................................................................................... 23 Local Jurisdiction Permitting .................................................................................................... 23 REC Qualification ..................................................................................................................... 24 Other Investment Incentives ..................................................................................................... 24 Greenhouse Gas Reduction ....................................................................................................... 25 SECTION 5 – DEVELOPMENT COST ...................................................................................... 27 ANAEROBIC DIGESTERS RESOURCE ASSESSMENT PACIFICORP WASHINGTON SERVICE TERRITORY Table of Contents (continued) ii Completed Major Equipment Revisions ................................................................................... 27 SECTION 6 – OPERATING COSTS .......................................................................................... 29 Addition of Other Organic Wastes ........................................................................................... 29 George DeRuyter & Sons Dairy ............................................................................................... 30 APPENDIX 1 ................................................................................................................................ 31 1 SECTION 1 – EXECUTIVE SUMMARY Harris Group Incorporated (“HGI”) has been engaged by PacifiCorp to assess the magnitude of the potential electrical power generation from dairy waste in the State of Washington. The purpose of the assessment is to evaluate the potential for inclusion of the dairy resource in PacifiCorp’s 2015 Integrated Resource Plan (“IRP”). Introduction The 2013 IRP Acknowledgment Letter issued by the Washington Public Utilities Commission requested an analysis of the potential within PacifiCorp’s service territory for anaerobic digesters to provide power generation resources to be included in the IRP. In this study HGI has included a technical analysis of the potential generation capacity based on a thorough review of the available information on the numbers and sizes of dairies within the PacifiCorp service territory. In addition, HGI has provided an analysis of the Renewable Energy Credit (“REC”) registration potential, greenhouse gas reduction potential, environmental permitting summary, capital investment estimate, and operating cost estimate. Other applications of anaerobic digestion that may exist within PacifiCorp’s service territory are beyond the scope of this report. Those other applications are not as readily identifiable or as concentrated as the dairy resources in the Yakima Valley. Other sources of organic feed are also not considered in this assessment due to their diverse nature, additional environmental permitting, and cost associated with the transportation over a large geographic area. Harris Group and professionals within HGI have significant experience in the development of anaerobic digester (“AD”) projects utilizing dairy manure as the primary substrate for biogas production. HGI has developed expertise in the following AD project related activities. Resource Assessment Overview  Biogas Plant Process Design;  Project Permitting;  Detailed Plant Design;  Power Generation and Interconnection;  Power Purchase Agreements;  Biogas Conditioning Process Design;  Natural Gas Compression and Metering;  Natural Gas Purchase Agreements;  Resource Evaluation, and  Plant Operations. Harris Group has combined our own experience in the development of biogas projects with a thorough literature search that included collecting available data on farm locations and sizes from the State of Washington Departments of Agriculture and Ecology. Based on the available farm information HGI determined the numbers of farms that are located within PacifiCorp’s SECTION 1 EXECUTIVE SUMMARY 2 service territory and began the process of evaluation of those resources and the potential to generate electrical power to satisfy power demand requirements in the service territory. PacifiCorp has service areas in the State of Washington that encompass a large concentration of dairies in the Yakima River Valley in Yakima County. A few of the dairies are located near the service territory in Benton County. PacifiCorp has additional service territories in the far southeast parts of the state that encompasses parts of Walla Walla, Columbia, and Garfield Counties. The State of Washington does not report any significant dairy operations in those counties. This report focuses on the dairies in Yakima County. PacifiCorp Service Territory Figure 1-1 shows the locations of dairies in the State of Washington. Figure 1-2 shows the locations of dairies within PacifiCorp’s service territories. Figure 1-1: State of Washington Dairies SECTION 1 EXECUTIVE SUMMARY 3 Figure 1-2: Dairies within the PacifiCorp Service Territory The Washington State Department of Agriculture (“WSDA”) published a report in October 2011 that described the state of the dairy industry and a summary of dairy based digesters. Washington Dairy Background 1 The report states that based on the 2010 registration data for WSDA Nutrient Management plans there are 443 commercial dairies in the State. Figure 1-3 taken from the report shows the size distribution of dairies based on the US EPA size categories developed under the Concentrated Animal Feeding Operation (“CAFO”) rules. 1 WSDA Publication AGR PUB 602-343 (N/10/11) “Washington Dairies and Digesters” SECTION 1 EXECUTIVE SUMMARY 4 Figure 1-3: Diary Size Distribution in Washington Milk is Washington’s second most valuable agricultural commodity behind apples and ranks Washington as the 10th largest dairy producing state in the US. The report states that the trend in the US in all dairy producing states is towards consolidation into larger and larger farms that develop significant economies of scale to better manage production costs but at the same time concentrates animal wastes in smaller areas. Whatcom County is listed as home to the most dairies while Yakima County is home to largest number of dairy cows indicating a smaller number of larger farms. The primary focus of this report is the two size ranges of farms shown as 700-2499 cows and greater than 2500 cows. These farms represent the portion of the dairy industry in Washington potentially capable of supporting AD development projects. The total represents approximately 24 percent of the dairies in Washington. There are currently 10 different digesters in commercial operation in Washington all producing power that range in generator capacity from 400 to 1200 kW. The largest digester is operating in Yakima County at the George DeRuyter & Sons Dairy supplying 1200 kW of power to PacifiCorp. It is reported that all of the digesters operating in Washington add varying amounts of other organic material to the digesters to provide additional biogas for fuel. The State of Washington has enacted specific environmental regulations that allow the digesters to receive pre-consumer organic waste-derived materials under certain conditions without the need for obtaining a solid waste permit. The conditions require that no more than 30 percent of the feed material can come from organic wastes and the digester designs and operations must meet federal standards defined in the USDA Natural Resources Conservation Service Practice Standard 366, Anaerobic Digester. The majority of the digesters in Washington utilize digester technology provided by GHD, Inc, now operating as DVO, Inc. SECTION 1 EXECUTIVE SUMMARY 5 The principal observations and opinions that we have reached during our assessment of digestion based power resources in Washington are set forth below. Observations and Conclusions Section 2 – Digester Technology 1. The use of anaerobic digesters as a combination of waste management and a source of renewable energy is a well developed technology. There has been significant growth in the use of digesters that utilize dairy waste as a feed material in the US over the last 20 years. 2. There are numerous federal and state programs that support the assessment and development of the technology. The State of Washington has a well developed regulatory and acceptance program. 3. There are four primary digester technologies in use in agricultural use. • Covered anaerobic lagoons • Fixed-film digester • Complete-mix digester • Plug flow digester 4. The plug flow technology is the predominant technology in use around the US and Washington. 5. The production of biogas is straight forward and the use of biogas as a fuel in reciprocating engines for power production does not pose a significant risk to resource development. Interconnection of those resources to the power grid can be completed without significant technical risk. There may be specific project locations or project capacities where system upgrades may be required. Section 3 – Power Production Estimate 1. Power estimates have been made using accepted protocols that have been applied to an inventory of resources provided by the State of Washington. 2. The only dairy resources in Washington that are in the service territory maintained by PacifiCorp are in Yakima County. There may be a few dairies in Benton County near the service territory that could be considered. 3. If all of the dairies in Yakima County installed anaerobic digesters, the total installed power would range from approximately 16.0 MW to 26.6 MW. The annual energy production would range from approximately 129 GWh/yr to 214 GWh/yr and would avoid 310,000 to 514,000 tonnes of CO2e emissions per year. 4. If the size of the AD systems was limited to 500 kW and larger, there are 11 potential projects that would total approximately 10.2 MW and produce approximately 82 GWh/yr and would avoid approximately 197,000 tonnes of CO2e emissions per year. SECTION 1 EXECUTIVE SUMMARY 6 Section 4 – Environmental and Regulatory 1. The State of Washington has a well developed and straight forward permit program that specifically addresses anaerobic digester development. 2. With the passage of Initiative 937 in 2006 the State of Washington passed a renewable energy standard that applies to PacifiCorp. The Renewable Portfolio Standard calls for electric utilities that serve more than 25,000 customers to obtain 15 percent of their power from renewable sources by the year 2020. Between January 1, 2012 through December 31, 2015 at least 3 percent of PacifiCorp’s load must be supplied by renewable sources. For the period January 1, 2016 through December 31, 2019 the percentage increases to 9 percent. The increase to 15 percent must be met by January 1, 2020. 3. All of the generation that could be produced from AD projects with dairies in the Yakima County service territory would generate REC’s that could be registered and traded. 4. REC’s can be registered with WREGIS and traded within the WECC states. It is beyond the scope of this assessment to establish the market value of REC’s traded within the region. Section 5 – Development Cost 1. Development or capital costs for development of the resources are based on data provided by the US EPA AgStar Program. 2. The total capital investment estimate that would be required to develop 100 percent of the resources would be approximately $91MM. It is not practical to assume that all projects rise to the level of investment quality. May of the smaller farms would not be practical. 3. Another way to consider the investment is to assume a unit cost per kilowatt of installed capacity to be $3000 to $3500. This figure would be applicable to systems from 500 kW to the maximum size project available in the county. This figure is consistent with Harris Group’s experience with similar projects. Section 6 – Operating Costs 1. Based on the data from the Natural Resources Conservation Service analysis and assuming a plug flow digester design it is estimated that the total operating costs for electrical production are $0.09/kWh. The cost analysis is based on the operating results of nine different projects. 2. The development of AD projects on farms that depend solely on electrical revenue for profitability is not currently economically attractive in an area like Yakima County where wholesale rates for power are relatively low compared to other parts of the country. Projects that meet the requirements of a Qualifying Facility in accordance with the Washington Schedule 37 rates would also not be currently economically attractive based on the value of the power production alone. Projects must include the production and sale of other marketable by products such as compost to reduce the reliance on electrical revenues alone to develop successful projects. Projects must also monetize the value of REC’s and Carbon Credits. 7 SECTION 2 – DIGESTER TECHNOLOGY Large-scale anaerobic digesters in use on dairy farms in the USA fall into four classifications or types of digesters: Dairy Based Digester Design  Covered anaerobic lagoons with a hydraulic retention time (HRT) of 35 to 60 days. Ponds operate at ambient conditions, so gas yield is reduced in cool seasons (methane production is severely limited in cold climates). Variations incorporating sludge recycling or distributed inflow are referred to as enhanced covered anaerobic ponds.  Fixed-film digester, usually heated, containing media that increase the surface area available for bacteria to adhere to, thus preventing washout. As more than 90 percent of the bacteria are attached to the media, an HRT of days, rather than weeks, is possible. Separation of fixed solids by settling and screening is necessary to prevent fouling.  Complete-mix digester sometimes referred to as a continuously stirred tank reactor; usually a circular tank with mixing to prevent solids settling and to maintain contact between bacteria and organic matter. Mixing also maintains a uniform distribution of supplied heat.  Plug flow digester, usually a long concrete tank where manure with as-excreted consistency is loaded at one end and flows in a plug to the other end. The digester is heated. Although it can have locally mixed zones, it is not mixed longitudinally. The determination of which digestion technologies are appropriate for a given project depend on the project specific conditions. The majority of the digesters in use in Washington are of the modified plug flow type which includes mixing zones and the introduction of other organic wastes. Figure 2-1 shows typical process flow diagram provided by the US EPA AgStar Program. The flow diagram is a good representation of the digestion process and includes other uses for energy and byproducts from the AD process. SECTION 2 DIGESTER TECHNOLOGY 8 Figure 2-1: Process Flow Diagram Figure 2-2 shows the relative distribution of digester types in use in the US. The mixed plug flow digester is the predominant technology. The two primary reasons for the popularity of the mixed plug flow digesters are lower capital costs and relative ease of operation. All of the digester technologies would produce a comparable quantity and quality of biogas fuel for generation. SECTION 2 DIGESTER TECHNOLOGY 9 Figure 2-2: Distribution of AD Technology in the US Manure management practices have an impact on the cost of AD. Dairies use a variety of manure collection and storage methods. The herd management practices also have an impact on the quality and quantity of manure collected and processed. Lactating dairy herd management practices can be classified by two different housing methods. Manure Management  Dry Lot – Animals are allowed to loaf in large pens where manure is dropped over a large area and mixed with significant quantities of inert material.  Free Stall – Animals are confined in free stall barns where manure drops in concrete lanes and is scraped or flushed to collection with small amounts of additional inert material. Larger dairies also manage replacement herds and depending on the dairy the manure may be collected and included with the lactating herd waste of managed separately through composting. Flush dairies flush the feeding lanes with large quantities of water which dilutes the manure and adds significant volumes of water to the waste necessitating the use of larger digester systems. In all cases the amount and quality of manure collected will vary from dairy to dairy dictating the choice of digestion technology, digester capacity, pre treatment and concentration of manure streams, and sand and grit removal. Typical manure digester projects utilize a digester residence time of 20 to 30 days. Each day the manure output from the dairy is fed to the digester and an equal volume of digested manure is discharged for storage and eventual disposal. Many projects also separate the cellulosic fiber and compost that material for sale as a soil amendment or utilize the digested solids as bedding Biogas Production SECTION 2 DIGESTER TECHNOLOGY 10 in the barns. In any case the liquid fraction that contains the majority of the nutrients must be discharged. The predominant disposal practice in the US and other parts of the world is land application as fertilizer to cropland. The biogas production is a biological process whereby complex organic compounds are degraded in two steps by two classes of microorganisms in the digester. In the first step, acidifying bacteria hydrolyze the organic compound into organic acids. In the second step, methanogenic bacteria convert the organic acids into methane and carbon dioxide. A typical composition of biogas from all sources is shown below. The range of methane content for biogas derived from manure is typically 60 to 65 percent with the carbon dioxide at 35 to 40 percent. The biogas production is not technology driven. The same total amount of biogas can be produced from any of the digester technologies. There are differences in the rate at which the gas is produced which drives some of the technology decisions. For purposes of this report we assume that regardless of the technology utilized, all of the farms in the Yakima River Valley would produce gas at the maximum potential based solely on the number of animals. This is an appropriate way to consider the maximum electrical potential in the PacifiCorp service territory. The limiting factor would be the actual size of the dairy. Smaller dairies may not have the capital resources to support the high costs to install the gas production and power generation equipment. Based on the composition above the biogas should be conditioned prior to use as a combustion fuel to remove the hydrogen sulfide (H2S). There are a number of cost effective technologies available to remove the H2S. Biogas Conditioning  Iron Sponge  Chemical/Biological External Scrubbers  Internal Biological Removal in the Digester In all cases it is desirable to remove the H2S prior to combustion to reduce the sulfur dioxide emissions in the exhaust and to reduce corrosion in the exhaust components of the engine. SECTION 2 DIGESTER TECHNOLOGY 11 Systems that generate electricity from biogas consist of: Electrical Power Generation  an internal combustion engine (compression or spark ignition) or a micro-turbine,  an optional heat recovery system,  generator, and  control system. Engines and Prime Movers In Europe it is a popular option to utilize compression ignition (converted diesel) internal combustion engines. Compression engines are also known as dual-fuel engines. A small amount of diesel (10%–20% of the amount needed for diesel operation alone) is mixed with the biogas before combustion. Dual-fuel engines offer an advantage during start-up and downtime as they can run on anywhere from 0 percent to 85 percent biogas. The majority of the projects in the US utilize spark-ignition internal combustion engines. All of the major gas engine manufacturers supply standard engines rated for use with biogas as the fuel. Typical heat rates for these types of reciprocating engines range from 9,000 to 10,000 Btu/kWh. The online capacity factor for these engines can average 95 percent due to their inherent reliability provided adequate service and maintenance procedures are implemented. Microturbines are not favored for use with raw biogas due to the dirty composition of the fuel which leads to reliability problems. Larger gas turbines are typically much larger than needed for biogas projects except for those projects that would produce in excess of 5 MW per project. One of the advantages that gas turbines have is a lower NOx emission profile. For engines that utilize lean burn control technology the NOx emission rate would range from 0.6 to 1.1 g/bhp-hr. Heat Recovery Systems Commercially available heat exchangers can recover heat from the engine water cooling system and exhaust. Typically, heat exchangers will recover around 0.8 kWh of heat per kWh of electrical output from the engine jacket and 0.75 kWh from the exhaust, increasing total (electrical plus thermal) energy efficiency to 65 to 80 percent. The heat is generally used for maintaining the digester temperatures, building heat, and in some cases providing refrigeration for milk cooling. Generators Generators typically run in parallel with the utility interconnection and export power in synchronization with the grid. The engine/generator sets are supplied by competent well known manufacturers that package complete systems with reliable controls to manage the power export to the interconnection and grid. Digested manure can be further processed to separate fibrous solids for compost or animal bedding. Separation also impacts the distribution of nutrients that must be managed under Manure Effluent Management SECTION 2 DIGESTER TECHNOLOGY 12 Nutrient Management Plans (“NMP”). Phosphorus will be largely distributed in the separated solids while nitrogen will be largely distributed in the liquid. The NMP is a management system that limits the amount of nutrient that can be applied to crop land to that fraction that can be utilized by growing crops. The limits are established to control excess nutrients that migrate to surface water and ground water systems. Digested manure reduces the organic fraction of those nutrients that are not in a form that can be utilized by crops in the current application year. The inorganic forms of nutrients in digested manure is more likely to be utilized by growing crops at the time of application and not accumulate and contaminate water sources. Ultimately manure whether it’s digested or not is land applied for disposal. Typical air emission controls include flares for excess biogas and engines that utilize lean burn carburetion for NOx and CO control. Permitting for these emissions is a relatively straight forward process with low risk for negative outcomes. Emission Control Systems 13 SECTION 3 – POWER PRODUCTION ESTIMATE There are numerous anaerobic digestion (“AD”) technologies available, and each technology provider has its own proprietary calculation to determine the potential energy production from a given mass of manure. In order to avoid publishing proprietary data, a method to calculate energy potential was chosen that is based on an industry accepted methodology for calculating the biomethane production from dairy cow manure. It is based on the Quantifying Energy Potential from Dairies in PacifiCorp’s WA State Territory U.S. Livestock Project Protocol, Version 4.0 (the “Protocol”) published by the Climate Action Reserve and relies heavily on years of research and other calculation protocols, most notably the Intergovernmental Panel on Climate Change Protocol for calculating Greenhouse Gas Emissions from Livestock Waste. The calculations provided in this protocol are derived from internationally accepted methodologies.2 The following parameters are necessary to quantify the energy potential: Required Parameters for Quantifying Energy Potential Population – PL The Protocol differentiates between livestock categories (L) (e.g. lactating dairy cows, dry cows, heifers, etc.). This accounts for differences in methane generation across livestock categories. Volatile solids – VSL The Volatile Solids (“VS”) represents the daily organic material in the manure for each livestock category and consists of both biodegradable and non-biodegradable fractions. The VS content of manure is a combination of excreted fecal material and urinary excretions, expressed in a dry matter weight basis (kg/animal).3 MassL This value is the annual average live weight of the animals, per livestock category. This data is necessary because default VS values are supplied in units of kg/day/1,000 kg mass. Therefore, the average mass of the corresponding livestock category is required in order to convert the units of VS into kg/day/animal. Site specific livestock mass is preferred for all livestock categories. Since site-specific data is unavailable, Typical Animal Mass (“TAM”) values were used. Maximum methane production – B0,L This value represents the maximum methane-producing capacity of the manure, differentiated by livestock category (L) and diet. Again, because site specific data is not available, this calculation uses the default B0 factors supplied as part of the Protocol. 2 The Reserve’s GHG reduction calculation method is derived from the Kyoto Protocol’s Clean Development Mechanism (ACM0010 V.5), the EPA’s Climate Leaders Program (Manure Offset Protocol, August 2008), and the RGGI Model Rule (January 5, 2007). 3 IPCC 2006 Guidelines volume 4, chapter 10, p. 10.42. SECTION 3 POWER PRODUCTION ESTIMATE 14 MS The MS value estimates the fraction of total manure produced from each livestock category that is collected and delivered the anaerobic digestion system. It is expressed as a percent (%), relative to the total amount of VS produced by the livestock category. Different manure management systems have different MS values. For example, a freestall barn system has an MS value of 0.95, whereas a drylot system has an MS value of 0.60. Methane conversion factor – MCF Each anaerobic digestion technology has a volatile solids-to-methane conversion efficiency that represents the degree to which maximum methane production (B0) is achieved and is a function of the temperature and retention time of organic material in the system.4 This method to calculate methane conversion from VS reflects the performance of the anaerobic digestion system using the van’t Hoff-Arrhenius equation, farm-level data on temperature, VS loading rate, and VS retention time.5 The following summarizes the steps to calculate the potential energy production: Methodology 1. Determine total manure produced from the dairies 2. Calculate the volatile solids available in for anaerobic digestion 3. Calculate the conversion of volatile solids to biomethane 4. Calculate the conversion of biomethane to electricity Step 1: Determine Total Manure Production Data on cow numbers for specific dairies is not publicly available. However, the Washington Department of Agriculture maintains a database of dairies in the state that have nutrient management plans. This database is publicly available and, while it does not contain specific data on the number of cows at each dairy, it provides a range for the numbers of mature dairy cows and heifers at each dairy. This data was overlaid on the map of PacifiCorp’s service territory in Washington State. This results in 60 dairies that are consolidated into eight different size categories based on the number of mature cows on site (see Table 3-1). 4 IPCC 2006 Guidelines volume 4, chapter 10, p. 10.43. 5 The method is derived from Mangino et al., “Development of a Methane Conversion Factor to Estimate Emissions from Animal Waste Lagoons” (2001). SECTION 3 POWER PRODUCTION ESTIMATE 15 Table 3-1: Number of Dairies of Various Sizes Number of Mature Cows 38 to 199 Dairies 2 200 to 699 15 700 to 1699 22 1700 to 2699 11 2700 to 3699 2 3700 to 4699 4 5700 to 6839 2 6840 and above 2 Total: 60 For each dairy, there is a range of the number of mature cows and heifers. This data was used to derive a range of the daily amount of manure for each dairy. Depending on their size, feed, and lactation status, different types of cows produce varying amounts of manure. The Protocol uses industry accepted values of TAM to estimate the daily manure produce for each livestock category (L) (see Table 3-2). SECTION 3 POWER PRODUCTION ESTIMATE 16 Table 3-2: Typical Animal Mass for each Livestock Category Dairy cows (on feed) 2009-2010 604b 680c Non-milking dairy cows (on feed) 684a 684a Heifers (on feed) 476b 407c Bulls (grazing) 750b 750c Calves (grazing) 118b 118c Heifers (grazing) 420b 351c Cows (grazing) 533b 582.5c Nursery swine 12.5a 12.5a Grow/finish swine 70a 70a Breeding swine 198b 198c Sources for TAM: a American Society of Agricultural Engineers (ASAE) Standards 2005, ASAE D384.2. b Environmental Protection Agency (EPA), Inventory of US GHG Emissions and Sinks 1990-2006 (2007), Annex 3, Table A-161, pg. A-195. c Environmental Protection Agency (EPA), Inventory of US GHG Emissions and Sinks 1990-2010 (2012), Annex 3, Table A-191, pg. A-246. Step 2: Calculate the Volatile Solids Available for Digestion Consistent with the Protocol, appropriate VSL values for dairy livestock categories were obtained from the state-specific lookup tables available through the Climate Action Reserve. The VSL values for lactating cows, mature dry cows, and heifers are shown in Table 3-3.L SECTION 3 POWER PRODUCTION ESTIMATE 17 Table 3-3: Daily Volatile Solids Production for each Livestock Category VSL Livestock Category (L) Dairy cows (kg/day/1000 kg mass) 11.50a Non-milking dairy cows 11.50a Heifers 8.43a Bulls (grazing) 6.04b Calves (grazing) 6.41b Heifers (grazing) 8.25a Cows (grazing) 7.82a Nursery swine 8.89b Grow/finish swine 5.36b Breeding swine 2.71b a Environmental Protection Agency (EPA) - U.S Inventory of Greenhouse Gas Sources and Sinks, 1990-2012 (2013), Annex 3, Table A-204. b Environmental Protection Agency (EPA) – Climate Leaders Draft Manure Offset Protocol, October 2006, Table IIa: Animal Waste Characteristics , p. 18. In order to arrive at VSL in the appropriate units (kg/animal/day), Equation 3.1 is used: VSL = VSTable x MassL/1,000 (Equation 3.1) Where: VSL = Volatile solid excretion on a dry matter weight basis, kg/animal/day VSTable = Volatile solid excretion from Climate Action Reserve lookup table, from Table 3, kg/day/1000kg MassL = Average live weight for livestock category L from Table 2 , kg The VSL is then converted into the monthly amount of VS available from each dairy by applying the population and manure management factors arrived at previously, using Equation 3.2. Because the dairies in the study area predominately utilize drylot manure management systems, the MSL for all livestock categories is 0.60, meaning that 60 percent of the total manure produced is collected and could be delivered to an AD system. SECTION 3 POWER PRODUCTION ESTIMATE 18 VSavail, L = (VSL x PL x MSL x daysmo) (Equation 3.2) Where: VSavail, L = Monthly volatile solids available for the anaerobic digestion system by livestock category L, kg dry matter VSL = Volatile solids produced by livestock category L on a dry matter basis, kg/animal/day PL = Average population of livestock category L MSL = Percent of manure produced by each livestock category L, that is collected in the manure management system and delivered to the AD system, % daysmo = Calendar days per month, days Step 3: Calculate the Conversion of Volatile Solids to Biomethane Now that the VS that are delivered to the AD system are known, the amount of methane that can be generated from those VS via anaerobic processes must be calculated. This is accomplished by multiplying the B0,L, the maximum methane capacity for each livestock category, by VSdeg, the amount of the VS delivered to the AD system (calculated in Equation 3.2) that is degraded and converted to methane (see Equation 3.3). The B0,L for each livestock category is derived from empirical data (see Table 3-4). The VSdeg is a function of the total VSavail and the ‘f’ factor, which incorporates the van’t Hoff-Arrhenius equation described previously. BECH4, L = (VSdeg, L x B0,L x daysmo) (Equation 3.3) Where: BECH4, L = Total monthly baseline methane emissions from anaerobic manure storage/treatment system AS from livestock category L, m3 CH4/mo VSdeg, L = Monthly volatile solids degraded in AD system for livestock category L, kg dry matter B0,L = Maximum methane producing capacity of manure for livestock category L – see Table 4 for default values, m3CH4/kg of VS daysmo = Calendar days per month, days Livestock Category (L) SECTION 3 POWER PRODUCTION ESTIMATE 19 Table 3-4: Maximum Methane Production for each Livestock Category B0,La Livestock Category (L) Dairy cows (m3 CH4/kg VS added) 0.24 Non-milking dairy cows 0.24 Heifers 0.17 Bulls (grazing) 0.17 Calves (grazing) 0.17 Heifers (grazing) 0.17 Cows (grazing) 0.17 Nursery swine 0.48 Grow/finish swine 0.48 Breeding swine 0.35 a Environmental Protection Agency (EPA) – Climate Leaders Draft Manure Offset Protocol, October 2006, Table IIa: Animal Waste Characteristics , p. 18. VSdeg, L = ƩL(VSavail, L x f) (Equation 3.4) Where: VSdeg, L = Monthly volatile solids degraded by AD system by livestock category L, kg dry matter VSavail, L = Monthly volatile solids available for degradation AD system by livestock category L, kg dry matter f = The van’t Hoff-Arrhenius factor = “the proportion of volatile solids that are biologically available for conversion to methane based on the monthly temperature of the system”6 The ‘f’ factor (see Equation 3.5) converts total available volatile solids in the AD system to methane-convertible volatile solids, based on the monthly temperature of the AD system. For heated AD systems that operate at either mesophilic (35–40°C) or thermophilic (50–60°C) temperatures, the ‘f’ factor is at the maximum value of 0.95. The ‘f’ factor comes into play only for AD systems that are significantly influenced by ambient temperatures (e.g. covered lagoons). It is assumed that the AD systems that are being contemplated in the study area are either mesophilic or thermophilic. Thus, the ‘f’ factor is 0.95. 6 Mangino, et al. SECTION 3 POWER PRODUCTION ESTIMATE 20 f = exp[E(Tmo - Tref)/(R x Tref x Tmo)] (Equation 3.5) Where: f = The van’t Hoff-Arrhenius factor E = Activation energy constant (15,175), cal/mol Tmo = Monthly average AD system temperature (K = °C + 273). If Tmo < 5°C then f = 0.104. If Tmo > 29.5°C then f = 0.95, Kelvin Tref = 303.16; Reference temperature for calculation, Kelvin R = Ideal gas constant (1.987), cal/Kmol The result of Equation 3.3 is the volume (in m3) of biomethane per month from each dairy that results in the collection delivery and anaerobic digestion of the manure-derived volatile solids. Step 4: Calculate the Conversion of Biomethane to Electricity For the volumes of biomethane that can be generated via the AD systems that are being considered for the dairies in the study area, the most appropriate biomethane-to-electricity conversion technology is a reciprocating engine-generator. While the electrical conversion efficiencies of reciprocating engine-generators generally increase in size, they vary by manufacturer. Therefore, rather than attempting to predict a conversion efficiency for each size of dairy, a first approximation of 37.5 percent was used as an electrical conversion efficiency for each size of AD system. This was used to calculate the electrical power production for each dairy, based on its calculated volume of biomethane. In addition, to arrive at the annual electrical energy production, it was assumed that each engine- genset was operating at the equivalent of full capacity for 90 percent of the hours each year. Based on the dairy data provided by the Washington Department of Agriculture and the methodology described above, Results Table 3-5 summarizes the potential electrical power production from the dairies. If all of the dairies installed anaerobic digesters, the total installed power would range from approximately 16.0 MW to 26.6 MW. The annual energy production would range from approximately 129 GWh/yr to 214 GWh/yr. These ranges are based on the range of dairy sizes. SECTION 3 POWER PRODUCTION ESTIMATE 21 Table 3-5: Electrical Power Production Ranges by Dairy Size Number of Mature Cows Minimum Power Dairies Maximum Power (kW) Average Power (kW) 38 to 199 (kW) 2 8 38 23 200 to 699 15 47 151 99 700 to 1699 22 143 248 246 1700 to 2699 11 322 520 421 2700 to 3699 2 576 779 677 3700 to 4699 4 679 894 787 5700 to 6839 2 1,102 1,345 1,221 6840 and above 2 1,242 1,509 1,375 Total: 60 15,971 26,576 21,273 Because the economics of installing digesters on smaller dairies may not be favorable, another useful way to view the potential is by grouping the engine-gensets by size. Figure 3-1 summarizes this information, based on the average number of mature dairy cows within each of the dairy size categories. If the size of the AD systems were limited to 500 kW and larger, there are 11 potential projects that would total approximately 10.2 MW and produce approximately 82 GWh/yr. SECTION 3 POWER PRODUCTION ESTIMATE 22 Figure 3-1: Potential Annual Electricity Production from Dairy AD Systems 2 Dairies 46 kW Total 32 Dairies 5452 kW Total 15 Dairies 5560 kW Total 2 Dairies 1074 kW Total 5 Dairies 3942 kW Total 1 Dairy 1120 kW Total 3 Dairies 4078 kW Total - 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 40,000,000 45,000,000 50,000,000 0-49 50-249 250-499 500-749 750-999 1000-1249 1250-1499 23 SECTION 4 – ENVIRONMENTAL AND REGULATORY The State of Washington has a well developed and straight forward permit program that specifically addresses anaerobic digester development. The following paragraphs briefly describe the various permit programs.7 AD systems that contain at least 50 percent manure and no more than 30 percent other organic waste may operate under an exemption from solid waste handling permits. Systems not subject to the exemptions must obtain a solid waste handling permit. WA Solid Waste Permitting AD systems operating at permitted CAFOs do not need an additional permit if the system is digesting only manure. WA Water Permitting Water quality permits are required for discharges to surface and ground water (RCW 90.48.160). Operators, including digesters and participating dairies, must manage their operations to ensure that they do not discharge to surface or ground water. When discharge is unavoidable, water quality permits are required prior to any discharge. Anaerobic digesters located on licensed dairies need to be covered under the dairy’s nutrient management plan (Chapter 90.64 RCW). The Dairy Nutrient Management Act (“NMA”) requires all licensed dairies to develop, update, and implement NMP’s, register with WSDA, allow regular inspections, and keep records verifying that the NMP is being followed. These records can also show that discharges are not occurring, thus avoiding the need for water quality permits. New or modified sources of air pollution in the state of Washington require an air permit prior to beginning construction and operation (Clean Air Act, Chapter 70.94 RCW; New Source Review WAC 173-400-110). Air permits (Notice of Construction or Orders of Approval) regulate criteria pollutants such as particulate matter, sulfur dioxide, and nitrogen oxides, and also toxic air pollutants such as ammonia and hydrogen sulfide WA Air Permitting Local or county planning agency requirements for the planned anaerobic digesters must be satisfied. Requirements may include permit approvals for building, grading, water systems, shorelines, right-of-way, utilities, site plans, septic systems, floodplains, zoning, and others. Local Jurisdiction Permitting The State Environmental Policy Act (SEPA) may require review of the environmental impacts of the planned digester by a local or state agency (Chapter 43.21C RCW). State policy requires state and local agencies to consider the likely environmental consequences of the decisions they make, including decisions to approve or deny license applications or permit proposals. 7 Washington State University Fact Sheet FS040E SECTION 4 ENVIRONMENTAL AND REGULATORY 24 With the passage of Initiative 937 in 2006 the State of Washington passed a renewable energy standard that applies to PacifiCorp. The Renewable Portfolio Standard calls for electric utilities that serve more than 25,000 customers to obtain 15 percent of their power from renewable sources by the year 2020. Between January 1, 2012 through December 31, 2015 at least 3 percent of PacifiCorp’s load must be supplied by renewable sources. For the period January 1, 2016 through December 31, 2019 the percentage increases to 9 percent. The increase to 15 percent must be met by January 1, 2020. For purposes of the standard anaerobic digesters qualify as renewable sources. Energy from renewable sources is eligible for compliance if the facility began operations after March 31, 1999. The facility must be located in the Pacific Northwest as defined by the Bonneville Power Administration. REC Qualification All of the generation that could be produced from AD projects with dairies in the Yakima County service territory would generate REC’s that could be registered and traded. The Western Renewable Energy Generation Information System (“WREGIS”) is an independent renewable energy tracking system for the region covered by the Western Electricity Coordinating Council (“WECC”). REC’s can be registered with WREGIS and traded within the WECC states. It is beyond the scope of this assessment to establish the market value of REC’s traded within the region. Investment Tax Credit Other Investment Incentives The federal business energy investment tax credit is available for CHP projects. The credit is equal to 10 percent of expenditures, with no maximum limit stated. Eligible CHP property generally includes systems up to 50 MW in capacity that exceeds 60 percent energy efficiency, subject to certain limitations and reductions for large systems. The efficiency requirement does not apply to CHP systems that use biomass for at least 90 percent of the system's energy source, but the credit may be reduced for less-efficient systems. This credit applies to eligible property placed in service after October 3, 2008. Production Tax Credit The federal electricity production tax credit has expired and is no longer available. Washington Renewable Energy Cost Recovery Incentive Payment Program In May 2005, Washington enacted Senate Bill 5101, establishing production incentives for individuals, businesses, and local governments that generate electricity from solar power, wind power or anaerobic digesters. The incentive amount paid to the producer starts at a base rate of $0.15 per kilowatt-hour (“kWh”) and is adjusted by multiplying the incentive by the following factors:  For electricity produced using solar modules manufactured in Washington State: 2.4.  For electricity produced using a solar or wind generator equipped with an inverter manufactured in Washington State: 1.2.  For electricity produced using an anaerobic digester, by other solar equipment, or using a wind generator equipped with blades manufactured in Washington State: 1.0. SECTION 4 ENVIRONMENTAL AND REGULATORY 25  For all other electricity produced by wind: 0.8. These multipliers result in production incentives ranging from $0.12 to $0.54/kWh, capped at $5,000 per year. Ownership of the renewable-energy credits (“RECs”) associated with generation remains with the customer-generator and does not transfer to the state or utility. Washington Energy Sales and Use Tax Exemption In Washington State, there is a 75 percent exemption from tax for the sales of equipment used to generate electricity using fuel cells, wind, sun, biomass energy, tidal or wave energy, geothermal, anaerobic digestion or landfill gas. The tax exemption applies to labor and services related to the installation of the equipment, as well as to the sale of equipment and machinery. Eligible systems are those with a generating capacity of at least 1 kilowatt (kW). Purchasers of the systems listed above may claim an exemption in the form of a remittance. Originally scheduled to expire on June 30, 2013, the exemption has been extended through January 1, 2020. According to the USEPA, methane is a greenhouse gas that is approximately 21 times more effective in trapping heat in the atmosphere than carbon dioxide over a 100-year period. Anthropogenic sources of methane include landfills, natural gas and petroleum systems, agricultural activities, coal mining, stationary and mobile combustion, wastewater treatment, and certain industrial processes. Methane emissions generated by the manure management practices of large dairy operations have been identified as a significant source of GHGs. The US EPA is required to regulate GHG emissions under the broad provisions and authorities of the Clean Air Act. Therefore, reducing GHG emissions has become important and a potential source of revenue on some dairies. Anaerobic digesters can provide a means for dairy farms to participate in markets for GHG avoidance and sequestration. Greenhouse Gas Reduction Anaerobic digestion is a waste stabilization process. Stabilization occurs by the microbially mediated decomposition of the carbon in complex organic compounds to methane and carbon dioxide. This natural process takes place in the manure storage lagoons that exist at most large dairies and results in the generation of biogas, which is made up of approximately 2/3 methane and 1/3 carbon dioxide. Because this process takes place in controlled conditions in an engineered AD system, such a system provides the opportunity to capture and combust the biogas it produces. It is the capture and combustion of this biogas, along with the ability to maximize the degree of waste stabilization that differentiates anaerobic digestion in an AD system from anaerobic decomposition, which occurs naturally in lagoons and other livestock manure storage structures. The total amount of GHG credits produced from an AD system can be calculated using a protocol published by the Climate Action Reserve and accepted by programs that value and trade the credits. The protocol calculates the net GHG emissions reductions from digestion, subtracting post-digester installation GHG emissions to those that would be emitted without digestion. In order to sell credits, a project must have these reductions certified by a third party registry. According to the Climate Trust, a third party that certifies such credits, a typical project in the Pacific Northwest that incorporates an on-farm AD system will generate 2.5 to 3.5 credits SECTION 4 ENVIRONMENTAL AND REGULATORY 26 per mature cow equivalent each year.8 Using the average of the two values and the range of animals described in Section 3, if all of the dairies that could produce more than 500 kW developed AD systems, they would avoid 164,000 to 230,000 tonnes of CO2e emissions per year. 8 Weisberg, Peter. Environmental Market Revenue Opportunities for Biogas Projects. NEBC NW Biogas Workshop, Portland, OR, April 27, 2012. 27 SECTION 5 – DEVELOPMENT COST The capital requirements to install a digester will vary widely depending on digester design chosen, size, and choice of equipment for utilization of the biogas. In 2009 the US EPA AgSTAR program analyzed the investment at 19 dairy projects that installed plug flow digester similar the digesters in use in Washington. The analysis of investments made versus herd size at 19 dairy farm plug-flow digesters yielded an estimate of $566,006 + $617 per cow in 2009 dollars. The estimates provided in this assessment have been normalized to 2014 dollars using an inflation rate of 1.5 percent per year. Ancillary items that may be incurred are charges for connecting to the utility grid and equipment to remove hydrogen sulfide, which could add up to 20 percent to the base amount. There is considerable interest in digester designs that are economically feasible for smaller farms, but some digester components are difficult to scale down. A complete mix digester with separator installed on a 160-cow Minnesota dairy farm in 2008 cost $460,000, or $2,875/cow. Another way to consider the investment is to assume a unit cost per kilowatt of installed capacity to be $3000 to $3500. Smaller farms would not likely invest the capital to install digesters for power production. Figure 5-1 below shows the total value of the potential capital investment if all of the farms in a given generation capacity were developed based on the AgStar estimated cost. Figure 5-2 shows the individual farm investment based on the generation capacity. The total capital investment estimate that would be required to develop 100 percent of the resources would be approximately $91MM. It is not practical to assume that all projects rise to the level of investment quality. May of the smaller farms would not be practical. We have included the capital investment shown for each generator capacity in Figure 5-2. Completed Major Equipment Revisions Figure 5-1: Total Capital Investment $1,265,973 $33,443,363 $24,305,787 $4,182,408 $14,128,399 $4,108,188 $13,741,425 - 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000 35,000,000 40,000,000 0-49 50-249 250-499 500-749 750-999 1000-1249 1250-1499 To t a l I n v e s t m e n t C o s t ( $ ) Size of Engine Genset at Individual Dairies (kW) Total Capital Cost For Each Category of Farm Sizes SECTION 5 DEVELOPMENT COST 28 Figure 5-2: Total Investment on an Individual Farm at Various Generation Capacities $632,986 $1,045,105 $1,620,386 $2,091,204 $2,825,680 $4,108,188 $4,580,475 - 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 5,000,000 Ca p i t a l C o s t p e r F a r m ( $ ) Size of Engine Genset at Individual Dairies (kW) Total Capital Cost For Individual Farm 29 SECTION 6 – OPERATING COSTS The USDA Natural Resources Conservation Service has been heavily involved in developing the federal design and operation standards for the design and installation of farm based digesters. Much of the work and information published by the AgStar program referenced NRCS Practice Standards. The following operating cost information is based on an analysis done by the NRCS.9 Table 6-1: USDA NRCS Operating Cost Analysis Based on the data from the NRCS analysis and keeping with the plug flow digester design it is shown that the operating costs with electrical production are $0.09/kWh. The cost analysis is based on the operating results of nine different projects. It is not reported in the discussion how large the systems are or what the basis of the fixed and variable expenses are. It should be expected that fixed operating costs would be lower based on economies of scale for larger digester projects. It has been accepted in the dairy based digester industry that using the electrical power internally and offsetting retail electricity rates with the generator output can yield better economic performance than the sale of power at wholesale rates. Including the various incentives does not normally lead to profitable commercial operations generally. The use of additional organic can boost the gas production by as much as 300 percent with very minimal increases in capital and operating costs. This would have a direct impact on the performance of the system and lower the O&M costs accordingly. Unfortunately the proximity to significant quantities of those additives is limited due to the location in Yakima County. Addition of Other Organic Wastes 9 “An Analysis of Energy Production Costs from Anaerobic Digestion systems on US Livestock Production Facilities” USDA NRCS, October 2007 SECTION 6 OPERATING COSTS 30 The George DeRuyter Dairy is located within the Yakima County service territory. It is the only dairy in the service territory to have installed a commercial digester and an excellent example of the implementation of the technology and profitability challenges associated with electrical sales as the only source of cash flow. Appendix 1 to this report includes a feasibility report prepared for the Washington State Department of Commerce outlining the economic and environmental challenges facing the development of AD projects in the state. George DeRuyter & Sons Dairy 10 The report provides an analysis of the development challenges and profitability of a dairy based digester in the Yakima Valley. The report is significant due to the fact that it is based on one of the largest dairies in the State of Washington where economies of scale can have a positive impact on the development cost and output. The report also has analysis of the cash flow impacts of utilizing electrical sales based on the Washington State Schedule 37 avoided cost rates for Qualifying Facilities as the only source of income. The lack of success in developing projects in the service territory is characterized as follows.  Projects based entirely on revenue streams from Power Purchase Agreements at the Qualifying Facility rate structure are not likely to have commercial success. This is a situation that is a factor elsewhere throughout the U.S with Pacific Northwest electrical prices only exacerbating the problem for the region, especially in the Yakima River Basin, which has some of the lowest rates in the nation.  Presence of the dairies in an area away from urban centers which negatively impacts a project’s ability to secure off-farm co-digestion substrates with or without tipping fees. In the northwest area of the state projects are more likely able to source additional substrates and organic wastes that contribute to gas production and revenue from both energy sales and tipping fees  Declining Renewable Energy Credits (RECs) for electrical power production has reduced the value of these credits, especially in the Pacific Northwest, where a multitude of wind projects and reduced demand have flooded the renewable power market.  Success rates for development projects could be improved with a move toward Renewable Natural Gas sales rather than dependence on revenue from electricity sales. 10 “An Anaerobic Digester Case Study Alternative Offtake Markets and Remediation of Nutrient Loading Concerns Within the Region” Washington State Department of Commerce PACIFICORP – 2015 IRP APPENDIX Q – ENERGY STORAGE STUDY 531 APPENDIX Q – ENERGY STORAGE SCREENING STUDY HDR Engineering (HDR) was retained by PacifiCorp Energy (PacifiCorp) to perform an Energy Storage Study to support PacifiCorp’s 2013 Integrated Resource Plan (IRP) intended to evaluate a portfolio of generating resources and energy storage options. This report has been updated for the 2015 IRP. The scope of this Energy Storage Study is to develop a current catalog of commercially available utility-scale and distributed scale energy storage technologies, and to define their applications, performance characteristics, and estimated capital and operating costs. The information presented in this report has been gathered from public and private documentation, studies, reports, and project data of energy storage systems and technologies. PACIFICORP – 2015 IRP APPENDIX Q – ENERGY STORAGE STUDY 532 Update to Energy Storage Screening Study For Integrating Variable Energy Resources within the PacifiCorp System July 9, 2014 Prepared for: PacifiCorp Energy Salt Lake City, Utah Prepared by: HDR Engineering, Inc. PacifiCorp Energy Storage Screening Study 1 Final July 2014 Table of Contents 1 Executive Summary ............................................................................................................................ 5 2 Introduction ......................................................................................................................................... 9 2.1 Integrating Variable Energy Resources ........................................................................................ 9 3 Energy Storage Systems and Technology ....................................................................................... 11 3.1 Pumped Storage .......................................................................................................................... 11 3.1.1 Single-Speed versus Variable-Speed Technology ............................................................... 13 3.1.2 Open-Loop and Closed-Loop Systems ................................................................................ 14 3.1.3 Potential Projects in PacifiCorp Service Area ................................................................... 15 3.1.4 Operating Characteristics ................................................................................................... 26 3.1.5 Regulatory Overview ........................................................................................................... 26 3.1.6 Capital, Operating, and Maintenance Cost Data ............................................................... 27 3.2 Batteries ...................................................................................................................................... 30 3.2.1 Battery Energy Storage Technology Description ............................................................... 30 3.2.2 Manufacturers and Commercial Maturity of Technology ................................................... 30 3.2.3 Summary of Project Data .................................................................................................... 39 3.2.4 Performance Characteristics .............................................................................................. 40 3.2.5 System Details and Requirements ....................................................................................... 43 3.2.6 Technology Risks................................................................................................................. 44 3.2.7 Capital, Operating and Maintenance Cost Data ................................................................ 44 3.3 Compressed Air Energy Storage ................................................................................................. 45 3.3.1 CAES Technology Description ............................................................................................ 45 3.3.2 Performance Characteristics .............................................................................................. 48 3.3.3 Geological Considerations ................................................................................................. 49 3.3.4 Capital, Operating, and Maintenance Cost Data ............................................................... 50 3.4 Flywheels .................................................................................................................................... 52 3.4.1 Flywheel Technology Description....................................................................................... 52 3.4.2 Manufacturers ..................................................................................................................... 52 3.4.3 Performance Characteristics .............................................................................................. 53 3.4.4 Manufacturer Pros and Cons .............................................................................................. 54 3.4.5 Capital, Operating and Maintenance Cost Data ................................................................ 54 3.5 Liquid Air Energy Storage (LAES) ............................................................................................ 54 3.5.1 LAES Technology Description ............................................................................................ 54 3.5.2 LAES Performance .............................................................................................................. 54 PacifiCorp Energy Storage Screening Study 2 Final July 2014 3.6 Supercapacitors ........................................................................................................................... 55 3.6.1 Supercapacitor Technology Description ............................................................................. 55 3.6.2 Supercapacitor Performance .............................................................................................. 55 3.7 Superconducting Magnet Energy Storage (SMES) ..................................................................... 55 3.7.1 SMES Technology Description ........................................................................................... 55 3.7.2 SMES Performance ............................................................................................................. 56 4 Comparison of Storage Technologies .............................................................................................. 57 4.1 Technology Development ........................................................................................................... 57 4.2 Applications ................................................................................................................................ 58 4.3 Space Requirements .................................................................................................................... 58 4.4 Performance Characteristics ....................................................................................................... 59 4.5 Project Timeline .......................................................................................................................... 61 4.6 Cost ............................................................................................................................................. 61 5 Conclusions ........................................................................................................................................ 63 Appendices APPENDIX A – ENERGY STORAGE MATRIX APPENDIX B – PUMPED STORAGE DATA B.1 – Klickitat Response – JD Pool B.2 – EDF Response – Swan Lake North B.3 – Swan Lake North Plan Drawing B.4 – Swan Lake North Profile Drawing B.5 – Gridflex Response – Black Canyon B.6 – Conceptual Pumped Storage Development Schedule B.7 – AACE Cost Estimating Guidelines APPENDIX C – BATTERY STORAGE DATA APPENDIX D – COMPRESSED AIR ENERGY STORAGE DATA APPENDIX E – OTHER STORAGE TECHNOLOGY DATA PacifiCorp Energy Storage Screening Study 3 Final July 2014 Table of Figures Figure 1 ‐ Existing Pumped Storage Projects in the United States .................................................................... 11 Figure 2 - Typical Pumped Storage Plant/System ........................................................................................................ 12 Figure 3 - Preliminary Proposed Pumped Storage Projects as of April, 2014 (HDR) ....................................... 15 Figure 4 - Swan Lake North Site Layout and Profile (Swan Lake North Pre-Application Document) ....... 20 Figure 5 - JD Pool Project Layout (JD Pool Preliminary License Application) .................................................. 22 Figure 6 - Black Canyon Layout (Black Canyon Preliminary Permit Application) .......................................... 24 Figure 7 - A123 Li-ion Cells ................................................................................................................................................ 31 Figure 8 - Renewable Integration Deployment in West Virginia ............................................................................ 32 Figure 9 - NAS Cell Module ................................................................................................................................................ 33 Figure 10 - NGK NAS 8 MW (Japan) .............................................................................................................................. 33 Figure 11 - VRB Cell Stack and Electrolyte Tanks ...................................................................................................... 34 Figure 12 - Standard VRB Plant Design 3 MW ............................................................................................................ 34 Figure 13 - PowerCellTM Stacks with PCS ................................................................................................................... 35 Figure 14 - DPR15-100C Container .................................................................................................................................. 36 Figure 15 - ZnBr Cell Stacks ............................................................................................................................................... 37 Figure 16 - Premium’s TransFlow2000 Section (ZnBr battery) .............................................................................. 37 Figure 17 - 3 MW of frequency regulation at the PJM Interconnection ................................................................ 38 Figure 18 - UberBattery Energy Block ............................................................................................................................. 38 Figure 19 - Rated MW Capacity of US Battery Energy Storage Projects ............................................................. 39 Figure 20 - Rated MWh Capacity of US Battery Energy Storage Projects .......................................................... 40 Figure 21 - Typical Battery Life Cycle Curve State of Charge (SOC) .................................................................. 42 Figure 22 - CAES Geological Formations ...................................................................................................................... 50 Figure 23 - Potential Geological Formations Favorable for CAES ......................................................................... 50 Figure 24 - Flywheel Plant Stephentown, New York .................................................................................................. 53 Figure 25 - Current Worldwide Installed Energy Storage Facility Capacity (Source: CESA) ....................... 58 Figure 26 - Li-ion Battery Field and a Hydroelectric P/S Plant for 20,000 MWh of Storage (Source: HDR) ...... 59 Figure 27 - Current Energy Storage Technology Capabilities in Real Time (Source: HDR) ......................... 60 Figure 28 - Current Energy Storage Technology Capabilities (Log-Log Scale) (Source: Electricity Storage Association) ....................................................................................................................................... 61 Figure 29 - Operation and Maintenance Costs for Energy Storage Technologies .............................................. 63 Table of Tables Table 1 - Summary of Highlighted Pumped Storage Projects .................................................................................... 5 Table 2 - Energy Storage Technology Summary Table ................................................................................................ 8 Table 3 - Example Comparison of Primary Characteristics....................................................................................... 14 Table 4 - Summary of Highlighted Pumped Storage Projects as Provided by the Project Developers ....... 16 Table 5 - Comparison of Cost Opinions ........................................................................................................................... 28 Table 6 - CAES Typical Project Schedule ...................................................................................................................... 51 Table 7 - Energy Storage Comparison Summary .......................................................................................................... 57 Table 8 - Space Required for 20,000 MWh of Energy Storage ................................................................................ 59 Table 9 - Summary of Cost and Capacity Data ............................................................................................................. 62 PacifiCorp Energy Storage Screening Study 4 Final July 2014 Legal Notice to Third Parties This report was prepared for PacifiCorp Energy by HDR Engineering Inc. (HDR) and is based on information not within the control of HDR. HDR has assumed that the information provided by others, both verbal and written, is complete and correct. While it is believed that the information, data, and opinions contained herein will be reliable under the conditions and subject to the limitations set forth herein, HDR does not guarantee the accuracy thereof. Use of this report or any information contained therein by any party other than PacifiCorp Energy or its affiliates, shall constitute a waiver and release by such third party of HDR from and against all claims and liability, including, but not limited to, liability for special, incidental, indirect, or consequential damages in connection with such use. In addition, use of this report or any information contained herein by any party other than PacifiCorp Energy or its affiliates, shall constitute agreement by such third party to defend and indemnify HDR from and against any claims and liability, including, but not limited to, liability for special, incidental, indirect, or consequential damages in connection with such use. To the fullest extent permitted by law, such waiver and release and indemnification shall apply notwithstanding the negligence, strict liability, fault, breach of warranty, or breach of contract of HDR. The benefit of such releases, waivers, or limitations of liability shall extend to the related companies and subcontractors of any tier of HDR, and the directors, officers, partners, employees, and agents of all released or indemnified parties. PacifiCorp Energy Storage Screening Study 5 Final July 2014 1 EXECUTIVE SUMMARY HDR Engineering (HDR) was retained by PacifiCorp Energy (PacifiCorp) to perform an Energy Storage Study to support PacifiCorp’s 2013 Integrated Resource Plan (IRP) intended to evaluate a portfolio of generating resources and energy storage options. This report has been updated for the 2015 IRP. The scope of this Energy Storage Study is to develop a current catalog of commercially available utility-scale and distributed scale energy storage technologies, and to define their applications, performance characteristics, and estimated capital and operating costs. The information presented in this report has been gathered from public and private documentation, studies, reports, and project data of energy storage systems and technologies. HDR has reviewed and investigated the following energy storage technologies for this study:  Pumped Storage Hydroelectric  Battery Energy Storage Systems  Compressed Air Energy Storage In addition, some less-than-utility-scale or emerging technologies are described without detailed discussion of cost or performance characteristics. Pumped storage hydroelectric facilities are classified as a mass energy storage technology capable of providing thousands of megawatt hours (MWh) of dispatchable energy. Pumped storage is ideal for large grid applications such as load shifting, peak shaving, spinning reserve, and intra-second grid needs such as frequency regulation, all on a large scale (200 to 1,000+ MW). Due to the grid scale size of the projects interconnection of these facilities typically requires availability of Extra High Voltage (EHV) transmission lines. Furthermore, pumped storage facilities also require site-specific attributes and resources, such as water rights and elevated reservoir. There are currently forty (40) pumped storage hydroelectric projects operating in the United States. In addition, there are currently over sixty (60) projects being considered for development under the Federal Energy Regulatory Commission (FERC) licensing process. Three projects within PacifiCorp’s territory have been reviewed for this IRP update report: the JD Pool Pumped Storage Project, the Swan Lake North Pumped Storage Project, and the Black Canyon Pumped Storage Project. These proposed sites were selected based on existing project features located within the PacifiCorp balancing area, environmental impacts that are fairly well understood, and the current status of project development and licensing. Project parameters are summarized in Table 1 below. Table 1 - Summary of Highlighted Pumped Storage Projects Item Swan Lake North JD Pool Black Canyon Location Oregon Washington Wyoming Approximate Static Head (ft) 1,300 2,400 1,063 Energy storage (MWh) 5,280 16,500 5,550 Assumed Hours of Storage (hrs) 8.8 11 9.5 PacifiCorp Energy Storage Screening Study 6 Final July 2014 Item Swan Lake North JD Pool Black Canyon Estimated Installed Capacity (MW) 600 1,500 600 Developer Provided Estimated Capital Cost ($/kW) (See section 3.1.6 for details of HDR’s Opinion of Costs) $2,300 $1,700-$2,500 $1,500 Estimated Year 1 O&M Cost (estimated as a function of capacity and annual energy. See section 3.1.6 for details) $9.4 million $19.1 million $9.4 million Water-to-wire efficiency 75-82% 75-82% 75-82% Battery storage is gaining acceptance in small-scale (~ 20 MW) storage applications, particularly in conjunction with renewable resources. Battery energy storage systems are considered to be a small scale energy storage option focused on applications such as energy regulation, frequency response, load following and ramping support, energy arbitrage, and even distribution system upgrade deferral. In the case of renewable integration, batteries primarily function to dampen the effects of generation and load differences resulting from the variability in renewable energy generation profiles. Battery technologies and their respective manufacturers reviewed for this study, including project characteristics, include the following:  Lithium ion (Li-ion) – A123 Systems: Since 2009, seven projects have been installed in the US with capacity of 69 MW / 47.5 MWh. Largest projects include 20 MW / 5 MWh in Johnson City, NY and 8 MW / 32 MWh in Tehachapi, CA. Currently under development is a 32 MW / 8MWh system in Oro Mountain, WV.  Sodium sulfur (NAS) – NGK Insulators, Ltd.: The first project was 0.5 MW for a TEPCO Kawasaki substation in 1995. Installations now include over 120 international projects with capacity of 190 MW and 1,300 MWh. The largest project is 12 MW / 86.4 MWh at a Honda facility Japan, installed in 2008. As of 2010, six projects in the US with 14.75 MW / 73.2 MWh have been installed, with the largest project being 4 MW / 24 MWh in Presidio, TX (2010). Five projects totaling 7.9 MW / 23.2 MWh are planned throughout the US.  Vanadium Redox (VRB) – Prudent Energy: The first US project was with PacifiCorp in Castle Valley, UT with 0.250 MW / 2 MWh installed in 2004. In 2009, a 0.6 MW / 3.6 MWh system was installed at Gills Onion plant, CA. Two other projects are in development in CA, with combined nameplate capacity of 2.2 MW.  Dry Cell – Xtreme Power, Inc.: The first installation of 0.5 MW / 0.1 MWh was a test facility in Antarctica for microgrid peak shaving completed in 2006. A 1.5 MW / 1 MWh test facility was installed in Maui, HI for renewable integration in 2009.  Zinc Bromide (ZnBr) – Premium Power: To date, 6.9 MW / 17.2 MWh has been installed in the US. Five recent projects, two in CA and three in MA, have been installed or are under development, rated at 0.5 MW / 3 MWh each. PacifiCorp Energy Storage Screening Study 7 Final July 2014  Advanced Lead Acid (Pb-Acid) – Ecoult has installed a 3 MW scale demonstration facility, as well as a 3 MW frequency regulation facility on the PJM grid in Pennsylvania. Also installed has been a 3 MW micro-grid application that allows an island of 1,500 people to utilize 100% renewable energy. Compressed Air Energy Storage (CAES) is also classified as mass energy storage, although on a capacity scale (~100 MW) between batteries and pumped storage. A typical CAES plant would consist of a series of motor driven compressors capable of filling a storage cavern with air during off-peak, low-load hours. At high-load, on-peak hours, the stored compressed air is delivered to a series of combustion turbines which are fired with natural gas for power generation. Utilizing pre-compressed air removes the need for a compressor on the combustion turbine, allowing the turbine to operate at high output and efficiency during peak load periods. Compressed air energy storage is the least implemented and developed of stored energy technologies evaluated herein. Only two plants are in operation, including Alabama Electric Cooperative’s (AEC) McIntosh plant which began operation in 1991. Others projects have been proposed, but have not progressed beyond concept. Other emerging energy storage technologies have been briefly reviewed for this report, including flywheels, liquid air energy storage, super-capacitors, and superconducting magnets. Although all of these technologies can be connected to the grid, they are still considered developmental and small scale. Generally, these other technologies could only be used for short durations (seconds to minutes), for supplying backup power in an outage event, or to help regulate voltage and frequency. HDR has performed an initial comparison of the three primary energy storage technologies, including pumped storage, batteries and compressed air. Table 2 summarizes the comparison of key criteria for these technologies including project capital cost as evaluated by HDR in 2014 dollars. More detailed comparisons are included in Appendix A. HDR has also reviewed and commented upon the overall commercial development of these technologies, the applications which each technology is suited to, along with space requirements, performance characteristics, project timelines, and the Developer provided capital, operating and maintenance (O&M) costs. There are challenges associated with comparing costs for these different types of energy storage technologies. Initial capital cost is one indicator; however long-term annual O&M cost provides another factor for comprehensive economics and determining financial feasibility. Operating and maintenance costs associated with various battery technologies can be high compared to pumped storage, but this cost varies depending upon the technology. As battery technology develops further, and grid scale installations continue, a better understanding of the costs associated with operation and maintenance will be achieved. Conversely, while the capital costs for pumped storage are high when looked at in total, they are competitive with batteries on a dollar/kW installed basis, and have low fixed and variable O&M costs. PacifiCorp Energy Storage Screening Study 8 Final July 2014 Table 2 - Energy Storage Technology Summary Table Pumped Storage Hydro (Three sites) Batteries Compressed Air Energy Storage Range of power capacity (MW) 600 – 1,500 1-32 100+ Range of energy capacity (MWh) 5,550 – 16,000 Variable depending on Depth Of Discharge 800+ Range of capital cost (2014$ per kW ) $1,700 - $2,500 $800 - $4,000 $2,000 - $2,300 Year of first installation 1929 1995 (sodium sulfur) 1978 PacifiCorp Energy Storage Screening Study 9 Final July 2014 2 INTRODUCTION PacifiCorp, as well as other utilities and power authorities throughout the world, face a major challenge in balancing increasing levels of variable energy resources. As generation from variable energy resources and their relative percentage of load grow, there is an increasing need for additional system flexibility to assure grid reliability. Based on both industry and HDR studies, it is evident that expanded transmission interconnections, continued modernization of the existing power plants, market changes that encourage greater operational flexibility of existing generation assets and new energy storage facilities will be required across the United States over the next decade. The 2015 PacifiCorp Integrated Resource Plan (IRP) is expected to include a portfolio of generating resources and energy storage options for evaluation. These include both fossil fuel options, such as coal and natural gas, as well as renewable options including wind, geothermal, hydro, biomass, and solar. In order to integrate additional renewable generation into their IRP, it is anticipated that energy storage may be required. For that reason, PacifiCorp has engaged HDR to develop a current catalog of commercially available and emerging energy storage technologies with estimates of performance and costs. Energy storage permeates our society, manifesting itself in products ranging from small button batteries to large-scale pumped storage hydro-electric projects. Energy storage for utility-scale applications has historically relied upon pumped storage hydro facilities and the large reservoirs associated with conventional hydropower stations. In recent years, utilities have also considered and implemented several pilot projects utilizing various battery technologies. To a limited extent, compressed air energy storage and flywheels have also been implemented. When installed over a large service area, the totality of these distributed systems could provide reserves to the regional grid for limited durations. Within the electric utility industry, there is uncertainty regarding which energy storage system can provide the optimal benefit for a given application. The following discussion is intended to catalog the energy storage technologies available to date, to summarize the current state of development of these energy storage technologies, to provide a high level comparison of these technologies, and provide comments and discussion on their implementation in an effort to assist PacifiCorp with the integration of variable energy resources and energy storage into its IRP. 2.1 Integrating Variable Energy Resources Variable energy resources provide a sustainable source of energy that uses no fossil fuel and produces zero carbon emissions. One of the constraints of variable generation is that the energy available is non- dispatchable; it tends to vary and is somewhat unpredictable. The power-system load is also variable; power-system reserves are required to match changes in generation and demand on a real-time basis. Variable generation cannot be dispatched specifically when energy is needed to meet load demand. Wind and utility industries have been able to address many of the variability issues through improvements in wind forecasting, diversification of wind turbine sites, improvements in wind turbine technology, and the creation of larger power-system control areas. At low wind penetration levels, wind output typically can be managed in the regulation time-frame by calling upon existing system reserves, curtailing output and/or diversifying the locations of wind farms over a broad geographic area. As more variable energy is added to the power system, additional reserves are required. Flexible and dispatchable generators, such as hydro, CAES, or batteries, are required to provide system capacity and balancing reserves to balance load in the hour-to-hour and sub-hour time-frame. In addition to system PacifiCorp Energy Storage Screening Study 10 Final July 2014 reserves, every balancing authority has the need for energy storage to balance excess generation at night and shift its use to peak demand hours during the day. Conventional hydropower projects do this by shutting down units and storing energy in the form of elevated water, and it is the most common form of energy storage in the world. As variable energy output and the ratio of wind generation to load grows, historical system responses will need to be modified to take advantage of the benefits of variable energy resources to the regional grid and to assure system reliability. It should be mentioned that variability is not a new phenomenon in power system operation. Demand has fluctuated since the first consumer was connected to the first power plant. The resulting energy imbalances have always had to be managed, mainly by dispatchable power plants. The evolution of variable energy resources in the system is an additional, rather than a new, challenge that presents two elements: variability (now on the supply-side as well), and uncertainty. The output from variable energy resource plants fluctuates according to the available resource — the wind, the sun or the tides. These fluctuations are likely to mean that, in order to maintain the balance between demand and supply, other parts of the power system will have to change their output or consumption more rapidly and/or more frequently than currently required. At small penetrations — a few percent in most systems — the additional effort is likely to be slight, because variable energy resource fluctuations will be dwarfed by those already seen on the demand side. Large variable energy penetration, in contrast, will exacerbate the system variability in extent, frequency and rate of change. As is known by system operators, electricity demand follows a regular pattern. Deducting the contribution of variable energy resources to the grid in correlation to demand is often referred to as the net load. In the review of net load tracking in the Bonneville Power Administration balancing area, no regular pattern is evident with the exception of a tendency for wind to pick up at night and drop off in the morning. This is opposite to electric demand, which highlights the greater variability of net load caused by a 30 percent penetration of variable supply.1 It is the extent of these ramps, the increases or decreases in the net load, as well as the rate and frequency with which they occur that are of principal relevance to the industry. This is where the balancing challenge lies — in the ability of the system to react quickly enough to accommodate such extensive and rapid changes. Net load ramping is more extreme than demand alone. This is not only because variable energy resource output can ramp up and down extensively over just a few hours, but also because it may do so in a way that is inversely proportional to fluctuations in demand. In contrast, VER output may complement demand — when both increase or decrease at the same time. So, rather than the question of — how can variable renewables be balanced? — the more pertinent may be: how can increasingly variable net load be balanced? The point is that variability in output (supply) should not be viewed in isolation from variability on the demand-side (load); if the variable energy resource side of the balancing equation is considered separately, a system is likely to be under-endowed with balancing resources.2 1 Hydroelectric Pumped Storage for Enabling Variable Energy Resources within the Federal Columbia River Power System, Bonneville Power Administration, HDR 2010 2 Harnessing Variable Renewables A Guide to the Balancing Challenge, 2011 International Energy Agency PacifiCorp Energy Storage Screening Study 11 Final July 2014 3 ENERGY STORAGE SYSTEMS AND TECHNOLOGY A review of available energy storage technologies was performed for comparative purposes in this study. The results are discussed throughout this report and include the following storage systems:  Pumped Storage Hydroelectric  Battery Energy Storage Systems  Compressed Air Energy Storage Each of these technologies has been employed for grid scale storage or to provide ancillary services. Many other technologies, such as flywheels, superconducting magnets, and supercapacitors, have been deployed at the distributed-energy scale, and there is significant ongoing research to further develop these technologies and scale them up for bulk energy storage applications. This research is expected to continue for the foreseeable future. 3.1 Pumped Storage Pumped storage hydroelectric projects have been providing storage capacity and transmission grid ancillary benefits in the U.S. and Europe since the 1920s. Today, there are 40 pumped storage projects operating in the U.S. that provide more than 20 GW, or nearly 2 percent, of the capacity for our nation’s energy supply system (Energy Information Admin, 2007). Figure 1 below indicates the distribution of existing pumped storage projects in the U.S. Pumped storage and conventional hydroelectric plants combined account for approximately 77 percent of the nation’s renewable energy capacity, with pumped storage alone accounting for an estimated 16 percent of U.S. renewable capacity (Energy Information Admin., 2007). Figure 1 ‐ Existing Pumped Storage Projects in the United States PacifiCorp Energy Storage Screening Study 12 Final July 2014 Pumped storage facilities store potential energy in the form of water in an upper reservoir, pumped from another reservoir at a lower elevation (Figure 2). Historically, pumped storage projects were operated in a manner that, during periods of high electricity demand, electricity is generated by releasing the stored water through pump-turbines in the same manner as a conventional hydro station. In periods of low energy demand or low cost, usually during the night or weekends, energy is used to reverse the flow and pump the water back up hill into the upper reservoir. Reversible pump-turbine/generator-motor assemblies can act as both pumps and turbines. Pumped storage stations are unlike traditional hydro stations in that they are actually a net consumer of electricity, due to hydraulic and electrical losses incurred in the cycle of pumping back from a lower reservoir to the upper reservoir. However, these plants have often proved very beneficial economically due to peak to off-peak energy price differentials, and as well as providing ancillary services to support the overall electric grid. Figure 2 - Typical Pumped Storage Plant/System The contributions of pumped storage hydro to our nation’s transmission grid are considerable, including providing stability services, energy-balancing, and storage capacity. Pumped storage stations also provide ancillary electrical grid services such as network frequency control and reserves. This is due to the ability of pumped storage plants, like other hydroelectric plants, to respond to load changes within seconds. Pumped storage historically has been used to balance load on a system and allow large, thermal generating sources to operate at peak efficiencies. Pumped storage is the largest-capacity and one of the most cost-effective forms of grid-scale energy storage currently available. PacifiCorp Energy Storage Screening Study 13 Final July 2014 3.1.1 Single‐Speed versus Variable‐Speed Technology Historically, typical pumped storage plants used electricity to pump water to the upper reservoir during periods of low-cost, off-peak power and generate electricity during periods of high-cost, on-peak power. New pumped storage projects are envisioned to provide significant load following or ramping capability to the grid during periods of rapid changes in net load (load minus wind or solar generation) in addition to energy absorption or pumping capability during periods of excess energy generation. In the case of conventional synchronous (single, constant speed) pump-turbine units, during generating mode, the individual units are operated to support grid requirements including load following and frequency regulation (Automatic Generation Control or AGC); however, during pumping, the units are operated at best pumping gate (most efficient operation) with no capability for load following or regulation. During pumping mode, the wicket gate positions may need to be decreased as the reservoir water elevation increases in order to keep the units on the best pumping gate curve and to prevent cavitation and vibration (net head control). Deviation from this best pumping gate operation results in low efficiency and rough operation, with minimal change in power input requirements. Many of the proposed pumped storage projects are considering variable-speed (asynchronous) pump- turbine technology where load following is possible during both the generating and pumping modes, and hence the primary difference between the two technologies. This allows a pumped storage owner to provide grid reliability services in both pump and generate modes of operation. Variable-speed operation in this context normally means that the rotating speed of a unit does not vary by more than +/-10% of its synchronous speed. The varying output frequency of the generator is converted to the grid frequency through a special frequency conversion system. Other advantages of variable-speed units are higher and flatter generator efficiency curves, wider generating and pumping operating ranges, and easier start-up process. The main disadvantage of this technology is the higher capital costs, which are on average about 30% greater than conventional single-speed units. Table 3 provides a summary comparing the operational characteristics and advantages/disadvantages of single and variable-speed units for an example particular project. Actual benefits will vary depending on specific site characteristics. Because of the multiple advantages, variable-speed units have been discussed in this report. PacifiCorp Energy Storage Screening Study 14 Final July 2014 Table 3 - Example Comparison of Primary Characteristics Characteristic Single-speed Variable-speed Proven Technology 45+ years - Worldwide 10+ years - Europe and Japan Equipment Costs - Approximately 10% to 30% Greater Powerhouse Size - Approximately 25% to 30% Greater Powerhouse Civil Costs - Approximately 20% Greater Project Schedule - Longer - Site Specific O&M Costs - Greater for the Power Electronics Operating Head Range 80% to 100% of Max. Head 70% to 100% of Max. Head Generating Efficiency Approximately 0.5% to 2% Greater Power Adjustment Generation Mode* Approximately 60% to 100% Approximately 50% to 100% Power Adjustment Pump Mode* None +/- 20% Operating Characteristics Idle to Full Generation Generally Less than 3 Minutes Generally Less than 3 Minutes 100 Percent Pumping to 100 Percent Generation Generally Less than 6 to 10 Minutes Generally Less than 6 to 10 Minutes 100 Percent Generation to 100 Percent Pumping Generally Less than 6 to 10 Minutes Generally Less than 6 to 10 Minutes Load Following Seconds (i.e., 10 MW per Second) Seconds (i.e., 10 MW per Second) Reactive Power Changes Instantaneously Instantaneously Automatic Frequency Control Yes in generate mode Yes in both pump and generate modes *Power Adjustment: The ability of a pump-turbine generator-motor to operate away from its best operating point based on rated head and flow. Single-speed units can operate over a range of flow in the generating mode which is identical to a conventional hydropower turbine, but not in the pumping mode (in pumping mode a single speed machine cannot vary flow or wicket gate settings at all). Variable-speed units have the ability to operate the turbine’s off-peak efficiency point in the pumping mode via the power electronics (no substantive change in flow), and typically have greater flexibility in the generating mode than single-speed units. 3.1.2 Open‐Loop and Closed‐Loop Systems Both open-loop and closed-loop pumped storage projects are currently operating in the U.S. The distinction between closed-loop and open-loop pumped storage projects is often subject to interpretation. The Federal Energy Regulatory Commission (FERC) offers the formal definitions for these projects, and it was FERC’s definitions that were followed while categorizing the pumped storage sites discussed in this report: Closed-loop pumped storage are projects that are not continuously connected to a naturally- flowing water feature; and open-loop pumped storage are projects that are continuously connected to a naturally-flowing water feature. Closed-loop systems are preferred for new developments, or Greenfield projects, as there are often significantly less environmental issues, primarily due to the lack of aquatic resource impacts. Projects that are not strictly closed-loop systems can also be desirable, depending upon the project configuration, and whether the project uses existing reservoirs. PacifiCorp Energy Storage Screening Study 15 Final July 2014 3.1.3 Potential Projects in PacifiCorp Service Area For PacifiCorp’s 2013 IRP, HDR made an assessment of fifteen potential projects located within the PacifiCorp balancing area. For the 2015 IRP, three projects have been selected in consultation with PacifiCorp for further review. Projects were selected based on the preliminary filings with FERC. Figure 3 below illustrates where proposed projects in the U.S. that have been granted and/or filed for a FERC Preliminary Permit Application. Figure 3 - Preliminary Proposed Pumped Storage Projects as of April, 2014 (HDR) 3.1.3.1 Pumped Storage Evaluation Criteria The following is a list of pumped storage evaluation criteria utilized for this study: Water conveyance – The tunnel length to head ratio is the single biggest variable cost component for a pumped storage project. The higher the head, the higher energy density and, as such, longer tunnel lengths are justifiable. Conversely, lower head (less than 300 feet) means that shorter tunnel lengths or a unique site configuration are required to be competitive. Capacity- The larger the project is in terms of capacity, the lower the installed cost per kilowatt (kW) is for similar civil cost components. PacifiCorp Energy Storage Screening Study 16 Final July 2014 Closed or open-loop- Closed-loop or off-stream embankments/dams generally means fewer regulatory challenges and a less complex FERC licensing process. Specific sites where the lower reservoir already exists may also be advantageous. Source of water- The source of water can be complicated in extremely dry (e.g. desert southwest) or politically charged (Columbia River Basin) areas of the country. Potential environmental/regulatory factors- Environmental and regulatory factors vary widely from site to site: these issues can range from minor challenges to a fatal flaws depending upon the project’s environmental impacts. Project location- A strong power market where ISO’s are integrating large amounts of variable energy will be seeking a project that can provide grid scale ancillary services. Transmission access- Energy evacuation and transmission line permitting is site specific and driven by a local project champion. Geological factors- Geological factors, such as active fault lines near the proposed site, can be a project fatal flaw if known or suspected. Technical development progress- HDR has evaluated the technical progress thus far of each project. Projects with more than a conceptual layout have been favored. Commercial development progress- HDR has evaluated the commercial analysis of each project, as initially performed by others, and has investigated whether the developer has explored the revenue streams beyond the traditional energy arbitrage model. Based on the above criteria, and the location of the projects within PacifiCorp’s regional footprint, HDR, in collaboration with PacifiCorp, selected the JD Pool Pumped Storage Project, the Swan Lake North Pumped Storage Project and the Black Canyon Pumped Storage Project for further evaluation. These proposed sites were selected due to existing project features, environmental impacts that are fairly well understood, and the current project development status. HDR reviewed the FERC preliminary filings and subsequent six-month progress reports for each site. In addition, the developers for each project were contacted for additional information. A request for information (RFI) was developed and distributed to Klickitat Public Utility District (Klickitat) for JD Pool, EDF Renewable Energy (EDF) for Swan Lake North, and Gridflex for Black Canyon, respectively. The RFI and each developer’s response are attached to this document in Appendix B. Table 4 below discusses a summary of these projects’ characteristics. Table 4 - Summary of Highlighted Pumped Storage Projects as Provided by the Project Developers Item Swan Lake North JD Pool Black Canyon Location Oregon Washington Wyoming Approx. static head (ft) 1,188-1,318 1,900-2,100 1,063 Energy storage (MWh) 5,280 16,500 5,550 Estimated hours of storage (hrs) 8.8 11 9.5 Estimated installed capacity (MW) 600 1,500 600 Developer Provided Estimated Capital Cost ($/kW) (See section 3.1.6 for details of HDR’s Opinion of Costs) $2,300 $1,700-$2,500 $1,500 Estimated O&M Costs (estimated as a function of capacity and annual energy. See section 3.1.6 for details) $9,400,000 $19,100,000 $9,400,000 PacifiCorp Energy Storage Screening Study 17 Final July 2014 3.1.3.2 Swan Lake North The current preliminary permit for the Swan Lake North Pumped Storage Project (FERC No. 13318) updates a prior preliminary permit filed by Symbiotics. The original preliminary permit application was filed in June 2010, and was granted on August 6, 2010. The draft license application was filed on December 16, 2011. A successive preliminary permit was filed in April 2012 by Symbiotics for Swan Lake LLC so that the project developer would be able to file a Final License Application before the expiration of the preliminary permit. EDF indicated that the final license application has been drafted, but revisions are pending completion of supplemental geotechnical studies and corresponding engineering revisions in the final license application. EDF has made a number of changes to the project layout when compared with the configuration in the active preliminary permit. EDF’s project is proposed to be 600 MW in capacity, a reduction from the 1000 MW project described in the preliminary permit. The size of the reservoirs was reduced to reflect the change in capacity. EDF has also revised water conveyance arrangement to reduce the overall amount of tunneling and is considering surface penstocks. The site layout as provided by EDF is shown in Figure 4. According to EDF, the headrace inlet/outlet structure would be located at the western end of the upper reservoir. The structure would consist of two circular bellmouth intakes to control the flow of water into two surface penstocks, approximately 2,320 feet long each. The penstocks would lead to two 572 foot long drop shafts. Horizontal headrace tunnels would connect the drop shaft to the underground powerhouse. A tailrace tunnel would be located on the southeastern end of the lower reservoir to connect the powerhouse to the lower reservoir. The powerhouse would be located at the foot of an escarpment between two scree fields. The powerhouse would contain four pump-turbine motor-generator turbine assemblies, all associated electrical and mechanical support equipment, personnel sanitary facilities, changing and meeting rooms, a control room, and transformers. This is a shift from the preliminary permit application’s design which reflected a powerhouse with separate transformer galleries. Four reversible units would be installed in the powerhouse. Each unit would have a rated generating capacity 150 MW for a total plant rating of 600 MW. The turbine operating head range is 1,188 to 1,318 feet. EDF reports that this configuration has a storage capacity of 5,280 MWh. The upper reservoir would be contained by a 111 foot tall, 6,560 foot long compacted rockfill dam with an asphalt concrete face. The upper reservoir would have a usable storage volume of 5,837 acre-ft. This is approximately one half the size of the upper reservoir in the active preliminary permit. The lower reservoir would be impounded by a 100 feet high, 5,245 feet long dam. The resulting reservoir would have a usable storage volume of approximately 6,000 acre-ft, which is smaller than the 11,583 acre-ft reservoir in the preliminary permit. The project site would be accessed from Highway 140 via a private road, with Swan Lake Road as a secondary access road for vehicles approaching the project area north of Highway 140. A new, permanent 24-foot-wide haul road would be constructed up the slope of Swan Lake Rim between the upper and lower reservoirs. The haul road would be approximately 3.5 miles long. Interconnection studies have been conducted with the Transmission Agency of Northern California (TANC) under the original 1,000 MW configuration. The study concluded that only 400 MW could be PacifiCorp Energy Storage Screening Study 18 Final July 2014 interconnected without requiring additional transmission circuits, and the interconnection request was withdrawn. Another interconnection study was performed for PacifiCorp utilizing the 600 MW configuration. The project would connect to the northern segment of the 500 kV #2 Malin-Round Mountain line. It appears that 600 MW could be interconnected without additional circuits. EDF is currently preparing for an Impact Study with PacifiCorp and BPA. A feasibility-level geotechnical and geophysical investigation of the project site has been performed to assess the soils and facilitate ongoing permitting. The primary objective of the investigation was to evaluate the susceptibility of the soils to liquefaction under seismic loading. Additional ongoing geo-tech testing is needed to validate assumptions and further refine the powerhouse location and conveyance alignments. EDF documented consultation with affected agencies and stakeholders. Limited resource studies have been conducted and reportedly include:  Water resources,  Fish and aquatic resources,  Botanical resources,  Wildlife resources,  Threatened and endangered species,  Wetlands,  Recreation,  Land use,  Cultural resources, and  Tribal resources. In reviewing the draft license exhibits, it appears that the studies have been performed using existing data and consultation. HDR anticipates that field studies would be the next step to further advance the project. EDF indicated that they have developed a Class 4 cost estimate in accordance with the Association for the Advancement of Cost Engineering (AACE). Refer to Appendix B.7 for the AACE cost estimating guidelines. The estimate for the project including direct costs, engineering, construction management, licensing costs is $1.4 billion. This is approximately $2,300 per kW. PacifiCorp Energy Storage Screening Study 19 Final July 2014 SITE LAYOUT PacifiCorp Energy Storage Screening Study 20 Final July 2014 Figure 4 - Swan Lake North Site Layout and Profile (Swan Lake North Pre-Application Document) PacifiCorp Energy Storage Screening Study 21 Final July 2014 HDR OPINION The Swan Lake North pumped storage project has been advanced by EDF subsequent to acquiring 100 percent ownership of the project LLC. Having the ground water rights issues resolved to support initial fill is significant and the initial geotechnical investigations are a step in the right direction to advance the engineering elements. The design decision to use surface penstocks should be carefully considered. While limiting tunnel lengths may potentially reduce tunneling capital costs, it is HDR’s experience that surface penstocks are typically more costly to construct where construction access is difficult or foundation conditions may be unstable. It should be noted that EDF France’s involvement is a major factor in the potential successful execution of the project given their extensive pumped storage design and execution resume around the globe. However in the absence of any substantive off-taker agreements, the Swan Lake North project has not progressed beyond the conceptual engineering stage; and firm estimates of cost, or project fatal flaws, have not been completed. 3.1.3.3 JD Pool The original preliminary permit application for the JD Pool Pumped Storage Project (FERC No. 13333) in the Columbia Gorge in southern Washington was filed by the Klickitat Public Utility District and Symbiotics LLC on November 20, 2008, and formed the basis of HDR’s 2011 energy storage technology assessment report. A successive application was filed by Klickitat on April 30, 2012, and the information included in the revised application forms the basis of HDR’s review of the project presented below. Klickitat provided a response to the RFI that generally replicates the information in the active preliminary permit application. The JD Pool project layout appears to have been modified such that both the upper and lower reservoirs have been shifted slightly to the west. This results in a potential increase of approximately 200 to 400 feet in total head to a maximum head of approximately 2000 feet. This new upper and lower reservoir alignment is achieved via the construction of much larger reservoir embankments in terms of volume of fill material; however, engineering studies documenting the technical feasibility of the change in reservoir location do not appear to have been conducted. According to Klickitat’s response to the RFI, the dam configuration, water conveyance layout, and equipment configuration have not been further developed. The project configuration below was extracted from the active preliminary permit application. All project features associated with JD Pool would be new with the exception of the existing pumping station, associated conveyance piping and equipment from the closed aluminum smelter, which is partially located on Federal lands near the John Day Pool. A new 24 foot diameter, 9,188 foot long steel penstock is proposed, connecting the upper reservoir to the underground powerhouse. The powerhouse would consist of 5 units, 300 MW each for a proposed capacity of 1,500 MW. The turbines would be rated at 2,100 CFS and would have an operating range between 1,900 feet and 2,100 feet of head. There are two reservoirs associated with the project. The upper reservoir would require a new earth embankment with a clay core. The dam would be 270 feet high and 8,610 feet long. The upper reservoir would have a storage capacity of 14,010 acre-ft, a surface area of 114 acres, and a normal surface, elevation of 2,710 MSL. The new lower reservoir would also require an earth embankment with a clay core. The dam would be 295 feet high and 5,870 feet long. The lower reservoir reportedly would have a PacifiCorp Energy Storage Screening Study 22 Final July 2014 storage capacity of 21,440 ac-ft (approximately 50% greater than the upper reservoir), a surface area of 110 acres, and a normal surface elevation of 705 MSL. Figure 5 - JD Pool Project Layout (JD Pool Preliminary License Application) According to the preliminary permit application, the project would interconnect with BPA’s 500kV John Day substation, approximately 5 miles away from the project site via a new 500 kV line. According to Klickitat’s RFI response, the project is also 8 miles from an alternate DC intertie. This project would be part of the Western Electricity Coordination Council market. According to Klickitat, this project is still in the early stages of development, and no detailed engineering or environmental studies have taken place. Klickitat indicated that they own the water to serve the project through the Washington State Department of Ecology, and the water withdrawal facilities are part of the existing infrastructure from the former aluminum smelter located at the site. Klickitat did not provide a cost estimate at this stage of development. In 2005, HDR was involved in a reconnaissance level study and AACE Class 5 cost opinion for the Goldendale Pumped Storage Project, an early version of JD Pool. PacifiCorp Energy Storage Screening Study 23 Final July 2014 At that time, HDR developed a cost opinion of approximately $2.8 billion. Assuming a 3% escalation per year, cost is approximately $3.7 billion 2014 USD, or approximately $ 2,500 USD per kW. HDR OPINION HDR believes that the JD Pool pumped storage site is one of the premier sites in the Pacific Northwest for development. It is in the middle of BPA’s robust high voltage transmission corridor, it can be developed in an environmentally benign manner, and the associated topography supports a high energy density design. The project status at this time, however, is still at the conceptual stage with no advancements in engineering trade-off studies or environmental and resource assessments. An example of a project disconnect is the disparity between the storage volumes of the upper and lower reservoir as indicated in the active preliminary permit; ideally they would be equal in a closed loop system. There have not been any field studies to date, and Klickitat indicated they are actively searching for a development partner. The lack of progress on the regulatory requirements does put the project developer at risk for being able to maintain the active preliminary permit. 3.1.3.4 Black Canyon The preliminary permit application for the Black Canyon Pumped Storage Project (FERC No. P-14087) was prepared by Gridflex Energy, LLC and was filed by Black Canyon Hydro, LLC on January 25, 2011. The application currently shows four alternatives for development. See Figure 4 for the project layout. Two new upper reservoirs, the East Reservoir and the North Reservoir, could be connected to one of two existing lower reservoirs, the Seminoe Reservoir and the Kortes Reservoir. The developer may select one or a combination of the alternatives. In their response to the RFI, Gridflex indicated that their preferred alternative at this time connects the East Reservoir and the existing Seminoe Reservoir. The other three configurations, however, are still under consideration. The project description below was extracted from the active preliminary permit application. Based upon the RFI response, it appears that Gridflex revised the project sizing for Black Canyon from the preliminary permit application. In the FERC filing, the project is described as a 400 MW plant with reportedly an additional 100 MW of pumping capacity. In the RFI submittal, Gridflex presents a 600 MW project for the same preferred alternative with no additional pumping capacity. The change appears to be in the unit sizing and not the configuration of the dams and reservoirs. The East Reservoir would be connected to the Seminoe Reservoir by approximately 6,800 feet of conduit. Maximum hydraulic head for the project would be 1,063 feet. A 20.4 ft diameter low pressure tunnel would extend for 800 ft and connect to a 5,800 ft long pressure shaft to the powerhouse. A 200 ft long section of tailrace tunnel would connect the powerhouse to the lower reservoir. The penstock configuration was not addressed in Gridflex’s response to the RFI. The powerhouse would be located approximately 200 feet east of the Seminoe Reservoir. Gridflex indicated that an underground powerhouse is preferred in the RFI submittal. HDR concurs with this underground cavern concept where the project is planning to utilize an existing lower reservoir due to constructability. However, in HDR’s opinion, the powerhouse is proposed to be located very close to the existing lower reservoir and appears to be a shoreline powerhouse configuration, and the constructability of the powerhouse should be carefully evaluated. PacifiCorp Energy Storage Screening Study 24 Final July 2014 Also the sizing of the pump-turbine generator-motor units differs between the RFI and the preliminary permit application. According to the preliminary application, three 133 MW adjustable-speed reversible pump-turbines would be utilized for 400 MW of generating capacity. The units would be capable of an additional 100 MW of additional pumping capacity. In Gridflex’s RFI response, a 600 MW project is described for the same East Reservoir-Seminoe alternative without any additional capacity during pumping operation. In their submittal, the developer reported that the units would provide 100-200 MW each in the pump mode and 50-200 MW in the generating mode, but HDR’s experience with pump- turbines indicates that this operating range is not realistic, including the most advanced variable speed technology. The proposed East upper reservoir would consist of a new 50 ft ring dam and would be 8,724 ft long and impound a 9,700 acre-ft reservoir. The lower reservoir for this project would be the existing Seminoe Reservoir. The reservoir is 1,016,717 acre-ft and is impounded by Seminoe dam, an existing 295 ft high concrete arch dam. The project would interconnect with the Western Area Power Administration (WAPA) Miracle Mile- Cheyenne line near the Seminoe Dam. This line runs through the Medicine Bow area, where energy from the project would be transferred to one of several planned terminals for new transmission facilities. These include the Gateway West line (PacifiCorp) via the Aeolus substation, the Zephyr line, the TransWest Express, and the Overland. The interconnection point would be adjacent to the project powerhouse. The project would utilize the water resources of the North Platte River as stored and transferred through the Seminoe and Kortes Reservoirs. Figure 6 - Black Canyon Layout (Black Canyon Preliminary Permit Application) PacifiCorp Energy Storage Screening Study 25 Final July 2014 The developer has indicated that they intend to purchase water rights from adjacent land owners who are existing water rights holders. In HDR’s experience, the acquisition of water rights can be a lengthy and difficult process depending upon the geographic region and stakeholder interests. Both upper reservoirs would be located on land managed by the Bureau of Land Management (BLM), as would a part of the conduit path. The existing Kortes and Seminoe Reservoirs and dams are owned and operated by Reclamation. Study plans have not been developed yet, but Gridflex reported that they have consulted with both the BLM and Reclamation. Gridflex indicated that their project an AACE Class 4 or 5 cost estimate of approximately $883 million dollars, which is about $1,500 per kW. This appears to be low given the stage of development of the project. In HDR’s opinion, the level of engineering demonstrated by Gridflex’s response to the RFI does not fully reflect the potential construction costs of a new upper reservoir, powerhouse, prime mover elements and other extensive balance of plant systems, plus the water conveyance system. The engineering and licensing also appears to be low, at only 7% of the project construction cost. Gridflex included construction management in the direct project cost, but in HDR’s experience this typically represents an additional cost and should be listed separately. For this level of project development, HDR would expect project contingency to be in excess of 30% for a Class 4 or 5 cost estimate rather than the 20% reflected in Gridflex’s response. Gridflex indicated that a renewable integration study has been conducted with Wyoming wind data, but the report was not attached to the RFI response. The developer indicated that the project could be operational as early as 2020, but from the level of engineering development and licensing progress, this date does not appear to be achievable to HDR. HDR OPINION The Black Canyon project is the least advanced of the three pumped storage projects investigated for this report, and significant additional feasibility work needs to be done to determine if the project is viable. It does not appear that any engineering alternatives analyses or preliminary desktop geological assessments have been completed to further refine the site or to identify potential geological fatal flaws. The concept of a shoreline powerhouse next to an existing lower reservoir should be refined to demonstrate that required unit submergence can be achieved. The reported unit operating parameters also require further clarification. The constructability of a shoreline powerhouse near an existing reservoir should be carefully considered. Pump-turbines typically require submergence, or setting of the centerline of the pump-turbine approximately 10% of the gross head below the minimum tailwater elevation. This equates to approximately 100 feet for Black Canyon just for unit submergence alone. The resulting very deep excavation required near an existing body of water would potentially create significant water management issues during construction. The reported costs appear to be low based upon HDR’s industry experience and the current market prices for the prime movers and the extensive balance of plant systems. The project timeline for construction and commissioning is also unrealistic based upon HDR’s industry experience, and do not appear to be based on advanced engineering or environmental studies. These studies would include analysis of existing infrastructure, site specific geology, transmission interconnect studies, resource (e.g. botanical, aquatic, land use, cultural) studies, and other factors critical for determining the technical and economic feasibility of a new pumped storage project. PacifiCorp Energy Storage Screening Study 26 Final July 2014 3.1.4 Operating Characteristics The pumped storage projects in development are driven by the opportunity to capitalize on the anticipated markets for energy arbitrage and ancillary services. Energy arbitrage refers to the practice of utilizing electric energy during the lower priced hours of excess energy to pump water from a lower reservoir into the upper reservoir. The water is then stored in the upper reservoir for potential use. When energy prices are higher, water is released from the upper reservoir through the turbines, and electricity is generated and sold at these higher prices. Energy arbitrage results in higher net income when the difference between on- peak and off-peak prices is greatest. The projects would also provide ancillary services in both operating modes. FERC has defined ancillary services as, “those services necessary to support the transmission of electric power from seller to the purchaser given the obligations of control areas and transmitting utilities within those control areas to maintain reliable operations of the interconnected transmission system” (FERC 1995). As described above, variable-speed units are more suitable for providing ancillary services than single-speed units, particularly frequency regulation. The projects could provide the following services:  Spinning Reserves - Reserve capacity provided by generating resources that are running (i.e., “spinning”) with additional capacity that is capable of ramping over a specified range within 10 minutes and running for at least two hours. Spinning Reserves are needed to maintain system frequency stability during periods of energy imbalance resulting from unanticipated variations in load, or variable energy supply. Reserves are also required to respond to emergency operating conditions created by forced outages of scheduled units.  Non-Spinning Reserves - Generally, reserve capacity provided by generating resources that are available but not rotating. These generating resources must be capable of being synchronized to the grid and ramping to a specified level within 10 minutes, and then be able to run for at least two hours. Non-Spinning Reserves are needed to maintain system frequency stability during emergency conditions.  Regulation - Reserve capacity provided by generating resources that are running and synchronized with the grid, so that the operating levels can be increased (incremented) or decreased (decremented) instantly through Automatic Generation Control to allow continuous balance between generating resources and demand. 3.1.5 Regulatory Overview Some of the most important aspects in the evaluation of siting and development of a potential pumped storage project are the environmental and regulatory factors. All pumped storage project development by non-federal entities requires the project developer to go through the FERC licensing process, which is expected to take approximately three to five years. For some projects, the potential issues associated with project development may be fatal flaws, for others the mitigation measures are minimal and manageable. Many of the most promising new pumped-storage sites identified by the hydropower industry are closed- loop pumped-storage. It is generally accepted within the industry that a Greenfield closed loop pumped storage project could be licensed in less than five years as many of the environmental and resource issues can be relatively easily mitigated. PacifiCorp Energy Storage Screening Study 27 Final July 2014 Environmental and resource concerns may include fisheries issues (e.g. entrainment or, impingement), site clearing and construction impacts, impacts to recreation, and land use concerns. For closed-loop systems, there is no water discharged from the station into the main-stem river as a result of routine unit operations and the historical concerns regarding fish entrainment and impingement at conventional hydropower stations is thereby avoided. With respect to site clearing and other land use concerns new large pumped-storage plants typically consist of an underground powerhouse and, thus, mitigate to a large degree the overall footprint of the station. But these hydroelectric projects generally require construction of roads, main or saddle dams, spillways, transmission lines, and other aspects that may alter the existing landscape. 3.1.6 Capital, Operating, and Maintenance Cost Data 3.1.6.1 Capital Cost The following discussion is applicable to pumped storage projects with which HDR is familiar, and does not necessarily reflect the three projects discussed above. Nonetheless, the three projects appear to fall in the range of reasonable cost for similar pumped storage projects. The direct cost to construct a pumped storage facility is highly dependent on a number of physical site factors, including but not limited to topography, geology, regulatory constraints, environmental resources, project size, existing infrastructure, technology and equipment selection, capacity, active storage, operational objectives, etc. According to the HDR database, one could expect the direct cost of a pumped storage facility utilizing single speed unit technology to be in the order of $1,700 to $2,500 per kW. The direct cost for a facility utilizing variable speed unit technology is expected to be approximately 10 to 20 percent greater than that of a facility utilizing single speed technology. Direct costs include:  Cost of materials  Construction of project features (tunnels, caverns, dams, roads, etc.)  Equipment  Labor for construction of structures  Supply and installation of permanent equipment  Procurement of water rights for reservoir spill and make up water Indirect costs generally run between 15 and 30 percent of direct costs and are largely dependent on configuration, environmental/regulatory, and ownership complexities and include cost such as:  Preliminary engineering and studies (planning studies, environmental impact studies, investigations),  License and permit applications and processing,  Detailed engineering and studies,  Construction management, quality assurance, and administration,  Bonds, insurances, taxes, and corporate overheads. HDR has summarized the cost opinions for the three selected pumped storage projects. For Swan Lake North, EDF provided a cost estimate of $2,300 per kW. In 2012, HDR prepared a Class 4 cost opinion at the request Symbiotics for Swan Lake North. HDR’s cost opinion at the time was PacifiCorp Energy Storage Screening Study 28 Final July 2014 between $2 billion and $2.3 billion. When HDR’s cost opinion is escalated using a rate of 3% per year, it appears to be consistent with EDF’s response to the RFI. HDR conducted a reconnaissance level study and a Class 5 cost opinion for the Goldendale Pumped Storage Project, which was an early version of the current JD Pool Pumped Storage Project. HDR’s cost opinion was on the order of $2.8 billion in 2005. The cost estimate was escalated at a rate of 3% per year, which yields $3.7 billion in 2014 USD. Klickitat PUD did not provide a cost estimate in their response to the RFI. In the Preliminary Permit Application, however, a cost opinion of $2 billion to $2.5 billion was provided. The cost opinion was for a 1,000 to 1,200 MW project, which equates to $1,700 to $2,500 per kW. It appears that Klickitat PUD’s cost opinion is budgetary in nature, and HDR could not verify that the cost opinion conformed to the AACE guidelines as there was no breakdown provided. HDR expects that the total project cost for JD Pool could be on the order of $2,000 to $2,500 per kW. Based on cost opinions developed for similar pumped storage projects, HDR expects that the construction cost for Black Canyon could be on the order of $2,000 per kW. The $1,500 per kW reported by Gridflex appears to low to cover both direct and indirect costs. It is also low when compared to cost opinions for other pumped storage projects. For Swan Lake North and JD Pool, the developer’s cost estimate seems reasonable given the early stage of development for each project. The cost estimate provided by Gridflex for Black Canyon appears low. This comparison is summarized in Table 5 below. Table 5 - Comparison of Cost Opinions Item Swan Lake North JD Pool Black Canyon HDR Cost Opinion ($/kW) $2,100 - $2,400 $2,500 $2,000 - $2,300 Developer Estimated Capital Cost ($/kW) $2,300 $1,700 - $2,500 $1,500 3.1.6.2 Annual Operation and Maintenance (O&M) Costs Operation, maintenance, and outage costs vary from site to site dependent on specific site conditions, the number of units, and overall operation of the project. For the purposes of this evaluation, a generic four unit, 1,000 MW underground powerhouse has been assumed. As seen from the project examples above, this is a common arrangement selected for a pumped storage project. Previous Electric Power Research Institute (EPRI) studies provide the following equation for estimating the annual operations and maintenance (O&M) costs for a pumped storage project in 1987 dollars: O&M Costs ($/yr) = 34,730 x C0.32 x E0.33 Where: C = Plant Capacity, MW E = Annual Energy, GWh This methodology is considered valid and an escalation multiplier of 2.06 is recommended to escalate 1987 costs to 2014. In addition, the following additional annual costs are recommended: PacifiCorp Energy Storage Screening Study 29 Final July 2014  Annual general and administration expenses in the order of 35% of site specific annual O&M costs, and  Annual insurance expenses equal to approximately 0.1% of the plant investment costs, or capital cost. For a 1,000 MW pumped storage project costing $2,500 per kW, generating 6 hours per day 365 days per year, and annual energy production of 2,190 GWh. The calculated annual O&M, administrative, and insurance costs are approximately $13.6 million in 2014 USD. 3.1.6.3 Bi‐Annual Outage Costs In addition to annual O&M costs, it is recommended within the industry that bi-annual outages be conducted. Again, the frequency of the inspections and the subsequent repairs following inspections can vary depending upon how the units are operated, how many hours per year the units will be on-line, how much time has elapsed since the last inspection/repair cycle, the technical correctness of the hydraulic design for site specific parameters, and water quality issues. Conservatively, in a four unit, 1,000 MW powerhouse, two units would be taken out of service for approximately a three week outage every two years. For units of this size, $262,000 for two units should be budgeted. 3.1.6.4 Major Maintenance Costs It is recommended within the industry that a pump-turbine overhaul accompanied by a generator rewind be scheduled at year 20. The typical outage duration is approximately six to eight months. Pumped storage units are typically operated twice as many hours or more per year than conventional generating units if utilized to full potential. This increased cycling duty also dramatically increases the degradation of the generator components. This increased duty results in the requirement to perform major maintenance on a more frequent basis. The work included and the frequency of this outage can vary based on project head, project operation, and regular maintenance cycles. Overhauls typically include restorations of all bushings and bearings in the wicket gate operating mechanism, replacement of wicket gate end seals, rehabilitation of the wicket gates including non destructive examination (NDE) of high-stress areas, rehabilitation of the servomotors, replacement of the runner seals, NDE of the head cover, restoration of the shaft sleeves and seals, and rehabilitation of the pump-turbine bearing. The end result is restoring the pump-turbine to like-new running condition. Pump-turbine inlet isolation valves will likely require refurbishment of the valve seats and seals. The service life of a generator-motor is generally dependent upon the condition of the insulation in the stator and rotor. The need for re-insulation of the stator and rotor, typical of a salient pole design, can vary from 20 to 40 years depending upon the duty cycle and insulating materials utilized. The costs for these modifications depend on many factors. Due to the complexity of the scope, an estimate must be developed for each installation. For the purposes of this study, approximately $6.28 million was estimated for reversible Francis units at year 20. PacifiCorp Energy Storage Screening Study 30 Final July 2014 3.2 Batteries 3.2.1 Battery Energy Storage Technology Description Battery energy storage systems are functionally electrochemical energy storage devices that convert energy between electrical and chemical states. Electrode plates consisting of chemically-reactive materials are situated in an electrolyte which allows the directional movement of ions within the battery. Negative electrodes (cathodes) give up electrons (through electrochemical oxidation) that flow through the electric load connected to the battery, and finally return to the positive electrodes (anodes) for electrochemical reduction. This basic direct current (DC) can be inverted into the desired alternating current (AC) frequency and voltage. Certain battery technologies have significant exposure in various markets including telecom, end-user appliance, automotive, and on a larger scale, utility applications. Batteries are becoming one of the faster- growing areas among utility energy storage technologies in frequency regulation applications, renewable energy systems integration, and in remote areas and confined grid systems where geographical constraints do not fit well with the application of hydroelectric storage or CAES. Batteries have surpassed CAES in stored energy capacity to total an estimated 556 MW, or 0.36% of global storage capacity in 2012. Electric utility companies as well as large commercial and industrial facilities typically utilize battery systems to provide an uninterruptible supply of electricity to power a load (e.g. substation, data center) and to start backup power systems. In the residential and small commercial sector, conventional use for battery systems includes serving as backup power during power outages. Common types of commercialized rechargeable and stationary battery technologies include, but are not limited to, the following:  Sodium sulfur (NAS)  Dry Cell  Advanced lead acid (Pb-acid)  Family of lithium ion chemistries (Li-ion)  Flow - Vanadium redox (VRB)  Flow - Zinc bromide (ZnBr) In physical form, these battery types are modular and enclosed in a sealed container, with the exception of flow batteries. Flow batteries’ distinguishing characteristic is their independent and isolated power and energy components, comprised of cell “stacks” and tanks to hold the electrolyte. They operate by flowing the electrolyte through cell stacks to generate electrical current. 3.2.2 Manufacturers and Commercial Maturity of Technology All of these batteries types have the technical potential for penetration into specific utility markets and applications. The remainder of this section discusses battery technologies that are considered suitable for specific utility applications. Due to the limited scope of this study, only information collected from manufacturers representing select battery technology is presented. The six manufacturers included in this study, based on their deployment on utility systems, are:  Lithium ion (Li-ion) - A123 Systems, Inc. (A123) PacifiCorp Energy Storage Screening Study 31 Final July 2014  Sodium sulfur (NAS) – NGK Insulators, Ltd. (NGK)  Vanadium redox battery (VRB) – Prudent Energy Corporation (Prudent)  PowerCellsTM – Xtreme Power, Inc. (Xtreme)  Zinc bromine (ZnBr) – Premium Power Corporation (Premium)  Advanced Lead Acid (Pb-Acid) – Ecoult Energy Storage Solutions (Ecoult) 3.2.2.1 Lithium Ion (Li‐ion) – A123 Systems, Inc. (A123) Li-ion and lithium polymer-type batteries have been widely used in end-user appliances (e.g. consumer electronics) and have become the de facto energy storage system in the electric vehicle industry (e.g. hybrids and electric vehicles). Within the battery itself, lithiated metal oxides make up the cathode and carbon (graphite) make up the anode. Lithium salts work as the electrolyte. In a charged battery, lithium atoms in the cathode become ions and deposits in the anode. An example chemical balance can be characterized as: LixC + Li1-xCoO2 <-> LiCoO2 + C Li-ion batteries are known for having high energy density and low internal resistance, making efficiencies (defined as round trip AC out to AC in) upwards of 90% possible. This technology is very attractive for mobile applications and potentially utility power quality applications. An external heating or cooling source may be required depending on ambient conditions and system operation to maintain their operating temperature range of 20 to 30 oC. A123 projects are focused on renewables firming and ramp management, frequency regulation, and T&D and substation support. Projects in their portfolio have less than 1 hour of energy storage with the exception of a 4-hr wind integration plant. Since 2009, seven projects have been installed in the US with capacity of 69 MW / 47.5 MWh. The largest projects include 20 MW / 5 MWh in Johnson City, NY and 8 MW / 32 MWh in Tehachapi, CA. Currently under development (Figure 8) is a 32 MW / 8MWh system in Oro Mountain, WV. This technology is classified as commercial because it has been implemented in the utility markets. Figure 7 - A123 Li-ion Cells PacifiCorp Energy Storage Screening Study 32 Final July 2014 Figure 8 - Renewable Integration Deployment in West Virginia 3.2.2.2 Sodium Sulfur (NaS) – NGK Insulators, Ltd. (NGK) In its simplest form, a NaS battery consists of molten sulfur positive electrode and molten sodium negative electrode, separated by a solid beta-alumina ceramic electrolyte (Figure 9). In the discharge cycle, the positive sodium ions pass through the electrolyte and combine with sulfur to form sodium polysulfides. During the charge cycle, the sodium polysulfides in the anode start to ionize to allow sodium formation in electrolyte according to: 2Na + xS <-> Na2Sx Among the prevalent technologies, NaS batteries have high energy densities that are only lower than that of Li-ion. The efficiency of NaS varies somewhat dependent on duty cycle due to the parasitic load of maintaining the batteries at the higher operating temperature of 330degrees Celsius. However, the battery modules are packaged with sufficient insulation to maintain the battery in its hot operating state for periods of several days in a “standby” mode. NGK projects are focused on island / peak shaving applications, and solar integration. Projects in their portfolio are multiple-hour systems. The first project was 0.5 MW for a TEPCO Kawasaki substation in 1995. Installations now include over 120 international projects with capacity of 190 MW and 1,300 MWh. The largest project is 12 MW / 86.4 MWh at a Honda facility Japan, installed in 2008 (Figure 10). As of 2010, six projects in the US with 14.75 MW / 73.2 MWh have been installed, with the largest project being 4 MW / 24 MWh in Presidio, TX (2010). Five projects totaling 7.9 MW / 23.2 MWh are planned throughout the US. This technology is mature, given its large number of installations, especially in Japan, and the many years of research and development targeted for utility energy storage applications. PacifiCorp Energy Storage Screening Study 33 Final July 2014 Figure 9 - NAS Cell Module Figure 10 - NGK NAS 8 MW (Japan) 3.2.2.3 Vanadium Redox Battery (VRB) – Prudent Energy Corporation (Prudent) VRB systems use electrodes to generate currents through flowing electrolytes. The size and shape of the electrodes govern power density, whereas the amount of electrolyte governs the energy capacity of the system. The cell stacks comprise of two compartments separated by an ion exchange membrane. Two separate streams of electrolyte flow in and out of each cell with ion or proton exchange through the membrane and electron exchange through the external circuit. Ionic equations at the electrodes can be characterized as follows: Anode: V5+ + e- <-> V4+ Cathode: V2+ <-> V3+ + e- VRB systems are recognized for their long service life as well as their ability to provide system sizing flexibility in terms of power and energy. Representative images of VRB technology is shown in Figure 11 and Figure 12. VRB efficiency tends to be in the range of 70-75%. The separation membrane prevents the mix of electrolyte flow, making recycling possible. Prudent projects are focused on solar and wind PacifiCorp Energy Storage Screening Study 34 Final July 2014 integration, and island / peak shaving. Projects in their portfolio are multiple-hour systems. The first US project utilizing VRBs was Rattlesnake #22 with PacifiCorp in Castle Valley, UT with 0.250 MW / 2 MWh installed in 2004. The VRBs were installed in order to increase capacity and reliability of a 25kV feeder without any major environmental impacts. Additional information is available in Appendix C. In 2009, a 0.6 MW / 3.6 MWh system was installed at Gills Onion plant, CA. Two other projects are in development in CA, with combined nameplate capacity of 2.2 MW. This battery technology is classified to be in its nascent commercialization stage as there has been only a handful of utility-scale implementations, although the technology itself has been in development for 20 years. Figure 11 - VRB Cell Stack and Electrolyte Tanks Figure 12 - Standard VRB Plant Design 3 MW PacifiCorp Energy Storage Screening Study 35 Final July 2014 3.2.2.4 Dry Cell – Xtreme Power, Inc. (Xtreme) Xtreme Power’s PowerCellsTM were first developed over two decades ago and bears the signature characteristic of having one cell store 1 kWh worth of energy at ultra-low internal impedance. The cells were developed to maximize nano-scale chemical reactions by providing electrode plates with large surface areas. Representative images of Dry Cell technology is shown in Figure 13 and Figure 14. These cells are solid state batteries developed from dry cell technology. Dry cells have been recognized in the industry for its high energy density and capacity as well as quick recharge times. Similar to the li-ion technology, dry cells have found success in the hybrid vehicle market and are considered to be a commercial technology in the utility industry. Xtreme works with wind and solar integration and offers peak shaving / load leveling. Projects in their portfolio range from sub-hourly to multiple-hour systems. The first installation of 0.5 MW / 0.1 MWh was a test facility in Antartica for microgrid peak shaving completed in 2006. A 1.5 MW / 1 MWh test facility was installed in Maui, HI for renewable integration in 2009. Today, Xtreme has over 78 MW of capacity installed, over 25,000 MWh charged and discharged, and has completed renewable integration projects for Kaheawa Wind Power (Hawaii) on the scale of 10 MW with a 45 minute duration. Figure 13 - PowerCellTM Stacks with PCS PacifiCorp Energy Storage Screening Study 36 Final July 2014 Figure 14 - DPR15-100C Container 3.2.2.5 Zinc Bromine (ZnBr) – Premium Power Corporation (Premium) The fundamental of energy conversion for ZnBr batteries is the same as that of VRBs. Two separate streams of electrolyte flow in and out of each cell compartment separated by an ion exchange membrane. Ionic equations at the electrodes can be characterized as follows: Anode: Br2 + 2e- <-> 2Br Cathode: Zn <-> Zn2+ + 2e- Like VRBs, ZnBr batteries are also recognized for their long service life and flexible system sizing based on power and energy needs. The separation membrane prevents the mix of electrolyte flow, making recycling possible. ZnBr efficiency is in the 60% range. Premium is focused on power quality, island / UPS applications, and on peak shaving / load leveling projects. Projects in their portfolio are multiple- hour systems. To date, 6.9 MW / 17.2 MWh has been installed in the US. Five recent projects, two in CA and three in MA, have been installed or are under development, rated at 0.5 MW / 3 MWh each. Like the VRB systems, ZnBr battery technology is considered in its early stages of commercialization. At the time of writing, there was no publicly available information on any of its electricity storage plants; the number and size of projects installed to date were provided by Premium. Figure 15 illustrates Premium’s standard cell stack. Figure 16 shows Premium’s TransFlow2000, a complete ZnBr battery system, complete with cell stacks, electrolyte circulation pumps, inverters and thermal management system configured into a standard trailer. PacifiCorp Energy Storage Screening Study 37 Final July 2014 Figure 15 - ZnBr Cell Stacks Figure 16 - Premium’s TransFlow2000 Section (ZnBr battery) PacifiCorp Energy Storage Screening Study 38 Final July 2014 3.2.2.6 Advanced Lead Acid (Pb‐Acid) – Ecoult Energy Storage Solutions (Ecoult) Lead acid battery technology is tried and proven, and Ecoult, with East Penn, have commercialized UltraBattery, an advanced lead acid battery without the traditional need to maintain a 100% charge. UltraBattery utilizes traditional lead acid reactions with an ultracapacitor. Ecoult focuses on high power-to-energy applications, primarily involving frequency regulation and power smoothing. However, they have at least one completed and tested project in peak shaving for multiple hours. Ecoult has installed a 3 MW scale demonstration facility, as well as a 3 MW frequency regulation facility on the PJM grid in Pennsylvania. A 3 MW micro-grid application has also been installed that allows an island of 1,500 people to utilize 100% renewable energy. UltraBattery fits best in high power- to-energy ratio applications, such as frequency regulation and renewable energy smoothing. It can achieve efficiencies higher than 90%, and is promoted to be 100% environmentally safe and recyclable. Figure 17 details a 3 MW frequency regulation installation, and Figure 18 shows a typical UberBattery rack. Figure 17 - 3 MW of frequency regulation at the PJM Interconnection Figure 18 - UberBattery Energy Block PacifiCorp Energy Storage Screening Study 39 Final July 2014 3.2.3 Summary of Project Data The following charts summarize the rated capacities of battery storage systems that have been operating or have been contracted to complete installation in the US as provided by the DoE’s Energy Storage Database (see Appendix C for a complete list). Data sets do not include any sales projections or forecasts, and only include data points of projects implemented, or projects breaking ground. Figure 19 - Rated MW Capacity of US Battery Energy Storage Projects PacifiCorp Energy Storage Screening Study 40 Final July 2014 Figure 20 - Rated MWh Capacity of US Battery Energy Storage Projects Data from the Energy Storage Database provides an approximate indication of the battery industry and should not be construed as an accurate predictor of industry / market behavior. The data collected is not all inclusive of all commercialized manufacturers, does not include all of the projects a given manufacturer has completed, and does not include any emerging technologies that are under final stages of research and development (e.g. American Recovery and Reinvestment Act (ARRA), Advanced Research Projects Agency-Energy (ARPA-E) funding or stealth companies backed by venture capital (VC)s)3. 3.2.4 Performance Characteristics Key performance metrics for battery systems include:  Roundtrip efficiency – alternating current (AC-to-AC) efficiency of complete battery system, including auxiliary loads  Energy footprint – amount of physical real estate needed to supply certain amounts of energy in kWh per square feet  Cycle life – estimated effective useful life of operation the battery in operation  Storage capacity – sub-hourly or multiple hours of discharge times for systems  Discharge times – time response of battery system 3 Acronyms: ARRA = American Reinvestment and Recovery Act of 2009, ARPA-E = Advanced Research Projects Agency – Energy, VC = Venture Capitalists, PacifiCorp Energy Storage Screening Study 41 Final July 2014  Technology risks – general limitations and concerns of battery systems Data points collected by manufacturers are summarized in the Technology Matrix in Appendix A. 3.2.4.1 Roundtrip Efficiency Not all metrics will remain constant throughout a battery system operation and over its life cycle. For almost all technologies, temperature will play a role in performance. Roundtrip efficiencies are also not a constant value and are dependent on the battery State-of-Charge (SOC), temperature and system operations. Losses that are included in roundtrip efficiency estimates include the conversion and storage efficiency of each technology (e.g. voltaic, coulombic, chemical losses), power conversion system losses, transformer losses, and any auxiliary losses due to support equipment (e.g. pumping, cooling, heaters, etc.). It is also important to distinguish that performance characteristics are generally driven by application requirements – li-ion and dry cell systems have significantly higher roundtrip efficiencies of approximately 90% than does NaS at about 70% or flow batteries at about 60%. In terms of applications, it is the NaS and flow batteries that are generally recognized as providing energy storage in the multiple- hour range (e.g. between 5 to 8 hrs). Roundtrip efficiency is affected by the amount of auxiliary loads needed to support the overall battery system and also by inherent technology inefficiencies. As an example, the flow batteries have chemical inefficiencies because they utilize electrolytes as opposed to solid state cells like li-ion. Flow battery systems also have additional parasitic loads due to the operation of pumps that circulate the electrolyte through the cell stack. One other contributing factor to roundtrip efficiency includes standby losses that are characterized by self-discharge or by auxiliary loads from support equipment needed to keep battery systems on standby mode. Generally flow batteries (especially during idle time), li-ion and dry cells have the lowest self- discharge rate. 3.2.4.2 Energy Footprint The energy footprint (square feet per MWh) of battery systems varies considerably, from a few hundred square feet to a few thousand square feet per MWh, depending on technology type and design. Each manufacturer offers standard products, or containerized solutions, as well as custom-designed systems to fit system loads and the physical constraints of the installation (e.g. placing systems in electric utility closet rooms, basements). Solid-state technologies like the li-ion, dry cells, UltraBattery, and NaS will have slightly better energy density than flow battery technology. HDR advises to use caution when interpreting energy footprint metrics since data points provided by manufacturers range for systems upwards of 1 MW. There will be a fixed amount of real estate needed for every system regardless of MW rating that is dedicated to auxiliary and support equipment (i.e. Power Conversion Systems (PCS), heating, ventilation and air conditioning (HVAC) equipment, transformers), as well as general constraints (i.e. clearances, road access). Premium’s TransFlow2000 is currently offered as trailer system and the manufacturer will be offering modular 2.3- and 3-MW plant designs. Depending on the application, footprint may be reduced by constructing a building to house the battery systems rather than the shipping container modules that most manufacturers offer. It is anticipated that the solid-state battery technology’s energy footprint will scale more linearly than that of flow batteries for the reason that energy and power characteristics have been decoupled. Power is a PacifiCorp Energy Storage Screening Study 42 Final July 2014 function of electrode surface area and efficiency whereas energy is a function of usable electrolyte. For a flow battery system, a 1 MW plant operating at 1 hour or at 6 hours will have very different footprints. Differences are due to size of storage tanks, as the following illustrates for Premium’s VRB system:  1 MW at 1 hour = 3,200 square feet (sq. ft.) at 13 ft. tall (volume = 42,000 cubic ft.)  1 MW at 6 hours = 4,800 sq. ft. at 16 ft. tall (volume = 78,000 cubic ft.) Finally, it is anticipated that flow batteries will offer a greater level of flexibility in system sizing design considering independent characteristics. For example, a 1 MW / 1 MWh system requirement will yield very different energy footprints when comparing a NGK NAS system versus a Prudent VRB system. 3.2.4.3 Plant Life System plant life is the general expectation of the number of years that the battery plant is expected to function with proper operations and maintenance given throughout its service life. Plant life can be expressed in number of years, or more typical of the battery industry to be expressed and the number of cycles. Generally-speaking, one charge and one discharge make up one cycle. The solid state batteries generally have a life expectancy of 5 to 15 years before replacement, while flow batteries are expected to last 30 years. System operation, aside from the quality of active maintenance, would also play a significant role in determining plant life – i.e. a battery system operating at reduced Depth-of-Discharge (DOD) will have a longer life. Xtreme PowerCellTM cell curve is used as an example of exponentially-changing number of cycles at various DOD: Figure 21 - Typical Battery Life Cycle Curve State of Charge (SOC) Note that plant life claimed by manufacturers is a compendium of engineering projections, and laboratory testing, while some data points are empirical from field service of battery plants. The flow battery systems claim an indefinite amount of cycles, but have yet to have a battery plant operate for over 20 years – these numbers were instead derived scientifically from tests and research in a laboratory setting. Flow battery PacifiCorp Energy Storage Screening Study 43 Final July 2014 systems do not suffer from solids accumulated from electrochemical reactions as with other battery types thus theoretically having a longer life. UltraBattery’s life cycle is highly dependent on application. Their 3 MW frequency regulation project operates 5 to 6 full cycles a day, and is expected to last 5 years before cell replacement is required. 3.2.4.4 Storage Capacity Storage capacity, rated by the number of hours, varies by technology type and application. Ancillary services focusing on frequency regulation and instantaneous bridging power will have sub-hour requirements whereas bulk energy storage and renewables integration will have multiple-hour requirements. All manufacturers highly recommend that detailed system load modeling and detailed load studies be completed prior to entering design phase to allow each manufacturer to offer the best solutions. NGK’s NAS has a maximum storage capacity of 7.2 hours although standard practice is to limit discharge to 6 hours. Prudent’s and Premium’s flow battery systems have a maximum capacity of 5 hours for standard product offerings, although it is not uncommon to design systems beyond that storage capacity window. A123’s li-ion system is geared for two applications: high power requiring 25 minutes or less storage capacity, or the high energy requiring 4 hours or less storage capacity. Xtreme’s dry cell systems are focused on applications with 40 minutes or less storage capacity as well as multiple-hour systems up to 3 hours. Ecoult’s UltraBattery systems exhibited case studies with as little as a few seconds of discharge time up to 2-3 hours of peak shaving. 3.2.4.5 Discharge Time Discharge time is a standard measure for a battery energy storage system to reach full output from a state of zero output. This may be a critical consideration for time-sensitive, quick-acting, applications like frequency regulation. The fastest discharge time presented is 7 milliseconds for the ZnBr system followed by 20 milliseconds for the li-ion system, and finally 40 milliseconds for the VRB and UltraBattery sytems. Li-ion systems are generally not suited for quick discharges because it results in generation of immense amount of heat, greatly reducing their efficiency through parasitic loads. 3.2.5 System Details and Requirements All battery systems use inverters to convert between DC and AC currents. Power electronics (e.g. chargers, transducers) are used to monitor battery cell performance and control overall system performance in real-time. All of these components, and other ancillary control or electronic systems, make up the Power Conversion System (PCS). All manufacturers currently offer PCS design services in- house, and source manufacturing to other reputed components manufacturers like Dynapower, Parker Hannifin, ABB, S&C, GE, Satcon etc. All battery systems require auxiliary ventilation, road access and some form of telecommunication infrastructure (e.g. radio, telephone line or Local Area Network (LAN) infrastructure). Prudent’s VRB will require a building structure to house the battery system and associated support equipment. Premium’s ZnBr system is currently marketed as a self-contained trailer system, but it is anticipated that their modular MW-block solutions will also require housing structures. Many manufacturers offer either modular container housing or the ability to be built into an existing or planned structure. PacifiCorp Energy Storage Screening Study 44 Final July 2014 NGK’s NAS battery system will require an auxiliary heating source to maintain operating temperatures at 300 degrees Celsius, or 572 degrees Fahrenheit, when the system has idled for a given period of time. The temperature tolerance could not be ascertained. Auxiliary heating is required to keep the battery chemical in a molten state to avoid the phase change of NaS from liquid to solid. Generally, a 7.2-kW electric resistance heater is used to keep cells within required temperature limits only when the battery system is idle. At a system level, parasitic loads can be characterized as 50 kW per 1 MW capacity for its Storage Management System (SMS) and 144 kW (heating) or 56 kW (temperature maintenance mode) per 1 MW capacity for its block heater. Conversely, A123’s li-ion system will require auxiliary cooling for its system, but only during operation, as long as the ambient conditions are between 20 and 30 oC. Auxiliary cooling is needed because of inherent energy extraction inefficiencies of an electrochemical cell. A battery plant is typically accompanied by a chiller plant. Flow battery systems will generally require some form of cooling for its system. Premium’s TransFlow2000 trailer system comes equipped with an integrated chiller. Depending on climate zones, Prudent’s VRB plants may require an accompanying chiller plant under warm conditions. In addition, flow battery systems will have pumps to move electrolytes into each compartment. Prudent’s electrolyte supply pumps are controlled by a Variable Frequency Drive (VFD) and power draw cycles between 2.5 kW (standby) and 5 kW (full load operation). All data points presented by manufacturers on system requirements are summarized in the Technology Matrix in Appendix A. 3.2.6 Technology Risks Each battery technology shares a certain amount of risk associated with installation and operation. NGK’s NAS systems require a heating source when running idle, and a recent fire incident prompted NGK to upgrade battery internals and fire suppression systems accordingly. Its ceramic-aluminum bonds within the beta alumina cell are susceptible to corrosion gradually over a period of 15 years. Leakage of molten sulfur is unlikely, but has happened, and fires are now prevented by additional fuses, insulation boards within the units, and anti-fire boards between stacked modules. Xtreme’s battery system is generally limited to 50% depth of discharge, meaning that the battery’s charge may not drop below 50%. Prudent’s VRB system has a relatively larger footprint than other systems and may require additional space to accommodate a chiller plant depending on site climate. Both flow battery systems share the same life- limiting component in the form of a plastic substrate that lies between the anode and cathode, effectively creating two compartments. Premium’s plastic substrate is made out of a high porosity polyethylene that can degrade over time. Power electronics failure was a common concern among the manufacturers. 3.2.7 Capital, Operating and Maintenance Cost Data Capital costs were collected at the system level to better reflect actual costs associated with each battery system. Based on vendor information, all-in costs for a typical 10 MWh installation at a 6:1 MWh to MW ratio are estimated to be between $17 and $20 million. Subsequent cost numbers do not reflect any site civil development costs and do not include any permitting or planning study costs. Because flow batteries have greater design flexibility in terms of power and energy, cost data is presented on a per kWh basis. System costs, common units either in $ per kW or $ per kWh, should only be compared when examining PacifiCorp Energy Storage Screening Study 45 Final July 2014 battery systems for a particular application. For example, A123’s li-ion battery systems are quoted for High Power (15 minutes) and High Energy (up to 4 hours). Throughout its service life, it is anticipated that every battery plant will undergo standard and routine maintenance including general housekeeping, active and preventive maintenance on predominantly electrical equipment (e.g. infrared scanning, visual inspection, replacing capacitors, fans, thermistors). Systems with mechanical equipment such as auxiliary HVAC equipment may require more maintenance (e.g. replacing air filters, pressure transducers, valves). Battery cells/stacks will need replacement throughout the effective useful life of the battery plant. All manufacturers currently offer standard product warranties spanning no more than 2 years with an option for extension for a certain period of time, or on an annual basis. Xtreme’s dry cells have longer standard warranty than the rest at 5 years, although balance of plant is warranted for 2 years. Component change-out or system repair under warranty is generally carried out by the manufacturer or in some cases, a qualified field service representative. The forced outage rate of all battery systems generally ranges from 0.3% to 3%. Although Prudent and Xtreme currently do not have in-house, contracted, maintenance service capabilities, they do offer comprehensive training services to ensure system owners and operations teams gains an thorough of system performance. Operating costs can be further defined as follows: Fixed O&M: Fixed operations and maintenance costs take into account plant operating and maintenance staff as well as costs associated with facility operations such as building and site maintenance, insurances, and property taxes. Also included are general housekeeping, routine inspections of equipment performance and general maintenance of systems. For battery systems with auxiliary cooling equipment (i.e. chiller plants), additional maintenance costs over other battery types will be incurred. General O&M costs will also include spare parts, and component or equipment change-out (i.e. inverter fan filters once they get dusty). For all battery systems, fixed O&M cost will also include the cost of remote monitoring (i.e. cost of telecommunications carrier, secured web hosting / monitoring). Variable O&M: Variable cost includes the cost of corrective maintenance and other costs that are proportional to unit output. This will likely be, but not limited to, the diagnosing, investigation and testing of components, and the subsequent costs for corrective action. All cost and maintenance data available from the manufacturers are summarized in the Technology Matrix in Appendix A. 3.3 Compressed Air Energy Storage 3.3.1 CAES Technology Description Compressed Air Energy Storage consists of a series of motor driven compressors capable of filling a storage cavern with air during off peak, low load hours. At high load, on peak hours the stored compressed air is delivered to a series of combustion turbines which are fired with natural gas for power generation. Utilizing pre-compressed air removes the need for a compressor on the combustion turbine, allowing the turbine to operate at high efficiency during peak load periods. Compressed air energy storage is the least implemented and developed of the stored energy technologies. Only two plants are currently in operation, including Alabama Electric Cooperative’s (AEC) McIntosh PacifiCorp Energy Storage Screening Study 46 Final July 2014 plant (rated at 110 MW) which began operation in 1991. The McIntosh plant was mostly funded by AEC, but the project was partially subsidized by EPRI and other organizations. Dresser Rand supplied the compressors and recuperators and is the only known supplier to offer a compressor for the application with a reliable track record. The other plant in operation, the Huntorf facility, is located in Huntorf, Germany which utilizes an Alstom turbine. The equipment utilized in CAES plants, which includes compressors and gas turbines, is well proven technology used in other mature systems and applications. Thus, the technology is considered commercially available, but the complete CAES system lacks the maturity of some of the other energy storage options as a result of the very limited number of installations in operation. Two primary types of CAES plants have been implemented or are being reviewed for commercial operation: (a) diabatic and (b) adiabatic. In diabatic CAES, the heat resulting from compressing the air is wasted in the process. The air must be reheated prior to expansion. Adiabatic CAES stores the heat of compressions in a solid (concrete, stone) or a liquid (oil, molten salt) form that is reused when the air is expanded. Due to the conservation of heat, adiabatic storage is expected to achieve efficiencies of 70%. Both the McIntosh and Huntorf are diabatic CAES plants. One adiabatic plant is currently under development in Germany. Other CAES plants have been proposed but, as of yet, have not moved forward beyond conceptual design. These proposed projects include the Western Energy Hub Project, the Norton Energy Storage (NES) project, the PG&E Kern County CAES plant, and the ADELE CAES plant in Stassfut, Germany. The Western Energy Hub project, promoted by Magnum Energy, LLC (Magnum), is probably the most advanced CAES project under development in the U.S. The salt dome geology has been well characterized, as well as land acquisition and local and state permitting underway. The first phase of the Magnum project is for natural gas liquids (propane and butane) storage which broke ground in April 2013. This initial phase is expected in service in 2014, and will involve leaching out two caverns for propane and butane storage. The second phase of the project under development is construction of four additional solution-mined underground storage caverns capable of storing 54 billion cubic feet of natural gas. On March 17, 2011, the Federal Energy Regulatory Commission (FERC) issued an order granting Magnum a certificate of public convenience and necessity under section 7(c) of the Natural Gas Act (NGA) to construct and operate a natural gas storage facility and header pipeline. On February 22, 2011 the Bureau of Land Management (BLM) issued a Decision Record granting Magnum a Right of Way Grant for the header pipeline. Magnum will construct and operate a 61.5 mile header pipeline from its storage facility near Delta to Goshen, Utah. Magnum has also been granted all the necessary permits for construction and operation of the gas storage facility from the State of Utah. The final phase of the Western Energy Hub project is CAES, in conjunction with a combined-cycle power generation project. The CAES will utilize additional solution-mined caverns to store compressed air. Off- peak renewable generation will be used to inject air into the caverns which will be released during periods of peak power demand. The compressed air will be delivered to a combustion turbine, eliminating the need for a compressor on the combustion turbine, allowing the turbine to operate at high output and efficiency during peak load periods. Magnum plans a total of 1,200 MW of capacity spread across four 300 MW modules, with two days of compressed air at full load. Magnum anticipates an in-service date of around 2017-2018. PacifiCorp Energy Storage Screening Study 47 Final July 2014 The NES Project has been purchased by First Energy. The proposed project was to have an initial capacity of 270 MW, with a potential expanded capacity of 2700 MW project. The project site is located above a 600-acre underground cavern that was formerly operated as a limestone mine in Norton, Ohio. The geological conditions of the site have been assessed by Hydrodynamics Group and Sandia National Laboratories, and the integrity of the mine has been confirmed as a stable vessel for compressed air storage. In December 2012, First Energy suspended construction on the project due to unfavorable economic conditions including low cost of power prices and insufficient demand. As of September 2013, the Ohio Power Siting Board invalidated the certificate at this site. PG&E has been awarded a $25M grant from the Department of Energy (DOE) to research and develop a CAES plant. The California Public Utility Commission (CPUC) has matched the grant and supplied an additional $25M; the California Energy Commission has supplied an additional $1M of support. The proposed project is a 300 MW plant in Kern County, CA. The first phase is reservoir feasibility study that is scheduled to be completed in Q4 2015. If the project proceeds, the plant is estimated to be operational in 2020. It has not been stated whether the proposed plant will be diabatic or adiabatic and is likely subject to the outcome of the feasibility study. The ADELE project is an adiabatic CAES plant is Stassfort, Germany. The project is planned to have a storage capacity of 360 MWh, with a total output of 90 MW and projected efficiency of 70%. The project is part of the Federal Government’s Energy Storage Initiative and is funded by the German Federal Ministry of Economics and Technology. The initial development phase is funded with $17M (12M Euro) and was expected to be completed by 2013. The total project was expected to have duration of 3.5 years and a cost of $56M (40M Euro). The initial project development is now slated for completion in 2016; the reason for the delay has not been disclosed and the project is still progressing. 3.3.1.1 Technology Risks CAES has performed very well at the AEC McIntosh plant and therefore little risk is perceived from a technical standpoint provided the proper equipment suppliers are utilized and design factors are considered. Dresser Rand provided the majority of the equipment for the AEC McIntosh plant. The construction of the Huntorf facility in Germany began construction in 1976, a time when gas turbines were not commercially implemented so the Huntorf turbine is a modified steam turbine. Alstom does currently offer a gas turbine for compressed air applications, but none are currently in operation. As such, there is limited potential to competitively bid the major equipment without exposing risk for utilizing first-of-a-kind equipment from an unproven supplier. Another significant risk involves the ability to identify an energy storage geological formation with integrity and accessibility. Adiabatic designs are under development and introduce new risks into the design of a CAES plant. There are additional heat-storage devices and components in the system that will increase the design complexity of the system. The compressed air is expected to have temperatures in excess of 1,100F, which will require alloyed and/or ceramic materials. There is still uncertainty regarding materials of construction for the compressors and heat storage that would optimize the design. GE Oil & Gas is currently developing an air compressor and air-turbine for use in the ADELE project. A partnership between German companies Zublin and Ooms-Ittner-Hof are developing the heat storage capabilities. PacifiCorp Energy Storage Screening Study 48 Final July 2014 3.3.2 Performance Characteristics During discharge of the compressed air, the AEC McIntosh plant achieves a fuel heat rate of roughly 4,550 Btu/kWh (HHV). Dresser Rand has made improvements to their CAES equipment offering since the commissioning of the McIntosh plant. These improvements could result in a heat rate of 4,300 Btu/kWh (HHV) but have not been proven on a commercial scale application that is in operation. The primary function of the McIntosh plant is for peak shaving. The ADELE plant will have similar operating characteristics to McIntosh and Huntorf. The compressors are being designed for compression of up to 1,450 psia; however, the planned storage pressure is 1,015 psia. The total storage capacity is expected to be 360 MWh with an electrical output of 90MW; equivalent to 4 hours of energy storage at full utilization. The big improvement in the adiabatic plant is the round-trip efficiency. The ADELE plant is projected to have a total efficiency in excess of 70%; compared to AEC McIntosh (54%) and Huntorf (42%). The efficiency gains are a result of capturing the heat in the adiabatic process. 3.3.2.1 Site Elevation Site elevation does impact the performance characteristics of a diabatic CAES plant. In simple cycle combustion turbine plants, the turbine output decreases with increased elevation as a result of the lower air density. Since gas turbines are standardized designs, the compressor and turbine sections are not modified or designed for specific site applications. The compressor size and compression ratio is therefore fixed and the flow rate of air through the compressor decreases as ambient air pressure decreases (i.e. elevation increases). The Compression ratio is the ratio between the discharged air pressure and the inlet air pressure to the compressor. At higher elevations, the compressed air on the turbine side enters the inlet of the gas turbine at a lower inlet pressure as a result of the fixed compression ratio. In turn, less fuel is combusted due to lower air flow rates. Thus, power generation decreases by as much as 20 percent when comparing a combustion turbine at sea level and one at 6,000 feet in elevation. The same fundamentals apply to CAES technology, except that there is more flexibility in the compressor design which can be decoupled from the gas turbine if desired. This allows a compressor to be designed to achieve a higher compression ratio for higher elevation applications, although the power required to drive the compressor will also increase. On the gas turbine side, the power output can actually increase slightly at higher elevations as a result of a lower turbine exhaust pressure, assuming the inlet pressure is the same as at lower elevations. The CAES performance is identified in the Technology Summary Matrix at 6,000 feet elevation assuming a plant located in the PacifiCorp service area. 3.3.2.2 Reliability/Availability Varying sources over varying time periods report that the AEC McIntosh plant offers availability from 86 to 95 percent. At this facility, every air compressor is mounted to a single shaft that is coupled to a combined motor/generator unit via a clutch. Likewise, every turbine is also mounted to a single shaft that is coupled to a combined motor/generator unit via a clutch. Depending on the operational mode, compression or power generation, the motor/generator unit is either coupled to the air compressors or turbines but not both. AEC not only recommends separating the motor for compression and generator for PacifiCorp Energy Storage Screening Study 49 Final July 2014 electrical production, but also recommends separating each air compressor and turbine to alleviate maintenance complexities and to increase reliability. During the design of a CAES plant, careful consideration regarding materials of construction must be undertaken such that materials do not fail or need replacement in an unexpected time frame due to corrosion and abrasive erosion. For example, if a salt cavern is utilized, the turbine manufacturers’ specifications regarding the quantity of salts in the incoming air must be considered. Additionally, the Huntorf design offers dual storage caverns which have enabled the plant to achieve approximately 90 percent plant availability. The Huntorf plant experienced corrosion problems with the storage cavern wells; thus, having two storage caverns enabled operation of the plant while one storage cavern was inoperable due to a well head repair. Due to the high temperatures (>1,100F) of adiabatic plant designs, specialized materials of construction could result in extended lead times for the fabrication of equipment. This would also result in increased cost of the plant to keep critical spares on-site. 3.3.2.3 Start Times Compressed air energy storage requires initial electrical energy input for air compression and utilizes natural gas for combustion in the turbine. The McIntosh plant offers fast startup times of approximately 9 minutes for an emergency startup and 12 minutes under normal conditions. As a comparison, simple cycle peaking plants consisting of gas turbines also typically require 10 minutes for normal startup. The Huntorf CAES plant has been designed as a fast-start and stand-by plant; it can be started and run at full-load in 6 minutes. 3.3.2.4 Emission Profiles/Rates It is expected that CAES will have emissions similar to that of a simple cycle combustion turbine, except reduced by approximately 60 to 70 percent due to reduced natural gas consumption on a per kWh basis. The diabatic plants, such as AEC McIntosh and Huntorf, require additional natural gas firing for the combustion turbine and for reheating the compressed air. Adiabatic plants, such as ADELE, will not require supplemental firing of natural gas for heating the air, and will have an overall lower plant emissions. 3.3.2.5 Air Quality Control System Design Dry low mono-nitrogen oxides (NOx) combustion technology can be utilized for control of NOx emissions on the combustion turbine for CAES. If NOx emissions are pushed lower such that dry low NOx combustion technology is insufficient, CAES technology permits use of a selective catalytic reduction (SCR) module, but in this case it would likely be integrated into the recuperator design, permitting close control of the catalyst temperature. 3.3.3 Geological Considerations There are three types of geological formations generally considered for storing compressed air: salt domes, aquifers, and rock caverns. These formations can then be classified as either constant volume or constant pressure caverns. Constant pressure caverns utilize surface water reservoirs to maintain a constant cavern pressure as the compressed air displaces the water when it is injected into the cavern. PacifiCorp Energy Storage Screening Study 50 Final July 2014 Constant volume caverns have a fixed volume and therefore the air pressure in the cavern decreases as compressed air is released from the cavern. Figure 22 depicts the aforementioned geological formations generally considered for compressed air energy storage. Figure 22 - CAES Geological Formations Figure 23 depicts an overall map of the continental United States with areas that contain potential geological formations favorable for CAES. Figure 23 - Potential Geological Formations Favorable for CAES 3.3.4 Capital, Operating, and Maintenance Cost Data The project schedule for a CAES plant is highly dependent on the manufacturer’s lead times for equipment. For the most part, a project should be able to be implemented in a time frame similar to that of a combined cycle combustion turbine plant, if a recuperator is to be implemented, provided the Air Shaft Salt Dome Storage Cavern Hard Rock Storage Cavern Water Air Reservoir Water Water Column Air Water Aquifer Hard Rock Layer Air Shaft CAE Plant Air Hard Rock Layer Hard Rock Layer CAE Plant CAE Plant Constant Volume Constant Pressure Constant Pressure PacifiCorp Energy Storage Screening Study 51 Final July 2014 compressed air storage geological formation is available. If a project forgoes a recuperator, the project schedule can be reduced by four to six months. If a salt cavern must be drilled and solution mined before implementation, this time frame becomes dependent upon the process used to permit and prepare the cavern. Solution mining the cavern may take up to 18 to 24 months, but can be done in conjunction with construction of the CAES plant. Based on information gathered from similar projects in development, expected project duration is summarized in Table 6. Table 6 - CAES Typical Project Schedule CAES options can vary considerably depending upon the specific project. The power island for a CAES option is typically small and similar in size to that of a combined cycle plant. Construction of the underground storage reservoir is a significant contributor to the cost of CAES. Aquifers and depleted gas reservoirs are the least expensive storage formations since mining is not necessary. Salt caverns are the most expensive storage formations since solution mining is necessary before storage. Storage formations vary in depth but most formations that can currently be utilized range between 2,500 ft to 6,000 ft below the earth’s surface. Storage formations vary naturally in size but storage caverns can be appropriately mined to achieve a specific storage capacity. 3.3.4.1 Capital Costs The McIntosh project was commissioned in 1991 and at that time cost $65 million. Since the McIntosh plant offers 110 MW of net power, the plant cost was $590/kW. The Iowa Stored Energy Park (ISEP) was originally estimated at approximately $400 million for a plant size of 270 MW. A detailed Sandia report on the lessons learned from the ISEP CAES plant is available in Appendix D. Projected cost information has not been made available for the PG&E Kern County and ADELE CAES plants. Due to the limited number of CAES projects completed and vague task descriptions often associated with project costs as well as external funding that was provided for McIntosh, HDR estimates that CAES project capital costs would be in the range of $1,600/kW to $2,200/kW for a 300 to 500 MW diabatic CAES plant, including ten hours of solution-mined storage capacity. The technology for an adiabatic plant has not been made public and a capital cost cannot be accurately projected at this time; the total capital cost will be greater than a diabatic plant. HDR assumes project capital costs to include project direct costs associated with equipment procurement, installation labor, and commodity procurement as Task Duration Test well 10 mo. Preliminary design 3 mo. Permitting 12 mo. Final design 6 mo. Construction 24 mo. Sum of Tasks 55 mo. PacifiCorp Energy Storage Screening Study 52 Final July 2014 well as construction management, project management, engineering, and other project and owner indirect costs. This estimate does not include storage cavern cost. Values are presented in 2014 dollars. 3.3.4.2 Operating Costs Fixed O&M: Fixed operations and maintenance costs take into account plant operating and maintenance staff as well as costs associated with facility operations such as building and site maintenance, insurances, and property taxes. Also included are the fixed portion of major parts and maintenance costs, spare parts and outsourced labor to perform major maintenance on the installed equipment. The estimated fixed O&M costs for the ISEP CAES plant would be $18.78/kW in 2014 USD. Fixed O&M costs are expected to be similar for a diabatic CAES facility. An adiabatic plant would have greater fixed O&M costs due to increased complexity in the system design. Variable O&M: The non-fuel related variable O&M costs for the ISEP CAES plant is estimated to be $2.28/MWh in 2014 USD. Variable O&M costs are expected to be similar for a diabatic CAES facility. Additional variable O&M for fuel and electric costs should be considered when evaluating a diabatic plant. Fuel and electric costs should be considered based on existing gas and power purchase agreements or local market pricing. 3.4 Flywheels 3.4.1 Flywheel Technology Description Flywheels are electromechanical energy storage devices that operate on the principle of converting energy between kinetic and electrical states. A massive rotating cylinder, usually spinning at very high speeds, connected to a motor stores usable energy in the form of kinetic energy. The energy conversion from kinetic to electric and vice versa is achieved through a variable frequency motor or drive. The motor accelerates the flywheel to higher velocities to store energy, and subsequently slows the flywheel down while drawing electrical energy. Flywheels also typically operate in a low vacuum environment to reduce inefficiencies. Superconductive magnetic bearings may also be used to further reduce inefficiencies. Generally, flywheels are used for short durations to supply backup power in a power outage event, or for regulating voltage and frequency. 3.4.2 Manufacturers A quick market survey of the energy storage industry reveals that there is only one flywheel technology manufacturer that has achieved utility market commercialization: Beacon Power Corporation with their Generation 4 Flywheels. Newer technology flywheel systems utilize a carbon fiber, composite flywheel that spins between 8,000 and 16,000 revolutions per minute (RPM) in an extremely low friction environment, near vacuum, using hybrid magnetic bearings. Flywheels store energy through its mass and velocity. Flywheels are recognized for potentially long service life, fast power response and short recharge times. They also tend to have relatively high turnaround efficiency on the order of 85%. This energy storage technology is classified as commercial in regards to utility applications. Beacon offers its flywheel technology and balance of system plants as the Smart Energy 25 product. In 2011, the company entered bankruptcy protection. In 2012, Beacon’s assets, including the 20 MW PacifiCorp Energy Storage Screening Study 53 Final July 2014 Stephentown NY storage plant (Figure 24), were bought by a private equity firm, Rockland Capital. Beacon offers turn-key solutions in the US and Europe, and also provides in-house operating and maintenance services. Figure 24 - Flywheel Plant Stephentown, New York 3.4.3 Performance Characteristics A few performance characteristics of flywheels include: low lifetime maintenance, operation can typically be of high number of cycles, 20-year effective useful life and since kinetic energy is used as the storage medium, there are no exotic or hazardous chemicals present. Roundtrip AC-to-AC efficiency of the system is in the order of 85% with primary parasitic loads being the Power Conversion System (PCS) and internal cooling system, among the mechanical and friction losses of the system. Beacon estimates the energy losses through a flywheel plant to be in the order of 7% or less of energy throughput of the plant. Primary losses are intrinsic, and include friction (between rotor and environment) and energy conversion losses (generator losses including windings, copper, induction). Energy footprint for flywheels is generally large and comparable to that of pumped hydropower. Plant life is expected to be 125,000 cycles (at 100% DOD) over a period of 25 years with no change in energy storage capacity resulting in a high amount of energy throughput throughout its effective useful life. Flywheel’s largest limitations are its large energy footprint and its relatively short energy storage duration of 15 minutes or less per system. System response times are less than 4 seconds and ramp up/down rates can be 5 MW per second. This makes it an ideal candidate to serve in the frequency regulation services to the grid operator while maintaining reliability. According to Beacon, one technology risk associated with flywheel systems lie in its power electronics modules which have statistically failed once every 150,000 PacifiCorp Energy Storage Screening Study 54 Final July 2014 hours of operations. There is also risk associated with catastrophic flywheel failure. Two flywheels failed at Stephentown soon after installation. 3.4.4 Manufacturer Pros and Cons Beacon is considered in the industry as a pioneer in developing utility scale flywheel energy storage systems. To date, the company has five projects in the U.S. with a nameplate capacity of 26 MW. A significant portion of Beacon’s services are focused on regulation services. Another Beacon flywheel energy storage project (20 MW) is currently under construction in Hazle Township, PA. Additionally, Beacon is studying the implication of integrating a 200-MW flywheel energy storage system at a wind farm in Ireland. 3.4.5 Capital, Operating and Maintenance Cost Data Capital and operating cost data points from Beacon Power Corporation remains proprietary and cannot be disclosed unless a Non-Disclosure Agreement (NDA) has been signed and executed. However, data points from publicly-available documents suggest that the 20 MW Beacon flywheel plant is estimated to cost $50 million. This yields $2,400 per installed kW. Throughout its service life, it is anticipated that the flywheel system will require standard and routine maintenance including general housekeeping and preventive maintenance on its electrical equipment. The flywheel plant will require telecommunications infrastructure (e.g. radio, telephone or local area network (LAN) to allow for remote monitoring. 3.5 Liquid Air Energy Storage (LAES) 3.5.1 LAES Technology Description LAES uses off-peak electricity to cool air from the atmosphere to minus 195 °C, the point at which air liquefies. The liquid air, which takes up one-thousandth of the volume of the gas, can be kept for a long time in a large vacuum flask at atmospheric pressure. At times of high demand for electricity, the liquid air is pumped at high pressure into a heat exchanger, which acts as a boiler. Either ambient air or low grade waste heat is used to heat the liquid and turn it back into a gas. The massive increase in volume and pressure from this is used to drive a turbine to generate electricity. 3.5.2 LAES Performance In isolation the process is only 25% efficient, but this can be increased (to around 50%) when used with a low-grade cold store, such as a large gravel bed, to capture the cold generated by evaporating the cryogen. The cold is re-used during the next refrigeration cycle. Efficiency is further increased when used in conjunction with a power plant or other source of low-grade heat that would otherwise be lost to the atmosphere. A 300 kW, 2.5MWh storage capacity pilot cryogenic energy system developed by researchers at the University of Leeds and Highview Power Storage, that uses liquid air (with the CO2 and water removed as they would turn solid at the storage temperature) as the energy store, and low-grade waste heat to boost the thermal re-expansion of the air, has been operating at a biomass power station in Slough, UK, since 2010. The efficiency is less than 15% for this pilot plant. PacifiCorp Energy Storage Screening Study 55 Final July 2014 3.6 Supercapacitors 3.6.1 Supercapacitor Technology Description Supercapacitors bridge the gap between conventional capacitors and rechargeable batteries. They have energy densities that are approximately 10% of conventional batteries, while their power density is generally 10 to 100 times greater. This results in much shorter charge/discharge cycles than batteries. Additionally, they will tolerate many more charge and discharge cycles than batteries. Supercapacitors have advantages in applications where a large amount of power is needed for a relatively short time, where a very high number of charge/discharge cycles or a longer lifetime is required. Typical applications range from milliamp currents or milliwatts of power for up to a few minutes to several amps current or several hundred kilowatts power for much shorter periods. Supercapacitors do not support AC applications. 3.6.2 Supercapacitor Performance Supercapacitors support a broad spectrum of applications, including:  Stabilizing power supply in hand-held devices with fluctuating loads.  Providing backup or emergency shutdown power to low-power equipment such as RAM, SRAM, micro-controllers and PC Cards.  Power for cars, buses, trains, cranes and elevators, including energy recovery from braking, short- term energy storage and burst-mode power delivery.  Providing uninterruptible power supplies where supercapacitors have replaced much larger banks of electrolytic capacitors.  Providing backup power for actuators in wind turbine pitch systems, so that blade pitch can be adjusted even if the main supply fails.  Stabilizing within milliseconds grid voltage and frequency, balancing supply and demand of power and managing real or reactive power. 3.7 Superconducting Magnet Energy Storage (SMES) 3.7.1 SMES Technology Description Superconducting Magnetic Energy Storage (SMES) systems store energy in the magnetic field created by the flow of direct current in a superconducting coil which has been cryogenically cooled to a temperature below its superconducting critical temperature. A typical SMES system includes three parts: superconducting coil, power conditioning system and cryogenically cooled refrigerator. Once the superconducting coil is charged, the current will not decay and the magnetic energy can be stored indefinitely. The stored energy can be released back to the network by discharging the coil. The power conditioning system uses an inverter/rectifier to transform alternating current (AC) power to direct current or convert DC back to AC power. The inverter/rectifier accounts for about 2–3% energy loss in each direction. PacifiCorp Energy Storage Screening Study 56 Final July 2014 3.7.2 SMES Performance SMES loses the least amount of electricity in the energy storage process compared to other methods of storing energy. SMES systems are highly efficient; the round-trip efficiency is greater than 95%. Due to the energy requirements of refrigeration and the high cost of superconducting wire, SMES is currently used for short duration energy storage. Therefore, SMES is most commonly devoted to improving power quality. The most important advantage of SMES is that the time delay during charge and discharge is quite short. Power is available almost instantaneously and very high power output can be provided for a brief period of time. There are several small SMES units available for commercial use and several larger test bed projects. Several 1 MWh units are used for power quality control in installations around the world, especially to provide power quality at manufacturing plants requiring ultra-clean power, such as microchip fabrication facilities. These facilities have also been used to provide grid stability in distribution systems. In northern Wisconsin, a string of distributed SMES units were deployed to enhance stability of a transmission loop. The transmission line is subject to large, sudden load changes due to the operation of a paper mill, with the potential for uncontrolled fluctuations and voltage collapse. PacifiCorp Energy Storage Screening Study 57 Final July 2014 4 COMPARISON OF STORAGE TECHNOLOGIES HDR has performed an initial comparison of the energy storage technologies discussed in this document. The full comparison can be seen in the energy storage matrix in Appendix A. Table 7 below lists some of the key criteria that were compared when considering these technologies. Table 7 - Energy Storage Comparison Summary Pumped Storage Hydro (Three sites) Batteries Compressed Air Energy Storage Range of power capacity (MW) for a specific site 600 – 1,500 1-32 100+ Range of energy capacity (MWh) 5,280 – 16,500 Variable depending on DOD 800+ Range of capital cost ($ per kW ) $1,700-$2,500 $800-$4,000 $2,000-$2,300 Year of first installation 1929 1995 (sodium sulfur) 1978 The following sections provide comments on the overall commercial development of the technology, the applications suited to each technology, space requirements for each technology, performance characteristics, project timelines, and capital, operating and maintenance costs. 4.1 Technology Development Figure 25 below by the California Energy Storage Association (CESA) illustrates the installed capacity of various energy storage technologies worldwide. Pumped storage is by far the most mature and widely used energy storage technology used not only in the US, but worldwide. In the U.S., pumped storage accounts for over 20,000 MW of capacity. By comparison, there is only one existing CAES facility in the U.S., with a capacity of 110 MW. Sodium-sulfur (Na-S) batteries have been used in Japan with the largest installation supplying approximately 34 MW of capacity for 6-7 hours of storage; this technology is gaining popularity in the U.S. Sixteen MW of lithium-ion (Li-ion) batteries have also recently been installed in Chile, and a 2-MW pilot project has been executed in the U.S. CAES systems, batteries, super capacitors, flywheels, and pumped storage were compared in a number of reports by Sandia National Laboratories (Sandia), Pacific Northwest National Laboratories (PNNL), and by the California Energy Storage Association (CESA). PacifiCorp Energy Storage Screening Study 58 Final July 2014 Figure 25 - Current Worldwide Installed Energy Storage Facility Capacity (Source: CESA) 4.2 Applications Pumped storage and CAES are considered to be the only functional technologies suitable for bulk energy storage as stand-alone applications. Bulk energy storage can be considered multi-hour, multi-day or multi-week storage events. Batteries and flywheels are most functional as a paired system with variable generation resources or for distributed energy storage on a smaller kW and kWh basis. Each of the technologies is capable of providing ancillary services such as frequency regulation and other power quality applications with bulk storage technologies also able to provide system load following and ramping capabilities. 4.3 Space Requirements Space requirements for energy storage systems vary depending upon capacity and power, and it is often difficult to perform an apples-to-apples comparison of the space requirements for the four technologies discussed above. Pumped storage and CAES are capable of much higher capacities and total energy storage and therefore their project footprint is substantially higher. For example, Table 8 below indicates the surface space requirements for comparable 20,000 MWh facilities: a 1,000-MW, 20-hour pumped storage plant (including upper and lower reservoirs), a Li-ion battery field, and a Na-S battery field. The space required for a pumped storage facility, including reservoirs, is somewhat less in acreage than a Na- S battery field, and far less than that of a Li-ion installation. The artist’s rendering in Figure 26 illustrates Pumped Hydro 98.3% Thermal 0.8% Compressed Air 0.4% Batteries 0.4% Flywheels and Others 0.2% Other 1.7% Current Worldwide Installed Energy Storage Capacity Note: Plotderived from data included in CESA, "Bolstering California's Economy with AB 2514", Page 3. Note: Plotderived from data included in CESA, "Bolstering California's Economy with AB 2514", Page 3. PacifiCorp Energy Storage Screening Study 59 Final July 2014 the number and size of the Li-ion batteries necessary to store 20,000 MWh of energy. The resulting 1,100 acres would be equivalent to approximately 833 football fields. For scale, a typical pumped storage powerhouse is indicated in the foreground. Table 8 - Space Required for 20,000 MWh of Energy Storage Project Type Approximate Footprint (Acres) Sodium Sulfur Batteries 270 Li-ion Battery Field 1,100 Pumped Storage Reservoirs 220 Figure 26 - Li-ion Battery Field and a Hydroelectric P/S Plant for 20,000 MWh of Storage (Source: HDR) 4.4 Performance Characteristics Project capacity and duration are the most important characteristics for bulk energy storage. For reference, Figures 27 and 28 illustrate the current capability of energy storage technologies. Included in these figures are pumped storage, CAES, various battery technologies flywheels as well as capacitors. Figure 27 is derived from Figure 28 and utilizes the same data, though plotted on a linear scale versus a log-log scale to better reflect the real-time MW and MWh capability of the different technologies. Figure 27 allows for a truer comparison of technologies with smaller capacities and discharge times to larger, longer duration energy storage systems. Figure 28 allows for a closer view of the smaller energy storage technologies. PacifiCorp Energy Storage Screening Study 60 Final July 2014 0 500 1,000 1,500 2,000 2,500 0 50,000 100,000 150,000 200,000 Ca p a c i t y (M W ) Energy Storage (MWh) Installed and Planned Energy Storage Systems in the US (ESA and HDR) Pumped Storage CAES Li Ion‐ Batteries NaS‐ Batteries ZnBr‐ Batteries VRB‐ Batteries Linear Scale Source: Electricity Storage Association Technical Working Group and HDR Engineering(Pumped Storage Only ) Figure 27 - Current Energy Storage Technology Capabilities in Real Time (Source: HDR) PacifiCorp Energy Storage Screening Study 61 Final July 2014 Figure 28 - Current Energy Storage Technology Capabilities (Log-Log Scale) (Source: Electricity Storage Association) 4.5 Project Timeline Project timelines vary widely for the various options. Pumped storage lead times require a FERC licensing process which takes on average 5 years. An additional five years is typically required for construction. Greenfield closed loop systems are expected to be shorter to license. There are also efforts within the industry to reduce licensing times and develop more streamlined processes. An example pumped storage development schedule is attached to this document in Appendix B. The timelines for CAES are on the order of 2 years. For both pumped storage and CAES it is assumed that a project location has been identified, and for CAES, the geology of the cavern has been verified. Batteries and flywheels have no licensing requirements and fewer restrictions on land use, so their development times are significantly shorter, on the order of 1 year. 4.6 Cost There are a number of challenges associated with comparing the different types of energy storage technology. While a conscientious effort was made to discuss the technologies in terms of similarly sized capacities and durations, this comparison is somewhat difficult as the maximum hours of available storage and maximum capacity vary widely from 1 or 2 MW for a lithium-ion battery to over 1,000 MW 0.001 0.010 0.100 1.000 10.000 100.000 1,000.000 0. 0 0 1 0. 0 1 0 0. 1 0 0 1. 0 0 0 10 . 0 0 0 10 0 . 0 0 0 1, 0 0 0 . 0 0 0 10 , 0 0 0 . 0 0 0 10 0 , 0 0 0 . 0 0 0 Ca p a c i t y (M W ) Energy Storage (MWh) Installed and Planned Energy Storage Systems In the US (ESA and HDR) Pumped Storage CAES Li Ion‐ Batteries NaS‐ Batteries ZnBr‐ Batteries VRB‐ Batteries Source: Electricity Storage Association Technical Working Group and HDR Engineering(Pumped Storage Only ) Logarithmic Scale PacifiCorp Energy Storage Screening Study 62 Final July 2014 for a pumped storage project. As noted earlier, many of these storage systems are still undergoing significant product development, and the maximum storage, capacity, lifetime, capital costs, and lifecycle costs of these technologies have yet to be determined. Also for pumped storage and CAES, site specific conditions can significantly impact the cost and spatial needs for any given project. These challenges emphasize the idea that a portfolio of many different storage technologies may be needed. Table 9 and Figure 29 were developed by HDR based on the information presented in the matrix in Attachment A. While this information is helpful in understanding the capital and O&M costs on a $ per kW basis, for some technologies, especially batteries, capital costs are better represented with both capacity (kW) and storage (kWh) elements. The capital cost per kW is shown in Table 9 below. Table 9 - Summary of Cost and Capacity Data (2014 $US) Pumped Storage A123 Li-Ion NGK NAS Prudent VRB Xtreme Dry Cell Premium ZnBr Ecoult Adv. Pb- Acid CAES System Cost ($/kW and/or $/kWh) $1,700- $2,500 per kW $800 - $1,000 per kW (High Power) $800 - $1,200 (High Energy) per kWh $4,000 per kW $675 per kWh $1,900 - 2,100 per kW $1,500 - $2,200 per kWh ~$1,700 per kW, highly dependent on application $2,000- $2,300 per kW Rated System (MW) 1000 1 (High Power) 89 (High Energy) 1 1 1 0.5 1 100+ Rated Capacity (hrs) 8 - 10 0.25 (High Power) 4(High Energy) 7.2 max (standard discharge is 6) 1 0.67 to 2 1 40 ms to 3 hours 8 Capital cost is one initial indicator of project economics, but long-term annual O&M costs may provide a more comprehensive representation of financial feasibility. Figure 29 compares annual costs per kW of various technologies. This figure was updated from the 2011 IRP to escalate costs to 2014 USD by a factor of 6%. Because of the significant difference in capacity of the technologies, the figure is shown in a logarithmic scale. A linear version of the plot is shown in the upper left corner of the figure. Pumped storage O&M costs vary from site to site as discussed above, but economy of scale keeps the O&M cost per kW low. The pumped storage costs represented in Figure 29 are for a 1,000 MW project. CAES’s O&M costs are estimated at 4% of the overall installed cost. The operating and maintenance costs associated with batteries are high, but vary depending upon the technologies. As battery technology develops further, and grid scale installations continue, a better understanding of the costs associated with operation and maintenance will be achieved. PacifiCorp Energy Storage Screening Study 63 Final July 2014 Figure 29 - Operation and Maintenance Costs for Energy Storage Technologies 5 CONCLUSIONS A number of technologies would be required to smooth variable energy resources, including bulk storage, distributed storage, and transmission system improvements. While there is much debate about the application of new energy storage technologies, for high capacity applications greater than 50 MW, pumped storage represents the least-cost grid-scale storage technology. Pumped Storage is a proven and attractive option in terms of space required, total life cycle costs, and proven MW and MWh capacity. Although CAES has the potential to provide relatively similar bulk storage capabilities, its limited heritage, low efficiency and requirement for geologic-specific siting makes it difficult to implement. For applications less than 50 MW with the goal towards improving the performance of individual, variable energy sources, or a group of such sources, battery and flywheel systems become a feasible alternative. Additionally, battery and flywheel systems have been successfully employed with lower capacities and shorter durations, which make them well suited to short-term storage for general grid stabilization and power quality needs on the order of minutes to a few hours. A variety of complementing technologies will be required to fully address the effects of variable renewable energy, including bulk storage, distributed storage, consolidated balancing areas, and improvements to the interconnecting transmission system. PacifiCorp Energy Storage Screening Study 64 Final July 2014 References 1. Black and Veach, Yale Hydroelectric Plant: Plant Upgrade and Expansion: Preliminary Engineering. 1992. 2. 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Compressed Air Energy Storage, PG&E; http://www.pge.com/en/about/environment/pge/cleanenergy/caes/index.page 15. Huntorf Profile, E.ON; http://www.eon.com/en/about-us/structure/asset-finder/huntorf.html 16. RWE Energy ADELE; http://www.rwe.com/web/cms/en/365478/rwe/innovation/projects- technologies/energy-storage/project-adele-adele-ing/ 17. Lessons Learned from Iowa: Development of a 270 MW CAES Storage Project in MISO; Sandia National Laboratories; June 2012; http://www.sandia.gov/ess/publications/120388.pdf 18. "Process". company website. Highview Power Storage. Retrieved 2012-10-07. 19. Roger Harrabin, BBC Environment analyst (2012-10-01). "Liquid air 'offers energy storage hope'". BBC News, Science and Environment. BBC. Retrieved 2012-10-02. PacifiCorp Energy Storage Screening Study 65 Final July 2014 20. Cheung K.Y.C, Cheung S.T.H, Navin De Silvia R.G, Juvonen M.P.T, Singh R, Woo J.J. Large-Scale Energy Storage Systems. Imperial College London: ISE2, 2002/2003. 21. "Maxwell Technologies Ultracapacitors (ups power supply) Uninterruptible Power Supply Solutions". Maxwell.com. Retrieved 2013-05-29. 22. International Energy Agency, Photovoltaic Power Systems Program, The role of energy storage for mini-grid stabilization, IEA PVPS Task 11, Report IEA-PVPS T11-02:2011, July 2011 23. J. R. Miller, JME, Inc. and Case Western Reserve University, Capacitors for Power Grid Storage, (Multi-Hour Bulk Energy Storage using Capacitors) 24. Wolsky, A., M. (2002). The status and prospects for flywheels and SMES that incorporate HTS. Physica C 372–376, pp. 1,495–1,499. 25. "ADELE – Adiabatic compressed-air energy storage (CAES) for electricity supply". Retrieved December 31, 2011. 26. CAES:McIntosh Power Plant, PowerSouth Energy Cooperative, 2010, retrieved April 15, 2012 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 603 APPENDIX R – UNCERTAINTY PARAMETERS STUDY In its 2013 IRP, the Company indicated its intent to re-estimate key stochastic parameters for purposes of ABB’s Planning and Risk (PaR) model runs used in the 2015 IRP. As such, PacifiCorp hired Erin O’Neill, an independent consultant, to re-estimate short-term stochastic parameters (volatilities, mean reversions, and correlations) for load, natural gas prices, electricity prices, and hydro generation. PaR, as used by PacifiCorp, develops portfolio cost scenarios via computational finance in concert with production simulation. The model stochastically shocks the case-specific underlying electricity price forecast as well as the corresponding case-specific key drivers (e.g., natural gas, loads, and hydro) and dispatches accordingly. Using exogenously calculated parameters (i.e., volatilities, mean reversions, and correlations), PaR develops scenarios that bracket the uncertainty surrounding a driver; statistical sampling techniques are then employed to limit the number of representative scenarios to 50. The stochastic model used in PaR is a two- factor short run mean reverting model. For this IRP, PacifiCorp used short-run stochastic parameters; long-run parameters were set to zero since PaR cannot re-optimize its capacity expansion plan. This inability to re-optimize or add capacity can create a problem when dispatching to meet extreme load and/or fuel price excursions, as often seen in long-term stochastic modeling. Such extreme out-year price and load excursions can influence portfolio costs disproportionately while not reflecting plausible outcome. Thus, since long-term volatility is the year-on-year growth rate, only the expected yearly price and/or load growth is simulated over the forecast horizon53. Key drivers that significantly affect the determination of prices tend to fall into two categories: loads and fuels. Targeting only key variables from each category simplifies the analysis while effectively capturing sensitivities on a larger number of individual variables. For instance, load uncertainty can encompass the sensitivities of weather and evolving end-uses. Depending on the region, fuel price uncertainty (especially that of natural gas) can encompass the sensitivities of weather, load growth, emissions, and hydro availability. The following paper, Uncertainty Representation for PacifiCorp's Long Range Plan, summarizes the development of stochastic process parameters to describe how these uncertain variables evolve over time. Ms. O’Neill’s previous works include: Grossman, Britt, Nicholas Muller, and Erin O’Neill. “The Ancillary Benefits from Climate Policy in the United States.” Environmental Resource Economics (2011) 50:585-60. O’Neill, Erin, and T. Parkinson. “Uncertainly Representation: Estimating Process Parameters for Forward Price Forecasting.” EPRI, Palo Alto, CA, and The NorthBridge Group, Lincoln, MA: 1999. TR-114201. O’Neill, Erin. “Guide to Process Parameter Estimation Tool Kit.” EPRI, Palo Alto, CA, and The NorthBridge Group, Lincoln, MA: 2000. EPRI 1001172. O’Neill, Erin. “Cost-Effective Strategies for Nitrogen Oxide Reduction: Ozone Attainment Policy for New England.” M.S. thesis, Massachusetts Institute of Technology, Cambridge, 1996. 53Mean reversion is assumed to be zero in the long run. PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 604 Uncertainty Representation for PacifiCorp's Long Range Plan July 2014 Prepared for PacifiCorp 825 NE Multnomah Street Portland, OR 97232 Prepared by Erin O'Neill Independent Consultant 1542 Valley View Court Golden, CO 80403 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 605 INTRODUCTION Long-term planning demands specification of how important variables behave over time. For the case of PacifiCorp's long-term planning, important variables include natural gas and electricity prices, regional loads, and regional hydro generation. Modeling these variables involves not only a description of their expected value over time as with a traditional forecast, but also a description of the spread of possible future values. The following paper summarizes the development of stochastic process parameters to describe how these uncertain variables evolve over time54. VOLATILITY The standard measure of uncertainty for a stochastic variable is volatility: J √ The standard deviation55 is a measure of how widely values are dispersed from the average value: J J ∑J J 1 Volatility incorporates a time component so a variable with constant volatility has a larger spread of possible outcomes two years in the future than one year in the future. Volatilities are typically quoted on an annual basis but can be specified for any desired time period. Suppose the annual volatility of load in Idaho is 2 percent. This implies that the standard deviation of the range of possible loads in Idaho a year from now is 2 percent, while the standard deviation four years from now is 4 percent. MEAN REVERSION If volatility were constant over the forecast period, then the standard deviation would increase linearly with the square root of time. This is described as a "Random Walk" process and often provides a reasonable assumption for long-term uncertainty. However, for energy commodities as well as many other variables in the short-term, this is not typically the case. Excepting seasonal effects, the standard deviation increases less quickly with longer forecast time. This is called a mean reverting process - variable outcomes tend to revert back towards a long-term mean after experiencing a shock: 54 A stochastic process, or random process, is the counterpart to a deterministic process. Instead of dealing with only one possible reality of how the variables might evolve over time, there is some indeterminacy in its future evolution described by probability distributions. 55 "Standard Deviation" and "Variance" are standard statistical terms describing the spread of possible outcomes. The Variance equals the Standard Deviation squared. PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 606 Figure 1 For a random walk process, the distribution of possible future outcomes continues to increase indefinitely. While for a mean reverting process, the distribution of possible outcomes reaches a steady-state. Actual observed outcomes will continue to vary within the distribution, but the distribution across all possible outcomes does not increase: Figure 2 The volatility and mean reversion rate parameters combine to provide a compact description of the distribution of possible variable outcomes over time. The volatility describes the size of a typical shock or deviation for a particular variable and the mean reversion rate describes how quickly the variable moves back towards the long-run mean after experiencing a shock. ESTIMATING SHORT-TERM PROCESS PARAMETERS Short-term uncertainty can best be described as a mean reverting process. The factors that drive uncertainty in the short-term are generally short-lived, decaying back to long-run average levels. Short-term uncertainty is mainly driven by weather (temperature, windiness, rainfall) but can also be driven by short-term economic factors, congestion, outages, etc. 0.0 0.5 1.0 1.5 2.0 2.5 0 10 20 30 40 50 60 Pr i c e In d e x Time to Delivery Stochastic Processes Random Walk Expectation Mean‐Reverting Expectation <‐‐‐‐Observed Forecast ‐‐> 0.0 0.5 1.0 1.5 2.0 2.5 0 6 12 18 24 30 36 Pr i c e In d e x Time to Delivery Random Walk Price Process 0.0 0.5 1.0 1.5 2.0 2.5 0 6 12 18 24 30 36 Lik e l i h o o d Time to Delivery Mean Reverting Price Process PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 607 The process for estimating short-term uncertainty parameters is similar for most variables of interest. However, each of PacifiCorp's variables have characteristics that make their processes slightly different. The process for estimating short-term uncertainty parameters is described in detail below for the most straightforward variable -- natural gas prices. Each of the other variables is then discussed in terms of how they differ from the standard natural gas price parameter estimation process. STOCHASTIC PROCESS DESCRIPTION The first step in developing process parameter estimates for any uncertain variable is to determine the form of the distribution and time step for uncertainty. In the case of natural gas, and prices in general, the lognormal distribution is a good representation of possible future outcomes. A lognormal distribution is a continuous probability distribution of a random variable whose logarithm is normally distributed56. The lognormal distribution is often used to describe prices because it is bounded on the bottom by zero and has a long, asymmetric "tail" reflecting the possibility that prices could be significantly higher than the average: Figure 3 The time step for calculating uncertainty parameters depends on how quickly a variable can experience a significant change. Natural gas prices can change substantially from day to day and are reported on a daily basis, so the time step for analysis will be one day. All short-term parameters were calculated on a seasonal basis to reflect the different dynamics present during different seasons of the year. For instance, the volatility of gas prices is higher in the winter and lower in the spring and summer. Seasons were defined as follows: Table 1 - Seasonal Definition Winter December, January, and February Spring March, April, and May Summer June, July, and August Fall September, October, and November 56 A normal distribution is the most common continuous distribution represented by a bell-shaped curve that is symmetrical about the mean, or average, value. 0 0 0.5 1 1.5 2 2.5 3 Lik e l i h o o d Price index Lognormal Distribution 90th Percentile 10th Percentile Expected Index 0 0 0.5 1 1.5 2 2.5 3 Lik e l i h o o d Price Index Cumulative Lognormal Distribution 90th Percentile10th Percentile Expected Index PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 608 DATA DEVELOPMENT Basic Data Set: The natural gas price data were organized into a consistent dataset with one natural gas price for each gas delivery point reported for each delivery day. The data were checked to make sure that there were no missing or duplicate dates. If no price is reported for a particular date, the date is included but left blank to maintain a consistent 24 hour time step between all observed prices. Four years of daily data from 2010 to 2013 was used for this short-term parameter analysis. The following chart shows the resulting data set for the Sumas gas basin: Figure 4 Development of Price Index: Uncertainty parameters are estimated by looking at the movement, or deviation, in prices from one day to the next. However, some of this movement is due to expected factors, not uncertainty. For instance, gas prices are expected to be higher during winter or as we move towards winter. This expectation is already included in the gas price forecast and should not be considered a shock, or random event. In order to capture only the random or uncertain portion of price movements, a price index is developed that takes into account the expected portion of price movements. There are three categories of price expectations that are calculated: Seasonal Average: The level of gas prices may be different from one year to the next. While this can be attributed to random movements or shocks in the gas markets, it is not a short-term event and should not be included in the short-term uncertainty process. In order to account for this possible difference in the level of gas prices, the average gas price for each season and year is calculated. For example, Sumas prices in the winter of 2010 average $4.99/MMBtu. ‐ 2 4 6 8 10 12 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 Ga s Pr i c e ($ / M M B t u ) Daily Gas Prices for SUMAS Basin from 2010 to 2013 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 609 Monthly Average: Within a season, there are different expected prices by month. For instance, within the fall season, November gas prices are expected to be much higher than September and October prices as winter is just around the corner. A monthly factor representing the ratio of monthly prices to the seasonal average price is calculated. For example, January prices in Sumas are 102% of the winter average price. Weekly Shape: Many variables exhibit a distinct shape across the week. For instance, loads and electricity prices are higher during the middle of the week and lower on the weekends. The expected shape of gas prices across the week was calculated but found to be insignificant (expected variation by weekday did not exceed 2% of the weekly average). These three components: seasonal average, monthly shape, and weekly shape, combine to form an expected price for each day. For example, the expected price of gas in Sumas in January of 2010 was $5.10/MMBtu, the product of the seasonal average and the monthly shape factor J . ∗ The chart below shows the comparison of the actual Sumas prices with the "expected" prices: Figure 5 Dividing the actual gas prices by the expected prices forms a price index that averages one. This index captures only the random component of price movements -- the portion not explained by expected seasonal, monthly, and weekly shape. ‐ 2 4 6 8 10 12 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 Ga s Pr i c e ($ / M M B t u ) Daily Gas Prices for SUMAS Basin from 2010 to 2013 Expected Prices Actual Prices PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 610 Figure 6 PARAMETER ESTIMATION -- AUTOREGRESSIVE MODEL Uncertainty parameters are calculated for each variable by regressing the movement of each regions price index compared to the previous day's index. Step 1 - Calculate Log Deviation of Price Index Since gas prices are log normally distributed, the regression analysis is performed on the natural log of prices and their log deviations. The log deviations are simply the differences between the natural log of one day's price index and the natural log of the previous day's price index. Step 2 - Perform Regression The log deviation of prices are regressed against the previous day's log price for each season as well as for the entire data set. The following chart shows the log of the price index versus the log deviations for Sumas gas for all seasons and the resulting regression equation: ‐ 0.5 1.0 1.5 2.0 2.5 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 Ga s Pr i c e In d e x Gas Price Index for SUMAS Basin from 2010 to 2013 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 611 Figure 7 Step 3 - Interpret the Results The INTERCEPT of the regression represents the log of the long-run mean. So in this case, the intercept is approximately zero, implying that the long-run mean is equal to 1. This is consistent with the way in which the price index is formulated. The SLOPE of the regression is related to the auto correlation and mean reversion rate: J Ø J 1 J J JlnØ The autocorrelation measures how much of the price shock from the previous time period remains in the next time period. For instance, if the autocorrelation is 0.4 and gas prices yesterday experienced a 10% jump over the norm, today's expected price would be 4% higher than normal. In addition, today's gas price will experience a shock today that may result in prices higher or lower than this expectation. The mean reversion rate expresses the same thing in a different manner. The higher the mean reversion rate, the faster prices revert to the long-run mean. The last component of the regression analysis is the STANDARD ERROR or STEYX. This measures the portion of the price movements not explained by mean reversion and is the estimate of the variable's volatility. Both the mean reversion rate and volatility calculated with this process are daily parameters and can be applied directly to daily movements in gas prices. Step 4 - Results The natural gas price parameters derived through this process are reported in the table below. y = ‐0.0872x ‐0.0006 R² = 0.0438 (0.60) (0.40) (0.20) ‐ 0.20 0.40 0.60 0.80 1.00 (0.40) (0.20)‐0.20 0.40 0.60 0.80 1.00 Lo g De v i a t i o n s Lognormal (Price Index) Regression for Sumas Gas Basin ‐All Seasons PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 612 Table 2 - Uncertainty Parameters for Natural Gas ELECTRICITY PRICE PROCESS For the most part, electricity prices behave very similar to natural gas prices. The lognormal distribution is generally a good assumption for electricity. While electricity prices do occasionally go below zero, this is not common enough to be worth using the Normal distribution assumption. And the distribution of electricity prices is often very skewed upwards. In fact, even the lognormal assumption is sometimes inadequate for capturing the tail of the electricity price distribution. Similar to gas prices, electricity price can experience substantial change from one day to the next so a daily time step should be used. Basic Data Set: The electricity price data were organized into a consistent dataset with one price for each region reported for each delivery day similar to gas prices. Data covers the 2010 through 2013 time period. However, electricity prices are reported for "High Load Level" periods (16 hours for 6 days a week) and "Low Load Level" periods (8 hours for 6 days a week and 24 hours on Sunday & NERC holidays). In order to have a consistent price definition, a composite price calculated based on 16 hours of peak and 8 hours of off-peak prices is used for Monday through Saturday. The Low Load Level price was used for Sundays since that already reflects the 24 hour price. Missing and duplicate data is handled in a fashion similar to gas prices. Development of Price Index: As with gas prices, an electricity price index was developed which accounts for the expected components of price movements. The "expected" electricity price incorporates all three possible adjustments: seasonal average, monthly shape and weekly shape. For instance, the expected price for January 2nd, 2010 in the Four Corners region was $38.42/MWh. This price incorporates the 2010 winter average price of $39.00/MWh times the monthly shape factor for January of 99% and the weekday index for Saturday of 99%. The following chart shows the Four Corners actual and expected electricity prices over the analysis time period. Winter Spring Summer Fall KERN OPAL Daily Volatility 4.8% 2.9% 2.9% 3.6% Daily Mean Reversion Rate 0.058 0.110 0.060 0.110 SUMAS Daily Volatility 6.3% 2.6% 2.9% 4.3% Daily Mean Reversion Rate 0.091 0.083 0.070 0.109 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 613 Figure 8 Electricity Price Uncertainty Parameters Uncertainty parameters are calculated for each electric region similar to the process for gas prices. The electricity price parameters derived through this process are reported in the table below. Table 3 - Uncertainty Parameters for Electricity Regions REGIONAL LOAD PROCESS There are only two significant differences between the uncertainty analysis for regional loads and natural gas prices. The distribution of daily loads is somewhat better represented by a normal distribution rather than a lognormal distribution. And, similar to electricity prices, loads have a significant expected shape across the week. The chart below shows the distribution of historical load outcomes for the Portland area as well as normal and lognormal distribution functions representing load possibilities. Both distributions do a reasonable job of representing the spread ‐ 10 20 30 40 50 60 70 80 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 El e c t r i c i t y Pr i c e ($ / M W h ) Daily Electricity Prices for Four Corners from 2010 to 2013 Expected Prices Actual Prices Winter Spring Summer Fall Four Corners Daily Volatility 7.6% 9.2% 11.1% 6.0% Daily Mean Reversion Rate 0.095 0.277 0.380 0.240 CA‐OR Border Daily Volatility 11.8% 31.8% 25.7% 6.3% Daily Mean Reversion Rate 0.193 0.682 0.534 0.168 Mid‐Columbia Daily Volatility 17.8% 31.7% 47.7% 6.9% Daily Mean Reversion Rate 0.282 0.488 0.943 0.152 Palo Verde Daily Volatility 6.2% 7.2% 9.1% 4.7% Daily Mean Reversion Rate 0.093 0.198 0.289 0.217 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 614 of possible load outcomes but the tail of the lognormal distribution implies the possibility of higher loads than is supported by the historical data. Figure 9 Development of Load Index: As with electricity prices, a load index was developed which accounts for the expected components of load movements incorporating all three possible adjustments. For instance, the expected load for January 2nd, 2010 in Portland was 311MW. This load incorporates the 2010 winter average load of 304MW times the monthly shape factor for January of 100% and the weekday index for Saturday of 95%. The following chart shows the Portland actual and expected loads over the analysis time period. 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0% 4.5% 5.0% 0 50 100 150 200 250 300 350 400 450 500 Pr o b a b i l i t y Average Daily Load in Portland (MW) Probability Distribution for Portland Load from 2010 to 2013 Actual Normal Lognormal PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 615 Figure 10 Load Uncertainty Parameters Uncertainty parameters are calculated for each load region similar to the process for gas and electricity prices. Since loads are modeled as normally, rather than lognormally distributed, deviations are simply calculated as the difference between the load index and the previous day's index. The uncertainty parameters for regional loads derived through this process are reported in the table below. 150 200 250 300 350 400 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 Av e r a g e Da i l y Lo a d (M W ) Daily Average Load for Portland 2010 to 2013 Expected Loads Actual Loads PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 616 Table 4 - Uncertainty Parameters for Load Regions HYDRO GENERATION PROCESS There are two differences between the uncertainty analysis for hydro generation and natural gas prices. Hydro generation varies on a slower time frame than other variables analyzed. As such, average hydro generation is calculated and analyzed on a weekly, rather than daily, basis. Generation is calculated as the average hourly generation across the 168 hour in a week. In addition, an extra year of data was analyzed for hydro generation. The hydro analysis covers the 2009 through 2013 time period. Development of Hydro Index: A hydro generation index was developed which accounts for the expected components of hydro movements incorporating seasonal and monthly adjustments. For instance, the expected hydro generation for the week of January 1st through 7th, 2009 in the Western Region was 548MW. This generation incorporates the 2009 winter average generation of 471MW times the monthly shape factor for January of 116%. The following chart shows the western hydro actual and expected generation over the analysis time period. Winter Spring Summer Fall California Daily Volatility 4.3% 4.0% 3.4% 4.6% Daily Mean Reversion Rate 0.227 0.251 0.193 0.206 Idaho Daily Volatility 2.9% 4.5% 5.1% 4.8% Daily Mean Reversion Rate 0.268 0.093 0.102 0.176 Portland Daily Volatility 3.0% 2.9% 3.5% 3.1% Daily Mean Reversion Rate 0.224 0.164 0.336 0.324 Oregon Other Daily Volatility 4.5% 3.6% 3.6% 3.9% Daily Mean Reversion Rate 0.226 0.280 0.242 0.207 Utah Daily Volatility 2.0% 2.5% 4.5% 2.9% Daily Mean Reversion Rate 0.333 0.295 0.260 0.339 Washington Daily Volatility 4.3% 3.6% 4.6% 4.2% Daily Mean Reversion Rate 0.215 0.220 0.243 0.182 Wyoming Daily Volatility 1.6% 1.6% 1.5% 1.8% Daily Mean Reversion Rate 0.279 0.318 0.179 0.230 PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 617 Figure 11 Hydro Generation Uncertainty Parameters Uncertainty parameters are calculated for each hydro region similar to the process for gas and electricity prices. The uncertainty parameters for hydro generation derived through this process are reported in the table below. Table 5 - Uncertainty Parameters for Hydro Generation Winter Spring Summer Fall Daily Volatility 23% 19% 17% 31% Daily Mean Reversion Rate 0.52 0.25 0.39 0.60 SHORT TERM CORRELATION ESTIMATION Correlation is a measure of how much the random component of variables tend to move together. After the uncertainty analysis has been performed, the process for estimating correlations is relatively straight-forward. Step 1 - Calculate Residual Errors Calculate the residual errors of the regression analysis for all of the variables. The residual error represents the random portion of the deviation not explained by mean reversion. It is calculated for each time period as the difference between the actual value and the value predicted by the linear regression equation: J J ∗ J All of the residual errors are compiled by delivery date. Step 2 - Calculate Correlations Correlate the residual errors of each pair of variables: ‐ 100 200 300 400 500 600 700 800 900 Jan‐09 Jul‐09 Jan‐10 Jul‐10 Jan‐11 Jul‐11 Jan‐12 Jul‐12 Jan‐13 Jul‐13 Av e r a g e We e k l y Ge n e r a t i o n (M W ) Weekly Average Hydro Generation in the West from 2009 to 2013 Expected Generation Actual Generation PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 618 ,J ∑JJ J .J ∗ J J .JJ J ∑J J .J ∗∑J J .J There are a few things to note about the correlation calculations. First, correlation data must always be organized so that the same time period is being compared for both variables. So for instance, weekly hydro deviations cannot be compared to daily gas price deviations. Thus, a daily regression analysis was performed for the hydro variables. Also note that what is being correlated is the residual errors of the regression -- only the uncertain portion of the variable movements. Variables may exhibit similar expected shapes - both loads and electricity prices are higher during the week than on the weekend. This coincidence is captured in the expected weekly shapes input into the planning model. The correlation calculated here captures the extent to which the shocks experienced by two different variables tend to have similar direction and magnitude: The resulting short-term correlations by season are reported below: Table 6 - Short-term Correlations by Season SHORT‐TERM WINTER CORRELATIONS K‐O SUMAS 4C COB Mid‐C PV CA ID Portland OR Other UT WA WY Hydro K‐O 100% 71% 31% 18% 13% 32% 13% 16% 19% 14% 20% 14% 15% 4% SUMAS 71% 100% 21% 18% 15% 14% 10% 11% 23% 18% 19% 21% 15% 2% 4C 31% 21% 100% 63% 57% 80% 13% 15% 13% 16% 22% 20% 9% 2% COB 18% 18% 63% 100% 95% 62% 13% 8% 17% 27% 15% 28% 10% 3% Mid‐C 13% 15% 57% 95% 100% 52% 10% 9% 14% 24% 15% 24% 12% 3% PV 32% 14% 80% 62% 52% 100% 9% 15% 5% 8% 17% 13% 5% 3% CA 13% 10% 13% 13% 10% 9% 100% 17% 47% 75% 29% 45% 18%‐2% ID 16% 11% 15% 8% 9% 15% 17% 100% 24% 26% 41% 30% 26%‐2% Portland 19% 23% 13% 17% 14% 5% 47% 24% 100% 74% 47% 66% 29% 0% OR Other 14% 18% 16% 27% 24% 8% 75% 26% 74% 100% 42% 71% 30% 2% UT 20% 19% 22% 15% 15% 17% 29% 41% 47% 42% 100% 40% 40% 3% WA 14% 21% 20% 28% 24% 13% 45% 30% 66% 71% 40% 100% 29% 0% WY 15% 15% 9% 10% 12% 5% 18% 26% 29% 30% 40% 29% 100%‐1% Hydro 4% 2% 2% 3% 3% 3%‐2%‐2% 0% 2% 3% 0%‐1% 100% SHORT‐TERM SPRING CORRELATIONS K‐O SUMAS 4C COB Mid‐C PV CA ID Portland OR Other UT WA WY Hydro K‐O 100% 76% 10% 7% 12% 11% 13% 4% 1%‐2%‐3%‐3% 1%‐1% SUMAS 76% 100% 11% 7% 11% 12% 12% 3% 12% 13% 0% 7% 2%‐6% 4C 10% 11% 100% 62% 40% 82%‐2% 14% 2% 4% 9% 9%‐4%‐13% COB 7% 7% 62% 100% 85% 60% 0% 5% 5% 7% 4% 14% 1%‐3% Mid‐C 12% 11% 40% 85% 100% 29%‐2% 10% 9% 6% 9% 17%‐1% 1% PV 11% 12% 82% 60% 29% 100%‐4% 9% 2% 3% 6% 4%‐3%‐9% CA 13% 12%‐2% 0%‐2%‐4% 100% 28% 33% 54% 23% 31% 3% 7% ID 4% 3% 14% 5% 10% 9% 28% 100% 15% 13% 44% 13% 8%‐4% Portland 1% 12% 2% 5% 9% 2% 33% 15% 100% 71% 28% 58% 16% 5% OR Other ‐2% 13% 4% 7% 6% 3% 54% 13% 71% 100% 28% 64% 15% 8% UT ‐3% 0% 9% 4% 9% 6% 23% 44% 28% 28% 100% 24% 31%‐1% WA ‐3% 7% 9% 14% 17% 4% 31% 13% 58% 64% 24% 100% 15% 0% WY 1% 2%‐4% 1%‐1%‐3% 3% 8% 16% 15% 31% 15% 100%‐2% Hydro ‐1%‐6%‐13%‐3% 1%‐9% 7%‐4% 5% 8%‐1% 0%‐2% 100% PACIFICORP – 2015 IRP APPENDIX R – UNCERTAINTY PARAMETERS 619 CONCLUSION For the continuous, stochastic variables that drive PacifiCorp's electricity environment short-term volatility and mean reversion, complete with corresponding correlations, provide a robust picture of the spread of future outcome. The standard parameters developed here can be used within the PaR model to develop PacifiCorp's Integrated Resource Plan. SHORT‐TERM SUMMER CORRELATIONS K‐O SUMAS 4C COB Mid‐C PV CA ID Portland OR Other UT WA WY Hydro K‐O 100% 89% 7% 5% 2% 8%‐3% 9% 5% 6% 2% 2% 1%‐5% SUMAS 89% 100% 8% 8% 0% 10%‐6% 4% 9% 6%‐3% 2%‐5%‐1% 4C 7% 8% 100% 49% 44% 86% 20% 17% 16% 21% 28% 19% 4%‐2% COB 5% 8% 49% 100% 74% 52% 11% 18% 27% 27% 19% 25%‐2%‐9% Mid‐C 2% 0% 44% 74% 100% 44% 17% 22% 25% 26% 24% 27% 8%‐9% PV 8% 10% 86% 52% 44% 100% 19% 17% 17% 23% 25% 18% 4%‐7% CA ‐3%‐6% 20% 11% 17% 19% 100% 34% 35% 56% 29% 42% 8%‐7% ID 9% 4% 17% 18% 22% 17% 34% 100% 13% 22% 39% 24% 27%‐10% Portland 5% 9% 16% 27% 25% 17% 35% 13% 100% 76% 28% 61% 9%‐11% OR Other 6% 6% 21% 27% 26% 23% 56% 22% 76% 100% 33% 78% 10%‐13% UT 2%‐3% 28% 19% 24% 25% 29% 39% 28% 33% 100% 35% 32%‐13% WA 2% 2% 19% 25% 27% 18% 42% 24% 61% 78% 35% 100% 11%‐15% WY 1%‐5% 4%‐2% 8% 4% 8% 27% 9% 10% 32% 11% 100% 2% Hydro ‐5%‐1%‐2%‐9%‐9%‐7%‐7%‐10%‐11%‐13%‐13%‐15% 2% 100% SHORT‐TERM FALL CORRELATIONS K‐O SUMAS 4C COB Mid‐C PV CA ID Portland OR Other UT WA WY Hydro K‐O 100% 63% 22% 24% 22% 29% 9% 15% 10% 14% 15% 10% 9% 1% SUMAS 63% 100% 13% 25% 26% 18% 20% 12% 21% 32% 11% 22% 24% 8% 4C 22% 13% 100% 33% 33% 77% 11% 16% 4% 10% 19% 11%‐7% 8% COB 24% 25% 33% 100% 90% 38% 26% 12% 33% 37% 10% 31%‐2% 3% Mid‐C 22% 26% 33% 90% 100% 35% 26% 15% 35% 42% 8% 36% 0% 2% PV 29% 18% 77% 38% 35% 100% 13% 16% 12% 16% 22% 20%‐2% 2% CA 9% 20% 11% 26% 26% 13% 100% 26% 44% 69% 29% 55% 12% 5% ID 15% 12% 16% 12% 15% 16% 26% 100% 17% 23% 30% 18% 1% 2% Portland 10% 21% 4% 33% 35% 12% 44% 17% 100% 71% 47% 67% 27% 1% OR Other 14% 32% 10% 37% 42% 16% 69% 23% 71% 100% 35% 75% 23% 5% UT 15% 11% 19% 10% 8% 22% 29% 30% 47% 35% 100% 33% 28% 0% WA 10% 22% 11% 31% 36% 20% 55% 18% 67% 75% 33% 100% 21% 2% WY 9% 24%‐7%‐2% 0%‐2% 12% 1% 27% 23% 28% 21% 100% 10% Hydro 1% 8% 8% 3% 2% 2% 5% 2% 1% 5% 0% 2% 10% 100%