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Home My WebLink About20230531Amended IRP Volume II.pdf2023 Integrated Resource Plan Volume II May 31, 2023 (Amended Final) This 2023 Integrated Resource Plan, Amended Final 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 Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 irp@pacificorp.com www.pacificorp.com PACIFICORP – 2023 IRP TABLE OF CONTENTS i TABLE OF CONTENTS – VOLUME II TABLE OF CONTENTS ................................................................................ i TABLE OF TABLES ................................................................................ Viii TABLE OF FIGURES .................................................................................. x APPENDIX A – LOAD FORECAST INTRODUCTION ....................................................................................................................................................... 1 SUMMARY LOAD FORECAST ...................................................................................................................................... 1 LOAD FORECAST ASSUMPTIONS ....................................................................................................................... 4 REGIONAL ECONOMY BY JURISDICTION .................................................................................................................... 4 WEATHER .................................................................................................................................................................. 5 STATISTICALLY ADJUSTED END-USE (“SAE”) .......................................................................................................... 7 INDIVIDUAL CUSTOMER FORECAST ........................................................................................................................... 7 ACTUAL LOAD DATA ................................................................................................................................................ 8 SYSTEM LOSSES ...................................................................................................................................................... 10 FORECAST METHODOLOGY OVERVIEW ...................................................................................................... 10 DEMAND-SIDE MANAGEMENT RESOURCES IN THE LOAD FORECAST ....................................................................... 10 MODELING OVERVIEW ............................................................................................................................................. 10 ELECTRIFICATION ADJUSTMENTS ............................................................................................................................ 12 SALES FORECAST AT THE CUSTOMER METER .......................................................................................... 12 RESIDENTIAL ........................................................................................................................................................... 13 COMMERCIAL .......................................................................................................................................................... 13 INDUSTRIAL ............................................................................................................................................................. 13 STATE SUMMARIES .............................................................................................................................................. 14 OREGON .................................................................................................................................................................. 14 WASHINGTON .......................................................................................................................................................... 14 CALIFORNIA ............................................................................................................................................................ 15 UTAH ....................................................................................................................................................................... 15 IDAHO ...................................................................................................................................................................... 16 WYOMING ............................................................................................................................................................... 16 ALTERNATIVE LOAD FORECAST SCENARIOS ............................................................................................. 17 APPENDIX B – REGULATORY COMPLIANCE INTRODUCTION ..................................................................................................................................................... 19 GENERAL COMPLIANCE ..................................................................................................................................... 19 CALIFORNIA ............................................................................................................................................................ 21 IDAHO ...................................................................................................................................................................... 21 OREGON .................................................................................................................................................................. 22 UTAH ....................................................................................................................................................................... 22 PACIFICORP – 2023 IRP TABLE OF CONTENTS ii WASHINGTON .......................................................................................................................................................... 22 WYOMING ............................................................................................................................................................... 22 WASHINGTON IRP REQUIREMENTS AND THE WASHINGTON IRP TWO-YEAR PROGRESS REPORT .................................................................................................................................................................... 86 APPENDIX C – PUBLIC INPUT PROCESS PARTICIPANT LIST ............................................................................................................................................... 91 COMMISSIONS .......................................................................................................................................................... 91 STAKEHOLDERS AND INDUSTRY EXPERTS ............................................................................................................... 92 GENERAL MEETINGS ............................................................................................................................................... 93 STATE-SPECIFIC INPUT MEETINGS ........................................................................................................................... 95 STAKEHOLDER COMMENTS.............................................................................................................................. 95 PRE-FILING .............................................................................................................................................................. 95 IRP Public-Input Meeting Process/General Comments ..................................................................................... 96 Load Forecasting ............................................................................................................................................... 97 Modeling Assumptions ....................................................................................................................................... 97 Natrium Demonstration Project ......................................................................................................................... 98 Natural Gas ........................................................................................................................................................ 98 Plexos ................................................................................................................................................................. 98 Reliability Assessment ........................................................................................................................................ 99 Renewable Energy Resources ............................................................................................................................ 99 Resource Adequacy ............................................................................................................................................ 99 State Energy Policy ............................................................................................................................................ 99 Supply-side Resource Costs/Supply-side Resource Table ................................................................................ 100 Transmission .................................................................................................................................................... 101 EXTENDED COMMENT PERIOD............................................................................................................................... 101 Extended comment period contributors ........................................................................................................... 101 CONTACT INFORMATION ................................................................................................................................. 105 APPENDIX D – DEAND-SIDE MANAGEMENT INTRODUCTION ................................................................................................................................................... 111 CONSERVATION POTENTIAL ASSESSMENT (CPA) FOR 2023-2042 ........................................................ 111 CURRENT DSM PROGRAM OFFERINGS BY STATE ................................................................................... 112 STATE-SPECIFIC DSM PLANNING PROCESSES .......................................................................................... 114 UTAH, WYOMING AND IDAHO ............................................................................................................................... 114 WASHINGTON ........................................................................................................................................................ 114 CALIFORNIA .......................................................................................................................................................... 115 OREGON ................................................................................................................................................................ 115 PREFERRED PORTFOLIO DSM RESOURCE SELECTIONS ....................................................................... 115 APPENDIX E – SMART GRID INTRODUCTION ................................................................................................................................................... 117 TRANSMISSION NETWORK AND OPERATION ENHANCEMENTS ............................................................................... 117 Dynamic Line Rating ....................................................................................................................................... 117 Digital Fault Recorders / Phasor Measurement Unit Deployment .................................................................. 118 DISTRIBUTION AUTOMATION AND RELIABILITY .................................................................................................... 119 PACIFICORP – 2023 IRP TABLE OF CONTENTS iii Distribution Automation................................................................................................................................... 119 Distribution Substation Metering ..................................................................................................................... 119 DISTRIBUTED ENERGY RESOURCES ....................................................................................................................... 120 Energy Storage Systems ................................................................................................................................... 120 Demand Response ............................................................................................................................................ 121 Dispatchable Customer Storage Resources ..................................................................................................... 121 ADVANCED METERING INFRASTRUCTURE ............................................................................................................. 122 OUTAGE MANAGEMENT IMPROVEMENTS .............................................................................................................. 123 FUTURE SMART GRID ........................................................................................................................................ 123 APPENDIX F – FLEXIBLE RESERVE STUDY INTRODUCTION ................................................................................................................................................... 125 OVERVIEW ............................................................................................................................................................. 127 FLEXIBLE RESOURCE REQUIREMENTS ...................................................................................................... 127 CONTINGENCY RESERVE ....................................................................................................................................... 128 REGULATION RESERVE .......................................................................................................................................... 128 FREQUENCY RESPONSE RESERVE .......................................................................................................................... 129 BLACK START REQUIREMENTS .............................................................................................................................. 130 ANCILLARY SERVICES OPERATIONAL DISTINCTIONS ............................................................................................ 130 REGULATION RESERVE DATA INPUTS ........................................................................................................ 131 OVERVIEW ............................................................................................................................................................. 131 LOAD DATA ........................................................................................................................................................... 132 WIND AND SOLAR DATA ....................................................................................................................................... 133 NON-VER DATA ................................................................................................................................................... 133 REGULATION RESERVE DATA ANALYSIS AND ADJUSTMENT ............................................................. 134 OVERVIEW ............................................................................................................................................................. 134 BASE SCHEDULE RAMPING ADJUSTMENT .............................................................................................................. 134 DATA CORRECTIONS ............................................................................................................................................. 134 REGULATION RESERVE REQUIREMENT METHODOLOGY ................................................................... 136 OVERVIEW ............................................................................................................................................................. 136 COMPONENTS OF OPERATING RESERVE METHODOLOGY ...................................................................................... 136 Operating Reserve: Reserve Categories .......................................................................................................... 136 Planning Reliability Target: Loss of Load Probability .................................................................................... 138 Balancing Authority ACE Limit: Allowed Deviations ...................................................................................... 138 Regulation Reserve Forecast: Amount Held .................................................................................................... 139 REGULATION RESERVE FORECAST ........................................................................................................................ 140 Overview .......................................................................................................................................................... 140 PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS ...................................................................... 145 PORTFOLIO DIVERSITY BENEFIT ............................................................................................................................ 145 EIM DIVERSITY BENEFIT ...................................................................................................................................... 146 FAST-RAMPING RESERVE REQUIREMENTS ............................................................................................... 148 PORTFOLIO REGULATION RESERVE REQUIREMENTS .......................................................................... 149 REGULATION RESERVE COST ................................................................................................................................ 151 FLEXIBLE RESOURCE NEEDS ASSESSMENT .............................................................................................. 153 OVERVIEW ............................................................................................................................................................. 153 FORECASTED RESERVE REQUIREMENTS ................................................................................................................ 154 PACIFICORP – 2023 IRP TABLE OF CONTENTS iv FLEXIBLE RESOURCE SUPPLY FORECAST .............................................................................................................. 154 FLEXIBLE RESOURCE SUPPLY PLANNING .............................................................................................................. 157 APPENDIX G – PLANT WATER CONSUMPTION STUDY STUDY DATA ......................................................................................................................................................... 161 APPENDIX H – STOCHASTIC PARAMETERS INTRODUCTION ................................................................................................................................................... 165 OVERVIEW ............................................................................................................................................................ 165 VOLATILITY .......................................................................................................................................................... 166 MEAN REVERSION .............................................................................................................................................. 166 ESTIMATING SHORT-TERM PROCESS PARAMETERS ............................................................................. 168 STOCHASTIC PROCESS DESCRIPTION ......................................................................................................... 168 DATA DEVELOPMENT ............................................................................................................................................ 169 PARAMETER ESTIMATION – AUTOREGRESSIVE MODEL ......................................................................................... 172 ELECTRICITY PRICE PROCESS ................................................................................................................................ 174 REGIONAL LOAD PROCESS .................................................................................................................................... 176 HYDRO GENERATION PROCESS.............................................................................................................................. 178 SHORT-TERM CORRELATION ESTIMATION ............................................................................................................. 179 APPENDIX I – CAPACITY EXPANSION RESULTS 2023 IRP PORTFOLIO SUMMARIES ..................................................................................................................... 185 P-MM PREFERRED PORTFOLIO .................................................................................................................................... 185 P-LN ....................................................................................................................................................................... 186 P-MN ..................................................................................................................................................................... 187 P-HH ...................................................................................................................................................................... 188 P-SC ....................................................................................................................................................................... 189 P01-JB3-4 GC ......................................................................................................................................................... 190 P02-JB3-4 EOL ....................................................................................................................................................... 191 P03-HUNTER3-SCR .................................................................................................................................................. 192 P04-HUNTINGTON RET28 ......................................................................................................................................... 193 P05-NO NUC .......................................................................................................................................................... 194 P06-NO FORWARD TECH ............................................................................................................................................ 195 P07-D3-D2 32 ........................................................................................................................................................ 196 P08-NO D3-D2 ....................................................................................................................................................... 197 P10-OFFSHORE WIND ............................................................................................................................................... 198 P11-MAX NG .......................................................................................................................................................... 199 P12-RET COAL 30/32 NG 40 .................................................................................................................................... 200 P13-MAX DSM ........................................................................................................................................................ 201 P15-NO GWS .......................................................................................................................................................... 202 P16-NO B2H ........................................................................................................................................................... 203 P18-CLUSTER EAST .................................................................................................................................................... 204 P19-CLUSTER WEST .................................................................................................................................................. 205 P20-JB3-4 CCUS ..................................................................................................................................................... 206 P21-DJ2 CCUS ........................................................................................................................................................ 207 PACIFICORP – 2023 IRP TABLE OF CONTENTS v P22-DJ4 CCUS ........................................................................................................................................................ 208 P23-RET COAL 30/32 .............................................................................................................................................. 209 P24-GAS 40-YEAR LIFE .............................................................................................................................................. 210 SENSITIVITY PORTFOLIO SUMMARIES ................................................................................................................ 211 S01 - HIGH LOAD ...................................................................................................................................................... 211 S02 -LOW LOAD........................................................................................................................................................ 212 S03 -1 IN 20 LOAD GROWTH ...................................................................................................................................... 213 S05 - LOW PRIVATE GENERATION ................................................................................................................................. 214 S06 - BUSINESS PLAN ................................................................................................................................................. 215 S07 - NEW LOAD ...................................................................................................................................................... 216 W10 - CETA ............................................................................................................................................................ 217 W11 - CLIMATE CHANGE COUNTERFACTUAL .................................................................................................................. 218 W12 - MAX CUSTOMER BENEFIT ................................................................................................................................. 219 ANNUAL PORTFOLIO RESOURCES BY TECHNOLOGY TYPE .................................................................................. 220 NON-EMITTING PEAKING1 ........................................................................................................................................... 220 DSM ENERGY EFFICIENCY ........................................................................................................................................... 221 DSM DEMAND RESPONSE ........................................................................................................................................... 222 RENEWABLE WIND1 ................................................................................................................................................... 223 RENEWABLE SOLAR1 ................................................................................................................................................... 224 BATTERY STORAGE1 .................................................................................................................................................... 225 BATTERY, LONG DURATION1 ........................................................................................................................................ 226 NUCLEAR1 ................................................................................................................................................................ 227 COAL RETIREMENTS1 .................................................................................................................................................. 228 COAL WITH CCUS INSTALLATION1,2 ............................................................................................................................... 229 COAL WITH SNCR INSTALLATION1,2 ............................................................................................................................... 230 COAL TO NATURAL GAS CONVERSIONS1,2 ....................................................................................................................... 231 APPENDIX J – STOCHASTIC SIMULATION RESULTS MEDIUM-TERM STOCHASTIC MODEL RESULTS .................................................................................................. 233 2023 IRP PREFERRED PORTFOLIO ................................................................................................................................ 233 (P01) JIM BRIDGER 3 & 4 GC 2026 ............................................................................................................................. 233 (P02) JIM BRIDGER 3 & 4 COAL EOL ............................................................................................................................ 234 (P03) HUNTER 3 SCR ................................................................................................................................................ 234 (P04) RETIRE HUNTINGTON 2028................................................................................................................................ 234 (P05) NO NUC ADD PEAKER ....................................................................................................................................... 235 (P06) NO NUC NO FORWARD TECH ............................................................................................................................ 235 (P07) D3 AND D2 IN 2032 ........................................................................................................................................ 235 (P08) NO D3 AND D2 ............................................................................................................................................... 236 (P09) WY NO OTR .................................................................................................................................................. 236 (P-10) OFFSHORE WIND ............................................................................................................................................ 236 (P-11) MAX NAT GAS ( NO NUCLEAR/PEAKER) .............................................................................................................. 237 (P12) COAL RETIRE END 2029 GAS END OF 2039 ........................................................................................................... 237 (P13) - ALL ENERGY EFFICIENCY .................................................................................................................................. 237 (P14) ALL GATEWAY .................................................................................................................................................. 238 (P15) NO GWS ........................................................................................................................................................ 238 (P16) NO B2H ......................................................................................................................................................... 238 (P17) COL3-4 RET25 ............................................................................................................................................... 239 (P18) CLUSTER EAST .................................................................................................................................................. 239 (P19) CLUSTER WEST ................................................................................................................................................ 239 PACIFICORP – 2023 IRP TABLE OF CONTENTS vi (P20) JB3-4 CCUS ................................................................................................................................................... 240 (P21) DJ2 CCUS ...................................................................................................................................................... 240 (P22) DJ4 CCUS ...................................................................................................................................................... 240 (P23) RET COAL 30 .................................................................................................................................................. 241 (P24) GAS 40-YEAR LIFE ............................................................................................................................................ 241 APPENDIX K – CAPACITY CONTRIBUTION INTRODUCTION ................................................................................................................................................... 243 CF METHODOLOGY ............................................................................................................................................ 244 APPENDIX L – PRIVATE GENERATION STUDY INTRODUCTION ................................................................................................................................................... 249 APPENDIX M – RENEWABLE RESOURCE ASSESSMENT INTRODUCTION ................................................................................................................................................... 343 APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION INTRODUCTION ................................................................................................................................................... 389 PART 1: GRID SERVICES .................................................................................................................................... 389 ENERGY VALUE ..................................................................................................................................................... 390 Background ...................................................................................................................................................... 390 Modeling .......................................................................................................................................................... 391 OPERATING RESERVE VALUE ................................................................................................................................ 393 Background ...................................................................................................................................................... 393 Modeling .......................................................................................................................................................... 394 TRANSMISSION AND DISTRIBUTION CAPACITY ...................................................................................................... 395 GENERATION CAPACITY ........................................................................................................................................ 395 Background ...................................................................................................................................................... 395 PART 2: ENERGY STORAGE OPERATING PARAMETERS ........................................................................ 396 PART 3: DISTRIBUTED RESOURCE CONFIGURATION AND APPLICATIONS .................................... 398 SECONDARY VOLTAGE .......................................................................................................................................... 398 T&D CAPACITY DEFERRAL ................................................................................................................................... 398 FLEXIBLE HYDROGEN PRODUCTION ...................................................................................................................... 398 APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS INTRODUCTION ................................................................................................................................................... 405 INTERIM AND SPECIFIC TARGETS ................................................................................................................ 406 INTERIM TARGETS ................................................................................................................................................. 407 TARGET DEVELOPMENT ........................................................................................................................................ 408 SPECIFIC TARGETS ................................................................................................................................................. 410 CUSTOMER BENEFIT INDICATORS ............................................................................................................... 410 SPECIFIC ACTIONS ............................................................................................................................................. 411 PACIFICORP – 2023 IRP TABLE OF CONTENTS vii SUPPLY-SIDE RESOURCE ACTIONS ........................................................................................................................ 411 DEMAND-SIDE RESOURCE ACTIONS ...................................................................................................................... 411 INCREMENTAL COST ......................................................................................................................................... 414 INTERIM TARGET SHORTFALL RESOLUTION .......................................................................................................... 414 REVENUE REQUIREMENT METHODOLOGY ............................................................................................................. 415 PUBLIC PARTICIPATION ................................................................................................................................... 418 SPECIFIC ACTIONS ................................................................................................................................................. 418 CONTINUED AND EXPANDED OUTREACH .............................................................................................................. 419 ADDRESSING BARRIERS TO PARTICIPATION .......................................................................................................... 420 INTERNAL STAKEHOLDER DEVELOPMENT ............................................................................................................. 421 APPENDIX P – ACRONYMS APPENDIX P ........................................................................................................................................................... 423 PACIFICORP – 2023 IRP TABLE OF CONTENTS viii TABLE OF TABLES – VOLUME II APPENDIX A – LOAD FORECAST TABLE A.1 – FORECASTED ANNUAL LOAD, 2023 THROUGH 2032 (MEGAWATT-HOURS), AT GENERATION, PRE-DSM ......................... 2 TABLE A.2 – FORECASTED ANNUAL COINCIDENT PEAK LOAD (MEGAWATTS) AT GENERATION, PRE-DSM ........................................... 3 TABLE A.3 – ANNUAL LOAD CHANGE: MAY 2022 FORECAST LESS JUNE 2022 FORECAST (MEGAWATT-HOURS) AT GENERATION, PRE- DSM ...................................................................................................................................................................... 3 TABLE A.4 – ANNUAL COINCIDENT PEAK CHANGE: MAY 2022 FORECAST LESS JUNE 2022 FORECAST (MEGAWATTS) AT GENERATION, PRE-DSM ................................................................................................................................................................ 3 TABLE A.5 – PROJECTED RANGE OF TEMPERATURE CHANGE IN THE 2020S AND 2050S RELATIVE TO THE 1990S ................................. 6 TABLE A.6 – WEATHER NORMALIZED JURISDICTIONAL RETAIL SALES 2000 THROUGH 2021 ............................................................ 8 TABLE A.7 – NON-COINCIDENT JURISDICTIONAL PEAK 2000 THROUGH 2021 ............................................................................... 9 TABLE A.8 – JURISDICTIONAL CONTRIBUTION TO COINCIDENT PEAK 2000 THROUGH 2021 ............................................................. 9 TABLE A.9 – SYSTEM ANNUAL RETAIL SALES FORECAST 2021 THROUGH 2032, POST-DSM .......................................................... 13 TABLE A.10 – FORECASTED RETAIL SALES GROWTH IN OREGON, POST-DSM .............................................................................. 14 TABLE A.11 – FORECASTED RETAIL SALES GROWTH IN WASHINGTON, POST-DSM ....................................................................... 14 TABLE A.12 - FORECASTED RETAIL SALES GROWTH IN CALIFORNIA, POST-DSM ........................................................................... 15 TABLE A.13 – FORECASTED RETAIL SALES GROWTH IN UTAH, POST-DSM .................................................................................. 15 TABLE A.14 - FORECASTED RETAIL SALES GROWTH IN IDAHO, POST-DSM .................................................................................. 16 TABLE A.15 – FORECASTED RETAIL SALES GROWTH IN WYOMING, POST-DSM ........................................................................... 16 APPENDIX B – REGULATORY COMPLIANCE TABLE B.1 – INTEGRATED RESOURCE PLANNING STANDARDS AND GUIDELINES SUMMARY BY STATE ................................................ 25 TABLE B.2 – HANDLING OF 2021 IRP ACKNOWLEDGMENT AND OTHER IRP REQUIREMENTS ......................................................... 35 TABLE B.3 – OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND GUIDELINES .................................................................. 64 TABLE B.4– UTAH PUBLIC SERVICE COMMISSION IRP STANDARD AND GUIDELINES ...................................................................... 78 TABLE B.5 – WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION IRP STANDARD AND GUIDELINES TO IMPLEMENT CETA RULES (RCW 19.280.030 AND WAC 480-100-620 THROUGH WAC 480-100-630) PER COMMISSION GENERAL ORDER R-601. ... 86 TABLE B.6 – WYOMING PUBLIC SERVICE COMMISSION GUIDELINES ........................................................................................... 94 APPENDIX C – PUBLIC INPUT PROCESS APPENDIX D – DEAND-SIDE MANAGEMENT TABLE D.1– CURRENT DEMAND RESPONSE AND ENERGY EFFICIENCY PROGRAM SERVICES AND OFFERINGS BY SECTOR AND STATE ...... 113 TABLE D.2 – CURRENT WATTSMART OUTREACH AND COMMUNICATIONS ACTIVITIES .................................................................. 114 TABLE D.3 –CUMULATIVE DEMAND RESPONSE RESOURCE SELECTIONS (2023 IRP PREFERRED PORTFOLIO) ................................... 115 TABLE D.4 – CUMULATIVE AND FIRST YEAR ENERGY EFFICIENCY RESOURCE SELECTIONS (2023 IRP PREFERRED PORTFOLIO) ............. 116 APPENDIX E – SMART GRID APPENDIX F – FLEXIBLE RESERVE STUDY TABLE F.1 - PORTFOLIO REGULATION RESERVE REQUIREMENTS............................................................................................... 127 TABLE F.2 - 2023 FLEXIBLE RESOURCE COSTS AS COMPARED TO 2021 COSTS, $/MWH ............................................................ 127 TABLE F.3 – SUMMARY OF STAND-ALONE REGULATION RESERVE REQUIREMENTS ...................................................................... 145 TABLE F.4 – EIM DIVERSITY BENEFIT APPLICATION EXAMPLE ................................................................................................. 147 TABLE F.5 – 2018-2019 RESULTS WITH PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS ..................................................... 147 PACIFICORP – 2023 IRP TABLE OF CONTENTS ix APPENDIX G – PLANT WATER CONSUMPTION STUDY TABLE G.1 – PLANT WATER CONSUMPTION WITH ACRE-FEET PER YEAR ................................................................................... 161 TABLE G.2 – PLANT WATER CONSUMPTION BY STATE (ACRE-FEET) .......................................................................................... 163 TABLE G.3 – PLANT WATER CONSUMPTION BY FUEL TYPE (ACRE-FEET) .................................................................................... 163 TABLE G.4 – PLANT WATER CONSUMPTION FOR PLANTS LOCATED IN THE UPPER COLORADO RIVER BASIN (ACRE-FEET) .................... 164 APPENDIX H – STOCHASTIC PARAMETERS TABLE H.1 - SEASONAL DEFINITIONS .................................................................................................................................. 169 TABLE H.2 - UNCERTAINTY PARAMETERS FOR NATURAL GAS .................................................................................................. 174 TABLE H.3 - UNCERTAINTY PARAMETERS FOR ELECTRICITY REGIONS ........................................................................................ 176 TABLE H.4 - UNCERTAINTY PARAMETERS FOR LOAD REGIONS ................................................................................................. 178 TABLE H.5 - UNCERTAINTY PARAMETERS FOR HYDRO GENERATION ......................................................................................... 179 TABLE H.6 - SHORT-TERM WINTER CORRELATIONS ............................................................................................................... 180 TABLE H.7 - SHORT-TERM SPRING CORRELATIONS ................................................................................................................ 181 TABLE H.8 - SHORT-TERM SUMMER CORRELATIONS ............................................................................................................. 181 TABLE H.9 - SHORT-TERM FALL CORRELATIONS .................................................................................................................... 182 APPENDIX I – CAPACITY EXPANSION RESULTS APPENDIX J – STOCHASTIC SIMULATION RESULTS APPENDIX K – CAPACITY CONTRIBUTION APPENDIX L – PRIVATE GENERATION STUDY APPENDIX M – RENEWABLE RESOURCE ASSESSMENT APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION TABLE N.1 - ENERGY MARGIN BY ENERGY STORAGE ATTRIBUTES............................................................................................. 392 APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS TABLE O.1 - INTERIM COMPLIANCE TARGETS (MWH) ........................................................................................................... 408 TABLE O.2 - ANNUAL MODELED IMPACTS OF CETA ............................................................................................................. 416 TABLE O.3 - NON-MODELED IMPACTS OF CETA ($MILLION) .................................................................................................. 416 TABLE O.4 - REVENUE REQUIREMENT OF COST ESTIMATES ..................................................................................................... 417 APPENDIX P – ACRONYMS PACIFICORP – 2023 IRP TABLE OF CONTENTS x TABLE OF FIGURES – VOLUME II APPENDIX A – LOAD FORECAST FIGURE A.1 – PACIFICORP SYSTEM ENERGY LOAD FORECAST CHANGE, AT GENERATION, PRE-DSM .................................................. 2 FIGURE A.2 – PACIFICORP ANNUAL RETAIL SALES 2000 THROUGH 2021 AND WESTERN REGION EMPLOYMENT ................................. 4 FIGURE A.3 – PACIFICORP ANNUAL RESIDENTIAL USE PER CUSTOMER 2001 THROUGH 2021 .......................................................... 5 FIGURE A.4 – COMPARISON OF UTAH 5, 10, AND 20-YEAR AVERAGE PEAK PRODUCING TEMPERATURES ........................................... 7 FIGURE A.5 – LOAD FORECAST SCENARIOS, PRE-DSM ............................................................................................................ 18 APPENDIX B – REGULATORY COMPLIANCE APPENDIX C – PUBLIC INPUT PROCESS APPENDIX D – DEAND-SIDE MANAGEMENT APPENDIX E – SMART GRID APPENDIX F – FLEXIBLE RESERVE STUDY FIGURE F.1 - BASE SCHEDULE RAMPING ADJUSTMENT .......................................................................................................... 134 FIGURE F.2 - PROBABILITY OF EXCEEDING ALLOWED DEVIATION .............................................................................................. 139 FIGURE F.3 - WIND REGULATION RESERVE REQUIREMENTS BY FORECAST - PACE ...................................................................... 141 FIGURE F.4 - WIND REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR - PACW ............................................ 141 FIGURE F.5 - SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR - PACE ............................................. 142 FIGURE F.6 - SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR - PACW ........................................... 142 FIGURE F.7 – NON-VER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR - PACE ..................................................... 143 FIGURE F.8 – NON-VER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR - PACW ................................................... 143 FIGURE F.9 – STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS - PACE ..................................................................... 144 FIGURE F.10 – STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS - PACW ................................................................. 144 FIGURE F.11 – INCREMENTAL WIND AND SOLAR REGULATION RESERVE COSTS .......................................................................... 153 FIGURE F.12 - COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES, EAST BALANCING AUTHORITY AREA (MW) ................... 157 FIGURE F.13 - COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES, WEST BALANCING AUTHORITY AREA (MW) .................. 157 APPENDIX G – PLANT WATER CONSUMPTION STUDY APPENDIX H – STOCHASTIC PARAMETERS FIGURE H.1 – STOCHASTIC PROCESSES ............................................................................................................................... 167 FIGURE H.2 – RANDOM WALK PRICE PROCESS AND MEAN REVERTING PROCESS ....................................................................... 167 FIGURE H.3 – LOGNORMAL DISTRIBUTION AND CUMULATIVE LOGNORMAL DISTRIBUTION ........................................................... 168 FIGURE H.4 – DAILY GAS PRICES FOR SUMAS BASIN, 2018-2021 ........................................................................................ 169 FIGURE H.5 – DAILY GAS PRICES FOR SUMAS BASIN WITH "EXPECTED" PRICES, 2018-2021 ...................................................... 171 FIGURE H.6 – GAS PRICE INDEX FOR SUMAS BASIN, 2018-2021 ......................................................................................... 172 FIGURE H.7 – REGRESSION FOR SUMAS GAS BASIN ............................................................................................................ 173 FIGURE H.8 – DAILY ELECTRICITY PRICES FOR FOUR CORNERS, 2018-2021 .............................................................................. 175 FIGURE H.9 – PROBABILITY DISTRIBUTION FOR PORTLAND LOAD, 2018-2021 .......................................................................... 176 FIGURE H.10 – DAILY AVERAGE LOAD FOR PORTLAND, 2018-2021 ....................................................................................... 177 FIGURE H.11 – WEEKLY AVERAGE HYDRO GENERATION IN THE WEST, 2017-2021 ................................................................... 179 PACIFICORP – 2023 IRP TABLE OF CONTENTS xi APPENDIX I – CAPACITY EXPANSION RESULTS FIGURE I.1 – PREFERRED PORTFOLIO RESOURCE AND TRANSMISSION MAP ............................................................................... 183 APPENDIX J – STOCHASTIC SIMULATION RESULTS APPENDIX K – CAPACITY CONTRIBUTION FIGURE K.1 – RENEWABLE RESOURCES VS. HIGH LOAD CONDITIONS ........................................................................................ 247 FIGURE K.2 – RENEWABLE RESOURCES VS. LOW LOAD CONDITIONS......................................................................................... 247 APPENDIX L – PRIVATE GENERATION STUDY APPENDIX M – RENEWABLE RESOURCE ASSESSMENT APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION FIGURE N.1 – HYDROGEN ELECTROLYSIS LOAD FACTOR ......................................................................................................... 400 FIGURE N.2 – HYDROGEN ELECTROLYSIS LOAD FACTOR BY MONTH AND HOUR, SOUTHERN OREGON ............................................ 401 FIGURE N.3 – HYDROGEN ELECTROLYSIS LOAD FACTOR BY MONTH AND HOUR, UTAH NORTH ..................................................... 402 FIGURE N.4 – HYDROGEN ELECTROLYSIS LOAD FACTOR BY MONTH AND HOUR, WYOMING EAST .................................................. 403 FIGURE N.5 – GREENHOUSE GAS EMISSIONS DURING HYDROGEN ELECTROLYSIS LOAD HOURS AS PERCENTAGE OF 2023 AVERAGE .... 404 APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS FIGURE O.1 – INTERIM TARGETS ....................................................................................................................................... 407 FIGURE O.2 - INCREMENTAL PORTFOLIO CHANGE: W-10 CETA DELTA P-SC ............................................................................ 415 APPENDIX P – ACRONYMS PACIFICORP – 2023 IRP TABLE OF CONTENTS xii PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 1 APPENDIX A – LOAD FORECAST Introduction This appendix reviews the load forecast used in the modeling and analysis of the 2023 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 to develop a 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. These separate customer classes include residential, commercial, industrial, irrigation, and lighting customer classes. The classes are modeled separately using variables specific to their usage patterns. For residential customers, typical energy uses include space heating, air conditioning, 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 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 May 2022. The compound annual load growth rate for the 10-year period (2023 through 2032) is 2.69 percent. Relative to the load forecast prepared for the 2021 IRP, PacifiCorp’s 2032 forecast load requirement increased in Oregon, Utah and Idaho, while PacifiCorp system load requirement increased 17.00 percent in 2032. Figure A.1 has a comparison of the load forecasts from the 2023 IRP to the 2021 IRP. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 2 Figure A.1 – PacifiCorp System Energy Load Forecast Change, at Generation, pre-DSM Table A.1 and Table A.2 show the annual load and coincident peak load forecast when not reducing load projections to account for new energy efficiency measures.1 Table A.3 and Table A.4 show the forecast changes relative to the 2021 IRP load forecast for loads and coincident system peak, respectively. Table A.1 – Forecasted Annual Load, 2023 through 2032 (Megawatt-hours), at Generation, pre-DSM Year Total OR WA CA UT WY ID 2023 64,032,930 16,209,670 4,638,720 863,330 28,599,180 9,644,200 4,077,830 2024 67,499,270 18,374,450 4,692,110 861,560 29,740,030 9,763,560 4,067,560 2025 69,805,060 19,730,320 4,700,760 855,220 30,361,220 10,074,860 4,082,680 2026 69,938,420 20,457,650 4,721,760 852,970 29,687,480 10,113,240 4,105,320 2027 72,649,770 21,761,290 4,756,830 853,180 31,034,420 10,116,940 4,127,110 2028 76,681,120 23,445,960 4,811,200 856,480 33,183,740 10,229,110 4,154,630 2029 77,919,280 23,952,780 4,841,310 855,160 33,861,360 10,239,970 4,168,700 2030 78,811,840 24,066,060 4,885,350 855,790 34,483,900 10,332,550 4,188,190 2031 80,380,690 24,821,690 4,930,700 856,600 35,199,890 10,364,120 4,207,690 2032 81,321,780 25,160,880 4,990,400 859,960 35,600,350 10,476,730 4,233,460 Compound Annual Growth Rate 2023-32 2.69% 5.01% 0.82% -0.04% 2.46% 0.92% 0.42% 1 Energy efficiency load reductions are included as resources in the Plexos model. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 3 Table A.2 – Forecasted Annual Coincident Peak Load (Megawatts) at Generation, pre-DSM Year Total OR WA CA UT WY ID 2023 11,033 2,650 835 147 5,408 1,221 772 2024 11,427 2,833 846 147 5,537 1,295 770 2025 11,747 3,011 857 148 5,628 1,301 803 2026 11,758 3,054 871 148 5,572 1,305 808 2027 12,051 3,188 887 150 5,707 1,306 813 2028 12,485 3,323 905 151 5,993 1,317 794 2029 12,683 3,487 926 156 6,023 1,292 798 2030 12,815 3,507 946 158 6,101 1,301 803 2031 13,123 3,631 966 160 6,214 1,311 841 2032 13,209 3,632 985 161 6,268 1,316 847 Compound Annual Growth Rate 2023-32 2.02% 3.56% 1.86% 1.03% 1.65% 0.83% 1.03% Table A.3 – Annual Load Change: May 2022 Forecast less June 2022 Forecast (Megawatt-hours) at Generation, pre-DSM Year Total OR WA CA UT WY ID 2023 789,940 450,990 (17,310) (19,170) 388,800 (112,270) 98,900 2024 3,047,960 2,268,330 (18,530) (26,610) 947,850 (199,700) 76,620 2025 4,642,800 3,490,810 (29,480) (33,670) 1,020,190 117,860 77,090 2026 5,411,390 4,038,830 (39,130) (38,160) 1,334,560 33,730 81,560 2027 7,471,370 5,152,040 (39,360) (39,230) 2,333,490 (23,110) 87,540 2028 10,597,700 6,589,320 (39,200) (39,800) 3,990,880 1,290 95,210 2029 11,150,620 6,915,680 (38,590) (40,210) 4,251,510 (38,250) 100,480 2030 11,088,630 6,798,020 (37,750) (42,820) 4,328,150 (61,120) 104,150 2031 11,852,040 7,341,690 (27,480) (42,960) 4,566,100 (101,550) 116,240 2032 11,814,570 7,448,410 (22,820) (43,290) 4,388,360 (85,440) 129,350 Table A.4 – Annual Coincident Peak Change: May 2022 Forecast less June 2022 Forecast (Megawatts) at Generation, pre-DSM Year Total OR WA CA UT WY ID 2023 342 188 46 5 154 (58) 7 2024 620 353 50 6 211 (5) 5 2025 805 511 53 6 209 (2) 28 2026 891 540 61 7 264 (10) 29 2027 1,112 661 71 7 356 (15) 31 2028 1,441 784 82 8 568 (12) 12 2029 1,550 936 96 14 533 (43) 14 2030 1,577 945 108 16 538 (47) 17 2031 1,785 1,060 120 18 584 (45) 49 2032 1,807 1,077 133 19 572 (49) 56 PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 4 Load Forecast Assumptions Regional Economy by Jurisdiction The PacifiCorp electric service territory is comprised of six states and within these states the Company serves customers in 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. PacifiCorp uses both economic data, such as employment, and population data, to forecast its retail sales. Looking at historical sales and employment data for PacifiCorp’s service territory, 2000 through 2021, in Figure A.2, it is apparent that the Company’s retail sales are correlated to economic conditions in its service territory, and most recently the economic downturn and rebound from the COVID-19 pandemic. Figure A.2 – PacifiCorp Annual Retail Sales 2000 through 2021 and Western Region Employment The 2023 IRP forecast utilizes the March 2022 release of IHS Markit economic driver forecast, whereas the 2021 IRP relied on the October 2019 release from IHS Markit. Figure A.3 shows the weather normalized average system residential use per customer. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 5 Figure A.3 – PacifiCorp Annual Residential Use per Customer 2001 through 2021 Weather The Company’s load forecast is based on historical actual weather adjusted for expectations and impacts from climate change. The historical weather is defined by the 20-year period of 2002 through 2021. The climate change weather uses the data from the historical period and adjusts the percentile of the data to achieve the expected target average annual temperature and calculate the HDD and CDD impacts and peak producing weather impacts within the energy forecast and peak forecast, respectively. The climate change weather target temperature relies on actual 1990 average temperatures and projected temperature increases over 1990 average temperatures as determined by the United States Bureau of Reclamation (Reclamation) in the West-Wide Climate Risk Assessments: Hydroclimate Projections Study (Study).2 The Company determined daily average temperatures and peak producing temperatures that correspond to the midpoint of the projected temperature increase between the Representative Concentration Pathway (RCP) 4.5 and RCP 8.5 ranges in the Study. 2 United States Bureau of Reclamation, March 2021, Managing Water in the West, Technical Memorandum No. ENV-2021-001, West-Wide Climate Risk Assessments: Hydroclimate Projections. https://www.usbr.gov/climate/secure/docs/2021secure/westwidesecurereport1-2.pdf PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 6 Table A.5 – Projected Range of Temperature Change in the 2020s and 2050s relative to the 1990s3 Bureau of Reclamation Site PacifiCorp Jurisdiction Assumption Projected Range of Temperature Change (°F)* 2020s 2050s Klamath River near Klamath California 1.7 to 2.6 3.6 to 5.2 Snake River Near Heise Idaho 1.6 to 3.0 4.1 to 5.9 Klamath River near Seiad Valley Oregon 1.8 to 2.7 3.7 to 5.3 Green River near Greendale Utah 1.8 to 3.3 4.2 to 6.3 Yakima River at Parker Washington 1.8 to 2.8 3.6 to 5.6 Green River near Greendale Wyoming 1.8 to 3.3 4.2 to 6.3 *Lower bound of temperature projections based on RCP 4.5, while upper bound based on RCP 8.5 In addition to climate change weather discussed above, the Company has reviewed the appropriateness of using the average weather from a shorter time period as its “normal” peak weather. Figure A.4 indicates that peak producing weather does not change significantly when comparing five, 10, or 20-year average weather. The Company also updated its temperature spline models to the five-year time period of October 2016 – September 2021. The Company’s spline models are used to model the commercial, residential and irrigation class temperature sensitivity at varying temperatures. 3 Ibid. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 7 Figure A.4 – Comparison of Utah 5, 10, and 20-Year Average Peak Producing Temperatures 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 the 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 0 10 20 30 40 50 60 70 80 90 100 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec De g r e e s Utah Average Peak Producing Weather (Average Dry Bulb Temperature on Peak Day (Deg F.)) 20 Year Average 10 Year Average 5 Year Average PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 8 jurisdictions. Customer forecasts are provided by the customer to the Company through a regional business manager (“RBM”). Actual Load Data With the exception to the industrial class, the Company uses actual load data from January 2000 through February 2022. The historical data period used to develop the industrial monthly sales forecast is from January 2000 through February 2022 in Utah, Wyoming, and Washington, January 2002 through February 2022 in Idaho, and January 2003 through February 2022 in California and January 2008 through February 2022 in Oregon. The following tables are the annual actual retail sales, non-coincident peak, and coincident peak by state used in calculating the 2023 IRP retail sales forecast. Table A.6 – Weather Normalized Jurisdictional Retail Sales 2000 through 2021 System Retail Sales - Megawatt-hours (MWh)* Year California Idaho Oregon Utah Washington Wyoming System 2000 770,820 3,116,508 13,850,006 18,970,364 4,084,537 7,411,248 48,203,483 2001 768,864 3,005,141 13,392,332 18,559,167 3,995,989 7,652,997 47,374,489 2002 791,735 3,256,168 12,957,060 18,630,359 3,992,241 7,429,503 47,057,066 2003 812,166 3,269,807 12,939,631 19,281,125 4,041,618 7,426,913 47,771,259 2004 835,515 3,333,624 13,058,719 19,892,658 4,073,666 7,793,618 48,987,800 2005 827,540 3,285,758 13,059,825 20,363,787 4,183,226 7,993,309 49,713,446 2006 848,726 3,346,052 13,774,581 21,187,643 4,108,566 8,209,339 51,474,907 2007 866,742 3,425,039 13,871,720 22,086,852 4,053,437 8,504,273 52,808,062 2008 857,500 3,444,347 13,135,644 22,715,811 4,052,529 9,203,352 53,409,183 2009 819,819 2,979,003 12,970,802 22,146,938 4,024,282 9,256,870 52,197,714 2010 835,326 3,468,573 13,046,266 22,590,597 4,023,412 9,648,267 53,612,440 2011 797,736 3,493,098 12,891,100 23,406,694 3,994,623 9,792,857 54,376,107 2012 776,608 3,543,173 12,902,817 23,692,760 4,017,534 9,469,443 54,402,334 2013 766,445 3,586,627 12,955,649 23,770,781 4,029,058 9,533,401 54,641,961 2014 763,083 3,574,849 13,044,614 24,245,893 4,074,243 9,587,020 55,289,702 2015 732,905 3,532,641 13,044,577 24,008,248 4,064,376 9,360,103 54,742,851 2016 745,142 3,495,674 13,203,510 23,655,727 4,012,667 9,191,271 54,303,991 2017 749,028 3,608,590 13,230,882 23,807,001 4,044,195 9,331,829 54,771,525 2018 733,383 3,641,048 13,190,422 24,586,138 4,030,934 9,243,563 55,425,488 2019 735,995 3,530,085 13,272,614 24,527,670 4,022,640 9,317,139 55,406,143 2020 755,926 3,596,981 13,179,949 24,703,889 4,074,386 8,317,048 54,628,180 2021 787,505 3,534,599 13,698,449 25,272,678 4,108,739 8,494,257 55,896,227 Compound Annual Growth Rate 2000-21 0.10% 0.60% -0.05% 1.38% 0.03% 0.65% 0.71% *System retail sales do not include sales for resale PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 9 Table A.7 – Non-Coincident Jurisdictional Peak 2000 through 2021 Non-Coincident Peak - Megawatts (MW)* 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 2015 157 843 2,598 5,226 837 1,326 10,986 2016 155 848 2,584 5,018 819 1,300 10,724 2017 177 830 2,920 4,932 943 1,354 11,156 2018 158 830 2,608 5,091 849 1,319 10,854 2019 151 793 2,632 5,158 895 1,363 10,993 2020 155 806 2,562 5,336 848 1,271 10,979 2021 149 771 2,894 5,547 938 1,299 11,598 Compound Annual Growth Rate 2000-21 -0.77% 0.56% 0.51% 1.97% 0.85% 0.96% 1.22% *Non-coincident peaks do not include sales for resale Table A.8 – Jurisdictional Contribution to Coincident Peak 2000 through 2021 Coincident Peak - Megawatts (MW)* 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 PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 10 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 2015 152 805 2,472 5,081 833 1,259 10,601 2016 139 575 2,462 4,940 817 1,201 10,135 2017 152 593 2,547 4,911 787 1,306 10,296 2018 126 741 2,526 5,037 790 1,295 10,514 2019 122 731 2,276 5,158 761 1,248 10,297 2020 127 603 2,428 5,336 839 1,180 10,515 2021 145 767 2,543 5,319 839 1,214 10,827 Compound Annual Growth Rate 2000-21 -0.29% 1.84% 0.38% 1.76% 0.50% 1.03% 1.19% *Coincident peaks do not include sales for resale System Losses Line loss factors are derived using the five-year average of the percent difference between the annual system load by jurisdiction and the retail sales by jurisdiction. System line losses were updated to reflect actual losses for the five-year period ending December 31, 2021. Forecast Methodology Overview Demand-side Management Resources in the Load Forecast PacifiCorp modeled as a resource option to be selected as part of a cost-effective portfolio resource mix using the Company’s Plexos capacity expansion optimization model. The load forecast used for IRP portfolio development excluded forecasted load reductions from energy efficiency; Plexos then determines the amount of energy efficiency —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 energy efficiency supply curves, along with the economic screening provided by Plexos, determines the cost-effective mix of energy efficiency 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 forecasted number of customers. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 11 The customer forecasts are based on a combination of regression analysis and exponential smoothing techniques using historical data from January 2000 to February 2022. For the residential class, the Company forecasts the number of customers using IHS Markit’s forecast of each state’s population or number of households as the major driver. The Company uses a differenced model approach in the development of the residential customer forecast. Rather than directly forecasting the number of customers, the differenced model predicts the monthly change in number of customers. 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 and non-farm employment designated as the major economic drivers, 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 RBM’s. 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 in all states with exception of Utah, in which an Industrial Production Index is used. 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 RBM’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 load above baseload 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 the climate change peak-producing weather discussed above. 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 for the 20-year period 2002 through 2021, 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. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 12 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. Electrification Adjustments The load forecast used for 2023 IRP portfolio development includes the Company’s expectations for transportation electrification based on current and expected electric-vehicle (EV) adoption trends. These projections were incorporated as a post-model adjustment to the residential and commercial sales forecasts. Vehicle adoption and load impacts vary by state depending on a variety of socioeconomic factors and policies particular to each state. To develop a prospective forecast of EV adoption, PacifiCorp developed a model to assess trends for light-duty EVs and medium-duty EVs. To develop a future EV adoption curve, the Company reviewed three national EV forecasts, each representing varying degrees of aggressiveness. While these forecasts represent national trends, the adoption curves themselves can be applied and adapted to state-specific parameters to reflect current market conditions in the state. The Company calibrates each adoption curve source to base inputs from EIA’s Annual Energy Outlook (AEO) projections and estimated historical vehicle actuals. The AEO inputs include estimated shares of battery electric vehicles and plug-in hybrid electric vehicles as well as light-duty vehicles and light-duty trucks. Each of the national adoption curve sources is discussed below to help contextualize the various sources reviewed for this plan’s EV adoption forecast4. The load forecast also incorporates the Company’s expectations for building electrification initiatives. In the near-term, building electrification is relatively minor share of load but is expected to grow over time as state and national policies encouraging fuel substitution and electrification become more prevalent. The Company’s building electrification forecast is based on expected fuel shares for space heating and water heating equipment at the end of its useful life and future new construction shares of electric fuel for these end-uses over time. Adoption curves are calibrated to expected equipment turnover and new construction rates in alignment with assumptions used in the Conservation Potential Assessment. Adoption curves and timing of building electrification is estimated based on the state specific policies or known market trends supporting advancement of building electrification. The Company continually assesses both transportation and building electrification market trends, policies, and adoptions levels in each state. As these markets evolve, the Company will continue to update forecasts to reflect new trends as they occur. 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. 4 Transportation electrification impacts for Oregon and Washington may differ slightly from estimated impacts provided in transportation electrification plans as result of the vintage associated with data inputs. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 13 Table A.9 – System Annual Retail Sales Forecast 2021 through 2032, post-DSM System Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 17,361,583 20,978,789 18,760,385 1,472,103 98,858 58,671,719 2024 17,561,027 23,333,643 18,912,628 1,463,717 95,519 61,366,533 2025 17,663,790 24,565,976 19,192,595 1,455,086 92,615 62,970,063 2026 17,860,209 25,344,020 17,755,233 1,449,220 90,685 62,499,366 2027 18,075,462 27,203,257 17,720,663 1,442,125 89,172 64,530,679 2028 18,386,033 30,063,031 17,769,947 1,434,670 88,119 67,741,799 2029 18,633,432 30,372,554 17,700,916 1,426,506 86,618 68,220,026 2030 18,972,662 30,145,257 17,751,969 1,419,207 85,392 68,374,488 2031 19,332,679 30,522,754 17,739,953 1,412,108 84,220 69,091,714 2032 19,852,639 30,155,847 17,782,332 1,403,445 83,419 69,277,682 Compound Annual Growth Rate 2023-32 1.50% 4.11% -0.59% -0.53% -1.87% 1.86% Residential The average annual growth of the residential class sales forecast increased from 0.80 percent in the 2021 IRP to 1.50 percent in the 2023 IRP. The number of residential customers across PacifiCorp’s system is expected to grow at an annual average rate of 1.48 percent, reaching approximately 2.06 million customers in 2032, with Rocky Mountain Power states adding 1.82 percent per year and Pacific Power states adding 0.92 percent per year. Commercial Average annual growth of the commercial class sales forecast increased from 1.04 percent annual average growth in the 2021 IRP to 4.11 percent in the 2023 IRP. The number of commercial customers across PacifiCorp’s system is expected to grow at an annual average rate of 0.90 percent, reaching approximately 246,000 customers in 2032, with Rocky Mountain Power states adding 1.18 percent per year and Pacific Power states adding 0.52 percent per year. Industrial Average annual growth of the industrial class sales forecast decreased from -0.11 percent annual average growth in the 2021 IRP to -0.59 percent expected annual growth in the 2023 IRP. A portion of the Company’s industrial load is in the extractive industry in Utah and Wyoming; therefore, changes in commodity prices can impact the Company’s load forecast. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 14 State Summaries Oregon Table A.10 summarizes Oregon state forecasted retail sales growth by customer class. Table A.10 – Forecasted Retail Sales Growth in Oregon, post-DSM Oregon Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 5,776,140 6,971,569 1,458,214 270,754 29,920 14,506,597 2024 5,813,544 8,727,403 1,466,594 270,264 29,236 16,307,041 2025 5,806,005 9,761,216 1,495,283 269,413 28,514 17,360,433 2026 5,840,308 10,246,092 1,489,796 269,210 28,009 17,873,416 2027 5,887,124 11,251,088 1,475,161 268,963 27,619 18,909,955 2028 5,974,783 12,561,821 1,461,575 268,836 27,405 20,294,420 2029 6,054,951 12,820,090 1,455,444 268,381 27,108 20,625,973 2030 6,172,566 12,677,326 1,453,566 268,029 26,950 20,598,436 2031 6,314,070 13,084,453 1,459,414 267,642 26,835 21,152,414 2032 6,495,531 13,089,511 1,476,758 267,370 26,832 21,356,002 Compound Annual Growth Rate 2023-32 1.31% 7.25% 0.14% -0.14% -1.20% 4.39% Washington Table A.11 summarizes Washington state forecasted retail sales growth by customer class. Table A.11 – Forecasted Retail Sales Growth in Washington, post-DSM Washington Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 1,569,912 1,569,506 828,111 161,366 3,294 4,132,188 2024 1,575,457 1,581,008 825,124 159,738 3,231 4,144,559 2025 1,566,405 1,568,866 812,588 158,750 3,199 4,109,809 2026 1,566,847 1,564,706 802,531 158,297 3,192 4,095,573 2027 1,567,629 1,565,138 796,393 157,806 3,190 4,090,156 2028 1,575,315 1,567,825 794,158 157,247 3,200 4,097,744 2029 1,574,971 1,559,991 789,614 156,835 3,190 4,084,601 2030 1,580,219 1,556,026 787,560 156,474 3,190 4,083,470 2031 1,585,479 1,555,833 787,983 156,415 3,190 4,088,900 2032 1,596,353 1,556,759 788,347 156,000 3,199 4,100,658 Compound Annual Growth Rate 2023-32 0.19% -0.09% -0.55% -0.38% -0.32% -0.09% PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 15 California Table A.12 summarizes California state forecasted sales growth by customer class. Table A.12 - Forecasted Retail Sales Growth in California, post-DSM California Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 377,233 238,946 54,997 97,232 1,628 770,037 2024 377,131 237,264 53,389 96,630 1,600 766,014 2025 374,277 233,240 52,235 96,229 1,569 757,549 2026 372,480 230,331 51,812 96,016 1,549 752,188 2027 370,942 228,808 51,440 95,783 1,534 748,507 2028 370,818 227,945 51,185 95,583 1,527 747,058 2029 368,319 225,742 50,735 95,268 1,515 741,578 2030 366,926 224,681 50,478 95,019 1,509 738,613 2031 365,606 223,441 50,232 94,649 1,504 735,432 2032 365,968 223,270 50,189 94,220 1,506 735,153 Compound Annual Growth Rate 2023-32 -0.34% -0.75% -1.01% -0.35% -0.86% -0.51% Utah Table A.13 summarizes Utah state forecasted sales growth by customer class. Table A.13 – Forecasted Retail Sales Growth in Utah, post-DSM Utah Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 7,835,131 10,246,229 8,137,068 233,429 49,506 26,501,364 2024 7,986,696 10,832,402 8,238,305 230,300 47,036 27,334,739 2025 8,119,480 11,064,958 8,233,901 227,009 45,163 27,690,511 2026 8,284,098 11,384,983 6,807,862 223,609 44,067 26,744,620 2027 8,454,824 12,261,214 6,827,830 219,645 43,400 27,806,913 2028 8,665,353 13,820,108 6,843,943 215,282 43,126 29,587,812 2029 8,844,710 13,908,034 6,817,082 210,766 42,770 29,823,362 2030 9,066,276 13,850,077 6,834,566 206,189 42,633 29,999,741 2031 9,287,214 13,845,537 6,834,089 201,514 42,554 30,210,908 2032 9,613,627 13,483,845 6,814,215 195,865 42,630 30,150,181 Compound Annual Growth Rate 2023-32 2.30% 3.10% -1.95% -1.93% -1.65% 1.44% PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 16 Idaho Table A.14 summarizes Idaho state forecasted sales growth by customer class. Table A.14 - Forecasted Retail Sales Growth in Idaho, post-DSM Idaho Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 793,909 551,520 1,770,789 679,642 2,641 3,798,500 2024 804,094 554,572 1,736,293 677,301 2,625 3,774,885 2025 806,682 552,218 1,736,660 674,431 2,594 3,772,585 2026 811,343 549,260 1,735,986 672,973 2,571 3,772,133 2027 815,138 545,183 1,734,061 670,967 2,547 3,767,897 2028 820,769 542,345 1,732,080 668,926 2,531 3,766,652 2029 819,247 534,579 1,728,504 666,588 2,502 3,751,419 2030 820,297 527,445 1,726,072 664,917 2,480 3,741,211 2031 820,173 519,098 1,724,099 663,366 2,460 3,729,196 2032 823,076 514,464 1,722,624 661,563 2,447 3,724,174 Compound Annual Growth Rate 2023-32 0.40% -0.77% -0.31% -0.30% -0.84% -0.22% Wyoming Table A.15 summarizes Wyoming state forecasted sales growth by customer class. Table A.15 – Forecasted Retail Sales Growth in Wyoming, post-DSM Wyoming Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 1,009,258 1,401,020 6,511,205 29,679 11,870 8,963,032 2024 1,004,104 1,400,993 6,592,922 29,485 11,791 9,039,295 2025 990,941 1,385,479 6,861,929 29,252 11,575 9,279,176 2026 985,132 1,368,647 6,867,245 29,115 11,297 9,261,436 2027 979,805 1,351,827 6,835,777 28,961 10,882 9,207,251 2028 978,994 1,342,988 6,887,006 28,797 10,329 9,248,113 2029 971,235 1,324,118 6,859,538 28,668 9,534 9,193,092 2030 966,378 1,309,701 6,899,728 28,579 8,631 9,213,017 2031 960,137 1,294,392 6,884,136 28,522 7,676 9,174,863 2032 958,085 1,287,998 6,930,199 28,427 6,805 9,211,514 Compound Annual Growth Rate 2023-32 -0.58% -0.93% 0.70% -0.48% -5.99% 0.30% Wyoming Retail Sales – Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2023 1,009,258 1,401,020 6,511,205 29,679 11,870 8,963,032 2024 1,004,104 1,400,993 6,592,922 29,485 11,791 9,039,295 2025 990,941 1,385,479 6,861,929 29,252 11,575 9,279,176 2026 985,132 1,368,647 6,867,245 29,115 11,297 9,261,436 2027 979,805 1,351,827 6,835,777 28,961 10,882 9,207,251 2028 978,994 1,342,988 6,887,006 28,797 10,329 9,248,113 2029 971,235 1,324,118 6,859,538 28,668 9,534 9,193,092 2030 966,378 1,309,701 6,899,728 28,579 8,631 9,213,017 2031 960,137 1,294,392 6,884,136 28,522 7,676 9,174,863 2032 958,085 1,287,998 6,930,199 28,427 6,805 9,211,514 Compound Annual Growth Rate 2023-32 -0.58% -0.93% 0.70% -0.48% -5.99% 0.30% PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 17 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 varying temperatures and economic conditions. The May 2022 forecast is the baseline scenario. For the high and low load growth scenarios, optimistic and pessimistic economic driver assumptions from IHS Markit were applied to the economic drivers in the Company’s load forecasting models. These growth assumptions were extended for the entire forecast horizon. Further, the high and low load growth scenarios also incorporate the standard error bands for the energy and the peak forecast to determine a 95% prediction interval around the base IRP forecast. Lastly, the high scenario incorporates the Company’s low private generation forecast, while the low scenario incorporates the high private generation forecast. The 95% prediction interval is calculated at the system level and then allocated to each state and class based on their contribution to the variability of the system level forecast. The standard error bands for the jurisdictional peak forecasts were calculated in a similar manner. The final high load growth scenario includes the optimistic economic forecast and low private generation forecast plus the monthly energy adder and the monthly peak forecast with the peak adder. The final low load growth scenario includes the pessimistic economic forecast and high private generation forecast minus the monthly energy adder and monthly peak forecast minus the peak adder. 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. The 20-year normal scenario is based on normal weather, which is defined by the 20-year time period of 2002 through 2021 (50th percentile). In prior IRP cycles, this scenario was traditionally used as the base IRP load forecast. Figure A.5 shows the comparison of the above scenarios relative to the Base Case scenario. PACIFICORP – 2023 IRP APPENDIX A – LOAD FORECAST 18 Figure A.5 – Load Forecast Scenarios, pre-DSM - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Me g a w a t t ( M W ) 1-in-20 Weather 20-Year Normal High Base Case Low PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 19 APPENDIX B - REGULATORY COMPLIANCE Introduction This appendix describes how PacifiCorp’s 2023 Integrated Resource Plan (IRP) complies with (1) the various state commission IRP standards and guidelines, (2) specific analytical requirements stemming from acknowledgment orders for the company’s 2021 Integrated Resource Plan, and other ongoing IRP acknowledgement order requirements as applicable, 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.33 ● Table B.2 - Provides a description of how PacifiCorp addressed the 2021 IRP acknowledgement order 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 Transportation Commission IRP rules issued in December 2020 in WAC 480-100-620. ● Table B.6 - Provides an explanation of how this plan addresses each of the items contained in the Wyoming Public Service Commission IRP guidelines updated in March 2016. 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 from 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 serves to inform all parties on the planning issues and approach. The public input process for this IRP will be described in Volume I, Chapter 2 (Introduction), as well as Volume II, Appendix C (Public) Input fully complies with IRP standards and guidelines. 33 California Public Utilities Code Section 454.5 allows utility with less than 500,000 customers in the state to request an exemption 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 – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 20 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 load 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 options include supply-side, demand- side, and transmission alternatives. The evaluation of the alternatives in the IRP, as detailed in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (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 could 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 8 – Modeling and Portfolio Evaluation. 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 carbon dioxide (CO2) emissions. This portfolio analysis and the results and conclusions drawn from the analysis are described in Volume I, Chapter 9 (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 10 (Action Plan). 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. The Action Plan also provides a progress report on action items contained in the 2021 IRP. The 2023 IRP and related Action Plan are filed with each commission with a request for acknowledgment or acceptance, as applicable. Acknowledgment or acceptance means that a commission recognizes the IRP as meeting all regulatory requirements at the time of acknowledgment. In a case where a commission acknowledges the IRP in part or not at all, PacifiCorp may modify and seek to re-file an IRP that meets their acknowledgment standards or address any deficiencies in the next plan. 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. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 21 California Public Utilities Code Section 454.52, mandates that the California Public Utilities Commission (CPUC) adopt a process for load serving entities to file an IRP beginning in 2017. In February 2016, the CPUC opened a rulemaking to adopt an IRP process and address the scope of the IRP to be filed with the CPUC (Docket R.16-02-007). Decision (D.) 18-02-018 instructed PacifiCorp to file an alternative IRP consisting of any IRP submitted to another public regulatory entity within the previous calendar year (Alternative Type 2 Load Serving Entity Plan). D.18-02-018 also instructed PacifiCorp to provide an adequate description of treatment of disadvantaged communities, as well as a description of how planned future procurement is consistent with the 2030 Greenhouse Gas Benchmark. PacifiCorp also provides its IRP and an IRP Supplement in lieu of providing a Renewables Portfolio Standard Procurement Plan, as authorized by Public Utilities Code Section 399.17(d). Requirements for PacifiCorp’s IRP Supplement are outlined in an annual Assigned Commissioner’s Ruling from the CPUC1 and D.22-12-030 issued on December 19, 2022, approving the company’s 2021 IRP Supplement (2022 Off-Year Supplement to its 2021 IRP). On October 18, 2019, PacifiCorp submitted its 2019 IRP in compliance with D.18-02-018. On April 6, 2020, the CPUC issued D.20-03-028, which reiterated PacifiCorp’s ability to file an alternative IRP. On September 1, 2021, PacifiCorp filed its 2021 IRP in Docket R.18-07-003 in compliance with D.08-05-029. On November 1, 2022, PacifiCorp filed its 2021 IRP in Docket R.20-05-003 in compliance with D.18-02-018, D.20-03-028, and D.22-02-004. On January 18, 2023, PacifiCorp filed its 2021 IRP Supplement (2022 Off-Year Supplement to its 2021 IRP) in Docket R.18-07-003 in compliance with D.08-05-029 and D.22-12-030. Idaho The Idaho Public Utilities Commission’s (Idaho PUC) Order No. 22299, issued in January 1989, specifies integrated resource planning requirements. This order mandates that PacifiCorp submit a 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 1 The most recent Assigned Commissioner’s Ruling is the Assigned Commissioner and Assigned Administrative Law Judge’s Ruling Identifying issues and Schedules of Review for 2022 Renewables Portfolio Standard Procurement Plans and Denying Joint IOU’s Motion to File Advice Letters for Market Offer Process¸ Rulemaking 18-07-003 (April 11, 2022). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 22 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 2023, 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 Oregon PUC’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), 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. 12-013 ). Consistent with the earlier guidelines (Order 89- 5072), the Oregon PUC notes that acknowledgment does not guarantee favorable ratemaking treatment, only that the plan seems reasonable at the time acknowledgment is given. Table B provides detail on how this plan addresses each of the requirements. Utah This IRP is submitted to the Public Service Commission of Utah 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 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 a two-year progress report of the previously filed plan, which was the Company’s 2021 IRP (Washington Administrative Code 480-100-625) (effective, December 2020). In its report, the rule requires PacifiCorp to include an update of its load forecast; demand-side resource assessment, including new conservation potential assessment; resource costs; and the portfolio analysis and preferred portfolio. The report must also include other updates that are necessary due to changing state or federal requirements, or significant changes to economic or market forces; and an update for any elements found in the Company’s current Clean Energy Implementation Plan (CEIP). Please refer to Appendix O (Washington Two-year Progress Report Additional Elements) for additional detail regarding updates to elements of the Company’s CEIP. Wyoming Wyoming Public Service Commission issued new rules that replaced the previous set of rules on March 21, 2016. Chapter 3, Section 33 outlines the requirements on filing IRPs for any utility serving Wyoming customers. The rule, shown below, went into effect in March 2016. 2 Public Utility Commission of Oregon, Order No. 12-013, Docket No. 1461, January 19, 2012. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 23 Table B.1 provides detail on how this plan addresses the rule requirements. Section 33. Integrated Resource Plan (IRP). Each utility serving in Wyoming that files an IRP in another jurisdiction shall file that IRP with the Commission. The Commission may require any utility to file an IRP. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 24 PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 25 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. 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). Commission General Order R-601 further adopted IRP rules compliant with CETA. Order 22299 Electric Utility Conservation Standards and Practices January 1989. Wyoming Electric, Gas and Water Utilities, Chapter 3, Section 33, March 21, 2016. 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. Filing Least-cost plans must be An IRP is to be submitted Submit a least cost plan to Submit Resource Each utility serving in Requirements filed with the Oregon to commission. the WUTC. Plan to be Management Report on Wyoming that files and PUC. developed with planning status. Also, file IRP in another consultation of WUTC progress reports on jurisdiction, shall file the staff, and with public conservation, low-income IRP with the commission. involvement. programs, lost opportunities and capability building. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 26 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. Unless otherwise ordered by the commission, each electric utility must file an integrated resource plan (IRP) with the commission by January 1, 2021, and every four years thereafter. At least every two years after the utility files its IRP, beginning January 1, 2023, the utility must file a two-year progress report. 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 to file an IRP. 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. 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 reviews the IRP as directed by the Commission and drafts a memo to report its findings to the commission in an open meeting or technical conference. Note, however, that Rate Plan legislation allows pre-approval of near- term resource investments. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 27 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 Oregon PUC 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 WUTC 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 15 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, environmental risks, and equitable distribution of benefits 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 – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 28 As part of the IRP, utilities must develop a ten-year clean energy action plan for implementing RCW 19.405.030 through 19.405.050. Elements Basic elements include: 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 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 July 2016 cover: • Sufficiency of the public comment process • Utility strategic goals, resource planning goals and preferred resource portfolio • Resource need over the near-term and long- term planning horizons • Types of resources considered • Changes in expected resource acquisitions and load growth from the previous IRP • Environmental impacts considered • Market purchase evaluation • Reserve margin analysis • Demand-side management and conservation options • 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. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 29 • Construction of resource portfolios over the range of system capability and reliability. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 30 identified risks and uncertainties. • Portfolio analysis shall include fuel transportation and transmission requirements. • Plan includes conservation potential study, demand response resources, environmental costs, and distributed generation technologies. • Avoided cost filing required within 30 days of acknowledgment. • A comparative evaluation of energy supply resources (including transmission and distribution) and improvements in conservation using “lowest reasonable cost” criteria. • An assessment and determination of resource adequacy metrics. • An assessment of energy and nonenergy benefits and reductions of burdens to vulnerable populations and highly impacted communities; long- term and short- term public health and environmental benefits, costs, and risks; and energy security risk • 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 – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 31 • Must develop a ten- year clean energy action plan for implementing RCW 19.405.030 through 19.405.050. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 32 • The IRP must include a summary of substantive changes to modeling methodologies or inputs that result in changes to the utility's resource need, as compared to the utility's previous IRP. • The IRP must include an analysis and summary of the avoided cost estimate for energy, capacity, transmission, distribution, and greenhouse gas emissions costs. The utility must list nonenergy costs and benefits addressed in the IRP and should specify if they accrue to the utility, customers, participants, vulnerable populations, highly impacted communities, or the general public. • The utility must provide a summary of public comments received during the development of its IRP and the utility's responses, including PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 33 whether issues raised in the comments were addressed and incorporated into the final IRP as well as documentation of the reasons for rejecting any public input PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 34 PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 35 Table B.2 – Handling of 2021 IRP Acknowledgment and Other IRP Requirements Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP Idaho Order No. 35514 p. 17 We direct the Company, in its next IRP, to clarify whether a LOLH reliability target of 2.4 hours per year was achieved by the Company’s portfolios and explain the development of FOT availability limits. Because of limitations on computing power, the Company has not performed detailed hourly stochastic analysis so as to precisely determine the reliability of each of its portfolios. For reference, due to the complexity of the Company’s portfolio and system operations, running one year of one study through 50 iterations could take a single computer upwards of a week. The Company’s reliability assessment is intended to ensure that each portfolio achieves a comparable level of reliability. Because each study measures availability against requirements in every hour during the reliability assessment, all portfolios will logically achieve comparable reliability. Further, ENS measures support that this is the case. Discussion of the Company’s FOT availability limits is provided in Chapter 5 (Reliability and Resiliency). Order No. 35514 p. 17 We further direct the Company to clarify the issue of exceedance of FOT limits in the early years of the planning horizon as it pertains to the first deficit date for purposes of PURPA avoided cost rates and whether the inclusion of three percent contingency amounts for firm purchases were appropriate to include to meet Company load. A discussion of exceedances in the first several years is provided in Chapter 5 (Reliability and Resiliency). Such exceedances are unavoidable as the Company pursues sufficient resources to reduce market reliance of the 20-year planning period. In actual operations, PacifiCorp must balance the risk of higher reliance on market purchases against the cost of procuring from a limited pool of resource options available in the very near term, rather than from a larger pool of resource options available in the next few years. That balancing will be a key consideration in PacifiCorp’s ongoing 2022 All-Source Request for Proposals. As a result, forthcoming developments may be more pertinent to the question of deficit dates than the 2023 IRP itself. As detailed in Volume II, Appendix F (Flexible Reserve Study), to the extent the PacifiCorp’s firm market purchases come from entities in other balancing authority areas, those entities will cover the contingency reserve obligation on the generation used to support the sale, and PacifiCorp’s contingency reserve obligation will be reduced relative to what it would have been had it used its own generation to serve that portion of its load. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 36 Order No. 35514 p. 17 While we understand the market realities of natural gas, we encourage the Company to continue exploring an approach in its IRP process that allows for a reasonable and accurate selection of cost-effective natural gas resources in a portfolio. PacifiCorp has included natural gas in its resource options per the supply-side resource table as developed throughout the public input meeting process. New gas options were not selected in the least-cost, least-risk methodology to develop the final preferred portfolio. PacifiCorp recognizes that many non-emitting technologies require technological progress to achieve the capabilities and costs assumed in the 2023 IRP, and will continue to consider technologies that are presently available. Because the Inflation Reduction Act provides tax credits only for non-emitting resources, gradually transitioning a new resource to a non-emitting fuel comes at a significant cost. See Volume I, Chapter 7 (Resource Options). Order No. 35514 p. 17 Finally, we acknowledge the inherent complexities with the Natrium project and direct the Company to continue to assess the risks of technology viability and potential delays with Natrium and plan accordingly. In this cycle, Natrium is anticipated to come online in the summer of 2030. The 2023 IRP includes two “no nuclear” variant studies as described in Chapters 8 and 9, designed to inform alternative path analysis and potential costs and benefits. PacifiCorp continues to evaluate nuclear resources within the context of an evolving planning environment. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 37 Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP Oregon Order No. 22-178, p. 7 Require PacifiCorp to perform additional and more varied analyses regarding Jim Bridger Units 3 and 4, including a no minimum take analysis as suggested by Staff and Sierra Club and an analysis of endogenous retirement dates frequent enough to approximately match Staffs suggestion of allowing for retirement every two years. In the 2023 IRP, retirements are optimized in every available year. As communicated during the 2023 public input meeting series and in response to feedback, no minimum take assumptions were assumed in Plexos modeling beyond present contracts. For Jim Bridger 3 and 4 this means the complete removal of minimum take provisions. Order No. 22-178, p. 7 PacifiCorp is directed to file an updated long-term fuel plan for Jim Bridger with its 2023 IRP. On March 28, 2023, the Commission granted PacifiCorp’s request for an extension of time to submit the updated long-term fuel plan for Jim Bridger on May 31, 2023. Order No. 22-178, p. 10 Consider how to ensure PacifiCorp has a complete and balanced portfolio given the current posture of the Natrium project. In this cycle, Natrium is anticipated to come online in the summer of 2030. The 2023 IRP includes two “no nuclear” variant studies as described in Volume I, Chapters 8 and 9, designed to inform alternative path analysis and potential costs and benefits. PacifiCorp continues to evaluate nuclear resources within the context of an evolving planning environment. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 38 Order No. 22-178, p. 11 In future IRPs, we expect PacifiCorp to articulate clearer justifications for its transmission projects, including how the company assessed transmission needs and alternatives comprehensively, how and why a particular project was selected in a transmission planning process, why it is reasonable for ratepayers to pay substantial costs for these particular projects, and what quantifiable (and quantified) and non-quantifiable (but valued qualitatively) benefits will come to Oregon ratepayers in particular and PacifiCorp ratepayers in general, as compared with benefits from regional projects that accrue to other regional actors not contributing to costs. For the 2023 IRP, PacifiCorp evaluated transmission options based on the three cluster study outcomes completed thus far, as well as other analysis for locations not well-represented in the cluster study process. This represents the best available information regarding potential costs and resources. The addition of surplus and flexible hybrid resource options specifically allows the model to avoid transmission costs while increasing net generating capability at a given location using proportions of different technologies that are appropriate to a location and the needs of the portfolio as a whole. These options were modeled endogenously and in competition with a wide array of resources as detailed in multiple public input meetings. See Volume I, Chapter 4 (Transmission), and Volume I, Chapter 8 (Modeling and Portfolio Evaluation). Order No. 22-178, p. 12 We also expect PacifiCorp to produce the full cost information for the [transmission] projects we acknowledge today in the rate cases where it seeks to place them into rate base. PacifiCorp is committed to giving full accounting in its rate case proceedings. For the 2023 IRP, summary cost information is provided in Volume I, Chapter 1 (Executive Summary), and expanded cost information is provided in workpapers. Order No. 22-178, p. 13 In order to connect new resources to the grid, it is critical not only that transmission be built, but that the right transmission be built; the Commission and stakeholders need to have sufficient information to verify that ratepayers are getting the benefits they are paying for at each stage of development. Going forward, we expect PacifiCorp to provide information that allows that assessment at the outset. We also expect the company to actively encourage key stakeholders like Commission Staff and consumer advocates to participate and provide a larger window into its own transmission planning processes. IRP modeling accounts for cost, location, total transfer capability and resource enabled by transmission options. Options are modeled endogenously, and selections are driven primarily by the need to increase interconnection to allow efficient system transfer and to serve load. In the 2023 IRP, costs, descriptions, and transfer capabilities are defined, and in addition near-term transfer options are rooted in cluster study and queue analysis and informed by surplus resource options which allow for transmission costs to be avoided where appropriate. The transmission option modeling strategy was discussed at three public input meetings spanning June 2022 through February 2023 with opportunities for feedback and recommendations. Also, modeling of scale renewable resources for Oregon’s CEP assumes there are no accompanying transmission requirements, providing an additional opportunity to evaluate transmission avoidance beyond the native core functionality of the Plexos PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 39 model. See Volume I, Chapter 4 (Transmission), and Volume I, Chapter 8 (Modeling and Portfolio Evaluation). Order No. 22-178, p. 14 We direct PacifiCorp to forecast a likely QF contract renewal rate. Because PacifiCorp operates in a multi-state footprint, we understand this assessment to be more complicated than an Oregon-only renewal rate. However, PacifiCorp should use historical renewable rates as well as other relevant information in its possession and attempt to make its forecast as accurate as possible. PacifiCorp used an analysis of historical rates to establish a 79% renewal rate, which was implemented in the 2023 IRP and presented at the September 1-2, 2022 public input meeting. The analysis can be viewed at this web link: https://www.pacificorp.com/content/dam/pcorp/doc uments/en/pacificorp/energy/integrated-resource- plan/2023-irp/QF_Extension_History_2012-2017- 2022.xlsx. For the purpose of modeling in the 2023 IRP, each QF was assumed to have a 79% chance of renewing, so it is reduced to 79% of its current size upon reaching its current expiration date and then continues indefinitely. Order No. 22-178, p. 14; Appx B p. 1 Develop and run a sensitivity that considers locations or online dates for large, flexible loads such as hydrogen electrolysis within the 2023 IRP. The parameters of the study would be further discussed in the 2023 IRP process. Such a sensitivity would consider optimal locations and years to include large amounts of highly flexible load, throughout the planning timeframe. We adopt this recommendation and note that there may be additional large loads, such as data centers, that fall under this recommendation too. See Volume II, Appendix N: (Energy Storage Potential Evaluation) for analysis of potential hydrogen electrolysis load opportunities. PacifiCorp would note that with expected transmission builds and the sizeable quantity of energy storage on its system in the preferred portfolio, the difference in marginal prices by location is relatively small. While co- locating hydrogen electrolysis with renewable generation may have some benefits, it may be outweighed by the costs of transporting hydrogen to end users. In addition, the potential for flexible load is also represented in part through stochastic load variation and through seven load-related sensitivities. In addition to the 2023 IRP’s four core load sensitivities (High load, Low Load, 1 in 20 Load and 20-year Normal Load) and two load-related sensitivities (High Private generation and Low Private Generation), PacifiCorp has also added a “New Load” sensitivity which contemplates an unanticipated large load addition to understand the impacts of such an occurrence. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results). PacifiCorp continues to evaluate how to usefully model larger amounts of flexible load. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 40 Order No. 22-178, p. 15; Appx B p. 1 PacifiCorp to conduct a stakeholder process to determine what source the cost data in the 2023 IRP will rely on. PacifiCorp’s initial cost assumptions were provided at a workshop held on September 2, 2022 as part of its public input process. In addition, stakeholders participated in the decision to model offshore wind and associated transmission on a linear basis where any amount of a 1000 MW project could be selected assuming PacifiCorp could participate in partnership with other utilities. The decision was also made to allow other resources to compete for usage of the land-based transmission system upgrades necessary to enable offshore wind. An offshore wind counterfactual study was also run to determine the magnitude of the costs and benefits of offshore wind. See Volume I, Chapters 8 and 9. Order No. 22-178, p. 15; Appx B p. 1 We expect PacifiCorp to engage in the company's local transmission planning process as appropriate and to request that sufficient information to inform consideration of offshore wind in future IRPs is made available in this local transmission study cycle. PacifiCorp completed an Economic Study Request (“ESR”), submitted by the Oregon Public Utility Commission (“OPUC”) Staff March 2022 to have PacifiCorp evaluate the effects of 1.0 GW of Offshore Wind (OSW) generation in southern Oregon, assumed to be interconnected to PacifiCorp’s Del Norte substation located in Del Norte, California. Order No. 22-178, p. 15; Appx B p. 2 PacifiCorp to review its pumped hydro proposals as part of its 2023 IRP public workshop series. PacifiCorp will perform a variety of analyses regarding pumped storage hydro … including a careful comparison with other possible pumped storage hydro projects, in the 2023 IRP … [and] sufficient information to be able to conclude that PacifiCorp has considered resources other than its own in this process. The 2023 IRP considered seven proxy pumped hydro resource locations across the system. All seven use identical cost and size characteristics appropriate for proxy modeling, and cover at minimum four projects unassociated with PacifiCorp. As modeled, none of the projects are actual, and the Company is not modeling its own projects. Instead, the 2023 IRP represents pumped hydro storage as proxy resources. Every endogenous model run considers the selection of any or all of these resources among the multitude of competing options. Whether selected or not, pumped hydro projects are eligible to bid into PacifiCorp’s all-source RFPs where determinations of which projects are contracted is decided by additional agnostic modeling of actual bids, potentially both benchmarks and market bids. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 41 Order No. 22-178, p. 16; Appx B p. 2 In places where there are inconsistencies between the WRAP and the approach the IRP takes … we direct that the reasons for any discrepancies be explained by PacifiCorp. The Western Resource Adequacy Program (WRAP) uses a series of Effective Load Carrying Capability (ELCC) analyses to identify the aggregate capacity contribution of wind, solar, and run-of-river hydro. Attribution of capacity to individual resources is based, in part, on a resource’s generation during the top 5 percent net load hours, i.e. those hours in which the remaining load is highest after subtracting out wind and solar generation. The WRAP also uses a five-hour duration for determining the capacity contribution of energy-limited resources, like batteries. A five-hour or longer duration storage resource receives a 100% contribution, while shorter durations are prorated relative to five hours, such that a one-hour storage has a 20% contribution, while four-hour storage has an 80% contribution. There is significant uncertainty about storage duration requirements and they are necessarily portfolio dependent, so the WRAP will update its capacity contribution calculations each year. PacifiCorp does not have the detailed information about WRAP participants to perform the same calculations over the IRP study horizon. Instead, Volume I, Chapter 6 (Load and Resource Balance) presents portfolio contributions to capacity for PacifiCorp’s 2023 IRP with capacity allocated among resources primarily based on generation during the top 5 percent net load hours, which was also part of the WRAP design. Because ELCC analyses require very data intensive studies with long run times, they have not been performed for the 2023 IRP load and resource reporting across the 20-year IRP horizon. Instead, the remaining capacity between the net load peak and the coincident peak, including the planning reserve margin was allocated among those resources with generation during the top 5 percent load hours that exceeded that during the top 5 percent net load hours. In addition to the above, PacifiCorp used the five-hour duration assumption from the WRAP for energy-limited resources at the start of the IRP planning horizon, but increased the required duration as more energy storage resources were added to the preferred portfolio, which emulates the likely outcomes in the WRAP. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 42 Order No. 22-178, p. 16 Commissioners, Staff, or the Administrative Hearings Division will lead … a workshop to discuss increasing efficiency and demand response, including the consideration of a new, or updated, risk-reduction credit to efficiency. Not applicable. PacifiCorp is supportive of the workshop and plans to participate as more details are known. Order No. 22-178, p. 16; Appx B p. 2 Staff stated that it is supportive of PacifiCorp's plan to include peak time rebates in the 2023 CPA. If peak time rebates are determined to be cost-effective, PacifiCorp should further include an exploration of the potential to use a third-party vendor to implement a peak time rebate in advance of the new billing system implementation, in comparison to an approach that waits until the new billing system is implemented, as part of its 2023 IRP. Engaging a consultant and preparing a study for a peak time rebate that would use the Company pre- existing billing system would be premature and duplicative at this time, because the Company is actively in the process of replacing its billing system. While AMI is a necessary precedent before deploying a peak time rebate program, an advanced billing system is also needed with an analytical engine that is capable of accurately billing customers on peak time rebate. Fortunately, the new billing system the Company is planning to deploy would be able to process a peak time rebate program with some minor changes and would be in service on or around 2025. PacifiCorp did assess the potential costs and benefits of peak time rebates in the CPA to inform future determinations and considerations for implementation of peak time rebates. Order No. 22-178, p. 16-17; Appx B p. 3 Require PacifiCorp to meet with developer intervenors, upon request, to determine a subset of the confidential data supporting the 2023 IRP that does not include commercially sensitive information that can be provided. The subset would not necessarily need to include all confidential data that is not commercially sensitive. Require PacifiCorp to seek to balance developer intervenors' need for information as IRP stakeholders with PacifiCorp's need to protect commercially sensitive information and keep the data management workload to a reasonable level. PacifiCorp met twice with Commission Staff and associations that represent developers and developer stakeholders that participated in the Company’s 2021 IRP proceeding, docket LC 77. The first meeting occurred on November 8, 2022 and a follow up meeting was held on March 20, 2023. As a result of these meetings, PacifiCorp restructured its workpaper reporting format that will allow a greater amount of information to be public. It will also designate commercially sensitive information as highly confidential; thus, ensuring developers will have access to all confidential information, not just a subset. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 43 Order No. 22-178, p. 17 We direct PacifiCorp to hold at least one workshop on equity and justice issues related to the generation transition in its 2023 IRP, and we will ask members of our staff with expertise on these issues to participate. We recognize PacifiCorp’s relationship to employees and to the communities where its resources are located and encourage the company to explain how consideration of both factor into planning processes. PacifiCorp held a “Generation Transition Equity and Justice Workshop” on September 2, 2022. Topics included community action, promotion and organization of resources, employee transition plan and transition program, and current actions. The company has also held 14 CBIAG meetings since October 27, 2022. Order No. 22-178, p. 18; Appx B p. 1 PacifiCorp to take steps to provide complete and accurate information in the 2023 IRP that reflects accurate IRP modeling assumptions. We adopt this recommendation, though we note that we believe PacifiCorp has already been attempting to comply with this principle. PacifiCorp has aligned itself with this expectation by providing timely and comprehensive modeling outcomes, which have been included in the 2023 IRP and the preferred portfolio respectively. Order No. 22-178, p. 18 Require PacifiCorp's 2023 IRP storage costs in the Supply Side Table to be in line with the most recent National Renewal Energy Laboratory Annual Technology Baseline report and most recent RFP Final Shortlist. Our understanding is that Staff’s recommendation reflects a preference from stakeholders for publicly available sources, but that Staff also acknowledges the relevance of the market information obtainable from the most recent RFP. We thus adopt Staff’s recommendation to the extent that it requires the use of publicly available data as well as proprietary sources, but with the understanding that discrepancies from the publicly available data be explained. PacifiCorp presented on this topic at the September 1, Public Input Meeting. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 44 Order No. 22-178, p. 18; Appx B p. 1 PacifiCorp to provide a map of resources in the IRP Executive Summary, which PacifiCorp agrees to do. This requirement is met by the preferred portfolio map provided in Appendix I (Capacity Expansion Results). Order No. 22-178, p. 18-19; Appx B p. 2 Require PacifiCorp to explain the reliability limitations of the LT capacity expansion model and how the IRP team selected the reliability resources of change. PacifiCorp made a strong effort at explanation in this IRP, but that the company should seek to understand questions that remain and mature its narrative discussion accordingly. The LT model simultaneously evaluates the entire 20 year IRP horizon and all possible resource additions and retirements. With PacifiCorp’s system and resource options, this is a lot of possibilities and the model cannot evaluate every hour, let alone maintain the chronological links necessary to consider all likely combinations of load, wind, and solar while enforcing energy storage duration limits, emissions constraints, and thermal unit cycling restrictions. As a result more granular analysis within the ST model is necessary to identify the extent that reliability, environmental compliance, and economics are addressed. Discussion of reliability resources follows below. Order No. 22-178, p. 19; Appx B p. 2 Require PacifiCorp to include with the 2023 IRP data discs: a. A list of the resources that were considered as reliability resources; b. A list of the reliability resources that were selected in each portfolio, sensitivity, and variant; c. A clearly marked set of hourly reliability (ENS) data that the Company used to identify the type and size of reliability resources to add to each portfolio, sensitivity, variant; and d. Any metric the Company used to select reliability resources in each portfolio, sensitivity and variant a. All resources were open to consideration as reliability resources for selection based on their value to the system. Workpapers will be provided for each case indicating portfolio changes and for each case indicating hourly unserved energy and reserve shortfalls. These workpapers identify the specific hours in which shortfalls occurred within each year. b. From the hourly shortfall data, the Company identified the largest consecutive blocks of shortfalls, including the month and hours of the day in which they occurred. The company then reviewed resource costs and benefits reported by Plexos specific to the case in question to determine which types of resources would be most economic to cover the identified need. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 45 Order No. 22-178, p. 19; Appx B p. 2 Before the 2023 IRP, include climate-change risk and adaptation as a topic of a public- input meeting to share and discuss approaches to modeling climate risk in the IRP including: proposed changes to how weather and extreme events are considered; proposed changes for the consideration of climate-related risks on supply side resources, transmission, and loads; and a discussion on how the Company proposes to include climate change impacts as part of the status quo. We adopt this recommendation and note that we appreciate PacifiCorp's thorough responses on this important issue. PacifiCorp engaged stakeholders on climate change at several public meetings, including: • May 12, 2022 • September 1-2, 2022 • October 13, 2022 • A primary function of these discussions was to discuss the incorporation of climate change as a base assumption in the 2023 IRP. In addition a “no climate change” study (W-11 Climate Change Counterfactual) is provided in the 2023 IRP. Order No. 22-178, p. 20; Appx B p. 2 Change PacifiCorp's Environmental, Transmission, and DSM Updates from a twice-annual report to an annual report. This change has been adopted. Order No. 22-178, Appx B p. 1 In the 2023 IRP, PacifiCorp should provide a metric calculated in its capacity expansion model that provides stakeholders with an estimate of the relative value of each coal unit to the system. This value is calculated in each study for every resource which is available for selection. Each resource’s annual value is calculated, as well as an aggregate value over the period of the study. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 46 Order No. 22-178,Appx B p. 1 The 2023 IRP data discs should provide graphs of the average fixed and variable costs of operating each coal unit over the planning timeframe. This should include fuel cost and run rate capital, but exclude depreciation expense. PacifiCorp will provide appropriate reference materials on the data disc. Order No. 22-178,Appx B p. 1 As a part of the 2023 IRP development process, PacifiCorp should fully assess the potential for gas conversion; use of hydrogen, biofuel, or other lower-carbon fuels; or alternate coal stockpile or supply methods for Jim Bridger 3 and 4. A report should be included with the 2023 IRP. PacifiCorp presented its assessment of alternative fuels at the 2023 IRP June 9-10 public input meeting. “LC 82 (PAC 2023 IRP) – Special Public Meeting – Waivers for extension to file the CEP and Long-Term Fuel Plan.” Order No. 22-178,Appx B p. 1 If technically feasible, PacifiCorp should report on the costs and emissions (CO2 and NOX) of green hydrogen combustion at the converted Bridger unit. PacifiCorp continues to assess the viability of green hydrogen, as well as the ability for existing infrastructure to accommodate the chemical properties of this fuel type. The Company’s existing generation equipment is not well suited to green hydrogen combustion because exposure to high- temperature hydrogen results in degradation of many critical alloy components, particularly within steam turbines. Conversion of combustion turbines to hydrogen fueling is more promising, because the hot gas path is more contained, with fewer components at risk, but is not yet commercially available for the large turbines in PacifiCorp’s fleet. Conversion of combustion turbines could potentially include combined cycle combustion turbines as the associated steam turbine is not directly exposed to hydrogen combustion. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 47 Order No. 22-178,Appx B p. 1 The 2023 IRP should more thoroughly investigate the potential to install a new turbine designed to run on 100 percent green hydrogen at the sites of one or more retiring coal plants. PacifiCorp continues to assess the viability of green hydrogen, as well as the ability for existing infrastructure to accommodate the chemical properties of this fuel type. PacifiCorp’s modeling in the 2023 IRP allows for non-emitting peaking units at current coal plant sites and in other locations. These peaking resources were assumed to be fueled using 100 percent green hydrogen, supplied via pipeline due the high cost of onsite storage, but a wide variety of non-emitting fuels and generation technologies are currently under development. Order No. 22-178,Appx B p. 1 In the 2023 IRP, variable O&M costs should be modeled accurately as variable with generation, and not approximated as part of fixed O&M costs as they have been in the 2021 IRP. This enhancement has been incorporated for the 2023 IRP. Order No. 22-178, Appx B p. 2 In future IRPs or during future RFP processes, potential RFP bidders should be given access to a 12x24 Loss of Load Probability matrix for one out of every five years in the IRP planning timeframe. Following the completion of the 2021 IRP and in advance of bid submissions in the 2022 All-Source RFP, PacifiCorp prepared the requested information and provided it to stakeholders in its January 25, 2022 filing in docket UM 2011. Following the completion of the 2023 IRP, PacifiCorp will develop comparable information for use in future RFP processes. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 48 Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP Utah DOCKET NO. 90-2035-01 p. 33-37 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 associated with different acquisition strategies. PacifiCorp’s load forecast is developed for each jurisdiction and by customer class. Further, this forecast includes off-system wholesale customers for which the Company has a contractual obligation to fulfill. To plan for non-firm off-system customer impacts returning to PacifiCorp’s system, 1-year and 3-year option direct access customers in Oregon are incorporated into the forecast assuming they will return once their opt-out period expires. DOCKET NO. 90-2035-01 p. 33-37 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. PacifiCorp has evaluated these market conditions to inform a least-cost, least-risk preferred portfolio outcome. Changes to consumer behavior are also outlined under the suite of existing demand-side management, energy efficiency and load forecast projections at the disposal of the Company. DOCKET NO. 90-2035-01 p. 33-37 An evaluation of all present and future resources, including future market opportunities (both demand-side and supply-side), on a consistent and comparable basis. PacifiCorp has attempted to include a wide range of potential resource options within its supply-side table, and has included reasonable cost estimates for all resource types. Where costs and operating characteristics are similar, as with different lithium- ion chemistries, the IRP does not attempt to differentiate – no particular technology is correct, and differences in performance are expected to be well within the normal range of offers from bidders. Even non-emitting peaking and nuclear resources are ultimately proxies for their particular combinations of costs, operating characteristics, and risks. Many types of risks are expected to evolve over the next few planning cycles both risks associated with these new technologies, and those associated with emitting technologies. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 49 DOCKET NO. 90-2035-01 p. 33-37 An assessment of all technically feasible and cost-effective improvements in the efficient use of electricity, including load management and conservation. PacifiCorp has evaluated all technically feasible and cost-effective energy efficiency, conservation, and load management through the Conservation Potential Assessment to compete with other resources in the IRP modeling. DOCKET NO. 90-2035-01 p. 33-37 An assessment of all technically feasible generating technologies including: renewable resources, cogeneration, power purchases from other sources, and the construction of thermal resources. PacifiCorp has evaluated all known technically feasible generating technologies including: renewable resources, cogeneration, and the construction of thermal resource. The IRP does not represent ownership structures for proxy resources. Any resource could end up being a Build Transfer Agreement (BTA), Power Purchase Agreement (PPA), self-build, or other contract structure. DOCKET NO. 90-2035-01 p. 33-37 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. The resource assessments include: life expectancy of the resources, the recognition of whether the resource is replacing/adding capacity or energy, dispatchability, lead-time requirements, flexibility, and efficiency of the resource and opportunities for customer participation. DOCKET NO. 90-2035-01 p. 33-37 An analysis of the role of competitive bidding for demand-side and supply-side resource acquisitions. Demand side bids were permitted to participate in the all-source RFP and inputs for assessment was developed so that potential demand side bids could compete with supply side resources. Additionally, demand side resources are evaluated as part of the IRP modeling to evaluate overall competitiveness with other resources. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 50 DOCKET NO. 90-2035-01 p. 33-37 A 20-year planning horizon. The 2023 IRP covers a 20-year horizon from 2023 through 2042. DOCKET NO. 90-2035-01 p. 33-37 A two-year 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. This requirement is met in Volume I, Chapter 10 (Action Plan). DOCKET NO. 90-2035-01 p. 33-37 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. This requirement is met in Volume I, Chapter 10 (Action Plan). DOCKET NO. 90-2035-01 p. 33-37 Load forecasts integrated with resource options in a manner which rationalizes the choice of resources under a variety of economic circumstances. Modeling for the 2023 IRP incorporates multiple load forecasts and price-policy scenarios under which resources compete on an optimized basis for the selection of resource options, retirements, unit conversions, transmission options, market purchases and sales, and other elements. See Volume I, Chapters 7, 8 and 9. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 51 DOCKET NO. 90-2035-01 p. 33-37 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. PacifiCorp presents it alternative path analysis in Volume I, Chapter 10 (Action Plan). DOCKET NO. 90-2035-01 p. 33-37 An evaluation of the cost-effectiveness of the resource options from a variety of perspectives and society as a whole. PacifiCorp’s 2023 IRP evaluates risk via a risk- adjustment metric based on stochastic modeling results, provides a set of competitive variant portfolios, and includes studies assuming a social cost of greenhouse gas cost-adder as a price-policy scenario. DOCKET NO. 90-2035-01 p. 33-37 An evaluation of the 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. PacifiCorp’s 2023 IRP evaluates risk via a risk- adjustment metric based on stochastic modeling results, and includes a Business Plan sensitivity. The 2023 IRP will be used to inform the Business Plan. DOCKET NO. 90-2035-01 p. 33-37 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 2023 IRP endogenously evaluates the attributes of competing resource options through its input data, which is reflective of the costs, operational characteristics, technology type, location, interconnection availability and other factors. In addition, the RFP non-price scoring process evaluates, in coordination with several independent evaluators representing three states, the project and reliability risks and scores these results accordingly. The assumptions in the Business Plan and 20-year Integrated Resource Plan are ultimately modified and realized through actual generating projects that are either owned or under contract and represent ratepayer risk, not shareholder risk, except to the extent that the commitments or actions of the Company are deemed imprudent in a future PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 52 ratemaking proceeding. During RFP procurements, the terms of contracts are also reviewed by independent evaluators and are available and submitted to regulatory staff upon request or by order or statute. These contracts include performance guarantees to balance the risk between the project owner and the Company on behalf of ratepayers. DOCKET NO. 90-2035-01 p. 33-37 Considerations permitting flexibility in the planning process so that the Company can take advantage of opportunities and can prevent the premature foreclosure of options. PacifiCorp assesses the potential value of resources against risk and the expense of time and resources in the development of its supply side resources. The 2023 IRP included discussion of supply side resource, beginning earlier in the public input process than in previous IRPs, and revisited several times. Particular options were considered in expanded discussion topics such as coal options and offshore wind. The 2023 IRP also included natural gas resource options, which had been excluded in the 2021 IRP. DOCKET NO. 90-2035-01 p. 33-37 An analysis of tradeoffs; for example, between such conditions of service as reliability and the acquisition of lowest cost resources. The 2023 IRP inherently evaluates trade-offs between reliability and resource cost, as well as operational costs incurred during dispatch as part of the core functionality of optimization modeling. This is the purpose of the optimization. Additional analysis is provided in narrative form where salient trade-offs are indicated in portfolio outcomes. See Volume I, Chapter 9 (Modeling and Portfolio Selection Results). DOCKET NO. 90-2035-01 p. 33-37 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. Future environmental and safety regulation has an almost unfathomable potential range of outcomes, many of which may be contradictory with other rules or policy goals, as in restrictions on non- emitting resources. What is certain, is that compliance may involve costs dramatically in excess of even the social cost of greenhouse gases price- policy scenario. As an example, coal ash handling and water treatment is only partly related to ongoing operations, but the costs could offset years of possible operational benefits depending on the circumstances. Environmental and safety regulation is not limited to fossil fuel resources, a few very basic examples include: - Very few battery chemistries have significant history in utility-scale operations, and some PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 53 examples of fire hazards have been identified. - Wind turbines present risks related to birds and bats. - Cadmium telluride solar panels include two toxic chemicals, which while significantly less harmful in compound form, do not have well documented long-term effects. The above is not intended to be comprehensive - all technologies have trade-offs and risks though some technologies have more unknown unknowns than others. The largest externality of which the Company is currently aware is the impact of greenhouse gases on the climate. A price-policy scenario with an estimate of the social cost of greenhouse gases is used to quantify that particular externality, and analysis including those costs is presented for the preferred portfolio and selected variant portfolios. DOCKET NO. 90-2035-01 p. 33-37 The public, state agencies and other interested parties will have the opportunity to make formal 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 acknowledgement 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 acknowledgement of the Integrated Resource Plan might be appropriate but are not required. 7. Acknowledgement of an acceptable Plan will not guarantee favorable ratemaking treatment of future resource acquisitions. PacifiCorp will participate fully in the described process. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 54 Docket No. 21-035-09, UPSC June 2, 2022 Order p. 5-8 PacifiCorp must comply with Guidelines 4(b) and 4(i) by not constraining its model to preclude selection of new natural gas resources The 2023 IRP included natural gas resource options, which had been excluded in the 2021 IRP. Docket No. 21-035-09, UPSC June 2, 2022 Order p. 9-18 PacifiCorp will provide information to stakeholders three business days in advance of public meetings PacifiCorp consistently provided meeting materials to stakeholders via email within the parameters of this requirement. See Volume II, Appendix C (Public Input). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 55 DOCKET NO. 90-2035-01 p. 33-37 The Integrated Resource Plan will be used in rate cases to evaluate the performance of the utility and to review avoided cost calculations. PacifiCorp is compliant with this standard. Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP Washington State Rule/Statute Requirement Incorporate the social cost of greenhouse gases (SCGHG) as a cost adder, as required by RCW 19.280.030(3), and provide a narrative illustrating step-by-step how the SCGHG cost adder is applied throughout its modeling logic. The SCGHG impact on the Company’s modeling and portfolio analyses should be addressed in numerous variables, including PacifiCorp’s imports and contracts and forward price curves. PacifiCorp is compliant with this statute and has provided a narrative framework outlining carbon price policy scenario assumptions and nominal electric and natural gas price inputs, which were discussed at the February 23, 2023 Public Input meeting. State Rule/Statute Requirement Integrate the demand forecasts and resource evaluations into a long-range IRP solution describing the mix of resources that meet current and projected resource needs, abiding by a variety of constraints pursuant to statute and per Commission rule. WAC 480-100-620(11) The Plexos models were used to evaluate resource on a comparable basis following the requirements in statute and appropriate to this filing’s status as a Two-Year Progress Report. See Chapter 8 and Appendix O. State Rule/Statute Requirement Include an assessment of battery and pumped storage for integrating renewable resources. The assessment may consider ancillary services at the appropriate granularity required to model such storage resources. WAC 480-100-620(5) The 2021 IRP Two-Year Progress Report incorporates multiple storage options including lithium-ion, flow and iron-air batteries, and pumped hydro storage. Modeling was conducted at appropriate granularity in the Plexos LT, MT and ST models. See Volume I, Chapters 7 and 8. State Rule/Statute Requirement A future climate change scenario that meets the requirements of WAC 480-100-620(10)(b), which is "At least one scenario must be a future climate change scenario. This scenario should incorporate the best science available to analyze impacts including, but not limited to, changes in snowpack, streamflow, rainfall, PacifiCorp’s base case includes future climate impacts on the load forecast, energy efficiency potential, and the hydro generation forecast. The base load forecast for the 2023 IRP is based on a Bureau of Reclamation median projection of climate impacts through time on heating and cooling degree days, resulting in increasing divergence from the 20-year normal weather further in the IRP planning horizon. The hydro forecast similarly relies on projected seasonal changes PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 56 heating and cooling degree days, and load changes resulting from climate change." in streamflows in response to climate impacts that evolve across the IRP planning horizon. A scenario using the 20-year normal weather forecast for load and hydro was prepared for comparison purposes. State Rule/Statute Requirement Identify an appropriate resource adequacy requirement (i.e., loss of load probability) and complete the assessment, as required by WAC 480-100-620(8) This item is not required for a Two-Year Progress Report and is not explicitly addressed in terms of avoided cost in this filing. However, the Progress Report includes expanded reporting of reliability assessment including identifying deficiencies and the resolution of deficiencies based on model outcomes. The Plexos modeling process and the ENS metric indicates that reliability has been achieved. State Rule/Statute Requirement Provide resource assumptions and market forecasts used in the utility's schedule of estimated avoided costs required in WAC 480-106-040, including but not limited to: -Cost Assumptions -Production Estimates -Peak capacity contribution estimates and annual capacity factor estimates This item is not required for a Two-Year Progress Report and is not explicitly addressed in terms of avoided cost in this filing. However, resource assumptions, capacity factors and price forecasts are included in workpapers. PacifiCorp would note that its 2023 IRP uses forward market prices from September 2022, which is the same vintage as PacifiCorp’s November 1, 2022 avoided cost filing in docket number 220804 State Rule/Statute Requirement Compare and evaluate all identified resources and potential changes to existing resources for achieving the clean energy transformation standards in WAC 480-100-610 at the lowest reasonable cost, including a narrative of the decisions it has made. WAC 480-100-620(7) and (11) The 2021 IRP Two-Year Progress Report compares all resource options in its optimized evaluation, and provides narratives of comparative analysis of outcomes in Volume I, Chapter 9, and details regarding resource attributes in Volume I, Chapter 7. Address WAC 480-100-620(2), The IRP must include a range of forecasts of projected customer demand that reflect the effect of economic forces on the consumption of electricity and address changes in the number, type, and efficiency of end uses of electricity. 1.) alternative load forecast scenarios, including climate change impacts 2.) Optimistic and Pessimistic assumptions in the low and high growth models and how these alternative forecasts differ from the base forecast 3.) Electrification adjustments made to the load forecast PacifiCorp conducts a variety of load forecast scenarios. Also, to account for changes in the number, type and efficiency of end-uses, the Company updates its statistically adjusted end-use model used in the load forecast. See Volume II, Appendix A (Load Forecast) for details regarding the alternative load forecast scenarios. Specifically, the Company’s base forecast includes expected climate change impacts on loads, while the 20-year normal load forecast scenario provides the load forecast without explicitly accounting for climate change temperatures. Further, the Company does produce both optimistic and pessimistic load forecast scenarios. Please refer to Appendix A (Load Forecast) for details regarding transportation and building electrification adjustments made to the load forecast. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 57 State Rule/Statute Requirement Address how the IRP update meets with the requirement in RCW 19.280.030(1)(m) regarding electric and zero-emission vehicles. RCW 19.280.030(1)(m) An analysis of how the plan accounts for: (I) Modeled load forecast scenarios that consider the anticipated levels of zero emissions vehicle use in a utility's service area, including anticipated levels of zero emissions vehicle use in the utility's service area provided in RCW 47.01.520, if feasible; (ii) Analysis, research, findings, recommendations, actions, and any other relevant information found in the electrification of transportation plans submitted under RCW 35.92.450, 54.16.430, and 80.28.365; and (iii) Assumed use case forecasts and the associated energy impacts. Electric utilities may, but are not required to, use the forecasts generated by the mapping and forecasting tool created in RCW 47.01.520. This subsection (1)(m)(iii) applies only to plans due to be filed after September 1, 2023. PacifiCorp’s load forecast accounts for zero-emission vehicles using the methods to determine utility impacts described in the Company’s Washington Transportation Electrification Plan. PacifiCorp develops multiple electric vehicle adoption futures for consideration. PacifiCorp updated its zero-emission vehicle forecast in September of 2022 account for impacts from the inflation reduction act and recently adopted ZEV standards. State Rule/Statute Requirement Demonstrate a wider incorporation of non-energy impacts (NEIs) in addition to those applied during conservation potential assessment (CPA) development. WAC 480-100-620(11)(g) PacifiCorp applied measure specific NEI results from a DNV NEI study in 2021 which developed a comprehensive assessment of NEIs. In response to stakeholder comments about NEI valuation, PacifiCorp revisited assumptions and presented results at the April 28, 2022, DSM advisory group meeting. Upon finalization of results, PacifiCorp mapped measure specific NEI’s to measures in the conservation potential assessment. This represents a broader application of NEIs compared to the prior study which used a proxy value adder to represent NEI valuation. Additionally, for demand response, a literature review was conducted to determine if there were any program specific NEIs. Since no quantitative values were found in the literature review, PacifiCorp chose to include a 10% adder to approximate NEI impacts for demand response. In the prior study, no NEI’s were included for demand response. State Rule/Statute Requirement Attribute NEIs considered, indicating whether nonenergy costs and benefits accrue to the utility, customers, participants, vulnerable populations, highly impacted communities, and/or the general public. WAC 480-100-620(13) The file labeled “2023 CPA - Appendix E - WA Non- Energy Impact Mapping”, as part of the CPA supplemental materials posted on the website, maps the accrual of NEIs to various groups consistent with WAC 480-100-620(13). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 58 State Rule/Statute Requirement Summarize (WAC 480-100-620(17)): -Public Comments received during the 2023 IRP development (rather than providing a download of stakeholder feedback forms the company has received to date -PacifiCorp corresponding responses to public comment -Whether and how the final plan addresses and incorporates comments received PacifiCorp has maintained compliance with this requirement by publishing all stakeholder comments received and associated responses in a centralized location externally. The narrative framework for each stakeholder form received is also outlined in greater detail in Appendix C of the 2023 IRP. State Rule/Statute Requirement Distributed energy resource (DER) potential assessments (WAC 480-100-620(3)(b)) Sub-section (iii) (energy assistance potential assessment)--The IRP must include distributed energy programs and mechanisms identified pursuant to RCW 19.405.120, which pertains to energy assistance and progress toward meeting energy assistance need. Sub-section (iv) (other DER potential assessments) – The IRP must assess other DERs that may be installed by the utility or the utility's customers including, but not limited to, energy storage, electric vehicles, and photovoltaics. Any such assessment must include the effect of DERs on the utility’s load and operations. DER potential assessment(s) must go beyond the utility’s legacy approach showing DERs as simply a load forecast decrement The Company assesses various levels of DER through a variety of methods. PacifiCorp evaluates private generation by considering varying levels of technology costs and electricity rate assumptions, which are considered within the Company’s high and low private generation load forecast sensitivities. With regard to the energy assistance potential assessment, PacifiCorp evaluates energy efficiency potential by income level so as to inform how energy efficiency resources can meet energy assistance need. The 2023 IRP also assesses other DERs such as energy storage, which is considered within the Company’s private generation study and the CPA as a demand response resource for acquisition is subsequently incorporated into PacifiCorp’s load forecast and IRP modeling. Further, utility scale battery storage is considered as a resource option within the context of portfolio analysis. The Company incorporates electric vehicle demand within the load forecast along with the control of electric vehicle load as a demand response resource in the IRP model. State Rule/Statute Requirement For the duration of the IRP public interest meetings (PIMs) informing PacifiCorp’s 2023 IRP progress report cycle, circulate completed presentation materials at least three business days prior to each meeting. WAC 480-100-630(2). PacifiCorp consistently provided meeting materials to stakeholders via email within the parameters of this requirement. Order Requirement Provide all data input files to the Commission in native format with appropriate context (e.g., assumptions made by the Company) as appendices or attachments to the final filing or via accompanying data PacifiCorp carefully manages its workpaper filing to adhere to this requirement within the limits of technology. Context is provided by the accompanying listing of file names with a description of the file’s content or purpose. This information is provided on the data disk. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 59 disk(s). Dockets UE-191023 and UE-190698, General Order R-601 at 60-61, ¶ 173 and 178 Order Requirement Include complete data sets informing the Company’s preferred portfolio. Dockets UE-191023 and UE-190698, General Order R-601 at 60-61, ¶ 173 and 178 The 2023 IRP data disc includes complete workpapers for each portfolio including the preferred portfolio. Order Requirement During CPA development, demonstrate progress towards identifying, researching, and properly valuing NEIs. Docket UE-210830, Order 01, Attachment A, condition 11a PacifiCorp discussed NEI research with the DSM advisory group on October 12, 2021, February 28, 2022 and April 28, 2022 and with the equity advisory group on June 16, 2022. These discussions sought feedback on NEI valuation, research and application. The 2023 CPA included measure specific NEIs for energy efficiency and proxies for demand response that were more substantive and comprehensive compared to what was used in the 2021 CPA. Rule Requirement At least every two years after the utility files its IRP, beginning January 1, 2023, the utility must file a two- year progress report. (a) In this report, the utility must update its: (i) Load forecast; (ii) Demand-side resource assessment, including a new conservation potential assessment; (iii) Resource costs; and (iv) The portfolio analysis and preferred portfolio. (b) The progress report must include other updates that are necessary due to changing state or federal requirements, or significant changes to economic or market forces. (c) The progress report must also update for any elements found in the utility's current clean energy implementation plan, as described in WAC 480-100-640. The 2023 IRP incorporates an updated load forecast, updated Demand-side management potential assessment, updated resource cost assumptions and portfolio analysis including the preferred portfolio. Please refer to Appendix O (Washington 2021 IRP Two-year Progress Report Additional Elements), for additional detail regarding updates for elements of the Clean Energy Implementation Plan. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 60 Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP Wyoming The following requirements correspond to the WPSC’s Order issued in the 2019 IRP investigation, the latest available for the 2023 IRP. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include a Reference Case based on the 2017 IRP Updated Preferred Portfolio, incorporating updated assumptions, such as load and market prices and any known changes to system resources and using environmental investments or costs only required by current law. For example, the reference case will not include an estimate or assumed price or cost for carbon emissions absent an existing legal requirement. PacifiCorp has complied with this requirement. Additional information on the specified reference case can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Conduct a more extensive analysis of the impact of alternative price-policy scenarios on the resource plan. The impact of price-policy scenarios on the resource plan is summarized in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Conduct a sensitivity analysis on top performing portfolio cases and the reference case. PacifiCorp has complied with this requirement. Additional information on sensitivity analyses can be found within Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Demonstrate rate impacts over the planning period between preferred portfolio and the reference case. The 2023 IRP includes reference case P02-JB3-4 EOL, which continues Wyoming coal through end-of-life until necessity of gas conversion or other treatment driven by major by environmental requirements. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Investigate alternative methodologies to integrate different reliability analyses including regional analysis of resource adequacy; analysis of power flow issues caused by retiring coal units; study of potential weather-related outages on intermittent generation; and an analysis of wildfire risk. PacifiCorp has introduced a new chapter into this IRP – Volume I, Chapter 5 (Reliability and Resiliency) – which includes regional analyses of resource adequacy, a discussion of power flow issues caused by baseload resource retirements and how PacifiCorp Transmission is planning for those retirements, an assessment of weather-related outages, and a discussion of wildfire risk and mitigation. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include additional analysis on operational experience, if any, with battery acquisition and operations and include a PacifiCorp has included a description of procurement and operational experience with battery acquisition and operations as part of Volume I, Chapter 7 (Resource Options). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 61 review of capabilities learned from other utilities. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include an analysis that demonstrates how the Company will maximize the use of dispatchable and reliable low-carbon electricity pursuant to HB200. PacifiCorp has included Carbon Capture Utilization and Sequestration analysis within the portfolio modeling process. Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results). Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Incorporate an analysis of any agreed upon change to the MSP and to the extent there are outstanding material disagreements regarding cost allocation at the time of filing, quantify those risks and potential impact to Wyoming ratepayers. PacifiCorp has included a discussion of the current status of the MSP within Volume I, Chapter 3 (Planning Environment). As there are no agreed- upon changes or outstanding material disagreements, PacifiCorp did not quantify potential impacts. To the extent that there are changes and/or material disagreements in future IRP cycles, the company will include the required quantified risk. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include a broader analysis of all generation types including nuclear and natural gas. PacifiCorp has expanded the generation types included in the supply-side table as part of the 2023 IRP. Advanced nuclear and natural gas resources have both been included in the supply-side table and analyzed in the 2023 IRP. Additional newly evaluated resources include offshore wind and long-term storage options. Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include a narrative discussing impacts and regulatory framework for renewable generation. PacifiCorp has added this narrative analysis to the Planning Environment discussion in Volume I, Chapter 3 (Planning Environment). Order, Docket No. 90000- 144-XI-19 (Record No. 15280) Include an acknowledgement that each of these requirements are addressed in the 2023 IRP to ensure compliance. PacifiCorp acknowledges these requirements and has addressed each within the 2023 IRP. Reference IRP Requirement or Recommendation How the Guideline is Addressed in the 2023 IRP California D.18-02-018 D.22-02-004 Public Utilities Code §§ 399.13(a)(7), 454.5, 454.52 Addressing Disadvantaged Communities Provide supplemental information about disadvantaged communities, including “a demonstration of how disadvantaged communities were considered.” (D.18-02-018, p. 135.) PacifiCorp serves fewer than 50,000 customers in mostly rural northern California, with a significant number of customers on energy assistance programs. PacifiCorp’s California customers are geographically-dispersed, with approximately four customers per square mile. 3. 3 SB 535 Disadvantaged Communities | OEHHA (ca.gov) PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 62 “PacifiCorp is required to supplement its multi-state IRP with … specific information on … a separate demonstration that satisfies the requirements for disadvantaged communities.” (D.22-02-004, p. 22.) “At a minimum, all LSEs shall provide the following information in their IRPs: i. A description of which disadvantaged communities, if any, it serves (LSEs will be expected to make the determination of what is considered “disadvantaged” every two years); ii. What current and planned LSE activities/programs, if any, impact disadvantaged communities; and iii. A qualitative description of the demographics of the customers it serves and how it is currently addressing or plans to comply with the requirement to minimize air pollutants.” (D.18-02-018, p. 68.) If we wish to provide additional information, we can address how PacifiCorp is: • strengthening “the diversity, sustainability, and resilience of the bulk transmission and distribution systems, and local communities.” (D.18-02-018, p. 66; Pub. Util. Code § 454.52.) • minimizing “localized air pollutants and other greenhouse gas emissions, with early priority on disadvantaged communities.” (D.18-02-018, p. 66; Pub. Util. Code § 454.52.) • giving “preference to renewable energy projects that provide environmental and economic benefits to communities afflicted with poverty or high unemployment, or that suffer from high emission levels of toxic air PacifiCorp is committed to affordability to protect disadvantaged communities. In PacifiCorp’s most current general rate case, which is currently pending at the California Public Utilities Commission, the company has requested recovery of costs associated with the addition of investments in renewable generation resources. Those resources reduce overall emissions and provide zero-fuel cost energy and production tax credits that benefit our customers. PacifiCorp also proposed an increase to its California Alternative Rates for Energy discount from 20 percent to 25 percent, new time varying rate options, and paperless bill credit, among other changes, to support customers during increased costs for wholesale energy and wildfire mitigation. In 2023, PacifiCorp plans to transition its Home Energy Savings residential energy efficiency program from a resource acquisition program to an equity program targeting Hard-to-Reach and Tribal customers. In addition, PacifiCorp filed an advice filing requesting approval to offer Home Energy Reports as an equity program targeting only Hard-to-Reach and Tribal customers. PacifiCorp IRP identifies increased investment in non- emitting resources to service all of its customers. Further, PacifiCorp does not own or operate any thermal generation in California that would negatively impact communities in the California service area. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 63 contaminants, criteria pollutants, and greenhouse gases.” (D.18-02-018, p. 67; Pub. Util. Code § 399.13(a)(7).) In soliciting bids for new gas-fired generating units, PacifiCorp should “actively seek bids for resources that are not gas-fired generating units located in communities that suffer from cumulative pollution burdens, including, but no [sic] limited to, high emission levels of toxic air contaminants, criteria air pollutants, and greenhouse gases.” (D.18-02-018, p. 67; Pub. Util. Code § 454.5(b)(9)(D).) D.19-04-040 D.22-02-004 ALJ Ruling Finalizing Load Forecasts and Greenhouse Gas Emissions Benchmarks for 2022 Integrated Resource Plan Filings GHG Emissions Accounting “PacifiCorp should consult with Commission staff and describe an alternative [to the CNS/CSP Calculator] methodology that addresses its share of the 2030 GHG emissions reduction responsibility.” (D.19-04-040, p. 74.) “PacifiCorp is required to supplement its multi-state IRP with … specific information on … another (non-CSP calculator) method to fulfill requirements that would otherwise have required the CSP tool and justification for the choice.” (D.22-02-004, p. 22.) PacifiCorp’s GHG benchmarks are available here: https://www.cpuc.ca.gov/- /media/cpuc- website/divisions/energy- division/documents/integrated- resource-plan-and-long-term- procurement-plan-irp-ltpp/2022-irp- cycle-events-and-materials/2022- final-ghg-emission-benchmarks-for- lses_public.xlsx PacifiCorp met with CPUC staff in 2020 and discussed its alternative methodology to address GHG benchmarks. PacifiCorp’s IRP supplement will include the results of the emissions forecast in California relative to GHG Benchmark. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 64 Table B.3 – Oregon Public Utility Commission IRP Standard and Guidelines No. Requirement How the Guideline is Addressed in the 2023 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, demand-side management, energy storage, power purchases, thermal resources, and transmission. Volume I, Chapter 4 (Transmission Planning), Chapter 7 (Resource Options), and Chapter 8 (Modeling and Portfolio Evaluation) 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, Plexos, 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 Plexos 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, “no fuel” renewables), lead-times (ranging from front office transactions to nuclear plants), in-service dates, operational lives, and locations. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation), Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix I (Capacity Expansion Results) and Appendix J (Stochastic 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 the Applied Energy Group’s supply curve data developed for this IRP for representation of DSM resources. The study 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 6 (Load and Resource Balance), Chapter 7 (Resource Options), and Chapter 8 (Modeling and Portfolio Evaluation) as well as Volume II, Appendix D (Demand-Side Management). 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 nominal after-tax WACC of 6.77 percent to discount all cost streams. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 65 No. Requirement How the Guideline is Addressed in the 2023 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. Each of the sources of risk identified in this guideline is treated as a stochastic variable in PacifiCorp’s production cost simulation apart from CO2 emission compliance costs, which are treated as a scenario risk and evaluated as part of a CO2 price assumption and a no CO2, a high CO2, and a social cost of carbon price-policy scenario for specific studies. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Volume I, Chapter 9 (Modeling and Portfolio Selection Results). 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 10 (Action Plan). Regulatory and financial risks associated with resource and transmission investments are highlighted in several areas in the IRP document, including Volume I, Chapter 3 (Planning Environment), Chapter 4 (Transmission), Chapter 8 (Modeling and Portfolio Evaluation), and Chapter 9 (Modeling and Portfolio Selection Results). 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 9 (Modeling and Portfolio Selection Results), Chapter 10 (Action Plan), and Volume II, Appendix I (Capacity Expansion Results) and Appendix H (Stochastic Parameters) 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 (2023-2042) 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 8 (Modeling and Portfolio Evaluation) provides a description of the PVRR methodology. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 66 No. Requirement How the Guideline is Addressed in the 2021 IRP 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. For the severity of bad outcomes, the company calculates several measures, including stochastic upper-tail mean PVRR and the 95th percentile stochastic production cost PVRR. 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 10 (Action Plan). 1.c.4 The utility should explain in its plan how its resource choices appropriately balance cost and risk. Volume I, Chapter 9 (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) 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 (Planning Environment). Volume I, Chapter 9 (Modeling and Portfolio Selection Results) provides the results. Volume I, Chapter 10 (Action Plan) presents an acquisition path analysis that describes resource strategies based on regulatory 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 Oregon PUC for resolution. PacifiCorp fully complies with this requirement. Volume II, Appendix C (Public Input) provides an overview of the public input process, all public-input meetings held for the 2023 IRP, and summarizes public input received throughout the 2023 IRP cycle. PacifiCorp also made use of a Stakeholder Feedback Form for stakeholders to provide comments and offer suggestions. Stakeholder Feedback Forms along with responses and the public- input meeting presentations are available on PacifiCorp’s webpage at: w ww.pacificorp.com/energy/integrated-resource- p lan.html PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 67 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 Oregon PUC. 2023 IRP Volumes I and II provide non-confidential information 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 and in response to Stakeholder Feedback Forms. Data discs will be available with public data. Additionally, data discs with confidential data will be provided to appropriate parties through use of a general protective order. 2.c The utility must provide a draft IRP for public review and comment prior to filing a final plan with the Oregon PUC. 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 2023 IRP. The materials shared with stakeholders at these meetings, outlined in Volume II, Appendix C (Public Input), is consistent with materials presented in Volumes I and II of the 2023 IRP report. PacifiCorp requested and responded to comments from stakeholders when establishing modeling assumptions and throughout its portfolio-development process and sensitivity definitions. 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 Oregon PUC. The 2023 IRP complies with this requirement. 3.b The utility must present the results of its filed plan to the Oregon PUC at a public meeting prior to the deadline for written public comment. This activity will be conducted following the filing of 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 following the filing of 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 following the filing of this IRP. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 68 No. Requirement How the Guideline is Addressed in the 2023 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 Oregon PUC, unless the utility is within six months of filing its next IRP. The utility must summarize the update at an Oregon PUC public meeting. The utility may request acknowledgment of changes in proposed actions identified in an update. Not applicable to this filing; this activity will be conducted following the filing of this IRP. 3.g Unless the utility requests acknowledgment of 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. Not applicable to this filing; this activity will be conducted following the filing of this IRP. Guideline 4. Plan Components: At a minimum, the plan must include the following elements No. Requirement How the Guideline is Addressed in the 2023 IRP 4.a An explanation of how the utility met each of the substantive and procedural requirements. The intent 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 Plexos model. Stochastic variability of loads was also captured in the risk analysis. See Volume I, Chapters 6 (Load and Resource Balance) and Chapter 8 (Modeling and Portfolio Evaluation), and Volume II, PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 69 Appendix A (Load Forecast Detail) for load forecast information. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 70 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 Chapter 6 (Load and Resource Balance) 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 Chapter 8 (Modeling and Portfolio Evaluation). 4.d For gas utilities only. Not applicable. 4.e Identification and estimated costs of all supply-side and demand side resource options, considering anticipated advances in technology. Volume I, Chapter 7 (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 Resources) referencing additional information on PacifiCorp’s IRP website. 4.f Analysis of measures the utility intends to take to provide reliable service, including cost-risk tradeoffs. In addition to incorporating a planning reserve margin for all portfolios evaluated, as supported by an updated Stochastic Loss of Load Study in Volume II, Appendix J (Stochastic Simulation Results), the company used several measures to evaluate relative portfolio supply reliability. These measures (Energy Not Served and Loss of Load Probability) are described in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). 4.g Identification of key assumptions about the future (e.g., fuel prices and environmental compliance costs) and alternative scenarios considered. Volume I, Chapter 8 (Modeling and Portfolio Evaluation) describes the key assumptions and alternative scenarios used in this IRP. Volume II, Appendix I (Capacity Expansion Results) includes summaries of assumptions used for each case definition analyzed in the 2023 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 IRP documents the development and results of portfolios designed to determine resource selection under a variety of input assumptions in Volume I, Chapters 8 (Modeling and Portfolio Evaluation) and Chapter 9 (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 9 (Modeling and Portfolio Selection Results) incorporates the stochastic portfolio modeling results as described in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), 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 9 (Modeling and Portfolio Selection Results) provides tables and charts with performance measure results, including rank ordering. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 71 No. Requirement How the Guideline is Addressed in the 2023 IRP 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. 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 10 (Action Plan) presents the 2023 IRP action plan. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 72 No. Requirement How the Guideline is Addressed in the 2023 IRP 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. PacifiCorp evaluated four 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. Fuel transportation costs were factored into resource costs. In addition to endogenous resource and transmission selects, the 2023 IRP modeled seven variants’ cases to evaluate Energy Gateway and its components, B2H, and Cluster 1 and 2 transmission. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation), and specifically Table 8.11 – Preferred Portfolio Variants. Guideline 6: Conservation 6.a Each utility should ensure that a conservation potential study is conducted periodically for its entire service territory. PacifiCorp’s conservation potential study is available on the company’s webpage, and the most recent results from the conservation potential assessment have been incorporated into the IRP modeling process. 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 7 (Resource Options), the results in Volume I, Chapter 9 (Modeling and Portfolio Selection Results), the targeted amounts in Volume I, Chapter 10 (Action Plan) and the implementation steps outlined in Volume II, Appendix D (DSM Resources 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 PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 73 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 (DSM) on a consistent basis with other resources. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 74 Guideline 8: Environmental Costs No. Requirement How the Guideline is Addressed in the 2023 IRP 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 an allowance for 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 compliance scenario should maintain logical consistency, to the extent practicable, between the CO2 regulatory requirements and other key inputs. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation). In the 2023 IRP, PacifiCorp’s base assumption includes a proxy price on CO2 starting in 2025 within the medium gas/medium (“MM”) CO2 price-policy scenario for evaluation of all portfolios. In addition PacifiCorp modeled a high gas/high CO2 (“HH”) and a Social Cost of Greenhouse Gas price-policy scenario (“SC”) for the preferred portfolio and relevant variants. 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 J (Stochastic Simulation Results) provides the stochastic mean PVRR versus upper tail mean less stochastic mean PVRR scatter plot diagrams that for a broad range of 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 8 (Modeling and Portfolio Evaluation) and uses a 20-year planning horizon. Early retirement and gas conversion alternatives to coal unit environmental investments were considered in the development of all resource portfolios. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 75 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 Evaluation) for a description of initial portfolio development definitions. Comparative analysis of these case results is included in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). 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 in the preferred and alternative portfolios. Several portfolios yield system emissions aligned with state goals for reducing greenhouse gas emissions. These cases are summarized in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). PacifiCorp’s Clean Energy Plan will filed by June 1, 2023, incremental to the statewide 2023 IRP preferred portfolio outcomes. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 76 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 alternative electricity supplier. Oregon Docket UE 267 established a long-term opt out option for eligible PacifiCorp customers. Going forward PacifiCorp will cease planning for customers who elect direct-access service on a long-term basis (i.e. five-year opt out customers). 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 2023 IRP conforms to the multi-state planning approach as stated in Volume I, Chapter 2 (Introduction) under the section “The Role of PacifiCorp’s Integrated Resource Planning”. The company notes the challenges in complying with multi-state integrated planning given differing state energy policies and resource preferences. 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 9 (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 different CO2 cost levels were used to inform the cost/risk tradeoff analysis. 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 DNV to provide estimates of expected private generation penetration. The study was incorporated in the analysis as a deduction to load. Sensitivities looked at both high and low penetration rates for private generation. The study is included in Volume II, Appendix L (Private Generation Study). Guideline 13: Resource Acquisition PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 77 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 10 (Action Plan) 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 Chapter 10 (Action Plan). PacifiCorp has not at this time identified any specific benchmark resources it plans to consider in the competitive bidding process summarized in the 2023 IRP action plan. 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. PacifiCorp as met this requirement in Volume II, Appendix F (Flexible Reserve Study). 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. PacifiCorp as met this requirement in Volume II, Appendix F (Flexible Reserve Study). 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. PacifiCorp as met this requirement in Volume II, Appendix F (Flexible Reserve Study). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 78 Table B.4– Utah Public Service Commission IRP Standard and Guidelines No. Requirement How the Guideline is Addressed in the 2023 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 2023 IRP 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 description of public- input meetings is provided in Volume II, Appendix C (Public Input). Public-input meeting materials can also be found on PacifiCorp’s website at: www.pacificorp.com/energy/integrated- resource- plan/public-input-process.html 5 Consideration of environmental externalities and attendant costs must be included in the integrated resource planning analysis. PacifiCorp used a scenario analysis approach along with externality cost adders to model environmental externality costs. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation) for a description of the methodology employed, including how CO2 cost uncertainty is factored into the determination of relative portfolio performance through a base case planning assumption and other price-policy scenarios. 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 Plexos optimization models. 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 Utah rules, PacifiCorp determination of avoided costs in Utah will be handled in a manner consistent with the IRP, with the caveat that the costs may be updated if better information becomes available. 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 10 (Action Plan) describes the linkage between the 2023 IRP preferred portfolio and December 2022 business plan resources. Significant resource differences are highlighted. The business plan portfolio was run consistent with PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 79 requirements outlined in the Order issued by the Utah Public Service Commission on September 16, 2016, Docket No. 15-035-04. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 80 No. Requirement How the Guideline is Addressed in the 2023 IRP Standards and Guidelines 1 Definition: Integrated resource planning is a utility planning process which evaluates all known resources on a consistent and comparable basis, 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 8 (Modeling and Portfolio Evaluation) outlines the portfolio performance evaluation and preferred portfolio selection process, while Chapter 9 (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 September 1, 2021, and filed this IRP on March 31, 2023, as an informational filing, meeting the requirement. PacifiCorp requested and was granted a 60 day extension of time to file the final 2023 IRP on May 31, 2023 in Docket No. 23-035-10. 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 and a summary of feedback and public comments is provided in Volume II, Appendix C (Public Input). 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 2021 IRP are provided in Volume I, Chapter 7 (Resource Options) and Volume II, Appendix A (Load Forecast). 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 associated with different acquisition strategies. Load forecasts are differentiated by jurisdiction and differentiate energy and capacity requirements. See Volume I, Chapter 6 (Load and Resource Balance) and Volume II, Appendix A (Load Forecast). 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. 4.a.ii Analyses of how various economic and demographic factors, including the prices of electricity and alternative energy sources, will Volume II, Appendix A (Load Forecast) documents how demographic and price factors are used in PacifiCorp’s load forecasting methodology. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 81 affect the consumption of electric energy services, and how changes in the number, type and efficiency of end-uses will affect future loads. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 82 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 Plexos optimization models for both supply side and demand side alternatives. See explanation in Volume I, Chapter 7 (Modeling and Portfolio Evaluation) and the results in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). Resource options are summarized in Volume I, Chapter 7 (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 Demand Response (dispatchable/schedulable load control) and Energy Efficiency in its capacity expansion model. Details are provided in Volume I, Chapter 7 (Resource Options). 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, cogeneration (combined heat and power), power purchases, thermal resources, energy storage, and Energy Gateway transmission configurations. Newly evaluated resources in this IRP include offshore wind and long-term storage options. Volume I, Chapters 7 (Resource Options) and 8 (Modeling and Portfolio Evaluation) 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 resource 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 private generation study, modeled as a reduction to load, also considered rates of participation. Replacement capacity is considered in the case of early coal unit retirements as evaluated in this IRP as an alternative to coal unit environmental investments. 4.c An analysis of the role of competitive bidding for demand-side and supply-side resource acquisitions A description of the role of competitive bidding and other procurement methods is provided in Volume I, Chapter 10 (Action Plan). 4.d A 20-year planning horizon. This IRP uses a 20-year study horizon (2023-2042). 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 The IRP action plan is provided in Volume I, Chapter 10 (Action Plan). A status report of the actions outlined in the previous action plan (2019 IRP Update) is provided in Volume I, Chapter 10 (Action Plan). In Volume I, Chapter 10 (Action Plan) Table 10.1 identifies actions anticipated in the next two-to- PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 83 No. Requirement How the Guideline is Addressed in the 2023 IRP years. The action plan will include a status report of the specific actions contained in the previous action plan. 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 10 (Action Plan) includes an acquisition path analysis that presents broad resource strategies based on regulatory trigger events, change in load growth, extension of federal renewable resource tax incentives and procurement delays. 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 7 (Resource Options). The IRP document addresses the impact of social concerns on resource cost-effectiveness in the following ways: ● Relevant portfolios were evaluated using a range of CO2 price-policy scenarios. ● A discussion of environmental policy status and impacts on utility resource planning is provided in Volume I, Chapter 3 (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 9 (Modeling and Portfolio Selection Results). In addition, distinct state filings also address clean energy. ● Volume II, Appendix G (Plant Water Consumption) reports historical water consumption for PacifiCorp’s thermal plants. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 84 No. Requirement How the Guideline is Addressed in the 2023 IRP 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 10 (Action Plan), and covers managing environmental risk for existing plants, risk management and hedging and treatment of customer and investment risk. Transmission expansion risks are discussed in Volume I, Chapter 4 (Transmission). Resource capital cost uncertainty and technological risk is addressed in Volume I, Chapter 7 (Resource Options). For reliability risks, the stochastic simulation model incorporates stochastic volatility of forced outages for new thermal plants and hydro availability. These risks are factored into the comparative evaluation of portfolios and the selection of the preferred portfolio upon which the action plan is based. Identification of the classes of risk and how these risks are allocated to ratepayers and investors is discussed in Volume I, Chapter 10 (Action Plan). 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 10 (Action Plan). 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 9 (Modeling and Portfolio Selection Results). 4.k A range, rather than attempts at precise quantification, of estimated external costs which may be intangible, 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 number 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 8 (Modeling and Portfolio Evaluation). 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 (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 7 (Resource Options). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 85 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 at various times when developing the 2023 IRP. The materials shared with stakeholders at these meetings, outlined in Volume I, Chapter 2 (Introduction), is consistent with materials presented in Volumes I and II of the 2023 IRP report. Public- input meetings materials can be located on PacifiCorp’s website at: www.pacificorp.com/energy/integrated-resource- plan/public-input-process.html PacifiCorp requested and responded to comments from stakeholders in throughout its 2023 IRP process. The company also considered comments received via Stakeholder Feedback Forms that can be located on PacifiCorp’s website at: www.pacificorp.com/energy/integrated-resource- plan/comments.html A total of 133 Stakeholder Feedback Forms were received and responded to during the 2023 IRP public-input process. 6 The public, state agencies and other interested parties will have the opportunity to make formal 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. Not addressed; this is a post-filing activity. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 86 No. Requirement How the Guideline is Addressed in the 2023 IRP 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. Washington IRP Requirements and the Washington IRP Two-Year Progress Report Requirements for the Two-Year Progress Report are significantly reduced compared to the four-year filing of the full IRP. Requirements are focused primarily on fundamental data input updates necessary to update some interim and specific targets and report progress on other elements of the Clean Energy Implementation Plan. Nonetheless, PacifiCorp has attempted to adhere to all IRP filing requirements where possible in addition to the requirements of the Two-Year Progress Report, as detailed below. Table B.5 – Washington Utilities and Transportation Commission IRP Standard and Guidelines to Implement CETA Rules (RCW 19.280.030 and WAC 480-100-620 through WAC 480-100-630) per Commission General Order R-601. No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-625(1) and (4) Integrated resource plan updated every four years, with a progress report at least every two years. The PacifiCorp IRP is published every two years with updates in the off cycles. This exceeds Washington State requirements. New to this IRP cycle is the requirement to file an IRP Two-Year Progress Report. This document constitutes the Progress Report. WAC 480- 100-620(1) Unless otherwise stated, all assessments, evaluations, and forecasts comprising the plan should extend over the long-range (e.g., at least ten years; longer if appropriate to the life of the resources considered) planning horizon. PacifiCorp's 2023 (and prior) IRPs span a 20-year long- term planning horizon. Additional analysis may extend beyond the 20-year horizon but not in the form of optimization modeling runs, as sufficient data is unavailable, resources insufficient and run times, which advance geometrically and not linearly with added years, are impractical. Rather than extrapolate all data inputs to cover longer periods, PacifiCorp extrapolates the optimized results. WAC 480- 100-620(2) Plan includes range of forecasts of projected customer demand that reflect effect of economic forces on electricity consumption. Variant load forecast cases will include High/low load, 1-in-20 load, High/low private generation, New Load and No Climate change load scenarios. Other load variants will be considered based on stakeholder feedback and model outcomes. WAC 480- 100-620(2) Plan includes range of forecasts of projected customer demand that address changes in the number, type, and efficiency of electrical end-uses. PacifiCorp has provided detail on load forecasts in Volume II, Appendix A (Load Forecast). Information can also be found in Volume I, Chapter 6 (Load and Resource Balance). WAC 480- 100-620(3)(a) Plan includes load management assessments that are cost-effective and commercially available, including current and new policies and programs to obtain: The IRP is informed by the company’s current conservation potential assessment, which is available on PacifiCorp’s website. Additional information on the load management assessments can be found in Volume II, Appendix D (Demand-Side Management PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 87 Programs). WAC 480- 100-620(3)(a) - all cost-effective conservation, efficiency, and load management improvements; IRP modeling optimally selects all cost-effective energy efficiency and demand response in each case portfolio as a part of core model functionality. Results are reported for all portfolios in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 109-100(2) - ten-year conservation potential used in the concurrent biennial conservation plan consistent with RCW 19.285.040(1); The IRP is informed by the current conservation potential assessment, which is available on PacifiCorp’s website. Volume I, Chapter 6 (Load and Resource Balance) provides additional detail. - identification of opportunities to develop combined heat and power as an energy and capacity resource; and Combined heat and power are addressed as a component of the Private Generation Study, which is included in Volume II, Appendix L (Private Generation Study). No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-620(3)(b) - all demand response (DR) at the lowest reasonable cost (LRC). IRP modeling optimally selects all cost-effective energy efficiency and demand response in each case portfolio as a part of core model functionality. Results are reported for all portfolios in Volume II, Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 100-620(3)(b) Plan includes assessments of distributed energy programs and mechanisms pertaining to energy assistance and progress toward meeting energy assistance need, including but not limited to the following: - Energy efficiency and CPA, - Demand response potential, - Energy assistance potential IRP modeling considers and selects energy efficiency and demand response potential, and distributed energy programs. Evaluation is detailed in Volume I, Chapter 8 (Modeling and Portfolio), and Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 100-620(3)(b) Plan assesses a forecast of distributed energy resources (DER) that may be installed by the utility's customers via a planning process pursuant to RCW 19.280.100(2). PacifiCorp has worked with DNV Consulting to prepare a Private Generation Study, which assesses distributed and customer-sited resources. Customer preference resources are also assessed as part of the portfolio selection process. Additional detail can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(3)(b) Plan includes effect of DERs on the utility's load and operations. The impacts of DERs on PacifiCorp's utility load and operations are assessed as part of Volume I, Chapter 8 (Modeling and Portfolio Evaluation). Inputs are assessed as part of Volume II, Appendix L (Private Generation Study). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 88 WAC 480- 100-620(3)(b) If utility engages in a DER planning process, which is strongly encouraged, IRP should include a summary of the process planning results. PacifiCorp understands this requirement and will include a summary in future integrated resource plans, if applicable. Also, summaries of our DER planning processes can be found in the conservation potential assessment and private generation studies posted on our website. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 89 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-620(4) Plan assesses wide range of conventional generating resources. PacifiCorp considered a wide range of resources including renewables, demand-side management, energy storage, distributed energy resources, power purchases, thermal resources, and transmission. Volume I, Chapter 7 (Resource Options) provides relevant detail on conventional generating resources. WAC 480- 100-620(5) In making new investments, plan considers acquisition of existing and new renewable resources at LRC. Cost and performance data for all resource types is evaluated and entered as a model input for the optimal selection of resources. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). See WA-UTC energy storage policy statement (UE-151069 & UE-161024 consolidated) Plan assesses energy storage resources. Energy storage resources are considered as part of the supply-side resource table, found in Volume I, Chapter 7 (Resource Options). Energy storage potential is assessed as part of Volume II, Appendix N (Energy Storage Potential Evaluation). WAC 480- 100-620(5) Plan assesses nonconventional generating, integration, and ancillary service technologies. Compressed air storage and advanced nuclear resources are represented in the Supply Resource Table, which is posted on PacifiCorp’s IRP website and included as Volume I, Chapter 7 (Resource Options). All resource types are appropriately subject to integration and ancillary services determination, including transmission upgrade costs, reserve holding capability and additional reserve requirements that are particular to technologies. These factors are inherent to every portfolio optimization run. WAC 480- 100-620(6) Plan assesses the availability of regional generation and transmission capacity for purposes of delivery of electricity to customers. Regional generation is incorporated into market availability and price forecasts, which are described and analyzed in Volume I, Chapter 3 (Planning Environment), Chapter 5 (Reliability and Resiliency). Transmission and resource options are described in Volume I, Chapter 4 (transmission) and Chapter 7 (Resource Options). WAC 480- 100-620(6) Plan assesses utility's regional transmission future needs and the extent Regional transmission is represented through markets and region-based price forecasting, while PacifiCorp's transmission system is represented by firm PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 90 No. Requirement How the Guideline is Addressed in the 2023 IRP transfer capability limitations may affect the future siting of resources. transmission rights and endogenous transmission upgrade options. These factors are discussed in the Volume I, Chapter 7 (Resource Options) and Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(7) Plan compares benefits and risks of purchasing power or building new resources. As a component of core modeling functionality, all competing resources are evaluated to determine each optimal portfolio. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 100-620(7) Plan compares all identified resources according to resource costs, including: The comparison of resources on a cost-risk basis is core functionality of PacifiCorp's optimization modeling. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(7) - transmission and distribution delivery costs; PacifiCorp's transmission system is represented by firm transmission rights and endogenous transmission upgrade options. Transmission dependencies implying additional resource costs are included in the optimization, resulting in a reasonable comparison of resource costs. Additional information can be found in Volume I, Chapter 7 (Resource Options), Chapter 8 (Modeling and Portfolio Evaluation), and Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 100-620(7) - risks, including environmental effects and the social cost of GHG emissions; The Company has conducted six SC-GHG cases, three of which were evaluated under a range of additional price-policy conditions. The cases evaluated are described in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(7) - benefits accruing to the utility, customers, and program participants (when applicable); and Benefits are characterized by present value revenue requirement differentials, emissions, reserve and load deficiencies, robustness across stochastic variances and additional factors as may emerge from modeling results. In addition to modeling outcomes presented in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), incremental costs relative to the Washington Clean Energy Implementation Plan are discussed in Volume II, Appendix O (Washington Two-Year Progress Report Additional Elements). WAC 480- 100-620(7) - resource preference public policies adopted by WA State or the federal government. The preferred portfolio selected in the 2023 IRP process is compliant with all policy requirements. A summary of the policy environment is included as Volume I, Chapter 3 (Planning Environment), and a description of the portfolio runs in compliance with policy is included as Volume I, Chapter 8 (Modeling and Portfolio Evaluation). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 91 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-620(7) Plan includes methods, commercially available technologies, or facilities for integrating renewable resources, including but not limited to battery storage and pumped storage, and addressing overgeneration events. IRP modeling endogenously considers "overgeneration" in dispatch and curtails resources appropriately. These curtailments are an inherent component of the cost and risk valuation of each portfolio, and is a driver for the optimal size, type and location of selected resources. WAC 480- 100-620(8) Plan assesses and determines resource adequacy metrics. For the 2023 IRP, resource adequacy is evaluated as a core model function, where each portfolio is obligated to meet reliability requirements including varying degrees of quality of operating reserves. This is described in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(8) Plan identifies an appropriate resource adequacy requirement. PacifiCorp has addressed this requirement as described in Volume I, Chapter 6 (Load and Resource Balance). WAC 480- 100-620(8) Plan measures corresponding resource adequacy metric consistent with prudent utility practice in eliminating coal-fired generation by 12/31/2025 (RCW 19.405.030), attaining GHG neutrality by 1/1/2030 (RCW 19.405.040), and achieving 100 percent clean electricity WA retail sales by 1/1/2045 (RCW 19.405.050). PacifiCorp has addressed this requirement as pertains to requirements for the Clean Energy Transformation Act and the Two-Year Progress Report as described in Volume I, Chapter 6 (Load and Resource Balance), Chapter 8 (Modeling and Portfolio Evaluation), and Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100-620(9) Plan reflects the cumulative impact analysis conducted under RCW 19.405.140, and includes an assessment of: Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. WAC 480- 100-620(9) - energy and nonenergy benefits; Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. WAC 480- 100-620(9) - reduction of burdens to vulnerable populations and highly impacted communities; Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. WAC 480- 100-620(9) - long-term and short-term public health and environmental benefits, costs, and Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 92 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-620(9) - long-term and short-term public health and environmental risks; and Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. WAC 480- 100-620(9) - energy security and risk. Please see Appendix O for details regarding the Company's plan for reporting on metrics related to CBIs. WAC 480- 100-620(10) Utility should include a range of possible future scenarios and input sensitivities for testing the robustness of the utility's resource portfolio under various parameters, including the following required components: A wide range of cases and sensitivities under various price-policy futures have been included, as discussed in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(10) CETA counter factual scenario - describe the alternative LRC and reasonably available portfolio that the utility would have implemented if not for the requirement to comply with RCW 19.405.040 and RCW 19.405.050, as described in WAC 480-100-660(1). PacifiCorp has met this requirement – additional detail can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(10) Climate change scenario - incorporate the best science available to analyze impacts including, but not limited to, changes in snowpack, streamflow, rainfall, heating and cooling degree days, and load changes resulting from climate change. PacifiCorp has met this requirement – additional detail can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(10) Maximum customer benefit sensitivity - model the maximum amount of customer benefits described in RCW 19.405.040(8) prior to balancing against other goals. PacifiCorp has met this requirement – additional detail can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(11) Plan must integrate demand forecasts and resource evaluations into a long-range IRP solution. PacifiCorp has met this requirement – additional detail can be found in Volume I, Chapter 6 (Load and Resource Balance). WAC 480- 100-620(11) IRP solution or preferred portfolio must describe the resource mix that meets current and projected needs. PacifiCorp has met this requirement – additional detail can be found in Volume I, Chapter 9 (Modeling and Portfolio Selection). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 93 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100- 620(11)(a) Preferred portfolio must include narrative explanation of the decisions made, including how the utility's long-range IRP solution: See individual entries below. WAC 480- 100- 620(11)(a) - achieves requirements for eliminating coal-fired generation by 12/31/2025 (RCW 19.405.030); PacifiCorp will remove coal-fired generation from Washington’s allocation of electricity by 2025 and will continue to analyze this pending further resolution of interpretive issues by the Commission. Additional information can be found in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). WAC 480- 100- 620(11)(a) - attains GHG neutrality by 1/1/2030 (RCW 19.405.040); and PacifiCorp has met this requirement. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results), and Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(a) - achieves 100 percent clean electricity WA retail sales by 1/1/2045 (RCW 19.405.050) at LRC, This is outside of the Two-Year Progress Report timeline, but is addressed as part of Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(a) - achieves 100 percent clean electricity WA retail sales by 1/1/2045 (RCW 19.405.050), considering risk. This is outside of the Two-Year Progress Report timeline, but the pathway to 2045 is addressed in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(c) Consistent with RCW 19.285.040(1), preferred portfolio shows pursuit of all cost-effective, reliable, and feasible conservation and efficiency resources, and DR. PacifiCorp has met this requirement. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(d) and I Preferred portfolio considers acquisition of existing renewable new resources and relies on renewable resources and energy storage, insofar as doing so is at LRC, PacifiCorp has met this requirement. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(d) and (e) Preferred portfolio considers acquisition of existing renewable new resources and relies on renewable resources and energy storage, considering risks. PacifiCorp has met this requirement. Additional information can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), Chapter 9 (Modeling and Portfolio Selection Results), and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100-620(11)(f) Preferred portfolio maintains and protects the safety, reliable operation, and balancing of the utility's electric system, including mitigating over- generation events and achieving identified resource adequacy requirements. PacifiCorp has met this requirement. Additional information can be found in Volume I, Chapter 6 (Load and Resource Balance). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 94 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100- 620(11)(g) Preferred portfolio ensures all customers are benefiting from the transition to clean energy through the: WAC 480- 100- 620(11)(g) - equitable distribution of energy and nonenergy benefits; reduction of burdens to vulnerable populations and highly impacted communities; Please see Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(g) - long-term and short-term public health and environmental benefits; reduction of costs and risks; and Please see Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(g) - energy security and resiliency. Please see Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100- 620(11)(h) Preferred portfolio: assesses the environmental health impacts to highly impacted communities, Please see Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100-620(11)(i) - analyzes and considers combinations of DER costs, benefits, and operational characteristics (incl. ancillary services) to meet system needs, Detail is included in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(11)(j) - incorporates the social cost of GHG emissions as a cost adder. Detail is included in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100-620(12) Utility must develop a ten-year clean energy action plan (CEAP) for implementing RCW 19.405.030 through 19.405.050 at LRC, and at an acceptable resource adequacy standard. The CEAP will: The Company’s CEAP was provided in the 2021 Integrated Resource Plan published September 1, 2021. WAC 480- 100- 620(12)(b) - identify and be informed by utility's ten- year CPA per RCW 19.285.040(1); The Clean Energy Action Plan is not a component of the IRP Two-Year Progress Report. WAC 480- 100- 620(12)(c) - demonstrate that all customers are benefiting from the transition to clean energy; The Clean Energy Action Plan is not a component of the IRP Two-Year Progress Report. WAC 480- 100- 620(12)(d) - establish a resource adequacy requirement; PacifiCorp establishes resource adequacy at a system level, and the resource adequacy requirement is explained in Volume I, Chapter 6 (Load and Resource Balance). WAC 480- 100- 620(12)(e) - identify the potential cost-effective DR and load management programs that may be acquired; This requirement is met in Volume I, Chapter 9 (Modeling and Portfolio Selection Results) and Volume II, Appendix O (Washington IRP Two-Year Progress Report Additional Elements). PACIFICORP – 2023 IRP APPENDIX B – IRP REGULATORY COMPLIANCE 95 WAC 480- 100-620(12)(f) - identify renewable resources, non emitting electric generation, and DERs that may be acquired and evaluate how each identified resource may be expected to contribute to meeting the utility's resource adequacy requirement; This is described at the system-level as part of PacifiCorp’s resource planning process. Volume I, Chapter 7 (Resource Options), Chapter 8 (Modeling and Portfolio Evaluation), and Chapter 9 (Modeling and Portfolio Selection) provide additional detail. PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 91 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100- 620(12)(g) - identify any need to develop new, or expand or upgrade existing, bulk transmission and distribution facilities; and This is described at the system level in Volume I, Chapter 4 (Transmission) and also within PacifiCorp’s Volume I, Chapter 10 (Action Plan). WAC 480- 100- 620(12)(h) - identify the nature and possible extent to which the utility may need to rely on alternative compliance options, if appropriate. Please see Volume II Appendix O (Washington IRP Two-Year Progress Report Additional Elements). WAC 480- 100-620(12)(i) Plan (both IRP and CEAP) considers cost of greenhouse gas emissions as a cost adder equal to the cost per metric ton of carbon dioxide emissions, using the two and one- half percent discount rate, listed in Table 2, Technical Support Document: Technical update of the social cost of carbon (SCC) for regulatory impact analysis under Executive Order 12866, published by the interagency working group on social cost of greenhouse gases of the United States government, August 2016, as adjusted by the Commission to reflect the effect of inflation. PacifiCorp updated its social cost of greenhouse gas pricing consistent with DOCKET U-190730 ORDER 03, which updates this specification. WAC 480- 100-620(13) Plan must include an analysis and summary of the estimated avoided cost for each supply- and demand-side resource, including (but not limited to): A new assessment of avoided cost is not a requirement of the Two-Year Progress Report; however, future determinations of avoided cost will follow the guidelines below. WAC 480- 100-620(13) - energy, The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(13) - capacity, The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(13) - transmission, The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(13) - distribution, and The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(13) - GHG emissions. The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 92 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 100-620(13) Listed energy and non-energy impacts should specify to which source party they accrue (e.g., utility, customers, participants, vulnerable populations, highly impacted communities, general public). The file labeled “2023 CPA - Appendix E - WA Non-Energy Impact Mapping”, as part of the CPA supplemental materials posted on the website, maps the accrual of NEIs to various groups consistent with WAC 480-100-620(13). PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 93 No. Requirement How the Guideline is Addressed in the 2023 IRP WAC 480- 106-040 Plan provides information and analysis used to inform annual purchases of electricity from qualifying facilities, including a description of the: A new assessment of avoided cost is not a requirement of the Two-Year Progress Report; however, future determinations of avoided cost will follow the guidelines below. WAC 480- 106-040 - avoided cost calculation methodology used; The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 106-040 - avoided cost methodology of energy, capacity, transmission, distribution, and emissions averaged across the utility; and The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 106-040 - resource assumptions and market forecasts used in the utility's schedule of estimated avoided cost, including (but not limited to): cost assumptions, production estimates, peak capacity contribution estimates, and annual capacity factor estimates. The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(14) To maximize transparency, the utility should submit data input files supporting the plan in native file format (e.g., supporting spreadsheets in Excel, not PDF file format). PacifiCorp will make data available in the native file format consistent with practice in prior IRPs. WAC 480-100- 620(15) Information relating to purchases of electricity from qualifying facilities. Each utility must provide information and analysis that it will use to inform its annual filings required under chapter 480- 106 WAC. The detailed analysis must include, but is not limited to, the following components: WAC 480-100- 620(15)(a) A description of the methodology used to calculate estimates of the avoided cost of energy, capacity, transmission, distribution and emissions averaged across the utility; and The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480-100- 620(15)(b) (b) Resource assumptions and market forecasts used in the utility's schedule of estimated avoided cost required in WAC 480-106-040 including, but not limited to, cost assumptions, production estimates, peak capacity contribution estimates and annual capacity factor estimates. The estimated avoided cost will be based on the values determined through the IRP modeling process. Values can be found in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection). WAC 480- 100-620(16) Plan must summarize substantive changes to modeling methodologies or inputs that change the utility's resource need, as compared to the utility's previous IRP. An assessment of modeling methodology is included in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). WAC 480- 100-620(17) Utility must summarize: WAC 480- 100-620(17) - public comments received on the draft IRP, This is included in Volume II, Appendix C (Public Input). PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 94 Table B.6 – Wyoming Public Service Commission Guidelines No. Requirement How the Guideline is Addressed in the 2023 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). B The utility’s strategic goals and resource planning goals and preferred resource portfolio; Volume I, Chapter 9 (Modeling and Portfolio Selection Results) documents the preferred resource portfolio and rationale for selection. Volume I, Chapter 10 (Action Plan) 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-term planning horizons; See Volume I, Chapter 6 (Load and Resource Balance). D A study detailing the types of resources considered; Volume, I Chapter 7 (Resource Options), presents the resource options used for resource portfolio modeling for this IRP. E 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 2021 IRP is presented in Volume I, Chapter 10 (Action Plan). A chart comparing the peak load forecasts for the 2019 IRP, and 2021 IRP is included in Volume II, Appendix A (Load Forecast Details). F The environmental impacts considered; Portfolio comparisons for CO2 and a broad range of environmental impacts are considered, including prospective early retirement and gas conversions of existing coal units as alternatives to environmental investments. See Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio Selection) as well as Volume II, Appendix J (Stochastic Simulation Results). G Market purchases evaluation; Modeling of firm market purchases (front office transactions) and spot market balancing transactions is included in the 2021 IRP. H Reserve Margin analysis; and Reserve margin analysis is included in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). I Demand-side management and conservation options; See Volume I, Chapter 7 (Resource Options) and Volume II, Appendix D (Demand-side Management) for a detailed discussion on DSM and energy efficiency resource options. Additional information on energy efficiency resource characteristics is available on the company’s website. WAC 480- 100-620(17) - utility's responses to public comments, and This is included in Volume II, Appendix C (Public Input). WAC 480- 100-620(17) - whether final plan addresses and incorporates comments raised. This is included in Volume II, Appendix C (Public Input). PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 95 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 to achieve long-term planning objectives. Stakeholders have been involved in the development of the 2023 IRP from the beginning. The public-input meetings held beginning in January 2022 were the cornerstone of the direct public- input process, and there have been 10 public-input meetings held as part of the 2023 IRP development cycle. Due to restrictions and concerns surrounding COVID-19, all meetings have been held via phone conference, with no in-person participation. The IRP public-input process also included state-specific stakeholder dialogue sessions held in the summer of 2022. The goal of these sessions was to capture key IRP issues of most concern to each state, as well as to discuss how to tackle these issues from a system planning perspective. PacifiCorp wanted to ensure 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 public- input meetings. PacifiCorp solicited agenda item recommendations from stakeholders in advance of the state meetings. There was additional open time to ensure participants had adequate opportunity for dialogue. PacifiCorp’s integrated resource plan website houses feedback forms included in this filing. This standardized form allows stakeholders to provide comments, questions, and suggestions. PacifiCorp also posts its responses to the feedback forms at the same location. Feedback forms and PacifiCorp’s responses can be found via the following link: https://www.pacificorp.com/energy/integrated-resource-plan/comments.html. Participant List PacifiCorp’s 2023 IRP continues to be a robust process involving input from many parties. Participants included commissions, stakeholders, and industry experts. Among the organizations that have been represented and actively involved in this collaborative effort are: Commissions • California Public Utilities Commission • Idaho Public Utilities Commission • Oregon Public Utility Commission • Public Service Commission of Utah • Washington Utilities and Transportation Commission • Wyoming Public Service Commission PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 96 Stakeholders and Industry Experts • ESS, INC • Renewable Northwest • SLC Corp • Utah Division of Public Utilities • Western Resource Advocates • Holland & Hart • Sierra Club • Utah Clean Energy • Interwest Energy Alliance • Powder River Basin Resource Council • Northwest Energy Coalition • Fervo Energy • Washington Utilities and Transportation Commission • Renewable Energy Coalition • Western Energy Storage Task Force • Enyo • Apex • City of Kemmerer Wyoming • NW Power Council • Energy Trust of Oregon • Oregon League of Women Voters • Oregon Citizen Utility Board • University of Wyoming • Applied Energy Group • Intermountain Wind-Colorado • Meta • City of SLC • Wyoming Energy Consumers • Wyoming Office of Consumer Advocates • Powder River Basin Conservation League • Wyoming Coalition of Local Governments PacifiCorp extends its gratitude for the continued time and energy that participants have given to the IRP process. Their participation has contributed significantly to the quality of this plan. As mentioned above, PacifiCorp has hosted 11 public-input meetings, as well as five state meetings during the public-input process, with an additional public-input meeting scheduled for April 2023. During the 2023 IRP public-input process presentations and discussions have covered various issues regarding inputs, assumptions, risks, modeling techniques, and analytical results. Below are the agendas from the public-input meetings; the presentations can be located at: https://www.pacificorp.com/energy/integrated-resource-plan/public-input-process.html PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 97 For the 2023 IRP, all General Public Meeting were held via conference call. The company has initiated making recording of these meeting publicly available through the IRP website: General Meetings February 25, 2022 – General Public Meeting (meeting materials provided to stakeholders on February 21, 2022) • Conservation Potential Assessment (CPA) • 2023 Supply-Side Resources • 2021 IRP Update / 2023 IRP Overview • 2023 IRP Public-Input Meeting Schedule April 7, 2022 – General Public Meeting (meeting materials provided to stakeholders on April 4, 2022) • Introductions • 2023 Conservation Potential Assessment (CPA) • Planning Environment Update • Optimization Modeling Overview May 12, 2022 – General Public Meeting (meeting materials provided to stakeholders on May 8, 2022) • Conservation Potential Assessment • Request For Proposals Update • Price Curve Development Update • Transmission Modeling • Climate Modeling June 10, 2022 – Public Meeting (meeting materials provided to stakeholders on June 6, 2022) • Greenhouse Gas and Renewable Portfolio Standards • State Policy Update • Load Forecast Development • Interconnection Options • Supply-Side Resource Alternative Fuels • 2021 IRP Acknowledgment Update • Stakeholder Feedback July 14, 2022 – Public Meeting (meeting materials provided to stakeholders on July 11, 2022) • Draft Load Forecast Update • Draft Private Generation Study • Draft Distribution System Planning • Renewable Portfolio Standards PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 98 • Stakeholder Feedback • Ozone Transport Rule Update September 1-2, 2022 – General Public Meeting (meeting materials provided to stakeholders on August 29, 2022) Day One • Inflation Reduction Act • Supply Side Resource Table • Existing Thermal Resource Options • Transmission Modeling • Price Forecasting • Customer Preference • Qualifying Facility Renewal • Conservation Potential Assessment Draft Results Day Two • Conservation Potential Assessment Draft Results—Part II • Stakeholder Feedback • Market Reliance Update • Oregon and Washington Update • Generation Transition Equity and Justice • Offshore Wind Workshop • Hydro Forecasting Under Climate Change October 13, 2022 – General Public Meeting (meeting materials provided to stakeholders on October 10, 2022) • Supply-Side Resource Escalation • Coal and Gas Modeling Options • Regional Haze Update • Load Forecast Update • Transmission Upgrade Options • Stochastics • Reliability Assessment • Portfolio Discussion • Stakeholder Feedback Update December 1, 2022 – General Public Meeting (meeting materials provided to stakeholders on November 28, 2022) • Conservation Potential Assessment • State Allocation and MSP Status Update • Transmission Interconnection: Cluster Study 2 Results • Initial Risk and Reliability Study Plan • State Policy Update • Stakeholder Feedback Form Update PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 99 January 13, 2023 – General Public Meeting (meeting materials provided to stakeholders on January 10, 2023) • Extended Day-Ahead Market Update • 2022 All-Source RFP Update • Distribution System Planning update • Transmission and Portfolio Selection Options Update • Stakeholder Feedback Form Update February 23, 2023 – General Public Meeting (meeting materials provided to stakeholders on February 20, 2023) • Expanded Public Comment Opportunities • Energy Efficiency Bundling • Modeling Updates • Forward Price Curve Updates • Stakeholder Feedback Update State-Specific Input Meetings June 7, 2022 – Oregon State Meeting Part 1 June 7, 2022 – Wyoming State Meeting June 21, 2022 – Oregon State Meeting Part 2 June 22, 2020 – Washington State Meeting June 29, 2022 – Utah State Meeting July 28, 2022 – Idaho State Meeting Stakeholder Comments Pre-filing For the 2023 IRP, PacifiCorp offered a Stakeholder Feedback Form which provided stakeholders a direct opportunity to provide comments, questions, and suggestions in addition to the opportunities for discussion at public-input meetings. PacifiCorp recognizes the importance of stakeholder feedback to the IRP public-input process. A blank form, as well as those submitted by stakeholders and PacifiCorp’s response, can be located on the PacifiCorp website at the IRP comments webpage at: www.pacificorp.com/energy/integrated-resource-plan/comments.html. As of March 23, 2023, PacifiCorp has received 36 Stakeholder Feedback Forms (including 4 pending forms) with hundreds of questions, comments, and recommendations. The Stakeholder Feedback Forms have allowed the company to review and summarize issues by topic as well as identify specific recommendations that were provided. Information collected is used to inform the 2023 IRP development process, including feedback related to process improvements and input assumptions, as well as responding directly to stakeholder questions. So far, Stakeholder Feedback Forms have been received from the following stakeholders: PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 100 • ESS, INC • Renewable Northwest • SLC Corp • Utah Division of Public Utilities • Western Resource Advocates • Holland & Hart • Sierra Club • Utah Clean Energy • Oregon Public Utilities Commission • Interwest Energy Alliance • Powder River Basin Resource Council • Northwest Energy Coalition • Fervo Energy • Washington Utilities and Transportation Commission • Renewable Energy Coalition • Western Energy Storage Task Force A discussion of topics included in the stakeholder feedback forms and how those topics were considered in the IRP are as follows: IRP Public-Input Meeting Process/General Comments Utah Division of Public Utilities submitted feedback stating that PacifiCorp must date its response to stakeholder forms, which the Company will continue to practice as a matter of policy.1 Note that some entries below may appear to anticipate events that have already occurred because they are presented from the perspective of the responses given at that time. Legislation A multi-party request asked that PacifiCorp include time and materials in an upcoming 2023 IRP stakeholder presentation to discuss the benefits and opportunities that may be available through the Infrastructure Investment and Jobs Act, and how they may affect resource and transmission planning. PacifiCorp emphasized active collaboration with state jurisdictions, as most of the Infrastructure Investment and Jobs Act funds for grid projects will be allocated to each state. 2 Sierra Club submitted a request that PacifiCorp elaborate on the relationship between the Inflation Reduction Act and load forecast assumptions. PacifiCorp responded stating that it has considered energy efficiency components of IRA for the Conservation Potential Assessment (CPA) by incorporating accelerated adoption rates for certain measure types eligible for IRA rebates and tax credits. It is difficult to exactly prescribe energy efficiency adjustments, but the Company did highlight changes for energy efficiency adoption rates at the December 1st PIM (Public Input Meeting) to reflect the IRA provisions noted in this stakeholder form.3 1 Feedback Form 007; June 7, 2022 2 Feedback Form 011; July 11, 2022 3 Feedback Form 030; December 7, 2022 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 101 Load Forecasting Western Resource Advocates recommend modeling two emissions reduction trajectories, in lieu of the “medium” and “high” carbon price scenarios, in addition to the social cost and no-cost GHG price assumptions.4 The Utah Division of Public Utilities requested an update on the 20-year weather pattern and Bureau of Reclamation Study, citing that the Reclamation study may not represent the most accurate climate change scenario in developing the IRP load forecast for Utah.5 Modeling Assumptions Holland and Hart requested clarification on how PacifiCorp developed the GHG cost methodology and what third party resources were used to develop these costs. PacifiCorp provided this at a subsequent IRP Public Input Meeting and detailed the source and derivation of its assumptions around the social cost of greenhouse gas and assumptions on price of CO2 that are included in the company’s IRP.6 Western Resource Advocates reiterated the request for information on Jim Bridger modeling, energy mix disclosure, GHG reporting, natural gas resources and hydrogen updates.7 Salt Lake City Corporation suggested that PacifiCorp evaluates wind and solar generation at an hourly rate vs. using monthly data. The Company acknowledged these limitations and is continuing to evolve the modeling process. 8 The Oregon Public Utilities Commission requested that PacifiCorp determine the assumptions used on installation of new AC units, conversion rates and how the daily shape of electric vehicle charging is modeled.9 Sierra Club submitted a request inquiring about reliability resources, coal capacity factors. Carbon Capture Utilization and Sequestration (CCUS), load forecast adjustments, Jim Bridger fuel contracts and the Inflation Reduction Act. PacifiCorp responded to this request at length and the response is publicly available on the Company IRP website. 10 Utah Clean Energy submitted a stakeholder request outlining the following questions pertaining to the Lila Canyon coal mine fire including efforts to extinguish the fire, operational and workforce implications, reliability and fuel risk assumptions and impacts to 2023 IRP Plexos modeling. PacifiCorp responded to the request at length and the response is publicly available on the Company IRP website. 11 4 Feedback Form 012; June 23, 2022 5 Feedback Form 021; September 9, 2022 6 Feedback Form 013; June 27, 2022 7 Feedback Form 015; July 11, 2022 8 Feedback Form 016; July 14, 2022 9 Feedback Form 019; August 5, 2022 10 Feedback Form 029; November 28, 2022 11 Feedback Form 031; November 23, 2022 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 102 Natrium Demonstration Project Powder River Basin Resource Council requested updates on Natrium project risk considerations, fuel availability for project longevity and viable waste disposal options. PacifiCorp responded to this request at length and the information is available to the public online. 12 The Washington Utilities and Transportation Commission submitted feedback noting concerns with the timeline for the release of the 2023 IRP preferred portfolio, modeling updates for the Natrium project following the announcement of a two-year delay and several procedural observations from IRP Public Input Meeting Series. PacifiCorp responded stating that it is the nature of IRP modeling and preparatory work that results must be confirmed before reporting and that all results are dependent upon ongoing work that is also subject to change. In response to emergent conditions which drive IRP timing, such as federal and state legislation, the Company is providing additional opportunities for public feedback after the March 31st filing and plans to file an addendum as needed and responsive to stakeholders.13 Natural Gas Salt Lake City Corporation noted that PacifiCorp should study whether a battery with a grid forming inverter would provide a lower-cost alternative to natural gas spinning reserves. PacifiCorp outlined its position that it considers a wide range of technologies for supply-side resources14 The Utah Division of Public Utilities outlined potential concerns concerning stranded cost risks and resource depreciation from conventional natural gas generation and asked to re—evaluate the use of natural gas proxy resources. The Company has since modeled for new natural gas resources in the 2023 IRP.15 Utah Clean Energy submitted feedback asking how PacifiCorp will assess the impacts of methane leakage mitigation policies on natural gas portfolio outcomes. PacifiCorp responded by stating that the overall impact of the Methane emissions fee is ~1% or less and therefore negligible in the long-term natural gas price forecast16 Salt Lake City Corporation submitted feedback insisting that PacifiCorp should consider revising its natural gas price forecast higher in line with the Energy Information Administration short-term energy outlook. PacifiCorp indicated that the plan is to develop a forecast in September 2022 for use in the 2023 IRP, which will incorporate then-current natural gas prices and the latest long-term expectations. 17 12 Feedback Form 028; October 5, 2022 13 Feedback Form 035; January 17, 2023 14 Feedback Form 009; June 16, 2022 15 Feedback Form 018: July 21, 2022 16 Feedback Form 023; September 8, 2022 17 Feedback Form 009; June 16, 2022 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 103 Plexos Utah Division of Public Utilities Requests Company updates its Supply Side table with current operating and costs characteristics of natural gas fueled generation resources and allow the model to endogenously select natural gas generating resources as proxy resources, as it has done in the past. In the 2021 IRP, PacifiCorp ran an analysis which included options for new gas and for the 2023 IRP, the company has also assessed viable options for the inclusion of new gas in its base modeling. 18 Reliability Assessment Sierra Club noted several observations pertaining to reliability modeling, the Inflation Reduction Act, and a potential reduction in Transmission costs via the Energy Infrastructure Reinvestment (EIR) program. PacifiCorp responded stating that many of these observations would be fully addressed once the Company provides a comprehensive IRP by the March 31, 2023, filing date.19 Renewable Energy Resources The Renewable Energy Coalition submitted a request outlining PacifiCorp’s compliance with Oregon Public Utility Commission Order No. 22-178 and relevant data including the current QF renewal and success rate at varying capacities. PacifiCorp responded by posting supporting documentation on the Company Public Input Meeting website titled “QF Extension History”, which provides an inventory of PacifiCorp qualifying facilities with other pertinent information. For supplemental data relating to qualifying facilities, this party was also directed to Oregon dockets LC-77 (2021 IRP) and LC-70 (2019 IRP).20 Resource Adequacy Utah Clean Energy submitted a request that PacifiCorp develop three demand-side management sensitivities utilizing a low, medium, and high method of measurement. With the above feedback considered PacifiCorp instead utilizes a bottom-up modeling approach, which is better suited to adjustments to inputs for the purpose of informing sensitivities.21 State Energy Policy Sierra Club requested updates on the Natrium Project, emissions profiles and state policy updates as they relate to the 2021 IRP acknowledgment, greenhouse gas reporting, Renewable Portfolio Standards, load forecast updates and compliance with the Washington Clean Energy Transformation Act (CETA).22 Washington Utilities and Transportation Commission Staff emphasized the statutory obligation for Washington utilities to incorporate the social cost of greenhouse gas into Washington allocated resource carbon cost assumptions. PacifiCorp responded by stating it is not aware of any language 18 Feedback Form 010; July 7, 2022 19 Feedback Form 034; January 18, 2023 20 Feedback Form 032; January 3, 2023 21 Feedback Form 017; July 21, 2022 22 Feedback Form 014; July 1, 2022 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 104 in RCW 19.280.030(3) and WAC 480-100-605 that requires utilities to include the SCGHG as their base carbon cost price-policy assumption for Washington-allocated resources.23 Supply-side Resource Costs/Supply-side Resource Table ESS Inc requested an update from PacifiCorp on what changes are being made to the IRP modeling to determine marginal values of long-duration flow battery storage. The Company informed this party that it is commissioning a study of the cost and performance characteristics of energy storage and expects the study to include information specific to long duration flow batteries24 Renewable Northwest submitted a request that PacifiCorp consider DC-coupled solar + storage as well as other additional battery storage durations (medium and long-duration) as part of the supply- side resource table and subsequent IRP modeling. The Company responded indicating that Proxy resource modeling in the 2023 IRP is intended to be representative of costs and operational characteristics across a range of configurations and at this time is based on AC configuration but does not preclude other constructs from participating in all-source requests for proposals. 25 Fervo Energy submitted a supply-side resources feedback outlining new cost assumptions that geothermal is becoming a less cost-prohibitive resource option that has the potential to create new jobs. In line with regulatory precedent, PacifiCorp remains committed to pursuing least- cost, least-risk preferred portfolio outcomes including geothermal when economically competitive.26 Renewable Northwest submitted feedback requesting updated transmission capacity metrics, offshore wind costs and recent modeling assumptions. PacifiCorp responded by stating that it has added 1,000 MW of offshore wind resources to the supply-side table among other more detailed information provided in this stakeholder form. 27 The Western Energy Storage Task Force recommended the use of a specified forecast for utility- scale battery storage resources and proposed revising price modifications. PacifiCorp responded and re-affirmed that the costs presented in the September 1st Public Input Meeting do not include tax incentives implemented in the Inflation Reduction Act. Additional supply-side table reporting will identify costs after accounting for tax incentives and all tax incentives are being accounted for in the 2023 IRP modeling process. The information about tax incentives presented to date is consistent with Table 7.1 in PacifiCorp’s 2021 IRP. Resource information inclusive of tax incentives was provided in Table 7.2 of PacifiCorp’s 2021 IRP and comparable information will be provided for the 2023 IRP.28 Salt Lake City Corporation submitted a request for the inclusion of a supply-side long-duration storage option with characteristics similar to the iron air battery announced earlier in the year. The Company responded by stating that it is considering longer duration energy storage similar to Form Energy Iron Air Battery in the 2023 IRP. PacifiCorp is commissioning a study of the cost and 23 Feedback Form 024; September 20, 2022 24 Feedback Form 001; February 24, 2022 25 Feedback Form 002; March 3, 2022 26 Feedback Form 020; August 23, 2022 27 Feedback Form 022; September 14, 2022 28 Feedback Form 027; October 27, 2022 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 105 performance characteristics of energy storage and expects the study to include cost information specific to long duration flow batteries.29 Transmission The Utah Division of Public Utilities requested supplemental study information and transmission topology, specifically referring to the Kiewit study on natural gas and hydrogen and requesting further information regarding why the Jim Bridger coal plant was moved to the PAC-east balancing authority. PacifiCorp responded directly to this stakeholder request and did not publish the response due to sensitivities around the Kiewit study. The Interwest energy alliance inquired about whether or not PacifiCorp reviews the potential for reconductoring with advanced conductors, grid enhancing technology or advanced transmission technologies. PacifiCorp responded by saying it considers reconductoring with advanced conductors such as ACCC and ACSS if this provides a solution to thermal issues that are observed during outage conditions for regular studies such as Cluster Studies, Transmission Planning Assessment studies TPL001-4 and others.30 Extended Comment Period During the 2023 IRP extended comment period, PacifiCorp received feedback from the following stakeholders outlining various resource planning considerations. PacifiCorp used this opportunity to address comments from each contributor, resulting in the addition of two variants to the 2023 IRP. These variants are described in Volume I, Chapters 8 and 9. For those seeking additional clarification on items submitted via stakeholder feedback form, please refer to the following resource: Stakeholder Feedback (pacificorp.com) Extended comment period contributors • Individual Ratepayer o Stakeholder outlined concerns with coal fire generation facilities and the need to deploy best-available technology to mitigate emissions • Individual Ratepayer o Stakeholder outlined grievances with Natrium demonstration project and retrofitting existing coal facilities to burn natural gas, citing ratepayer expense and increased methane emissions as a primary concern. • Individual Ratepayer o Stakeholder outlined concerns that nuclear technology is unproven. • Individual Ratepayer o Stakeholder outlined concern with retrofitting existing facilities to burn natural gas, citing that such facilities produce excessive noise and air pollution. • AARP o In summary, AARP stated that Rocky Mountain Power (RMP) should revise the IRP to show the retail rate impact of its preferred plan and disclose how it compares 29 Feedback Form 003; May 12, 2022 30 Feedback Form 033; January 10, 2023 PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 106 with other alternatives such as the business as usual scenario, allowing options like natural gas and hydrogen plants to be considered, etc. AARP also insisted that RMP should apply to DOE to use Federal funds for as much of the spending as possible including new transmission lines, new experimental nuclear technologies, and storage projects. Lastly, AARP concluded that it does not support RMP joining an RTO. • Utah Office of Consumer Services o Stakeholder outlined requests for the following via stakeholder feedback form: ▪ Explain why no natural gas resources were selected in any portfolio except for in the one NG scenario P11-Max NG. Discuss the parameters and assumptions in the model causing no selection of NG resources. Please include this discussion in the text of the final 2023 IRP. Also, are these parameters and assumptions for natural gas fired resources reflected in the 2023 Supply-Side Resource Tables in Chapter 7? ▪ 2. Perform a scenario not allowing nuclear and non-emitting peakers and limiting the availability of batteries (say to 500 MW per year?) to show the resulting portfolio. The purpose of this model run is to explore what happens if the nuclear and non-emitting peakers technologies don't materialize and because of very high demand by all US utilities, battery systems are difficult to procure. The purpose of this scenario is to show how and whether system reliability can be maintained without depending on these 3 types of resources. Include a short discussion of the results of this scenario in the final 2023 IRP. ▪ How is the energy needed to recharge batteries in the Preferred Portfolio accounted for? What resources are most likely supplying the energy? Is it possible to identify what resources (solar, wind, nuclear) are needed to provide energy for the batteries? Please include this discussion in the text of the final 2023 IRP. ▪ Perform a scenario that includes a long lasting extreme weather event in a planning year where most fossil fuel resources are retired - events such as September 2022 heat wave or February 2021 Texas extreme cold. The purpose is to identify reliability issues when the system is assumed to be relying primarily on intermittent resources and batteries for reliability. Extreme weather events are becoming more common and a discussion of this scenario and how the future system based on the preferred portfolio handles the extreme event should be included in the text of the final 2023 IRP. ▪ Provide the total capital costs for the new resources in the preferred portfolio by broad category - e.g. by wind, solar, batteries, nuclear, non-emitting peakers, transmission, etc. Provide this for the Action Plan and for the entire 20-year planning period. Please include tables in the final 2023 IRP with this capital cost information. ▪ Provide a customer rate impact analysis (for retail ratepayers) of the preferred portfolio as compared to a base scenario - such as the system at December 2022. It is not sufficient to provide customer rate impacts between the final preferred portfolio and the other 2023 IRP portfolio candidates. Provide this information in the text of the 2023 IRP, including PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 107 using a table similar to Table 8.4 from the 2011 IRP and a chart similar to Figure 4.1 from the 2017 IRP Energy Vision Update. ▪ Please run a scenario where new NG resources are assumed to have normal or typical depreciation lives (not shortened to 10 years as explained in the April 13, 2023 Stakeholder meeting). Include this information in the final 2023 IRP. ▪ Please respond and provide an explanation on how PacifiCorp will address the risks listed below that are involved in pursuing the selected Natrium nuclear units. The Utah OCS requests that PacifiCorp include its response to these risks in the Nuclear section of IRP Chapter 7 – “Resource Options”. ▪ Fuel Risk - how will PacifiCorp procure (include a timeline) the necessary HALEU fuel on time for each unit? ▪ Financial Risk - the likelihood of large cost overruns for each unit. Recent construction of nuclear plants in Georgia and South Carolina and other parts of the world have resulted in more than 100% (i.e. more than double costs) cost overruns. ▪ Construction Delay Risk – recent nuclear plants have also been hobbled by lengthy construction delays – how can PacifiCorp quickly replace the need capacity? ▪ Operational Risk – Natrium nuclear is a first of its kind untested-in-the-real-world technology. What is PacifiCorp’s plan if these reactors do not perform as promised or if they fail prematurely? PacifiCorp has no operational experience with Natrium nuclear reactors – how will be PacifiCorp know how to operate these plants effectively? ▪ Storage and Disposal of Nuclear Waste Risk – How and where will PacifiCorp store and dispose of the nuclear waste resulting from the planned nuclear resources? ▪ Please clarify and provide corrections in the final 2023 IRP as necessary to the following statements in the IRP: Page 238 of the Preliminary 2023 IRP states: "For the 2023 IRP natural gas resources are available in the endogenous LT model for selection, a change from the 2021 IRP." But then page 240 states: "Therefore, new natural gas proxy resources were not made available for selection in any of Initial Portfolios". • Individual Ratepayer o Stakeholder expressed cost concerns associated with gas conversions, miles of transmission lines, and small modular nuclear reactors. Stakeholder further insisted that PacifiCorp reinvests in communities to bolster energy resiliency as a least cost, least risk option. • Powder River Basin Resource Council o Stakeholder expressed concern that the IRP’s short-term action plan and longer-term resource plan fail to adequately disclose costs and risks associated with coal or nuclear plants, and the plan creates a situation where grid reliability and electricity affordability are dependent on unproven technologies. • Western Resource Advocates o Stakeholder requested that PacifiCorp address questions regarding methodology in its May filing. Specifically, issues of which resource additions result from model PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 108 optimization, and which are exogenously added is not always clear in the discussion. o Lastly, WRA in conjunction with other parties submitted two Variants requests to be simulated and included as part of the Final 2023 IRP. • Sierra Club o Model full compliance with the federal Clean Air Act by modeling SCRs at Wyodak, Hunter, and Huntington; o Inflation Reduction Act: ▪ Utilize the IRS guidance on qualifying “energy communities” to apply the energy community tax bonus credit under the Inflation Reduction Act to all qualifying communities. ▪ Incorporate opportunities afforded by the Energy Infrastructure Reinvestment program for low-cost financing that can be applied to closing coal plants and clean replacement resources as well as transmission infrastructure; ▪ Increase the private generation forecast by an additional 115 –504 MW and reassess planning capacity requirements. ▪ Clearly state what tax credits have been applied to “non-emitting peakers,” and ensure if a hydrogen production tax credit is applied that the model includes scenarios assuming 100% of the credit, 33.4%, and none; ▪ Complete model runs of the P02-JB-3-4 GC, P03-Huntington RET28, and P17-Col3-4 RET25 variants under all of the different price/policy scenarios; ▪ Increase the medium CO2 price forecast to account for increasing risk of climate regulation. ▪ Complete a variant model run in which the CO2 price is used in the LT model but not the ST model ▪ Provide greater clarification in the final 2023 IRP on the impact of including the CO2 price; ▪ Identify in the final 2023 IRP any assumptions made regarding minimum volumes or take or pay requirements throughout the planning horizon; ▪ Include up-to-date pricing for the Jim Bridger plant from the 2023 Long Term Fuel Supply Plan in the final 2023 IRP ▪ Provide further clarifications on workpaper naming conventions and ensure that all model results files are provided to stakeholders. ▪ Pursue a new all-source RFP every year, rather than every two years and include actions associated with a 2025 RFP in the action plan. ▪ Detail actions that will need to be taken to realize EDAM participation. ▪ Clarify whether PacifiCorp intends to “terminate, amend, or close out” coal supply agreements at the Black Butte and/or Bridger mines and identify all other activities PacifiCorp is planning to pursue related to coal contract origination or termination over the next three years. ▪ Clarify how transmission rights will be reassigned at plants scheduled to retire within the next five years. • Individual Ratepayer o Stakeholder expressed concerns with the viability of nuclear and coal generation retrofit technology citing public health risks. • HEAL Utah PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 109 o Stakeholder contends that PacifiCorp is significantly underestimating the overall cost and timeline of nuclear power plant replacement for Hunter and Huntington coal fired power plants, while relying on assumptions for the Natrium demonstration plant. Deeper examination of other non-emitting renewable resources as part of the analysis is encouraged • Utah Clean Energy o Stakeholder provided a large spectrum of considerations which were addressed by staff and can be found on PacifiCorp’s external stakeholder feedback page. • Utah DPU o Stakeholder submitted feedback outlining natrium plant considerations, new natural gas resources, front office transactions, forward tech variants, load and resource balance and end of life coal retirements. A response to this feedback can be found on PacifiCorp’s external stakeholder feedback page. • JRDS Law o Stakeholder provided a large spectrum of considerations which were addressed by staff and can be found on PacifiCorp’s external stakeholder feedback page. Contact Information PacifiCorp’s IRP website: w ww.pacificorp.com/energy/integrated-resource-plan.html. PacifiCorp requests any informal request be sent to the following address or email. PacifiCorp IRP Resource Planning Department 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 Email Address: I RP@PacifiCorp.com PACIFICORP – 2023 IRP APPENDIX C – PUBLIC INPUT PROCESS 110 PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 111 APPENDIX D – DEMAND-SIDE MANAGEMENT Introduction This appendix reviews the studies and reports used to support the demand-side management (DSM) resource information used in the modeling and analysis of the 2023 Integrated Resource Plan (IRP). In addition, it provides information on the economic DSM selections in the 2021 IRP’s Preferred Portfolio, a summary of existing DSM program services and offerings, and an overview of the DSM planning process in each of PacifiCorp’s service areas. Conservation Potential Assessment (CPA) for 2023-2042 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. The Conservation Potential Assessment (CPA) for 2023-2042,1 conducted by Applied Energy Group (AEG) on behalf of PacifiCorp, primarily seeks to develop reliable estimates of the magnitude, timing, and costs of DSM resources likely available to PacifiCorp over the IRP’s 20-year planning horizon. The study focuses on resources realistically achievable during the planning horizon, given normal market dynamics that may hinder or advance resource acquisition. Study results were incorporated into PacifiCorp’s 2023 IRP and will be used to inform subsequent DSM planning and program design efforts. This study serves as an update of similar studies completed since 2007. For resource planning purposes, PacifiCorp classifies DSM resources into four categories, differentiated by two primary characteristics: reliability and customer choice. These resource classifications can be defined as: demand response (e.g., a firm, capacity focused resource such as direct load control), energy efficiency (e.g., a firm energy intensity resource such as conservation), demand side rates (DSR) (e.g., a non-firm, capacity focused resource such as time of use rates), and behavioral-based response (e.g., customer energy management actions through education and information). From a system-planning perspective, demand response resources can be considered the most reliable, as they can be dispatched by the utility. In contrast, behavioral-based resources are the least reliable due to the resource’s dependence on voluntary behavioral changes. With respect to customer choice, demand response and energy efficiency resources should be considered involuntary in that, once equipment and systems have been put in place, savings can be expected to occur over a certain period. DSR and behavioral-based activities involve greater customer 1 PacifiCorp’s Demand-Side Resource Potential Assessment for 2023-2042, completed by AEG, can be found at: www.pacificorp.com/energy/integrated-resource-plan/support.html. PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 112 choice and control. This assessment estimates potential from demand response, energy efficiency, and DSR. The CPA excludes an assessment of Oregon’s energy efficiency resource potential, as this work is performed by Energy Trust of Oregon, which provides energy efficiency potential in Oregon to PacifiCorp for resource planning purposes. Current DSM Program Offerings by State Currently, PacifiCorp offers a robust portfolio of DSM programs and initiatives, most of which are offered in multiple states, depending on size of the opportunity and the need. Programs are reassessed on a regular basis. PacifiCorp has the most up-to-date programs on its website.2 Demand response and energy efficiency program services and offerings are available by state and sector. Energy efficiency services listed for Oregon, except for low-income weatherization services, are provided in collaboration with Energy Trust of Oregon.3 Table D.1 provides an overview of the breadth of demand response and energy efficiency program services and offerings available by Sector and State. PacifiCorp has numerous DSR offerings currently available. They include metered time-of-day and time-of-use pricing plans (in all states, availability varies by customer class), and residential seasonal rates (Idaho and Utah). System-wide, approximately 16,100 customers were participating in metered time-of-day and time-of-use programs as of December 31, 2022. Savings associated with rate design are captured within the company’s load forecast and are thus captured in the integrated resource planning framework. PacifiCorp continues to evaluate DSR programs for applicability to long-term resource planning. PacifiCorp provides behavioral based offerings as well. Educating customers regarding energy efficiency and load management opportunities is an important component of PacifiCorp’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. Load reductions due to behavioral activity will show up in demand response and energy efficiency program results and non-program reductions in the load forecast over time. Table D.2 provides an overview of DSM related wattsmart Outreach and Communication activities (Class 4 DSM activities) by state. 2 Programs for Rocky Mountain Power can be found at www.rockymountainpower.net/savings-energy-choices.html and programs for Pacific Power can be found at www.pacificorp.com/environment/demand-side-management.html. 3 Funds for low-income weatherization services are forwarded to Oregon Housing and Community Services. PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 113 Table D.1– Current Demand Response and Energy Efficiency Program Services and Offerings by Sector and State Program Services & Offerings by Sector and State California Oregon Washington Idaho Utah Wyoming Residential Sector Air Conditioner Direct Load Control  Lighting Incentives       New Appliance Incentives       Heating And Cooling Incentives       Weatherization Incentives - Windows, Insulation, Duct Sealing, etc.       New Homes       Low-Income Weatherization       Home Energy Reports      School Curriculum    Financing Options With On-Bill Payments   Trade Ally Outreach       Program Services & Offerings by Sector and State California Oregon Washington Idaho Utah Wyoming Non-Residential Sector Irrigation Load Control     Commercial and Industrial Demand Response    Standard Incentives       Energy Engineering Services       Billing Credit Incentive (offset to DSM charge)    Energy Management       Energy Profiler Online       Business Solutions Toolkit       Trade Ally Outreach       Small Business Lighting      Lighting Instant Incentives       Small to Mid-Sized Business Facilitation       DSM Project Managers Partner With Customer Account Managers       PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 114 Table D.2 – Current wattsmart Outreach and Communications Activities wattsmart Outreach & Communications (incremental to program specific advertising) California Oregon Washington Idaho Utah Wyoming Advertising      Sponsorships   Social Media       Public Relations      Business Advocacy (awards at customer meetings, sponsorships, chamber partnership, university partnership)       wattsmart Workshops and Community Outreach       BE wattsmart, Begin at Home - in school energy education     State-Specific DSM Planning Processes A summary of the DSM planning process in each state is provided below. Utah, Wyoming and Idaho The company’s biennial IRP and associated action plan provides the foundation for DSM acquisition targets in each state. Where appropriate, the company maintains and uses external stakeholder groups and vendors to advise on a range of issues including annual goals for conservation programs, development of conservation potential assessments, development of multi- year DSM plans, program marketing, incentive levels, budgets, adaptive management, and the development of new and pilot programs. Washington The company is one of three investor-owned utilities required to comply with the Energy Independence Act (also referred to as I-937) approved in November 2006. The Act requires utilities to pursue all conservation that is cost-effective, reliable, and feasible. Every two years, each utility must identify its 10-year conservation potential and two-year acquisition target based on its IRP and using methodologies that are consistent with those used by the Northwest Power and Conservation Council. Each utility must maintain and use an external conservation stakeholder group that advises on a wide range of issues including conservation programs, development of conservation potential assessments, program marketing, incentive levels, budgets, adaptive management, and the development of new and pilot programs. PacifiCorp works with the conservation stakeholder group annually on its energy efficiency program design and planning. In 2019, Washington passed the Clean Energy Transformation Act (CETA), which requires utilities to meet three primary clean energy standards: remove coal-fueled generation from Washington’s allocation of electricity by 2025, serve Washington customers with greenhouse gas neutral electricity by 2030, and to serve customers in Washington with 100% renewable and non- PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 115 emitting electricity by 2045. The conservation stakeholder group and the demand-side management advisory group inform the CETA planning process as documented in the Company’s Clean Energy Implementation Plan (CEIP)4. California On December 19, 2022, the Commission issued approved the company’s Biennial Budget Advice Letter (BBAL) Filing 697E to administering its energy efficiency programs through 2024. The BBAL was submitted PacifiCorp submitted in accordance with Ordering Paragraph 4 of Decision (D.) 21-12-034 an application for the continuation of energy efficiency programs for program years 2022-2026 on December 31, 2020. Oregon Energy efficiency programs for Oregon customers are planned for and delivered by Energy Trust of Oregon in collaboration with PacifiCorp. Energy Trust’s planning process is comparable to PacifiCorp’s other states, including establishing resource acquisition targets based on resource assessment and integrated resource planning, developing programs based on local market conditions, and coordinating with stakeholders and regulators to ensure efficient and cost-effective delivery of energy efficiency resources. Preferred Portfolio DSM Resource Selections The following tables show the economic DSM resource selections by state and year in the 2023 IRP preferred portfolio5. Table D.3 –Cumulative Demand Response Resource Selections (2023 IRP Preferred Portfolio)6 4 The Company’s CEIP can be found online at https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/ceip/PAC-CEIP-12-30-21_with_Appx.pdf 5 Following DSM resource selection methodologies described in Chapter 7 of the IRP. 6 A portion of cost-effective demand response resources identified in the 2023 preferred portfolio in 2023 for Oregon and Washington represent planned volumes expected to be acquired in 2023 PacifiCorp will pursue all cost-effective demand response resources identified as incremental to resources offered through approved programs. Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 DR Summer - ID 0.0 0.0 4.1 13.1 18.8 19.8 20.1 20.5 20.7 20.7 DR Summer - UT 0.0 8.5 36.1 59.4 88.1 108.7 120.8 131.4 145.2 145.2 DR Summer - WY 0.0 0.0 14.3 15.2 36.9 40.4 40.5 40.5 40.6 40.6 DR Winter - ID 0.0 0.4 1.3 2.5 3.0 3.3 3.3 3.3 3.3 3.3 DR Winter - UT 0.0 0.5 7.2 12.8 14.5 16.4 16.4 16.4 16.4 16.4 DR Winter - WY 0.0 0.0 9.8 24.1 31.4 35.7 36.1 36.5 36.8 36.8 DR Summer - CA 0.0 0.0 2.7 4.2 5.6 6.1 6.2 6.3 6.5 6.5 DR Summer - OR 47.0 48.9 82.4 102.9 147.5 163.5 175.8 179.8 185.3 185.3 DR Summer - WA 24.5 27.4 34.7 42.2 52.9 56.5 58.6 58.6 60.4 60.4 DR Winter - CA 0.0 0.0 1.2 2.9 3.2 4.3 4.3 4.3 4.3 4.3 DR Winter - OR 0.0 14.7 51.7 71.9 81.0 104.2 104.2 104.2 104.2 104.2 DR Winter - WA 0.0 9.7 16.8 20.3 21.6 26.6 26.6 26.6 26.6 26.6 PACIFICORP – 2023 IRP APPENDIX D – DEMAND-SIDE MANAGEMENT RESOURCES 116 Table D.4 – Cumulative Energy Efficiency Resource Selections (2023 IRP Preferred Portfolio)7 For the 20-year assumed nameplate capacity contributions (MW impacts) by state and year associated with the energy efficiency resource selections above, see Volume I, Chapter 9 (Modeling and Portfolio Selection). 7 First Year energy may differ somewhat from incremental values, i.e., subtracting cumulative energy from the prior year, due to hourly shapes of energy efficiency changing from year to year. Resource 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 DR Summer - ID 20.7 20.7 20.7 20.7 20.7 58.1 58.5 58.8 58.8 58.8 DR Summer - UT 145.2 145.2 145.2 145.2 145.2 258.4 273.2 288.7 288.7 288.7 DR Summer - WY 40.6 40.6 40.6 40.6 40.6 48.0 48.1 48.2 48.2 48.2 DR Winter - ID 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 DR Winter - UT 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 DR Winter - WY 36.8 36.8 36.8 36.8 36.8 37.3 37.3 37.3 37.3 37.3 DR Summer - CA 6.5 6.5 6.6 6.6 6.6 10.5 10.5 10.6 10.6 10.6 DR Summer - OR 185.3 185.3 188.9 188.9 188.9 246.2 249.4 252.4 252.4 252.4 DR Summer - WA 60.4 60.4 61.1 61.1 61.1 74.3 75.0 75.5 75.5 75.5 DR Winter - CA 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 DR Winter - OR 104.2 104.2 104.2 104.2 104.2 104.2 104.2 104.2 104.2 104.2 DR Winter - WA 26.6 26.6 29.1 29.1 29.1 29.1 29.1 29.1 29.1 29.1 Cumulative Energy Efficiency Energy (MWh) Selected by State and Year State 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 CA 2,425 5,133 8,230 11,950 16,241 21,119 25,863 29,746 34,049 37,657 OR 164,891 353,829 554,093 718,490 884,712 1,049,968 1,193,317 1,336,694 1,484,539 1,599,999 WA 53,112 92,825 139,678 176,285 217,245 263,078 307,593 352,688 391,869 438,353 UT 266,500 533,698 784,596 1,104,475 1,465,324 1,863,964 2,293,908 2,729,834 3,222,474 3,683,967 ID 12,000 26,904 44,488 67,589 93,874 122,627 152,904 183,153 215,350 246,305 WY 44,204 82,779 136,203 193,306 254,854 323,039 392,795 463,866 536,134 609,312 Total System 543,132 1,095,168 1,667,288 2,272,095 2,932,250 3,643,795 4,366,380 5,095,981 5,884,415 6,615,593 Cumulative Energy Efficiency Energy (MWh) Selected by State and Year State 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 CA 40,743 43,828 46,619 51,494 55,937 60,279 64,163 67,225 68,125 68,894 OR 1,709,682 1,828,196 1,932,389 2,033,607 2,130,095 2,215,474 2,298,014 2,387,815 2,435,920 2,501,977 WA 481,166 523,072 562,857 601,436 634,690 667,807 696,675 724,608 740,934 750,998 UT 4,136,697 4,594,146 5,036,490 5,500,751 5,982,526 6,394,484 6,788,840 7,232,255 7,543,238 7,574,529 ID 276,616 307,597 337,181 367,670 395,935 422,404 445,889 470,511 489,381 499,899 WY 677,181 744,975 809,670 881,135 947,588 1,004,063 1,055,407 1,113,621 1,149,399 1,182,690 Total System 7,322,085 8,041,814 8,725,206 9,436,093 10,146,771 10,764,511 11,348,988 11,996,035 12,426,997 12,578,987 PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 117 APPENDIX E – SMART GRID Introduction Smart grid is the application of advanced communications and controls to the electric power system. As such, a wide array of applications can be defined under the smart grid umbrella. PacifiCorp has identified specific areas for research that include technologies such as dynamic line rating, phasor measurement units, distribution automation, advanced metering infrastructure (AMI), automated demand response and other advanced technologies. PacifiCorp has reviewed relevant smart grid technologies for transmission and distribution systems that provide local and system benefits. When considering these technologies, advanced controls and communications often the most critical infrastructure decision. This network must have relevant speed, reliability, and security to support applications such as current real-time WEIM (optimizes the energy imbalances throughout the West) by transferring energy between participants in 15-minute and 5- minute intervals throughout the day. PacifiCorp has planned to build on the success of real-time energy market innovation by joining the new Western day-ahead market, (EDAM), developed by the California Independent System Operator (CAISO). A modernized western energy market is a key component of PacifiCorp’s strategy to connect and optimize the West’s abundant and diverse energy resources to deliver the lowest cost and most reliable pathway to a net-zero energy future. PacifiCorp is committed to advancing innovation in markets and new energy technologies to meet its commitment to affordability and reliability while supporting its communities throughout the energy transition. PacifiCorp has focused on those technologies that present a positive benefit for customers and has implemented functions such as advanced metering, dynamic line rating, and distribution automation. This will optimize the electrical grid when and where it is economically feasible, operationally beneficial and in the best interest of customers. PacifiCorp is committed to consistently evaluating the value of emerging technologies for integration when they are found to be appropriate investments. The company is working with state commissions to improve reliability, energy efficiency, customer service, and integration of renewable resources by analyzing the total cost of ownership, performing thorough cost-benefit analyses, and reaching out to customers concerning smart grid applications and technologies. As technology advances and development continues, PacifiCorp can improve cost estimates and benefits of smart grid technologies that will assist in identifying the best suited technologies for implementation. Transmission Network and Operation Enhancements Dynamic Line Rating Dynamic line rating is the application of sensors to transmission lines to indicate the real-time current-carrying capacity of the lines in relation to thermal restrictions. Transmission line ratings are typically based online-loading calculations given a set of worst-case weather assumptions, such as high ambient temperatures and very low wind speeds. Dynamic line rating (DLR) allows an increase in current-carrying capacity of transmission lines, when more favorable weather conditions are present, a without compromising safety. DLR has become increasingly relevant with higher shares of variable renewable energy (VRE) in the power system. By seeking to increase the ampacity of transmission lines, it provides economic and technical benefits to all PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 118 involved. FERC NOPR (RM21-17-000) is calling to fully consider dynamic line ratings and advanced power flow control devices in local and regional transmission planning processes. PacifiCorp has been using DLR since 2014. The Standpipe-Platte project was implemented in 2014 and has delivered positive results as windy days are directly linked to increased wind power generation and increased transmission ratings. A dynamic line rating system is used to determine the resulting cooling effect of the wind on the line. The current carrying capacity is then updated to a new weather dependent line rating. The Standpipe-Platte 230 kilovolt (kV) transmission line is one of three lines in the Aeolus West transmission corridor and had been one of the lines that limits the corridor power transfer. As a result of this project, the Aeolus West Western Electricity Coordinating Council (WECC) non-simultaneous path rating was increased. The DLR system on the Platte – Standpipe 230 kV line has been updated with a Transmission Line Monitoring (TLM) system manufactured by Lindsey Systems. Additionally, a new DLR system is being implemented on the existing Dave Johnston- Amasa – Difficulty – Shirley Basin 230 kV line as part of the Gateway Segment D.1 Project. The Dave Johnston- Amasa – Difficulty – Shirley Basin 230 kV line connects two areas with a high penetration of wind generation resources and implementation of the DLR system will improve the link between those two areas to reduce the need for operational curtailments when wind patterns result in a variation in generation between the two areas, such as high winds in the northeast area and moderate to low winds in the southeast area. The DLR system will increase the transmission line steady-state rating under increased wind conditions and reduce instances and duration of associated generation curtailments. Dynamic line rating will be considered for all future transmission needs as a means for increasing capacity in relation to traditional construction methods. Dynamic line rating is only applicable for thermal constraints and only provides additional site-dependent capacity during finite time periods, and it may or may not align with expected transmission needs of future projects. PacifiCorp will continue to look for opportunities to cost-effectively employ dynamic line rating systems similarly to the one deployed on the Standpipe – Platte 230 kV transmission line... Digital Fault Recorders / Phasor Measurement Unit Deployment To meet compliance with the North American Electric Reliability Corporation (NERC) MOD- 033-1 and PRC-002-2 standards, PacifiCorp has installed over 100 multifunctional digital fault recorders (DFR) which include phasor measurement unit (PMU) functionality. The installations are at key transmission and generation facilities throughout the six-state service territory, generally placed on WECC identified critical paths. PMUs provide sub-second data for voltage and current phasors, which can be used for MOD-033-1 event analysis and model verification. DFRs have a shorter recording time with higher sampling rate to validate dynamic disturbance modelling per PRC-002-2. The DFR/PMUs will deliver dynamic PMU data to a centralized phasor data concentrator (PDC) storage server where offline analysis can be performed by transmission operators, planners, and protection engineers to validate system models has been completed. Transmission planners will use the phasor data quantities from actual system events to benchmark performance of steady-state and transient stability models of the interconnected transmission system and generating facilities. Using a combination of phasor data from the PMUs and analog quantities currently available through Supervisory Control and Data Acquisition System (SCADA), transmission planners can set up the system models to accurately depict the transmission system prior to, during, and following an event. Differences in simulated versus PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 119 actual system performance will then be evaluated to allow for enhancements and corrections to the system model. Model validation procedures are being evaluated, in conjunction with data and equipment availability to fulfill MOD-033-1. The process of validating the system model against a historical system outage event that includes the comparison of a planning power flow model to actual system behavior and the comparison of the planning dynamic model to actual system response is ongoing. PacifiCorp will continually evaluate potential benefits of PMU installation and intelligent monitoring as the industry considers PMU in special protection, remedial action scheme and other roles that support transmission grid operators. PacifiCorp will continue to work with the California Independent System Operator’s (CAISO) Reliability Coordinator West to share data as appropriate. Distribution Automation and Reliability Distribution Automation Distribution automation encompasses a wide field of smart grid technology and applications that focus on using sensors and data collection on the distribution system, as well as automatically adjusting the system to optimize performance. Distribution automation can also provide improved outage management with decreased restoration times after failure, operational efficiency, and peak load management using distributed resources and predictive equipment failure analysis using complex data algorithms. PacifiCorp is working on distribution automation initiatives focused on improved system reliability through improved outage management and response. In Oregon, PacifiCorp identified 40 circuits on which cost benefit analyses were performed. From this analysis two circuits in Lincoln City, Oregon were selected to have a fault location, isolation and service restoration (FLISR) system installed. The project was installed through 2019 and commissioning of the automation scheme conducted through 2020 in the distribution loop out of Devil’s Lake substation in Lincoln City, Oregon. The Company also moved its pre-deployment distribution automation testing equipment to its Tech Ops center in Portland, Oregon to expand open discussion between internal end users including operations, service crews and field technicians. Throughout the implementation of the Devil’s Lake DA scheme, the Company faced persistent challenges with communication over its existing AMI network. The Company found the communication capability of AMI was not suited well for a FLISR scheme and evaluated alternative solutions. The solution now uses fiber optic communication, which the Company installed in a loop configuration to increase resiliency of the FLISR scheme’s communication path. The fiber infrastructure was deployed in Q4 2022, and the Company now has complete FLISR capability with the Devil’s Lake DA system. Based on that experience additional two additional automation projects were initiated in Portland and Medford, relying on private fiber optic communications (in a manner very similar to how transmission assets would be monitored) Engineering and construction are in progress and commissioning during 2022 is anticipated. Distribution Substation Metering Substation monitoring and measurement of various electrical attributes were identified as a necessity due to the increasing complexity of distribution planning driven by growing levels of primarily solar generation as distributed energy resources. Enhanced measurements improve PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 120 visibility into loading levels and generation hosting capacity as well as load shapes, customer usage patterns, and information about reliability and power quality events. In 2017, an advanced substation metering project was initiated to provide an affordable option for gathering required substation and circuit data at locations where SCADA is unavailable and/or uneconomical. SCADA has been the preferred form of gathering load profile data from distribution circuits, however SCADA systems can be expensive to install, and additional equipment is required to provide the data needed to perform distribution system and power quality analysis. When system data rather than data and control is important, SCADA is no longer the best option. Engineers require data to perform analysis of system loading and diagnose waveform and harmonics issues; the lack of data can inhibit accurate system evaluations. The substation metering project recognizes that system data has value independent of control and current system status. The advanced substation metering pilot is intended to provide an affordable option for gathering required distribution system data. The advanced substation metering project was intended to provide an affordable option for gathering required distribution system data. The Company’s work plan included: • Finalize installation of advanced substation meters at distribution substations and document installations • Ensure all substation meters installed as part of this program are enabled with remote communication capabilities • Refine a data management system (PQView) to automatically download, analyze and interpret data downloaded from all installed substation meters The advanced substation metering project enabled installation of enhanced monitors at more than fifty distribution circuits in the state of Utah. The Company also deployed PQView software, a data analytics tool that provides users with a refined view of power quality information gathered from substation meters. Distributed Energy Resources Energy Storage Systems In 2017, PacifiCorp filed the Energy Storage Potential Evaluation and Energy Storage Project proposal with the Public Utilities Commission or Oregon. This filing was in alignment with PacifiCorp’s strategy and vision regarding the expansion and integration of renewable technologies. The company proposed a utility-owned targeted energy storage system (ESS) pilot project. In 2019 PacifiCorp began project development and is progressing to build an ESS on a Hillview substation distribution circuit in Corvallis, Oregon. Due to issues finding a suitable location in Corvallis the company located a different location. The new location for the ESS is the Lakeport Substation in Klamath Falls. The intent of this project is to integrate the ESS into the existing distribution system with the capability and flexibility to potentially advance to a future micro grid system. Phase I of the project involves/involved installation of a single, utility-owned energy storage device to address historic outage characterization on a specific feeder, validate modeling through field test data, create a research platform and optimize energy storage controls and integration on the Company network. The Company contracted an owner’s engineer to aid in project development and is progressing on the Phase I project to build an ESS at the Oregon Institute of Technology PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 121 (OIT) on circuit SL49, fed from the Lakeport substation. The Company contracted Powin Energy to provide the ESS. The intent of this project is to integrate the ESS into the existing distribution system with the capability and flexibility to potentially provide renewables integration support with OIT’s solar generation. The minimum system size is: • Energy requirement of 6 MWh • Power requirement of 2 MW Phase II of the project involves/involved the addition of an additional energy storage device to pilot distributed storage, optimize use cases per Phase I results, explore tariff structure and ownership models and continue research. In 2020, PacifiCorp developed Community Resiliency programs in Oregon and California to expand customer and utility understanding of how the use of ESS equipment might increase the resilience of critical facilities. The initial pilot programs provided technical support and evaluation of potential options as well as grant funding for on-site battery storage systems. Over one dozen feasibility studies have been delivered across the service territory of the two states. Two ESS systems have been installed in California with a third approved; two grant submissions in Oregon are in the final stage of application approval. As part of the Company’s forthcoming first Clean Energy Plan (CEP) with the Oregon Public Utilities Commission. PacifiCorp presented a strawman proposal to expand the Oregon pilot into a larger program that could provide grant funding for the installation of solar as well as battery storage. The Program would continue to provide feasibility studies and technical support to interested facilities. The Company plans to elicit feedback on the proposal through CEP stakeholder channels and determine next steps by the end of 2023. The PacifiCorp filing with FERC covering optional generation interconnection study assumptions for stand-alone electric storage resources was approved on February 28, 2023 (section 38.1 of the Open Access Transmission Tariff). The use of real-world operating assumptions for electric storage resources should lead to a more efficient interconnection process. Demand Response In 2018, PacifiCorp transitioned to the automatic dispatch of the residential air conditioner (A/C) program in Utah, utilizing two-way communication devices to respond to frequency dispatch signals. Known as Cool Keeper this frequency dispatch innovation is a grid-scale solution using fast-acting residential demand response resources to support the bulk power system. Some utilities use generating resources to perform this function, but as higher levels of wind and solar resources are added, additional balancing resources are required. The Cool Keeper system provides over 200 MWs of operating reserves to the system through the control of more than 108,000 A/C units. In 2021, PacifiCorp released a Request for Proposals for Demand Response resources. The Company has used the responses to incorporate the cost of Demand Response programs more accurately in the 2021 Integrated Resource Plan. In 2022 and 2023, PacifiCorp contracted with vendors solicited during the demand response RFP and filed for programs in Oregon, Washington, Idaho, Utah, and Wyoming. These programs included new Irrigation and Commercial and Industrial curtailment programs. Dispatchable Customer Storage Resources Based on the learnings from Rocky Mountain Power’s partnership with Soleil Lofts and Sonnen in 2018, the company developed the wattsmart Battery Program which was approved in Utah October 2020 and in Idaho April 2022. This innovative demand response program allows the PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 122 Company to manager behind the meter customer batteries for daily load cycling, backup power real time grid needs such as peak load management, contingency reserves, and frequency response. Customer controlled batteries will allow the company to maximize renewable energy when it’s needed to support the electrical gird. The program is experiencing exponential growth and has over 2,700 residential batteries and 8 commercial batteries participating as of Q1 2023. Advanced Metering Infrastructure Advanced metering infrastructure (AMI) is an integrated system of smart meters, communications networks, and data management systems that provide interval data available daily. This infrastructure can also provide advanced functionalities including remote connect/disconnect, outage detection and restoration signals, and support distribution automation schemes. In 2016, PacifiCorp identified economical AMI solutions for California and Oregon that delivered tangible benefits to customers while minimizing the impact on consumer rates. In 2019, PacifiCorp completed installation of the Itron Gen5 AMI system across the Company’s Oregon and California service territories. The AMI system consists of head-end software, FANs and approximately 656,000 meters. Interval energy usage data is provided to customers via the Pacific Power website and mobile app. The project was completed on schedule and on budget. In 2018, PacifiCorp awarded a contract to Itron for their OpenWay Riva AMI system in the states of Idaho and Utah. In early 2020, Itron proposed a change for the information technology (IT) and network systems, using their Gen5 system rather than the OpenWay system, while still deploying the more advanced Riva meter technology. Itron’s Gen5 system has the same IT and network used in PacifiCorp’s Oregon and California service territories. This solution aligns with Itron’s future road map and provides PacifiCorp with a single operational system that will reduce cybersecurity issues and operating costs associated with maintaining separate systems. This solution provides a stronger, more flexible network coupled with a high-end metering solution. The Utah/Idaho project involves upgrading the head-end software and installation of the Field Area Network (FAN) and approximately 240,000 new Itron Riva AMI meters for most customer classification and 20,000 Aclara AMI meters for the Utah rate schedule 136 private generation accounts. This solution will utilize over 80% of the existing AMR meters in Utah to provide hourly interval data for residential customers as well as outage detection and restoration messaging. The project will replace all current meters in Idaho with new Itron Riva AMI meters as AMR was not fully deployed there. Furthermore, the project will leverage the customer communication tools developed for the Oregon and California AMI projects. Meter and FAN system installations in Idaho are substantially complete. Utah FAN and meter installations are underway with completion scheduled for Q4 2023. Costs and benefits associated with the AMI project will be tracked and analyzed and will be evaluated against the business case projections after completion. Financial analyses to extend AMI solutions to Washington and Wyoming were performed in 2019 and 2020, respectively. The analyses determined that moving these states to an AMI solution was PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 123 not cost effective at this time. The Company is currently updating the business case for both states. The review should be completed by Q2 2023. Financial analyses to extend AMI solutions to Washington and Wyoming were performed in 2019 and 2020, respectively. These states utilize the same AMR meter technology as Utah and can be leveraged to provide extended functionality and value. The analyses determined that moving these states to an AMI solution is not cost effective at this time but has improved slightly over previous analyses. The Company will continue to review and evaluate the business case and cost effectiveness for these states routinely over the next few years. Outage Management Improvements PacifiCorp advanced a new module in its OMS which allows for field responders to update outage data as they complete their work, using Mobile Workforce Management tools; this functionality is restricted to service transformer and customer meter devices, which comprise approximately half of the outages to which the company responds. This ensures more rapid, accurate and efficient updates to outage data, but still maintains the OMS topology as the method to manage line worker safety by having real-time access to elements that are energized and those which may be in an abnormal state. Meter pinging and last-gasp outage management functionalities were put in place for the AMI system in Oregon and California. The same outage management systems (OMS) will be used for Utah and Idaho when those projects are complete. Company’s system operations organization has begun using meter ping functionality and last-gasp messages to augment customer calls and create outage tickets in the Company’s OMS. The Company implemented business process changes to facilitate outage management functionality for single service as well as large-scale outages. These changes have provided the system operations with more flexibility to identify and respond to outages. The intelligent line sensors will be installed on distribution circuits that will provide service to critical facilities. For this project, critical facilities have been defined as major emergency facility centers such as hospitals, trauma centers, police, and fire dispatch centers, etc. The information provided by the line sensors will allow control center operators to target restoration at critical facilities during major outages sooner than is currently possible. Full implementation of the project is was completed in December 2021, concurrent with the completion of the AMI project. Future Smart Grid The Company continues to develop a strategy to attain long-term goals for grid modernization and smart grid-related activities to continually improve system efficiency, reliability, and safety, while providing a cost-effective service to our customers. The Company will continue to monitor smart grid technologies and determine viability and applicability of implementation to the system, and as tipping points to broader implementation occur it’s expected these will be communicated through a variety of methods, including this IRP as well as other regulatory mechanisms relevant to that state. PACIFICORP – 2023 IRP APPENDIX E – SMART GRID 124 PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 125 APPENDIX F – FLEXIBLE RESERVE STUDY Introduction While PacifiCorp had significant increases in both wind and solar capacity on its system in 2021, there has not yet been time to collect and assess sufficient historical data that includes this expanded output. Therefore, for the 2023 IRP, PacifiCorp is continuing to use the methodology developed in its 2021 Flexible Reserve Study (FRS), which relied upon historical data from 2018-2019, as discussed below.1 The 2021 Flexible Reserve Study (FRS) estimated the regulation reserve required to maintain PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation (NERC) reliability standards. Because the FRS methodology accounts for changes in PacifiCorp’s resource mix, both the quantity and cost of reserves has been updated for the 2023 IRP, as reported herein. PacifiCorp operates two balancing authority areas (BAAs) in the Western Electricity Coordinating Council (WECC) NERC region--PacifiCorp East (PACE) and PacifiCorp West (PACW). The PACE and PACW BAAs are interconnected by a limited amount of transmission across a third-party transmission system and the two BAAs are each required to comply with NERC standards. PacifiCorp must provide sufficient regulation reserve to remain within NERC’s balancing authority area control error (ACE) limit in compliance with BAL-001-2,2 as well as the amount of contingency reserve required to comply with NERC standard BAL-002-WECC-2.3 BAL-001-2 is a regulation reserve standard that became effective July 1, 2016, and BAL-002-WECC-3 is a contingency reserve standard that became effective June 28, 2021. Regulation reserve and contingency reserve are components of operating reserve, which NERC defines as “the capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages and local area protection.”4 Apart from disturbance events that are addressed through contingency reserve, regulation reserve is necessary to compensate for changes in load demand and generation output to maintain ACE within mandatory parameters established by the BAL-001-2 standard. The FRS estimates the amount of regulation reserve required to manage variations in load, variable energy resources5 1 2021 IRP Volume II, Appendix F (Flexible Reserve Study): https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20II%20-%209.15.2021%20Final.pdf 2 NERC Standard BAL-001-2, https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-001-2.pdf, which became effective July 1, 2016. ACE is the difference between a BAA’s scheduled and actual interchange and reflects the difference between electrical generation and Load within that BAA. 3 NERC Standard BAL-002-WECC-3, https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-002-WECC-3.pdf, which became effective June 28, 2021. BAL-002-WECC-3 removed the requirement that at least 50% of contingency reserves be held as “spinning” resources, as this was deemed redundant with frequency response requirements under BAL-003-2. 4 Glossary of Terms Used in NERC Reliability Standards: https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf, updated March 8, 2023. 5 VERs are resources that resources that: (1) are renewable; (2) cannot be stored by the facility owner or operator; and (3) have variability that is beyond the control of the facility owner or operator. Integration of Variable Energy PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 126 (VERs), and resources that are not VERs (“Non-VERs”) in each of PacifiCorp’s BAAs. Load, wind, solar, and Non-VERs were each studied because PacifiCorp’s data indicates that these components or customer classes place different regulation reserve burdens on PacifiCorp’s system due to differences in the magnitude, frequency, and timing of their variations from forecasted levels. The FRS is based on PacifiCorp operational data recorded from January 2018 through December 2019 for load, wind, solar, and Non-VERs. PacifiCorp’s primary analysis focuses on the actual variability of load, wind, solar, and Non-VERs during 2018-2019. A supplemental analysis discusses how the total variability of the PacifiCorp system changes with varying levels of wind and solar capacity. The estimated regulation reserve amounts determined in this study represent the incremental capacity needed to ensure compliance with BAL-001-2 for a particular operating hour. The regulation reserve requirement covers variations in load, wind, solar, and Non-VERs, while implicitly accounting for the diversity between the different classes. An explicit adjustment is also made to account for diversity benefits realized because of PacifiCorp’s participation in the Energy Imbalance Market (EIM) operated by the California Independent System Operator Corporation (CAISO). The methodology in the FRS is like that employed in PacifiCorp’s 2019 IRP but has been enhanced in two areas.6 First, the historical period evaluated in the study has been expanded to include two years, rather than one, to capture a larger sample of system conditions. Second, the methodology for extrapolating results for higher renewable resource penetration levels has been modified to better capture the diversity between growing wind and solar portfolios. The FRS results produce an hourly forecast of the regulation reserve requirements for each of PacifiCorp’s BAAs that is sufficient to ensure the reliability of the transmission system and compliance with NERC and WECC standards. This regulation reserve forecast covers the combined deviations of the load, wind, solar and Non-VERs on PacifiCorp’s system and varies as a function of the wind and solar capacity on PacifiCorp’s system, as well as forecasted levels of wind, solar and load. The regulation reserve requirement methodologies produced by the FRS are applied in production cost modeling to determine the cost of the reserve requirements associated with incremental wind and solar capacity. After a portfolio is selected, the regulation reserve requirements specific to that portfolio can be calculated and included in the study inputs, such that the production cost impact of the requirements is incorporated in the reported results. As a result, this production cost impact is dependent on the wind and solar resources in the portfolio as well as the characteristics of the dispatchable resources in the portfolio that are available to provide regulation reserves. Resources, Order No. 764, 139 FERC ¶ 61,246 at P 281 (2012) (“Order No. 764”); order on reh’g, Order No. 764-A, 141 FERC ¶ 61,232 (2012) (“Order No. 764-A”); order on reh’g and clarification, Order No. 764-B, 144 FERC ¶ 61,222 at P 210 (2013) (“Order No. 764-B”). 6 2019 IRP Volume II, Appendix F (Flexible Reserve Study): https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2019_IRP_Volume_II_Appendices_A-L.pdf PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 127 Overview The primary analysis in the FRS is to estimate the regulation reserve necessary to maintain compliance with NERC Standard BAL-001-2 given a specified portfolio of wind and solar resources. The FRS next calculates the cost of holding regulation reserve for incremental wind and solar resources. Finally, the FRS compares PacifiCorp’s overall operating reserve requirements over the IRP study period, including both regulation reserve and contingency reserve, to its flexible resource supply. The FRS estimates regulation reserve based on the specific requirements of NERC Standard BAL-001-2. It also incorporates the current timeline for EIM market processes, as well as EIM resource deviations and diversity benefits based on actual results. The FRS also includes adjustments to regulation reserve requirements to account for the changing portfolio of solar and wind resources on PacifiCorp’s system and accounts for the diversity of using a single portfolio of regulation reserve resources to cover variations in load, wind, solar, and Non-VERs. A comparison of the results of the current analysis and that from previous IRPs is shown in Table F.1Table F.1 and Table F.2Table F.2. Flexible resource costs are portfolio dependent and vary over time. For more details, please refer to Figure F.11 – Incremental Wind and Solar Regulation Reserve CostsFigure F.11 – Incremental Wind and Solar Regulation Reserve Costs. Table F.1 - Portfolio Regulation Reserve Requirements Wind Capacity Solar Capacity Stand-alone Regulation Requirement Portfolio Diversity Credit Regulation Requirement with Diversity Case (MW) MW (MW) (%) (MW) CY2017 (2019 FRS) 2,750 1,021 994 47% 531 2018-2019 (2021 FRS) 2,745 1,080 1,057 49% 540 Table F.2 - 2023 Flexible Resource Costs as Compared to 2021 Costs, $/MWh Wind 2023 FRS Solar 2023 FRS Wind 2021 FRS Solar 2021 FRS (2022$) (2022$) (2022$) (2022$) Study Period 2025-2042 2025-2042 2023-2040 2023-2040 Flexible Resource Cost $1.2015 $1.4849 $1.58 $1.32 Flexible Resource Requirements PacifiCorp’s flexible resource needs are the same as its operating reserve requirements over the planning horizon for maintaining reliability and compliance with NERC regional reliability standards. Operating reserve generally consists of three categories: (1) contingency reserve (i.e., spinning, and supplemental reserve), (2) regulation reserve, and (3) frequency response reserve. Contingency reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC regional reliability standard BAL-002-WECC-3.7 Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC Control Performance Criteria in 7 NERC Standard BAL-002-WECC-3 – Contingency Reserve: https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-002-WECC-3.pdf PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 128 BAL-001-2.8 Frequency response reserve is capacity that PacifiCorp holds available to ensure compliance with NERC standard BAL-003-2.9 Each type of operating reserve is further defined below. Contingency Reserve Purpose: Contingency reserve may be deployed when unexpected outages of a generator or a transmission line occur. Contingency reserve may not be deployed to manage other system fluctuations such as changes in load or wind generation output. Volume: NERC regional reliability standard BAL-002-WECC-3 specifies that each BAA must hold as contingency reserve an amount of capacity equal to three percent of load and three percent of generation in that BAA. Duration: Except within 60 minutes of a qualifying contingency event, a BAA must maintain the required level of contingency reserve at all times. Generally, this means that up to 60 minutes of generation are required to provide contingency reserve, though successive outage events may result in contingency reserves being deployed for longer periods. To restore contingency reserves, other resources must be deployed to replace any generating resources that experienced outages, typically either market purchases or generation from resources with slower ramp rates. Ramp Rate: Only up capacity available within ten minutes can be counted as contingency reserve. This can include “spinning” resources that are online and immediately responsive to system frequency deviations to maintain compliance with frequency response obligations under BAL- 003-1.1, as well as from “non-spinning” resources that do not respond immediately, though they must still be fully deployed in ten minutes.10 Regulation Reserve Purpose: NERC standard BAL-001-2, which became effective July 1, 2016, does not specify a regulation reserve requirement based on a simple formula, but instead requires utilities to hold sufficient reserve to meet specified control performance standards. The primary requirement relates to area control error (“ACE”), which is the difference between a BAA’s scheduled and actual interchange and reflects the difference between electrical generation and load within that BAA. Requirement 2 of BAL-001-2 defines the compliance standard as follows: Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more than 30 consecutive clock-minutes… 8 NERC Standard BAL-001-2 – Real Power Balancing Control Performance: https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-001-2.pdf 9 NERC Standard BAL-003-2 — Frequency Response and Frequency Bias Setting: https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-003-2.pdf 10 While the minimum spinning reserve obligation previously contained within BAL-002-WECC-2a was retired due to redundancy with frequency response obligations under BAL-003-2, PacifiCorp’s 2023 IRP does not explicitly model the frequency response obligation and retains the spinning obligation to ensure a supply of rapidly responding resources is maintained. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 129 In addition, Requirement 1 of BAL-001-2 specifies that PacifiCorp’s Control Performance Standard 1 (“CPS1”) score must be greater than equal to 100 percent for each preceding 12 consecutive calendar month period, evaluated monthly. The CPS1 score compares PacifiCorp’s ACE with interconnection frequency during each clock minute. A higher score indicates PacifiCorp’s ACE is helping interconnection frequency, while a lower score indicates it is hurting interconnection frequency. Because CPS1 is averaged and evaluated monthly, it does not require a response to every ACE event, but rather requires that PacifiCorp meet a minimum aggregate level of performance in each month. Regulation reserve is thus the capacity that PacifiCorp holds available to respond to changes in generation and load to manage ACE within the limits specified in BAL-001-2. Volume: NERC standard BAL-001-2 does not specify a regulation reserve requirement based on a simple formula, but instead requires utilities to hold sufficient reserve to meet performance standards as discussed above. The FRS estimates the regulation reserve necessary to meet Requirement 2 by compensating for the combined deviations of the load, wind, solar and Non- VERs on PacifiCorp’s system. These regulation reserve requirements are discussed in more detail later in the study. Ramp Rate: Because Requirement 2 includes a 30-minute time limit for compliance, ramping capability that can be deployed within 30 minutes contributes to meeting PacifiCorp’s regulation reserve requirements. The reserve for CPS1 is not expected to be incremental to the need for compliance with Requirement 2 but may require that a subset of resources held for Requirement 2 be able to make frequent rapid changes to manage ACE relative to interconnection frequency. Duration: PacifiCorp is required to submit balanced load and resource schedules as part of its participation in EIM. PacifiCorp is also required to submit resources with up flexibility and down flexibility to cover uncertainty and expected ramps across the next hour. Because forecasts are submitted prior to the start of an hour, deviations can begin before an hour starts. As a result, a flexible resource might be called upon for the entire hour. To continue providing flexible capacity in the following hour, energy must be available in storage for that hour as well. The likelihood of deploying for two hours or more for reliability compliance (as opposed to economics) is expected to be small. Frequency Response Reserve Purpose: NERC standard BAL-003-2 specifies that each BAA must arrest frequency deviations and support the interconnection when frequency drops below the scheduled level. When a frequency drop occurs because of an event, PacifiCorp will deploy resources that increase the net interchange of its BAAs and the flow of generation to the rest of the interconnection. Volume: When a frequency drop occurs, each BAA is expected to deploy resources that are at least equal to its frequency response obligation. The incremental requirement is based on the size of the frequency drop and the BAA’s frequency response obligation, expressed in megawatt (MW)/0.1 Herts (Hz). To comply with the standard, a BAA’s median measured frequency response during a sampling of under-frequency events must be equal to or greater than its frequency response obligation. PacifiCorp’s 2022 frequency response obligation was 25.3 PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 130 MW/0.1Hz for PACW, and 63.5 MW/0.1Hz for PACE.11 PacifiCorp’s combined obligation amounts to 88.8 MW for a frequency drop of 0.1 Hz, or 266.4 MW for a frequency drop of 0.3 Hz. The performance measurement for contingency reserve under the Disturbance Control Standard (BAL-002-3)12, allows for recovery to the lesser of zero or the ACE value prior to the contingency event, so increasing ACE above zero during a frequency event reduces the additional deployment needed if a contingency event occurs. Because contingency, regulation, and frequency events are all relatively infrequent, they are unlikely to occur simultaneously. Because the frequency response standard is based on median performance during a year, overlapping requirements that reduced PacifiCorp’s response during a limited number of frequency events would not impact compliance. As a result, any available capacity not being used for generation is expected to contribute to meeting PacifiCorp’s frequency response obligation, up to the technical capability of each unit, including that designated as contingency or regulation reserves. Frequency response must occur very rapidly, and a generating unit’s capability is limited based on the unit’s size, governor controls, and available capacity, as well as the size of the frequency drop. As a result, while a few resources could hold a large amount of contingency or regulation reserve, frequency response may need to be spread over a larger number of resources. Additionally, only resources that have active and tuned governor controls as well as outer loop control logic will respond properly to frequency events. Ramp Rate: Frequency response performance is measured over a period of seconds, amounting to under a minute. Compliance is based on the average response over the course of an event. As a result, a resource that immediately provides its full frequency response capability will provide the greatest contribution. That same resource will contribute a smaller amount if it instead ramps up to its full frequency response capability over the course of a minute or responds after a lag. Duration: Frequency response events are less than one minute in duration. Black Start Requirements Black start service is the ability of a generating unit to start without an outside electrical supply and is necessary to help ensure the reliable restoration of the grid following a blackout. At this time, PACW grid restoration would occur in coordination with Bonneville Power Administration black start resources. The Gadsby combustion turbine resources can support grid restoration in PACE. PacifiCorp has not identified any incremental needs for black start service during the IRP study period. Ancillary Services Operational Distinctions In actual operations, PacifiCorp identifies two types of flexible capacity as part of its participation in the EIM. The contingency reserve held on each resource is specifically identified and is not 11 NERC. BAL-003-2 Frequency Response Obligation Allocation and Minimum Frequency Bias Settings for Operating Year 2022. https://www.nerc.com/comm/OC/RS%20Landing%20Page%20DL/Frequency%20Response%20Standard%20Resources/BA_FRO_Allocations_for_OY2022-document(002).pdf 12 NERC Standard BAL-002-3 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event: https://www.nerc.com/pa/Stand/Reliability Standards/BAL-002-3.pdf PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 131 available for economic dispatch within the EIM. Any remaining flexible capacity on participating resources that is not designated as contingency reserve can be economically dispatched in EIM based on its operating cost (i.e. bid) and system requirements and can contribute to meeting regulation reserve obligations. Because of this distinction, resources must either be designated as contingency reserve or as regulation reserve. Contingency events are relatively rare while opportunities to deploy additional regulation reserve in EIM occur frequently. As a result, PacifiCorp typically schedules its lowest-cost flexible resources to serve its load and blocks off capacity on its highest-cost flexible resources to meet its contingency obligations, subject to any ramping limitations at each resource. This leaves resources with moderate costs available for dispatch up by EIM, while lower-cost flexible resources remain available to be dispatched down by EIM. Regulation Reserve Data Inputs Overview This section describes the data used to determine PacifiCorp’s regulation reserve requirements. To estimate PacifiCorp’s required regulation reserve amount, PacifiCorp must determine the difference between the expected load and resources and actual load and resources. The difference between load and resources is calculated every four seconds and is represented by the ACE. ACE must be maintained within the limits established by BAL-001-2, so PacifiCorp must estimate the amount of regulation reserve that is necessary to maintain ACE within these limits. To estimate the amount of regulation reserve that will be required in the future, the FRS identifies the scheduled use of the system as compared to the actual use of the system during the study term. For the baseline determination of scheduled use for load and resources, the FRS used hourly base schedules. Hourly base schedules are the power production forecasts used for imbalance settlement in the EIM and represent the best information available concerning the upcoming hour.13 The deviation from scheduled use was derived from data provided through participation in the EIM. The deviations of generation resources in EIM were measured on a five-minute basis, so five-minute intervals are used throughout the regulation reserve analysis. EIM base schedule and deviation data for each wind, solar and Non-VER transaction point were downloaded using the SettleCore application, which is populated with data provided by the CAISO. Since PacifiCorp’s implementation of EIM on November 1, 2014, PacifiCorp requires certain operational forecast data from all its transmission customers pursuant to the provisions of Attachment T to PacifiCorp’s Federal Energy Regulatory Commission (FERC) approved Open 13 The CAISO, as the market operator for the EIM, requests base schedules at 75 minutes (T-75) prior to the hour of delivery. PacifiCorp’s transmission customers are required to submit base schedules by 77 minutes (T-77) prior to the hour of delivery – two minutes in advance of the EIM Entity deadline. This allows all transmission customer base schedules enough time to be submitted into the EIM systems before the overall deadline of T-75 for the entirety of PacifiCorp’s two BAAs. The base schedules are due again to CAISO at 55 minutes (T-55) prior to the delivery hour and can be adjusted up until that time by the EIM Entity (i.e., PacifiCorp Grid Operations). PacifiCorp’s transmission customers are required to submit updated, final base schedules no later than 57 minutes (T-57) prior to the delivery hour. Again, this allows all transmission customer base schedules enough time to be submitted into the EIM systems before the overall deadline of T-55 for the entirety of PacifiCorp’s two BAAs. Base schedules may be finally adjusted again, by the EIM Entity only, at 40 minutes (T-40) prior to the delivery hour in response to CAISO sufficiency tests. T-40 is the base schedule time point used throughout this study. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 132 Access Transmission Tariff (OATT). This includes EIM base schedule data (or forecasts) from all resources included in the EIM network model at transaction points. EIM base schedules are submitted by transmission customers with hourly granularity, and are settled using hourly data for load, and fifteen-minute and five-minute data for resources. A primary function of the EIM is to measure load and resource imbalance (or deviations) as the difference between the hourly base schedule and the actual metered values. A summary of the data gathered for this analysis is listed below, and a more detailed description of each type of source data is contained in the following subsections. Source data: - Load data o Five-minute interval actual load o Hourly base schedules - VER data o Five-minute interval actual generation o Hourly base schedules - Non-VER data o Five-minute interval actual generation o Hourly base schedules Load Data The load class represents the aggregate firm demand of end users of power from the electric system. While the requirements of individual users vary, there are diurnal and seasonal patterns in aggregated demand. The load class can generally be described to include three components: (1) average load, which is the base load during a particular scheduling period; (2) the trend, or “ramp,” during the hour and from hour-to-hour; and (3) the rapid fluctuations in load that depart from the underlying trend. The need for a system response to the second and third components is the function of regulation reserve in order to ensure reliability of the system. The PACE BAA includes several large industrial loads with unique patterns of demand. Each of these loads is either interruptible at short notice or includes behind the meter generation. Due to their large size, abrupt changes in their demand are magnified for these customers in a manner which is not representative of the aggregated demand of the large number of small customers which make up most PacifiCorp’s loads. In addition, interruptible loads can be curtailed if their deviations are contributing to a resource shortfall. Because of these unique characteristics, these loads are excluded from the FRS. This treatment is consistent with that used in the CAISO load forecast methodology (used for PACE and PACW operations), which also nets these interruptible customer loads out of the PACE BAA. Actual average load data was collected separately for the PACE and PACW BAAs for each five-minute interval. Load data has not been adjusted for transmission and distribution losses. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 133 Wind and Solar Data The wind and solar classes include resources that: (1) are renewable; (2) cannot be stored by the facility owner or operator; and (3) have variability that is beyond the control of the facility owner or operator.14 Wind and solar, in comparison to load, often have larger upward and downward fluctuations in output that impose significant and sometimes unforeseen challenges when attempting to maintain reliability. For example, as recognized by FERC in Order No. 764, “Increasing the relative amount of [VERs] on a system can increase operational uncertainty that the system operator must manage through operating criteria, practices, and procedures, including the commitment of adequate reserves.”15 The data included in the FRS for the wind and solar classes include all wind and solar resources in PacifiCorp’s BAAs, which includes: (1) third-party resources (OATT or legacy contract transmission customers); (2) PacifiCorp-owned resources; and (3) other PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and exchanges. In total, the FRS study period includes an average of 2,745 megawatts of wind and 1,080 megawatts of solar. Non-VER Data The Non-VER class is a mix of thermal and hydroelectric resources and includes all resources which are not VERs, and which do not provide either contingency or regulation reserve. Non-VERs, in contrast to VERs, are often more stable and predictable. Non-VERs are thus easier to plan for and maintain within a reliable operating state. For example, in Order No. 764, FERC suggested that many of its rules were developed with Non-VERs in mind and that such generation “could be scheduled with relative precision.”16The output of these resources is largely in the control of the resource operator, particularly when considered within the hourly timeframe of the FRS. The deviations by resources in the Non-VER class are thus significantly lower than the deviations by resources in the wind class. The Non-VER class includes third-party resources (OATT or legacy transmission customers); many PacifiCorp-owned resources; and other PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and exchanges. In total, the FRS includes 2,202 megawatts of Non-VERs. In the FRS, resources that provide contingency or regulation reserve are considered a separate, dispatchable resource class. The dispatchable resource class compensates for deviations resulting from other users of the transmission system in all hours. While non-dispatchable resources may offset deviations in loads and other resources in some hours, they are not in the control of the system operator and contribute to the overall requirement in other hours. Because the dispatchable resource class is a net provider rather than a user of regulation reserve service, its stand-alone regulation reserve requirement is zero (or negative), and its share of the system regulation reserve requirement is also zero. The allocation of regulation reserve requirements and diversity benefits is discussed in more detail later in the study. 14 Order No. 764 at P 281; Order No. 764-B at P 210. 15 Order No. 764 at P 20 (emphasis added). 16 Id. at P 92. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 134 Regulation Reserve Data Analysis and Adjustment Overview This section provides details on adjustments made to the data to align the ACE calculation with actual operations, and address data issues. Base Schedule Ramping Adjustment In actual operations, PacifiCorp’s ACE calculation includes a linear ramp from the base schedule in one hour to the base schedule in the next hour, starting ten-minutes before the hour and continuing until ten-minutes past the hour. The hourly base schedules used in the study are adjusted to reflect this transition from one hour to the next. This adjustment step is important because, to the extent actual load or generation is transitioning to the levels expected in the next hour, the adjusted base schedules will result in reduced deviations during these intervals, potentially reducing the regulation reserve requirement. Figure F.1Figure F.1 below illustrates the hourly base schedule and the ramping adjustment. The same calculation applies to all base schedules: Load, Wind, Non-VERs, and the combined portfolio. Figure F.1 - Base Schedule Ramping Adjustment Data Corrections The data extracted from PacifiCorp’s systems for, wind, solar and Non-VERs was sourced from 2300 2400 2500 2600 2700 2800 2900 3000 3100 4: 4 5 4: 5 0 4: 5 5 5: 0 0 5: 0 5 5: 1 0 5: 1 5 5: 2 0 5: 2 5 5: 3 0 5: 3 5 5: 4 0 5: 4 5 5: 5 0 5: 5 5 6: 0 0 6: 0 5 6: 1 0 6: 1 5 6: 2 0 6: 2 5 6: 3 0 6: 3 5 6: 4 0 6: 4 5 6: 5 0 6: 5 5 7: 0 0 7: 0 5 7: 1 0 7: 1 5 Ba s e S c h e d u l e ( M W h ) Time Base Schedule Adjusted Base Schedule PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 135 CAISO settlement quality data. This data has already been verified for inconsistencies as part of the settlement process and needs minimal cleaning as described below. Regarding five-minute interval load data from the PI Ranger system, intervals were excluded from the FRS results if any five-minute interval suffered from at least one of the data anomalies that are described further below: Load: • Telemetry spike/poor connection to meter • Missing meter data • Missing base schedules VERs: • Curtailment events Load in PacifiCorp’s BAAs changes continuously. While a BAA could potentially maintain the exact same load levels in two five-minute intervals in a row, it is extremely unlikely for the exact same load level to persist over longer time frames. When PacifiCorp’s energy management system (EMS) load telemetry fails, updated load values may not be logged, and the last available load measurement for the BAA will continue to be reported. Rapid spikes in load telemetry either up or down are unlikely to be the result of conditions which require deployment of regulation reserve, particularly when they are transient. Such events could be a result of a transmission or distribution outage, which would allow for the deployment of contingency reserve, and would not require deployment of regulation reserve. Such events are also likely to be a result of a single bad load measurement. Load telemetry spike irregularities were identified by examining the intervals with the largest changes from one interval to the next, either up or down. Intervals with inexplicably large and rapid changes in load, particularly where the load reverts within a short period, were assumed to have been covered through contingency reserve deployment or to reflect inaccurate load measurements. Because they do not reflect periods that require regulation reserve deployment, such intervals are excluded from the analysis. During the study period, in PACW 15 minutes’ worth of telemetry spikes were excluded while no telemetry spikes were observed in PACE. There were also 10 minutes’ worth of missing load meter data, and 82 hours of missing load base schedules. The available VER data includes wind curtailment events which affect metered output. When these curtailments occur, the CAISO sends data, by generator, indicating the magnitude of the curtailment. This data is layered on top of the actual meter data to develop a proxy for what the metered output would have been if the generator were not curtailed. Regulation reserve requirements are calculated based on the shortfall in actual output relative to base schedules. By adding back curtailed volumes to the actual metered output, the shortfall relative to base schedules is reduced, as is the regulation reserve requirement. This is reasonable since the curtailment is directed by the CAISO or the transmission system operator to help maintain reliable operation, so it should not exacerbate the calculated need for regulation reserves. After review of the data for each of the above anomaly types, and out of 210,216 five-minute intervals evaluated, approximately 1,000 five-minute intervals, or 0.5% of the data, was removed due to data errors. While cleaning up or replacing anomalous hours could yield a more complete data set, determining the appropriate conditions in those hours would be difficult and subjective. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 136 By removing anomalies, the FRS sample is smaller but remains reflective of the range of conditions PacifiCorp experiences, including the impact on regulation reserve requirements of weather events experienced during the study period. Regulation Reserve Requirement Methodology Overview This section presents the methodology used to determine the initial regulation reserve needed to manage the load and resource balance within PacifiCorp’s BAAs. The five-minute interval load and resource deviation data described above informs a regulation reserve forecast methodology that achieves the following goals: - Complies with NERC standard BAL-001-2; - Minimizes regulation reserve held; and - Uses data available at time of EIM base schedule submission at T-40.17 The components of the methodology are described below, and include: - Operating Reserve: Reserve Categories; - Calculation of Regulation Reserve Need; - Balancing Authority ACE Limit: Allowed Deviations; - Planning Reliability Target: Loss of Load Probability (“LOLP”); and - Regulation Reserve Forecast: Amount Held. Following the explanation below of the components of the methodology, the next section details the forecasted amount of regulation reserve for: - Wind; - Solar; - Non-VERs; and - Load. Components of Operating Reserve Methodology Operating Reserve: Reserve Categories Operating reserve consists of three categories: (1) contingency reserve (i.e., spinning and supplemental reserve), (2) regulation reserve, and (3) frequency response reserve. These requirements must be met by resources that are incremental to those needed to meet firm system demand. The purpose of the FRS is to determine the regulation reserve requirement. The contingency reserve and frequency response requirements are defined formulaically by their respective reliability standards. Of the three categories of reserve referenced above, the FRS is primarily focused on the requirements associated with regulation reserve. Contingency reserve may not be deployed to manage other system fluctuations such as changes in load or wind generation output. Because deviations caused by contingency events are covered by contingency reserve rather than regulation 17 See footnote 12 above for explanation of PacifiCorp’s use of the T-40 base schedule time point in the FRS. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 137 reserve, they are excluded from the determination of the regulation reserve requirements. Because frequency response reserve can overlap with that held for contingency and regulation reserve requirements it is similarly excluded from the determination of regulation reserve requirements. The types of operating reserve and relationship between them are further defined in in the Flexible Resource Requirements section above. Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC Control Performance Criteria in BAL-001-2, which requires a BAA to carry regulation reserve incremental to contingency reserve to maintain reliability.18 The regulation reserve requirement is not defined by a simple formula, but instead is the amount of reserve required by each BAA to meet specified control performance standards. Requirement two of BAL-001-2 defines the compliance standard as follows: Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more than 30 consecutive clock-minutes… PacifiCorp has been operating under BAL-001-2 since March 1, 2010, as part of a NERC Reliability-Based Control field trial in the Western Interconnection, so PacifiCorp had experience operating under the standard, even before it became effective on July 1, 2016. The three key elements in BAL-001-2 are: (1) the length of time (or “interval”) used to measure compliance; (2) the percentage of intervals that a BAA must be within the limits set in the standard; and (3) the bandwidth of acceptable deviation used under each standard to determine whether an interval is considered out of compliance. These changes are discussed in further detail below. The first element is the length of time used to measure compliance. Compliance under BAL-001-2 is measured over rolling thirty-minute intervals, with 60 overlapping periods per hour, some of which include parts of two clock-hours. In effect, this means that every minute of every hour is the beginning of a new, thirty-minute compliance interval under the new BAL-001-2 standard. If ACE is within the allowed limits at least once in a thirty-minute interval, that interval is in compliance, so only the minimum deviation in each rolling thirty-minute interval is considered in determining compliance. As a result, PacifiCorp does not need to hold regulation reserve for deviations with duration less than 30 minutes. The second element is the number of intervals where deviations are allowed to be outside the limits set in the standard. BAL-001-2 requires 100 percent compliance, so deviations must be maintained within the requirement set by the standard for all rolling thirty-minute intervals. The third element is the bandwidth of acceptable deviation before an interval is considered out of compliance. Under BAL-001-2, the acceptable deviation for each BAA is dynamic, varying as a function of the frequency deviation for the entire interconnect. When interconnection frequency exceeds 60 Hz, the dynamic calculation does not require regulation resources to be deployed regardless of a BAA’s ACE. As interconnection frequency drops further below 60 Hz, a BAA’s permissible ACE shortfall is increasingly restrictive. 18 NERC Standard BAL-001-2, https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-001-2.pdf PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 138 Planning Reliability Target: Loss of Load Probability When conducting resource planning, it is common to use a reliability target that assumes a specified loss of load probability (LOLP). In effect, this is a plan to curtail firm load in rare circumstances, rather than acquiring resources for extremely unlikely events. The reliability target balances the cost of additional capacity against the benefit of incrementally more reliable operation. By planning to curtail firm load in the rare event of a regulation reserve shortage, PacifiCorp can maintain the required 100 percent compliance with the BAL-001-2 standard and the Balancing Authority ACE Limit. This balances the cost of holding additional regulation reserve against the likelihood of regulation reserve shortage events. The FRS assumes that a regulation reserve forecasting methodology that results in 0.50 loss of load hours per year due to regulation reserve shortages is appropriate for planning and ratemaking purposes. This is in addition to any loss of load resulting from transmission or distribution outages, resource adequacy, or other causes. The FRS applies this reliability target as follows: • If the regulation reserve available is greater than the regulation reserve need for an hour, the LOLP is zero for that hour. • If the regulation reserve held is less than the amount needed, the LOLP is derived from the Balancing Authority ACE Limit probability distribution as illustrated below. Balancing Authority ACE Limit: Allowed Deviations Even if insufficient regulation reserve capability is available to compensate for a thirty-minute sustained deviation, a violation of BAL-001-2 does not occur unless the deviation also exceeds the Balancing Authority ACE Limit. The Balancing Authority ACE Limit is specific to each BAA and is dynamic, varying as a function of interconnection frequency. When WECC frequency is close to 60 Hz, the Balancing Authority ACE Limit is large and large deviations in ACE are allowed. As WECC frequency drops further and further below 60 Hz, ACE deviations are increasingly restricted for BAAs that are contributing to the shortfall, i.e. those BAAs with higher loads than resources. A BAA commits a BAL-001-2 reliability violation if in any thirty-minute interval it does not have at least one minute when its ACE is within its Balancing Authority ACE Limit. While the specific Balancing Authority ACE Limit for a given interval cannot be known in advance, the historical probability distribution of Balancing Authority ACE Limit values is known. Figure F.2Figure F.2 below shows the probability of exceeding the allowed deviation during a five-minute interval for a given level of ACE shortfall. For instance, an 82 MW ACE shortfall in PACW has a one percent chance of exceeding the Balancing Authority ACE Limit. WECC-wide frequency can change rapidly and without notice, and this causes large changes in the Balancing Authority ACE Limit over short time frames. Maintaining ACE within the Balancing Authority ACE Limit under those circumstances can require rapid deployment of large amounts of operating reserve. To limit the size and speed of resource deployment necessitated by variation in the Balancing Authority ACE Limit, PacifiCorp’s operating practice caps permissible ACE at the lesser of the Balancing Authority ACE Limit or four times L10. This also limits the occurrence of PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 139 transmission flows that exceed path ratings as result of large variations in ACE.19,20 This cap is reflected in Figure F.2Figure F.2. Figure F.2 - Probability of Exceeding Allowed Deviation In 2018-2019, PacifiCorp’s deviations and Balancing Authority ACE Limits were uncorrelated, which indicates that PacifiCorp’s contribution to WECC-wide frequency is small. PacifiCorp’s deviations and Balancing Authority ACE Limits were also uncorrelated when periods with large deviations were examined in isolation. If PacifiCorp’s large deviations made distinguishable contributions to the Balancing Authority ACE Limit, ACE shortfalls would be more likely to exceed the Balancing Authority ACE Limit during large deviations. Since this is not the case, the probability of exceeding the Balancing Authority ACE Limit is lower, and less regulation reserve is necessary to comply with the BAL-001-2 standard. Regulation Reserve Forecast: Amount Held To calculate the amount of regulation reserve required to be held while being compliant with BAL-001-2 – using a LOLP of 0.5 hours per year or less – a quantile regression methodology was used. Quantile regression is a type of regression analysis. Whereas the typical method of ordinary least 19 “Regional Industry Initiatives Assessment.” NWPP MC Phase 3 Operations Integration Work Group. Dec. 31, 2014. Pg. 14. Available at: www.nwpp.org/documents/MC-Public/NWPP-MC-Phase-3-Regional-Industry-Initiatives-Assessment12-31-2014.pdf 20 “NERC Reliability-Based Control Field Trial Draft Report.” Western Electricity Coordinating Council. Mar. 25, 2015. Available at: www.wecc.biz/Reliability/RBC%20Field%20Trial%20Report%20Approved%203-25-2015.pdf 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0 25 50 75 100 125 150 175 200 225 Pr o b a b i l i t y o f E x c e e d i n g A l l o w e d D e v i a t i o n ( % ) ACE Shortfall (MW) Exceedance Probability (PACW)Exceedance Probability (PACE) PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 140 squares results in estimates of the conditional mean (50th percentile) of the response variable given certain values of the predictor variables, quantile regression aims at estimating other specified percentiles of the response variable. Eight regressions were prepared, one for each class (load/wind/solar/non-VER) and area (PACE/PACW). Each regression uses the following variables: • Response Variable: the error in each interval, in megawatts; • Predictor Variable: the forecasted generation or load in each interval, expressed as a percentage of area capacity; The forecasted generation or load in each interval used as the predictor variable contributes to the regression as a combination of linear, square, and higher order exponential effects. Specifically, the regression identifies coefficients that correspond to the following functions for each class: Load Error: Load Forecast1 + Constant Wind Error: Wind Forecast2 + Wind Forecast1 Solar Error: Solar Forecast4 + Solar Forecast3 + Solar Forecast2 + Solar Forecast1 Non-VER Error: Non-VER Forecast2 + Non-VER Forecast1 The instances requiring the largest amounts of regulation reserve occur infrequently, and many hours have very low requirements. If periods when requirements are likely to be low can be distinguished from periods when requirements are likely to be high, less regulation reserve is necessary to achieve a given reliability target. The regulation reserve forecast is not intended to compensate for every potential deviation. Instead, when a shortfall occurs, the size of that shortfall determines the probability of exceeding the Balancing Authority ACE Limit and a reliability violation occurring. The forecast is adjusted to achieve a cumulative LOLP that corresponds to the annual reliability target. Regulation Reserve Forecast Overview The following forecasts are polynomial functions that cover a targeted percentile of all historical deviations. These forecasts are stand-alone forecasts, based on the difference between hour-ahead base schedules and actual meter data, expressing the errors as a function of the level of forecast. The stand-alone reserve requirement shown achieves the annual reliability target of 0.5 hours per year, after accounting for the dynamic Balancing Authority ACE Limit. The combined diversity error system requirements are discussed later in the study. Figure F.3Figure F.3- Figure F.8Figure F.8 illustrate the relationship between the regulation reserve requirements during 2018-2019 and the forecasted level of output, for each resource class and control area. Both the regulation reserve requirements and the forecasted level of output are expressed as a percentage of resource nameplate (i.e., as a capacity factor). Figure F.9Figure F.9 and Figure F.10Figure F.10 illustrate the same relationship between the regulation reserve requirements during 2018-2019 and the forecasted load for each control area. Both the regulation reserve requirements and the forecasted load are expressed as a percentage of the annual peak load (i.e., as a load factor). PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 141 Figure F.3 - Wind Regulation Reserve Requirements by Forecast - PACE Figure F.4 - Wind Regulation Reserve Requirements by Forecast Capacity Factor - PACW PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 142 Figure F.5 - Solar Regulation Reserve Requirements by Forecast Capacity Factor - PACE Figure F.6 - Solar Regulation Reserve Requirements by Forecast Capacity Factor - PACW PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 143 Figure F.7 – Non-VER Regulation Reserve Requirements by Capacity Factor - PACE Figure F.8 – Non-VER Regulation Reserve Requirements by Capacity Factor - PACW PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 144 Figure F.9 – Stand-alone Load Regulation Reserve Requirements - PACE Figure F.10 – Stand-alone Load Regulation Reserve Requirements - PACW PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 145 The results of the analysis are shown in Table F.3Table F.3 below. Table F.3 – Summary of Stand-alone Regulation Reserve Requirements Stand-alone Regulation Capacity Stand-alone Regulation Scenario Forecast (aMW) (MW) Forecast (%) Non-VER 106 1,304 8.2% Load 334 10,094 3.3% VER - Wind 457 2,745 16.7% VER - Solar 159 1,080 14.8% Total 1,057 Portfolio Diversity and EIM Diversity Benefits The EIM is a voluntary energy imbalance market service through the CAISO where market systems automatically balance supply and demand for electricity every fifteen and five minutes, dispatching least-cost resources every five minutes. PacifiCorp and CAISO began full EIM operation on November 1, 2014. Several additional participants have since joined the EIM, and more participants are scheduled to join in the next several years. PacifiCorp’s participation in the EIM results in improved power production forecasting and optimized intra-hour resource dispatch. This brings important benefits including reduced energy dispatch costs through automatic dispatch, enhanced reliability with improved situational awareness, better integration of renewable energy resources, and reduced curtailment of renewable energy resources. The EIM also has direct effects related to regulation reserve requirements. First, because of EIM participation, PacifiCorp has improved data used in the analysis contained in this FRS. The data and control provided by the EIM allow PacifiCorp to achieve the portfolio diversity benefits described in the first part of this section. Second, the EIM’s intra-hour capabilities across the broader EIM footprint provide the opportunity to reduce the amount of regulation reserve necessary for PacifiCorp to hold, as further explained in the second part of this section. Portfolio Diversity Benefit The regulation reserve forecasts described above independently ensure that the probability of a reliability violation for each class remains within the reliability target; however, the largest deviations in each class tend not to occur simultaneously, and in some cases, deviations will occur in offsetting directions. Because the deviations are not occurring at the same time, the regulation reserve held can cover the expected deviations for multiple classes at once and a reduced total quantity of reserve is sufficient to maintain the desired level of reliability. This reduction in the reserve requirement is the diversity benefit from holding a single pool of reserve to cover deviations in Solar, Wind, Non-VERs, and Load. As a result, the regulation reserve forecast for the portfolio can be reduced while still meeting the reliability target. In the historical period, portfolio diversity from the interactions between the various classes results in a regulation reserve PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 146 requirement that is 36% lower than the sum of the stand-alone requirements, or approximately 679 MW. EIM Diversity Benefit In addition to the direct benefits from EIM’s increased system visibility and improved intra-hour operational performance described above, the participation of other entities in the broader EIM footprint provides the opportunity to further reduce the amount of regulation reserve PacifiCorp must hold. By pooling variability in load and resource output, EIM entities reduce the quantity of reserve required to meet flexibility needs. The EIM also facilitates procurement of flexible ramping capacity in the fifteen-minute market to address variability that may occur in the five-minute market. Because variability across different BAAs may happen in opposite directions, the flexible ramping requirement for the entire EIM footprint can be less than the sum of individual BAA requirements. This difference is known as the “diversity benefit” in the EIM. This diversity benefit reflects offsetting variability and lower combined uncertainty. This flexibility reserve (uncertainty requirement) is in addition to the spinning and supplemental reserve carried against generation or transmission system contingencies under the NERC standards. The CAISO calculates the EIM diversity benefit by first calculating an uncertainty requirement for each individual EIM BAA and then by comparing the sum of those requirements to the uncertainty requirement for the entire EIM area. The latter amount is expected to be less than the sum of the uncertainty requirements from the individual BAAs due to the portfolio diversification effect of forecasting a larger pool of load and resources using intra-hour scheduling and increased system visibility in the hypothetical, single-BAA EIM. Each EIM BAA is then credited with a share of the diversity benefit calculated by CAISO based on its share of the stand-alone requirement relative to the total stand-alone requirement. The EIM does not relieve participants of their reliability responsibilities. EIM entities are required to have sufficient resources to serve their load on a standalone basis each hour before participating in the EIM. Thus, each EIM participant remains responsible for all reliability obligations. Despite these limitations, EIM imports from other participating BAAs can help balance PacifiCorp’s loads and resources within an hour, reducing the size of reserve shortfalls and the likelihood of a Balancing Authority ACE Limit violation. While substantial EIM imports do occur in some hours, it is only appropriate to rely on PacifiCorp’s diversity benefit associated with EIM participation, as these are derived from the structure of the EIM rather than resources contributed by other participants. Table F.4Table F.4 below provides a numeric example of uncertainty requirements and application of the calculated diversity benefit. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 147 Table F.4 – EIM Diversity Benefit Application Example a b c d e =a+b+c+d f g = e-f h = g / e i = c * h j = c - i CAISO req't. before benefit NEVP req't. before benefit PACE req't. before benefit PACW req't. before benefit Total req't. before benefit Total req't. after benefit Total diversity benefit Diversity benefit ratio PACE benefit PACE req't. after benefit Hour (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 1 550 110 165 100 925 583 342 37.00% 61 104 2 600 110 165 100 975 636 339 34.80% 57 108 3 650 110 165 110 1,035 689 346 33.40% 55 110 4 667 120 180 113 1,080 742 338 31.30% 56 124 While the diversity benefit is uncertain, that uncertainty is not significantly different from the uncertainty in the Balancing Authority ACE Limit previously described. In the FRS, PacifiCorp has credited the regulation reserve forecast based on a historical distribution of calculated EIM diversity benefits. While this FRS considers regulation reserve requirements in 2018-2019, the CAISO identified an error in their calculation of uncertainty requirements in early 2018. CAISO’s published uncertainty requirements and associated diversity benefits are now only valid for March 2018 forward. To capture these additional benefits for this analysis, PacifiCorp has applied the historical distribution of EIM diversity benefits from the 12 months beginning March 2018. In the historical study period, EIM diversity benefits used in the FRS would have reduced regulation reserve requirements by approximately 140 MW. The inclusion of EIM diversity benefits in the FRS reduces the magnitude, and thus probability, of reserve shortfalls and, in doing so, reduces the overall regulation reserve requirement. This allows PacifiCorp’s forecasted requirements to be reduced. As shown in Table F.5Table F.5 below, the resulting regulation reserve requirement is 540 MW, which is a 49 percent reduction (including the portfolio diversity benefit) compared to the stand-alone requirement for each class. This portfolio regulation forecast is expected to achieve an LOLP of 0.5 hours per year. Table F.5 – 2018-2019 Results with Portfolio Diversity and EIM Diversity Benefits Stand-alone Regulation Forecast Stand-alone Rate Portfolio Regulation Forecast w/EIM Portfolio Rate Capacity Rate Scenario (aMW) (%) (aMW) (%) (MW) Determinant Non-VER 106 8.2% 55 4.2% 1,304 Nameplate Load 334 3.3% 172 1.7% 10,094 12 CP VER - Wind 457 16.7% 237 8.6% 2,745 Nameplate VER - Solar 159 14.8% 76 7.1% 1,080 Nameplate Total 1,057 540 Formatted: Font: Not Bold PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 148 Fast-Ramping Reserve Requirements As previously discussed, Requirement 1 of BAL-001-2 specifies that PacifiCorp’s CPS1 score must be greater than equal to 100 percent for each preceding 12 consecutive calendar month period, evaluated monthly. The CPS1 score compares PacifiCorp’s ACE with interconnection frequency during each clock minute. A higher score indicates PacifiCorp’s ACE is helping interconnection frequency, while a lower score indicates it is hurting interconnection frequency. Because CPS1 is averaged and evaluated on a monthly basis, it does not require a response to each and every ACE event, but rather requires that PacifiCorp meet a minimum aggregate level of performance in each month. The Regulation Reserve Forecast described above is evaluating requirements for extreme deviations that are at least 30 minutes in duration, for compliance with Requirement 2 of BAL- 001-2. In contrast, compliance with CPS1 requires reserve capability to compensate for most conditions over a minute-to-minute basis. These fast-ramping resources would be deployed frequently and would also contribute to compliance with Requirement 2 of BAL-001-2, so they are a subset of the Regulation Reserve Forecast described above. To evaluate CPS1 requirements, PacifiCorp compared the net load change for each five-minute interval in the study period to the corresponding value for Requirement 2 compliance in that hour from the Regulation Reserve Forecast, after accounting for diversity (resulting in a 540 MW average requirement). Resources may deploy for Requirement 2 compliance over up to 30 minutes, so the average requirement of 540 MW would require ramping capability of at least 18.0 MW per minute (540 MW / 30 minutes). Because CPS1 is averaged and evaluated monthly, it does not require a response to each and every ACE event, but rather requires that PacifiCorp meet a minimum aggregate level of performance in each month. Resources capable of ensuring compliance in 95 percent of intervals are expected to be sufficient to meet CPS1 and given that ACE may deviate in either a positive or negative direction, the 97.5th percentile of incremental requirements versus Requirement 2 in that interval was evaluated. At the 97.5th percentile, fast ramping requirements for PACE and PACW are 1.7 MW/minute and 0.8 MW/minute higher than the Requirement 2 ramp rate, respectively; however, if dynamic transfers between the BAAs are available, the 97.5th percentile for system is 0.6 MW / minute lower than the Requirement 2 value. When viewed on a system basis, this means that 30-minute ramping capability held for Requirement 2 would be sufficient to cover an adequate portion of the fast-ramping events to ensure CPS1 compliance. Note that resources must respond immediately to ensure compliance with Requirement 1, as performance is measured on a minute-to-minute basis. As a result, resources that respond after a delay, such as quick-start gas plants or certain interruptible loads, would not be suitable for Requirement 1 compliance, so these resources cannot be allocated the entire regulation reserve requirement. However, because Requirement 1 compliance is a small portion of the total regulation reserve requirement, these restrictions on resource type are unlikely to be a meaningful constraint. In addition, CPS1 compliance is weighted toward performance during conditions when interconnection frequency deviations are large. The largest frequency deviations would also result in deployment of frequency response reserves, which are somewhat larger in magnitude, though PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 149 they have a less stringent performance metric under BAL-003-2, based on median response during the largest events. In light of the overlaps with BAL-001-2 Requirement 2 and BAL-003-2 described above, CPS1 compliance is not expected to result in an additional requirement beyond what is necessary to comply with those standards. Portfolio Regulation Reserve Requirements The IRP portfolio optimization process contemplates the addition of new wind and solar capacity as part of its selection of future resources, as well as changes in peak load due to load growth and energy efficiency measure selection. These load and resource changes are expected to drive changes in PacifiCorp’s regulation reserve requirements that will vary from portfolio to portfolio. The locations that have been identified as likely sites for future wind and solar additions are in relatively close proximity to existing wind and solar resources, and PacifiCorp’s portfolio of resources is already relatively diverse with significant wind in Wyoming, along the Columbia River gorge, and in eastern Idaho/western Wyoming and significant solar in southern Utah and southern Oregon. Because future resources are likely to be added in relatively close proximity to these existing resources, they are not likely to change the diversity for that class of resources as a whole. Given the sizeable sample of existing wind and solar resources in PACE and PACW, maintaining the existing level of diversity as a class of resources doubles or quadruples is a more likely outcome than the continuing improvements previously assumed in the 2019 FRS. With that in mind, the incremental regulation reserve analysis for the 2021 FRS methodology assumes that wind, solar, and load deviations scale linearly with capacity increases from the actual data in the 2018-2019 historical period. While diversity within each class is not expected to change significantly, there is the opportunity for greater diversity among the wind, solar, and load requirements. These portfolio-related benefits are inherently tied to the portfolio, so it is appropriate that they vary with the portfolio. To that end, the 2021 FRS methodology calculates the portfolio diversity benefits specific to a wide variety of wind and solar capacity combinations, rather than relying upon the historical portfolio diversity value. As part of the portfolio diversity calculation, the analysis assumes that minimum EIM flexible reserve requirements and EIM diversity benefits scale with changes in portfolio capacity. EIM minimum flexible reserve requirements are tied to the uncertainty in PacifiCorp’s requirements, which grow with changes portfolio capacity, so it would be impacted directly. EIM diversity benefits reflect PacifiCorp’s share of stand-alone requirements relative to those of the rest of the BAA’s participating in EIM. All else being equal, increases in PacifiCorp’s portfolio capacity would result in a greater proportion of the EIM diversity benefits being allocated to PacifiCorp. Portfolio diversity is driven by interplay among the deviations by wind, solar, and load, so it is not a single number, but rather is dependent on the specific conditions. The 2021 FRS methodology incorporates two mechanisms to better account for these interactions. First, a portfolio diversity value is calculated specific to each hour of the day in each season. Second, rather than applying an equal percentage reduction to all hours, diversity benefits are assumed to be highest when stand- PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 150 alone requirements are highest. For example, there is more opportunity for offsetting requirements when load, wind, and solar all have significant stand-alone requirements. With that in mind, diversity is applied as an exponent to the incremental requirement more than the EIM minimum requirement. The result of this calculation is a diversity benefit which is highest for large reserve requirements, and which approaches zero as the requirement approaches the EIM minimum, as illustrated in Table F.6Table F.6. Table F.6 – Portfolio Diversity Exponent Example Incremental Requirement w/ Diversity (MW) Portfolio Diversity (%) By Diversity Exponent By Diversity Exponent Stand-alone Reserve Req. (MW) EIM Floor (MW) Stand-alone Incremental Req. (MW) d = c ^ 75% e = c ^ 85% f = c ^ 95% g = 1 - (b + d)/a h = 1 - (b + e)/a i = 1 - (b + f)/a a b c = a - b 75% 85% 95% 75% 85% 95% 200 200 0 0 0 0 0% 0% 0% 250 200 50 19 28 41 12% 9% 4% 300 200 100 32 50 79 23% 17% 7% 350 200 150 43 71 117 31% 23% 9% 400 200 200 53 90 153 37% 27% 12% 450 200 250 63 109 190 42% 31% 13% 500 200 300 72 128 226 46% 34% 15% For each combination of wind and solar capacity, the hourly portfolio diversity exponents for each season are increased in a stepwise fashion until the risk of regulation reserve shortfalls during an interval is sufficiently low and the overall risk of regulation reserve shortfalls achieves the target of 0.5 hours per year. The resulting portfolio diversity is maximized for a combination of wind and solar as summarized in Table F.7Table F.77 and Table F.Table F.8 for PacifiCorp East and PacifiCorp West, respectively. Table F.7 – PacifiCorp East Diversity by Portfolio Composition MW % (% Reduction vs. Stand-alone Requirements) Ea s t W i n d C a p a c i t y 8,224 548% 17.2% 18.8% 20.6% 7,184 472% 19.2% 21.5% 23.0% 25.5% 26.5% 6,144 395% 22.9% 24.1% 25.6% 27.9% 28.5% 29.0% 5,104 319% 26.0% 27.3% 29.2% 30.7% 30.7% 30.5% 29.5% 4,064 242% 30.4% 31.6% 32.9% 33.8% 32.7% 32.8% 32.8% 3,024 166% 35.0% 36.2% 38.5% 37.1% 37.6% 36.2% 33.9% 31.9% 1,575 100% 48.0% 45.8% 43.1% 39.5% 35.8% 32.2% 29.4% 788 50% 46.4% 40.3% 36.4% 33.0% 30.0% 27.3% 50% 100% 166% 329% 493% 656% 820% 983% % 428 855 1,462 2,502 3,542 4,582 5,622 6,662 MW East Solar Capacity 2018-2019 Actual Wind and Solar Capacity Formatted: Font: Not Bold Formatted: Font: Not Bold PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 151 Table F.8 – PacifiCorp West Diversity by Portfolio Composition MW % (% Reduction vs. Stand-alone Requirements) We s t W i n d C a p a c i t y 4,389 548% 21.1% 22.4% 22.9% 3,669 472% 23.4% 24.8% 25.4% 29.0% 33.0% 2,949 395% 26.2% 26.7% 27.6% 32.1% 34.8% 38.1% 2,229 319% 29.6% 30.6% 31.4% 36.2% 39.5% 42.7% 42.7% 1,509 242% 33.8% 34.5% 36.3% 40.8% 45.2% 46.2% 43.9% 789 166% 38.8% 41.6% 43.1% 47.6% 48.4% 47.7% 45.0% 44.3% 726 100% 42.4% 42.9% 48.6% 49.3% 47.7% 46.2% 44.4% 363 50% 41.7% 47.1% 49.8% 47.4% 45.0% 43.2% 50% 100% 166% 329% 493% 656% 820% 983% % 111 221 321 1,041 1,761 2,481 3,201 3,921 MW West Solar Capacity 2018-2019 Actual Wind and Solar Capacity After portfolio selection is complete, regulation reserve requirements are calculated specific to a portfolio’s load, wind, and solar resources in each year. The hourly regulation reserve requirement varies as a function of annual peak load net of energy efficiency selections as well as total wind and solar capacity. The regulation reserve requirement also varies based on the hourly load net of energy efficiency and hourly wind and solar generation values. Diversity exponents specific to the wind and solar capacity in each year are applied by hour and season, by interpolating among the scenarios illustrated in Tables F.7 and F.8. For example, the diversity exponent for hour five in the spring for a PACW study with 1,000 MW of wind and 1,000 MW of solar would reflect a weighting of diversity exponents in hour five in the spring from four scenarios. The highest weighting would apply to the 789 MW wind/1,041 MW solar scenario, and successively lower weightings would apply to 1,509 MW wind/1,041 MW solar, 789 MW wind/321 MW solar, and 1,509 MW wind/321 MW solar, with the total weighting for all four scenarios summing to 100%. Finally, an adjustment is made to account for the ability of resources that are combined with storage to offset their own generation shortfalls beyond what is already captured by the model. For example, combined solar and storage resources can offset their own generation shortfalls, up to their interconnection limit. In actual operation, a reduction in solar generation would enable additional storage discharge. However, within the PLEXOS model, there are no intra-hour variations in load or renewable resource output and thus no potential increase in storage discharge. Note that combined storage can only be discharged when there is a generation shortfall at the adjacent resource, so it cannot cover all shortfalls across the system. For example, many solar resources do not have co-located storage, and their errors would continue to need to be met with incremental reserves. Nonetheless, combined solar and storage can cover a portion of their own shortfalls, and that portion increases as more combined storage resources are added to the system. This adjustment reduces the hourly regulation reserve requirement that is entered in the model. Regulation Reserve Cost The PLEXOS model reports marginal reserve prices on an hourly basis. So long as the change in reserve obligations or capability from what was input for a study is relatively small, this reserve PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 152 price can provide a reasonable estimate of the impact of changes in reserves, without requiring additional model runs. To estimate wind and solar integration costs for the 2023 IRP, PacifiCorp prepared a PLEXOS scenario that reflected the final regulation reserve requirements, consistent with the Company’s existing wind and resources plus selections in the preferred portfolio. Hourly regulation reserve prices were reported from this study. Wind Integration The wind reserve case uses the 2021 FRS methodology to recalculate the wind reserve requirement for a portfolio with 5 MW more wind resources starting in the first-year proxy resources are potentially available and extending to the end of the IRP study horizon (2025-2042). The change in resources is applied equally between PACE and PACW, and is allocated pro-rata among all wind resources in the area, such that the aggregate hourly capacity factor is not impacted by the change in capacity. The change in wind capacity results in incremental regulation reserve requirements that average approximately 16% of the nameplate capacity of the wind. Wind integration costs are calculated by multiplying the hourly change in reserve requirements (in MW) by the hourly regulation reserve price in each hour of the year, and then dividing that total by the incremental wind generation over the year. Solar Integration The solar reserve case uses the 2021 FRS methodology to recalculate the solar reserve requirement for a portfolio with 5 MW more solar resources starting in the first-year proxy resources are potentially available and extending to the end of the IRP study horizon (2025- 2042). The reduction in resources is applied equally between PACE and PACW, and is allocated pro-rata among all solar resources in the area, such that the aggregate hourly capacity factor is not impacted by the change in capacity. The change in solar capacity results in incremental regulation reserve requirements that average approximately 10% of the nameplate capacity of the solar. Solar integration costs are calculated by multiplying the hourly change in reserve requirements (in MW) by the hourly regulation reserve price in each hour of the year, and then dividing that total by the incremental solar generation over the year. The incremental regulation reserve cost results for wind and solar are shown in Figure F.11Figure F.11. The comparable regulation reserve costs from the 2021 FRS are also shown. Integration costs are high in the near term, as market prices are currently high and flexible capacity is somewhat limited. Integration costs fall as energy storage resources are added to the portfolio, as they can provide free operating reserves while charging and in any hour in which they are not discharging and not fully depleted, which for a four-hour energy storage resource is most of the day. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 153 Figure F.11 – Incremental Wind and Solar Regulation Reserve Costs Flexible Resource Needs Assessment Overview In its Order No. 12-013 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 section, PacifiCorp first identifies its flexible resource needs for the IRP study period of 2023 through 2042, and the calculation method used to estimate those requirements. PacifiCorp then identifies its supply of flexible capacity from its generation resources, in accordance with the Western Electricity Coordinating Council (WECC) operating reserve guidelines, demonstrating that PacifiCorp has sufficient flexible resources to meet its requirements. $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 20 2 3 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 20 3 6 20 3 7 20 3 8 20 3 9 20 4 0 20 4 1 20 4 2 In t e g r a t i o n C o s t ( $ / M W h ) Wind (21IRP) Solar (21IRP) Wind (23IRP) Solar (23IRP) PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 154 Forecasted Reserve Requirements Since contingency reserve and regulation reserve are separate and distinct components, PacifiCorp estimates the forward requirements for each separately. The contingency reserve requirements are derived from the PLEXOS model. The regulating reserve requirements are part of the inputs to the PLEXOS model and are calculated by applying the methods developed in the Portfolio Regulation Reserve Requirements section. The contingency and regulation reserve requirements include three distinct components and are modeled separately in the 2023 IRP: 10-minute spinning reserve requirements, 10-minute non-spinning reserve requirements, and 30-minute regulation reserve requirements. The average reserve requirements for PacifiCorp’s two balancing authority areas are shown in Table F.9Table F.99 below. Table F.9 - Reserve Requirements (Average MW) Flexible Resource Supply Forecast Requirements by NERC and the WECC dictate the types of resources that can be used to serve the reserve requirements. • 10-minute spinning reserve can only be provided by resources currently online and synchronized to the transmission grid; Spin Non-spin Regulation Spin Non-spin Regulation (10-minute)(10-minute)(30-minute)(10-minute)(10-minute)(30-minute) 2023 342 342 850 272 272 261 2024 343 343 1,113 278 278 274 2025 347 347 1,268 283 283 291 2026 344 344 1,539 285 285 381 2027 347 347 1,534 289 289 422 2028 353 353 1,548 294 294 424 2029 355 355 1,640 296 296 425 2030 356 356 1,633 296 296 425 2031 358 358 1,602 298 298 424 2032 357 357 1,598 298 298 422 2033 359 359 1,597 299 299 424 2034 360 360 1,634 300 300 495 2035 361 361 1,837 301 301 606 2036 362 362 2,216 301 301 757 2037 365 365 1,801 303 303 910 2038 367 367 1,789 303 303 921 2039 368 368 1,963 305 305 947 2040 369 369 2,047 306 306 950 2041 382 382 2,048 310 310 954 2042 386 386 2,074 312 312 968 East Requirement West Requirement Year PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 155 • 10-minute non-spinning reserve 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 provide non-spinning reserve. Non-spinning reserve may be provided by resources that are capable of providing spinning reserve. • 30-minute regulation reserve can be provided by unused spinning or non-spinning reserve. Incremental 30-minute ramping capability beyond the 10-minute capability captured in the categories above also counts toward this requirement. 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 reserve capability. 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 reserve that these 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 its share of generation and capacity from the Mid-Columbia projects. In the PacifiCorp East balancing authority area, PacifiCorp may use facilities on the Bear River to provide spinning reserve. Thermal resources are also used to meet the spinning reserve requirements when they are online. The amount of reserve provided by these resources is determined by their ability to ramp up within a 10-minute interval. For natural gas-fired combustion turbines, the amount of reserve can be close to the differences between their nameplate capacities and their minimum generation levels. In contrast, both coal and gas-converted steam turbines have slower ramp rates, and may ramp from minimum to maximum over an hour or more. In the current IRP, PacifiCorp’s reserve needs are increasingly met by energy storage resources, including contracted resources and proxy resource selections in the preferred portfolio. Table F.10Table F.10 lists the annual reserve capability from resources in PacifiCorp’s East and West balancing authority areas.21 The changes in the flexible resource supply reflect retirement of existing resources, addition of new preferred portfolio resources, and 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. 21 Frequency response capability is a subset of the 10-minute capability shown. Battery resources are capable of responding with their maximum output during a frequency event and can provide an even greater response if they were charging at the start of an event. PacifiCorp has sufficient frequency response capability at present and by 2025 the battery capacity currently contracted or added in the preferred portfolio will exceed PacifiCorp’s current 266.4 MW frequency response obligation for a 0.3 Hz event. As a result, compliance with the frequency response obligation is not anticipated to require incremental supply. PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 156 Table F.10 - Flexible Resource Supply Forecast (Average MW) Figure F.12Figure F.12 and Figure F.13Figure F.13 graphically display the balances of reserve requirements and capability of spinning reserve resources in PacifiCorp’s East and West balancing authority areas respectively. The graphs demonstrate that PacifiCorp’s system has sufficient resources to serve its reserve requirements throughout the IRP planning period. Note that keeping minimum amounts in energy storage or bringing thermal plants online and/or reducing their generation while online could increase the available response beyond that shown in the figures, and accounts for some of the increase in supply after 2030. In addition, PacifiCorp currently can transfer a portion of the operating reserves held in either of its balancing authority areas to help meet the requirements of its other balancing authority area, based on the reserve need and relative economics of the available supply. East Supply West Supply East Supply West Supply (10-Minute)(10-Minute)(30-Minute)(30-Minute) 2023 1,301 922 1,823 895 2024 1,291 934 2,221 1,036 2025 1,247 949 2,606 992 2026 1,245 911 2,734 1,819 2027 1,231 1,104 2,714 1,970 2028 1,333 824 3,022 1,837 2029 1,274 858 3,233 1,925 2030 1,277 855 3,335 1,912 2031 1,282 858 3,304 1,887 2032 1,202 2,314 3,089 2,186 2033 1,237 2,295 3,202 2,206 2034 3,256 2,199 3,264 2,117 2035 3,357 2,138 3,529 2,273 2036 3,463 2,164 3,974 2,510 2037 3,544 2,171 3,748 2,495 2038 3,517 2,154 3,842 2,648 2039 3,672 2,190 3,965 2,695 2040 3,725 2,205 4,000 2,693 2041 3,742 2,157 4,078 2,697 2042 3,756 2,015 4,106 2,541 Year PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 157 Figure F.12 - Comparison of Reserve Requirements and Resources, East Balancing Authority Area (MW) Figure F.13 - Comparison of Reserve Requirements and Resources, West Balancing Authority Area (MW) Flexible Resource Supply Planning In actual operations, PacifiCorp has been able to serve its reserve requirements and has not experienced any incidents where it was short of reserve. PacifiCorp manages its resources to meet its reserve obligation in the same manner as meeting its load obligation – through long term 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 MW East Spin (10-minute)East Non-spin (10-minute)East Regulation (30-minute) East Supply (10-Minute)East Supply (30-Minute) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 MW West Spin (10-minute)West Non-spin (10-minute)West Regulation (30-minute) West Supply (10-Minute)West Supply (30-Minute) PACIFICORP – 2023 IRP APPENDIX F – FLEXIBLE RESERVE STUDY 158 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, and participation by other utilities has expanded significantly with more participants scheduled for entry through 2023. By pooling variability in load and resource output, EIM entities reduce the quantity of reserve required to meet flexibility needs. Because variability across different BAAs may happen in opposite directions, the uncertainty requirement for the entire EIM footprint can be less than the sum of individual BAAs’ requirements. This difference is known as the “diversity benefit” in the EIM. This diversity benefit reflects offsetting variability and lower combined uncertainty. PacifiCorp’s regulation reserve forecast includes a credit to account for the diversity benefits associated with its participation in EIM. As indicated in OPUC order 12-013, electric vehicle technologies may be able to meet flexible resource needs. For the first time in the 2023 IRP, electric vehicle load control is one of the demand response options available for selection. While electric vehicle load control was not one of the programs selected to the preferred portfolio, new demand response programs included in the preferred portfolio provide 275 average megawatts of operating reserves by 2030, and 860 average megawatts of operating reserves by 2042. While operating reserves supply is projected to be well in excess of operating reserve requirements, the rising supply of zero-cost renewable resources increases the value associated with shifting load within the day and seasonally, rather than just within the hour as contemplated in this appendix. PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION STUDY 159 APPENDIX G – PLANT WATER CONSUMPTION STUDY The information provided in this appendix is for PacifiCorp owned plants. Total water consumption and generation includes all owners for jointly owned facilities. PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION STUDY 160 PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION 161 Study Data Table G.1 – Plant Water Consumption with Acre-Feet per Year Gadsby includes a mix of both Rankine steam units and Brayton peaking gas turbines. 1 acre-foot of water is equivalent to 325,851 Gallons or 43,560 Cubic Feet. 4-year Average Plant Name Zero Discharge Cooling Media 2019 2020 2021 2022 4-year Average 2019 2020 2021 2022 Gals/ MWH GPM/ MW Chehalis Air 63 66 71 47 62 2,431,536 2,407,519 2,248,237 2,172,465 9 0.1 Currant Creek Yes Air 101 95 113 85 98 2,917,279 2,335,426 2,746,290 2,805,979 12 0.2 Dave Johnston Water 8,485 7,856 6,571 5,901 7,203 4,686,381 4,325,604 3,601,242 3,581,919 580 9.7 Gadsby Water 281 409 339 454 371 134,182 133,410 83,008 118,821 1,029 17.2 Hunter Yes Water 15,808 15,103 16,326 13,426 15,166 8,681,784 7,988,203 9,248,963 7,381,184 594 9.9 Huntington Yes Water 9,028 7,929 12,019 11,717 10,173 4,897,541 4,515,305 6,263,658 5,673,115 621 10.4 Jim Bridger Yes Water 19,893 18,184 19,103 19,076 19,064 11,254,989 10,458,575 10,342,840 10,662,019 582 9.7 Lake Side Water 3,894 4,075 4,421 4,591 4,245 5,063,816 5,560,112 6,389,355 6,578,673 235 3.9 Naughton Yes Water 10,195 7,622 7,236 6,929 7,996 2,840,374 2,659,033 2,596,446 2,456,201 988 16.5 Wyodak Yes Air 292 336 333 324 321 1,852,094 1,732,784 1,717,528 1,779,843 59 1.0 68,040 61,675 66,531 62,551 64,699 44,759,976 42,115,971 45,237,567 43,210,219 481 8.0 Acre-Feet Per Year TOTAL Net MWhs Per Year PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION STUDY 162 PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION STUDY 163 Table G.2 – Plant Water Consumption by State (acre-feet) Table G.3 – Plant Water Consumption by Fuel Type (acre-feet) UTAH PLANTS Plant Name 2016 2017 2018 2019 2020 2021 2022 Currant Creek 124 116 110 101 95 113 85 Gadsby 262 100 205 281 409 339 454 Hunter 14,225 15,383 14,751 15,808 15,103 16,326 13,426 Huntington 9,189 9,653 9,804 9,028 7,929 12,019 11,717 Lake Side 3,619 2,698 3,648 3,894 4,075 4,421 4,591 TOTAL 27,419 27,950 28,518 29,112 27,611 33,217 30,274 Percent of total water consumption = 45.4% WYOMING PLANTS Plant Name 2016 2017 2018 2019 2020 2021 2022 Dave Johnston 8,864 8,231 8,325 8,485 7,856 6,571 5,901 Jim Bridger 18,000 19,047 20,067 19,893 18,184 19,103 19,076 Naughton 6,896 6,927 9,916 10,195 7,622 7,236 6,929 Wyodak 329 332 319 292 336 333 324 TOTAL 34,090 34,537 38,627 38,865 33,998 33,243 32,230 Percent of total water consumption = 54.6% COAL FIRED PLANTS Plant Name 2016 2017 2018 2019 2020 2021 2022 Dave Johnston 8,864 8,231 8,325 8,485 7,856 6,571 5,901 Hunter 14,225 15,383 14,751 15,808 15,103 16,326 13,426 Huntington 9,189 9,653 9,804 9,028 10,423 10,643 10,240 Jim Bridger 18,000 19,047 20,067 19,893 18,184 19,103 19,076 Naughton 6,896 6,927 9,916 10,195 7,622 7,236 6,929 Wyodak 329 332 319 292 336 333 324 TOTAL 57,504 59,573 63,182 63,701 59,524 60,212 55,896 Percent of total water consumption = 93.3% NATURAL GAS FIRED PLANTS Plant Name 2016 2017 2018 2019 2020 2021 2022 Currant Creek 124 116 110 101 95 113 85 Chehalis 48 54 33 63 66 71 47 Gadsby 262 100 205 281 409 339 454 Lake Side 3,619 2,698 3,648 3,894 4,075 4,421 4,591 TOTAL 4,053 2,968 3,996 4,339 4,644 4,943 5,178 Percent of total water consumption = 6.7% PACIFICORP – 2023 IRP APPENDIX G – PLANT WATER CONSUMPTION STUDY 164 Table G.4 – Plant Water Consumption for Plants Located in the Upper Colorado River Basin (acre-feet) Plant Name 2016 2017 2018 2019 2020 2021 2022 Hunter 14,225 15,383 14,751 15,808 15,103 16,326 13,426 Huntington 9,189 9,653 9,804 9,028 7,929 12,019 11,717 Naughton 6,896 6,927 9,916 10,195 7,622 7,236 6,929 Jim Bridger 18,000 19,047 20,067 19,893 18,184 19,103 19,076 TOTAL 48,311 51,010 54,537 54,924 48,839 54,684 51,148 Percent of total water consumption = 80.8% PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 165 APPENDIX H – STOCHASTIC PARAMETERS Introduction For the 2023 IRP, PacifiCorp updated and re-estimated the stochastic parameters provided in the 2021 IRP for use in the development of the 2023 IRP preferred portfolio. Plexos, 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), Plexos 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 Plexos is a two-factor (short- and long-run) mean reverting model. PacifiCorp used short-run stochastic parameters for this Integrated Resource Plan (IRP); long-run parameters were set to zero since Plexos 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 horizon1. 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, transmission availability, unit outages, and evolving end-uses. Depending on the region, fuel price uncertainty (especially natural gas) can encompass the sensitivities of weather, load growth, emissions, and hydro availability. The following sections summarize the development of stochastic process parameters and describe how these uncertain variables evolve over time. Overview 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 sections summarize the development of stochastic process parameters to describe how these uncertain variables evolve over time2. 1 Mean reversion is assumed to be zero in the long run. 2 A stochastic 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 the future evolution described by probability distributions. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 166 Volatility The standard deviation3(𝜎) is a measure of how widely values are dispersed from the average value: 𝜎= √∑(𝑥𝑖−𝜇)2𝑛 𝑖=1 (𝑛−1) where 𝜇 is the average value of the observations {x1, x2,…,xn}, and n is the number of observations. Volatility (𝜎𝑇) 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: 𝜎𝑇=𝜎√𝑇 Volatilities are typically quoted on an annual basis but can be specified for any desired time (𝑇). Suppose the annual volatility of load is two percent. This implies that the standard deviation of the range of possible loads a year from now is two percent, while the standard deviation four years from now is four percent. Mean Reversion If volatility was 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. 3 "Standard Deviation" and "Variance" are standard statistical terms describing the spread of possible outcomes. The Variance equals the Standard Deviation squared. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 167 Figure H.1 – Stochastic Processes 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 H.2 – Random Walk Price Process and Mean Reverting Process 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 0.0 0.5 1.0 1.5 2.0 2.5 0 10 20 30 40 50 60 Pr i c e I n 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 I n 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 – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 168 shock or deviation for a particular variable and the mean reversion rate describes how quickly the variable moves back toward 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. 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 for 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 distributed4. 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 H.3 – Lognormal Distribution and Cumulative Lognormal Distribution 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. 4 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 Li k 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 Li k e l i h o o d Price Index Cumulative Lognormal Distribution 90th Percentile10th Percentile Expected Index PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 169 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 H.1 - Seasonal Definitions Winter December, January, and February Spring March, April, and May Summer June, July, and August Fall September, October, and November Data Development Basic Data Set: The natural gas price data was organized into a consistent dataset with one natural gas price for each gas delivery point reported for each delivery day. The data was 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 2018 to 2021 was used for this short-term parameter analysis. The following chart shows the resulting data set for the Sumas gas basin: Figure H.4 – Daily Gas Prices for SUMAS Basin, 2018-2021 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 PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 170 instance, gas prices are expected to be higher during winter or as we move toward winter. This expectation is already included in the gas price forecast and should not be considered a shock, or random event. 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. Three categories of price expectations are calculated: Seasonal Median: 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. To account for this possible difference in the level of gas prices, the median gas price for each season and year is calculated. For example, Sumas prices in the winter of 2018 average $2.68/MMBtu. Monthly Median: 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 median price is calculated. For example, February prices in Sumas are 91 percent of the winter median 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 and found to be insignificant (expected variation by weekday did not exceed three percent of the weekly average). These three components – seasonal median, monthly shape, and weekly shape – combine to form an expected price for each day. For example, the expected price of gas in Sumas on February 1, 2018 was $2.21/MMBtu, the product of the seasonal median and the monthly shape factor 𝐸𝑥𝑝𝑒𝑐𝑡𝑒𝑑 𝐺𝑎𝑠 𝑃𝑟𝑖𝑐𝑒 =𝑆𝑒𝑎𝑠𝑜𝑛𝑎𝑙 𝑀𝑒𝑑𝑖𝑎𝑛.𝑃𝑟𝑖𝑐𝑒∗𝑀𝑜𝑛𝑡ℎ𝑙𝑦 𝑆ℎ𝑎𝑝𝑒 𝑤𝑖𝑡ℎ𝑖𝑛 𝑡ℎ𝑒 𝑆𝑒𝑎𝑠𝑜𝑛 The following chart shows the comparison of the actual Sumas prices with the "expected" prices: PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 171 Figure H.5 – Daily Gas Prices for SUMAS Basin with "expected" prices, 2018-2021 Dividing the actual gas prices by the expected prices forms a price index with a median of one. This index, illustrated by the chart below, captures only the random component of price movements—the portion not explained by expected seasonal, monthly, and weekly shape. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 172 Figure H.6 – Gas Price Index for SUMAS Basin, 2018-2021 Parameter Estimation – Autoregressive Model Uncertainty parameters are calculated for each variable by regressing the movement of each region’s price index compared to the previous day's index. Step 1 - Calculate Log Deviation of Price Index Since gas prices are lognormally 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 deviations of price index are regressed against the previous day's logarithm of price index 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: PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 173 Figure H.7 – Regression for SUMAS Gas Basin 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 one. This is consistent with the way in which the price index is formulated. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 174 The SLOPE of the regression is related to the auto correlation and mean reversion rate: 𝑎𝑢𝑡𝑜 𝑐𝑜𝑟𝑟𝑒𝑙𝑎𝑡𝑖𝑜𝑛=Ø =1 +𝑠𝑙𝑜𝑝𝑒 𝑀𝑒𝑎𝑛 𝑅𝑒𝑣𝑒𝑟𝑠𝑖𝑜𝑛 𝑅𝑎𝑡𝑒 𝛼= −ln(Ø) 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 percent jump over the norm, today's expected price would be 4 percent 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. Table H.2 - Uncertainty Parameters for Natural Gas Electricity Price Process For the most part, electricity prices behave very similarly 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 skewed upwards. In fact, even the lognormal assumption is sometimes inadequate for capturing the tail of the electricity price distribution. Like 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 was organized into a consistent dataset with one price for each region reported for each delivery day, like gas prices. The data covers the 2018 through 2021 period. However, electricity prices are reported for "High Load Level" periods (16 hours for six days a week) and "Low Load Level" periods (eight hours for six days a week and 24 hours on Sunday & NERC holidays). To have a consistent price definition, a composite price, calculated based on 16 PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 175 hours of peak and eight 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 like gas prices. Illiquid delivery point prices are filled using liquid hub prices as reference. Mid-C is the most liquid market in PACW, so missing prices for COB are filled using the latest available spread between COB and Mid-C markets. Similarly, Four Corner prices are filled using Palo Verde 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 median, monthly shape, and weekly shape. For instance, the expected price for January 2, 2018, in the Four Corners region was $24.22/megawatt hours (MWh). This price incorporates the 2018 winter median price of $26.00/MWh times the monthly shape factor for January of 90 percent and the weekday index for Saturday of 98 percent. The following chart shows the Four Corners actual and expected electricity prices over the analysis time period. Figure H.8 – Daily Electricity Prices for Four Corners, 2018-2021 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. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 176 Table H.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 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 H.9 – Probability Distribution for Portland Load, 2018-2021 PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 177 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 2, 2018, in Portland was 275 megawatts (MW). This load incorporates the 2018 winter average load of 245 MW times the monthly shape factor for January of 99 percent and the weekday index for Saturday also of 93 percent. The following chart shows the Portland actual and expected loads over the analysis period. Figure H.10 – Daily Average Load for Portland, 2018-2021 Load Uncertainty Parameters: Uncertainty parameters are calculated for each load region, like the process for gas and electricity prices. Since loads are modeled as normally, rather than log-normally 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. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 178 Table H.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, median hydro generation is calculated and analyzed on a weekly, rather than daily, basis. Generation is calculated as the median hourly generation across the 168 hours in a week. The hydro analysis covers the 2017 through 2021 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 1, 2017, through January 7, 2017 in the Western Region was 467 MW. This generation incorporates the 2017 winter median generation of 515 MW times the monthly shape factor for January of 113 percent. The following chart shows the western hydro actual and expected generation over the analysis period. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 179 Figure H.11 – Weekly Average Hydro Generation in the West, 2017-2021 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 H.5 - Uncertainty Parameters for Hydro Generation 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 the variables. The residual error represents the random portion of the deviation not explained by mean reversion. It is calculated for each period as the difference between the actual value and the value predicted by the linear regression equation: 𝐸𝑟𝑟𝑜𝑟=𝐴𝑐𝑡𝑢𝑎𝑙 𝐷𝑒𝑣𝑖𝑎𝑡𝑖𝑜𝑛−(𝑆𝑙𝑜𝑝𝑒∗𝑃𝑟𝑒𝑣𝑖𝑜𝑢𝑠 𝐷𝑒𝑣𝑖𝑎𝑡𝑖𝑜𝑛+𝐼𝑛𝑡𝑒𝑟𝑐𝑒𝑝𝑡) PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 180 All of the residual errors are compiled by delivery date. Step 2 - Calculate Correlations Correlate the residual errors of each pair of variables: 𝐶𝑜𝑟𝑟𝑒𝑙𝑎𝑡𝑖𝑜𝑛(𝑋,𝑌)= ∑[(𝑥𝑖−𝑥𝑎𝑣𝑔.)∗(𝑦𝑖−𝑦𝑎𝑣𝑔.)]𝑛 𝑖 √∑(𝑥𝑖−𝑥𝑎𝑣𝑔.)2 ∗𝑛 𝑖∑(𝑦𝑖−𝑦𝑎𝑣𝑔.)2𝑛 𝑖 There are a few things to note about the correlation calculations. First, correlation data must always be organized so that the same period is being compared for both variables. 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 are 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 H.6 - Short-term Winter Correlations Deviation events that impact one part of PacifiCorp’s system do not necessarily affect other parts of the system, due to its geographic diversity and transmission constraints. The correlation between these different deviations can be low if the deviations are caused by different drivers. An example from the winter season is the nine percent correlation between the Southeast Idaho load area, which is driven by weather events in PacifiCorp’s PACE balancing area, and Hydro, which is predominantly driven by weather events in PacifiCorp’s PACW balancing area, the unit commitment stack and unplanned unit outages. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 181 Table H.7 - Short-term Spring Correlations Similarly, the spring season shows a very low correlation of 14 percent between the Northern California and Wyoming loads, which are driven by different local weather deviations and different customer types. Wyoming loads are mostly driven by large industrial customers, whose loads are relatively flat across the year. Table H.8 - Short-term Summer Correlations In the summer season, 13 percent correlation has been observed between the deviations of Kern-Opal gas prices and Palo Verde power prices. Palo Verde prices are driven by a resource mix of southwest nuclear operations and gas unit dispatch based off SoCal gas prices. The operations of gas storage facilities and physical planned and unplanned maintenance of Kern-Opal and SoCal pipelines are independent of each other. PACIFICORP – 2023 IRP APPENDIX H – STOCHASTIC PARAMETERS 182 Table H.9 - Short-term Fall Correlations In the fall, a low correlation of 11 percent has been observed between Mid-C market price deviations and Wyoming load deviations. Market deviations are due to deviations in northwest weather patterns and resource mix while Wyoming loads are mostly dictated by planned or unplanned outages of industrial customer class. 183 APPENDIX I – CAPACITY EXPANSION RESULTS Figure I.1 – Preferred Portfolio Resource and Transmission Map 184 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 185 2023 IRP Portfolio Summaries P-MM Preferred Portfolio PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 186 P-LN PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 187 P-MN PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 188 P-HH PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 189 P-SC PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 190 P01-JB3-4 GC PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 191 P02-JB3-4 EOL PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 192 P03-Hunter3-SCR PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 193 P04-Huntington RET28 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 194 P05-No NUC PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 195 P06-No Forward Tech PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 196 P07-D3-D2 32 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 197 P08-No D3-D2 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 198 P10-Offshore Wind PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 199 P11-Max NG PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 200 P12-RET Coal 30/32 NG 40 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 201 P13-Max DSM PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 202 P15-No GWS PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 203 P16-No B2H PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 204 P18-Cluster East PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 205 P19-Cluster West PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 206 P20-JB3-4 CCUS LT_15442_23I.LT.RP.20.PA1_.EP.MM.JB3&4_CCUS Delayed Wind v114.3 Summary Portfolio Capacity by Resource Type and Year, Installed MW Installed Capacity, MW Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Total Expansion Options Gas - CCCT - - - - - - - - - - - - - - - - - - - - - Gas - Peaking - - - - - - - - - - - - - - - - - - - - - NonEmitting Peaker - - - - - - - 606 - - - - - 345 289 - - - - - 1,240 DSM - Energy Efficiency 123 220 259 197 214 219 236 261 665 112 175 185 162 277 594 150 170 169 139 426 4,953 DSM - Demand Response 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - 929 Renewable - Wind - 194 1,937 - 100 300 1,900 - - 2,283 1,359 - - - 940 - - - - - 9,013 Renewable - Utility Solar - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - 7,855 Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - - Renewable - Battery - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - 7,910 Renewable - Battery (Long Duration) - - - - - 200 - - - - 150 - - - 200 - - - - - 550 Storage - CAES - - - - - - - - - - - - - - - - - - - - - Storage - Pumped Hydro - - - 35 - - - - - - - - - - - - - - - - 35 Nuclear - - - - - - - 500 - 500 500 - - - - - - - - - 1,500 Front Office - Selected Markets - - - - - - - - - - - - - - - - - - - - - Front Office Transactions - Winter 62 118 50 1 43 52 31 42 42 52 41 52 52 52 52 52 52 65 47 100 53 Front Office Transactions - Summer 652 846 176 1,142 944 553 522 519 570 207 89 66 66 92 86 115 132 190 228 257 373 Existing Unit Changes Coal Plant End-of-life Retirements - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - (1,141) Coal Early Retirements - - - - - - - - - - - - - - - - - - - - - Coal - CCUS - - - - - (187) - - - - - - - - - - - (513) - - (699) Coal - SCR - - - - - - - - - - - - - - - - - - - - - Coal - SNCR - - - - - - - - - (418) (1,649) - - - - - - (268) - - (2,335) Coal - Duel Fuel - - - - - - - - - - - - - - - - - - - - - Coal - Gas Conversions - 713 - 357 - - - - - - - - - - (357) (713) - - - - 0 Coal Plant ceases running as Coal - (713) - (357) - - - - - - - - - - - - - - - - (1,070) Gas Plant End-of-life Retirements 247 - - - - - - - - - (358) - - - (484) - - - - - (595) Retire - Non-Thermal (23) - - - - - - - - - - - - - - - - - - - (23) Expire - Wind PPA - - - - - - - - - - - - - - - - - - - - - Expire - Solar PPA - - - - - - - - - - - - - - - - - - - - - Expire - QF - - - - - - - - - - - - - - - - - - - - - Expire - Other - (22) - - - - - - - - - - - - - - - - - - (22) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Total 1,133 1,395 4,997 6,855 2,545 4,772 3,737 1,796 1,299 3,708 457 603 287 766 1,520 (163) 373 (668) 414 783 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 207 P21-DJ2 CCUS LT_24412_23I.LT.RP.20.PA1_.EP.MM.DJ2_CCUS v124.2 Summary Portfolio Capacity by Resource Type and Year, Installed MW Installed Capacity, MW Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Total Expansion Options Gas - CCCT - - - - - - - - - - - - - - - - - - - - - Gas - Peaking - - - - - - - - - - - - - - - - - - - - - NonEmitting Peaker - - - - - - - 606 - - - - - 345 289 - - - - - 1,240 DSM - Energy Efficiency 123 220 259 197 214 219 236 261 665 112 175 185 162 277 594 150 170 169 139 426 4,953 DSM - Demand Response 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - 929 Renewable - Wind - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - 9,113 Renewable - Utility Solar - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - 7,855 Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - - Renewable - Battery - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - 7,910 Renewable - Battery (Long Duration) - - - - - - - - - - 150 - - - 200 - - - - - 350 Storage - CAES - - - - - - - - - - - - - - - - - - - - - Storage - Pumped Hydro - - - 35 - - - - - - - - - - - - - - - - 35 Nuclear - - - - - - - 500 - 500 500 - - - - - - - - - 1,500 Front Office - Selected Markets - - - - - - - - - - - - - - - - - - - - - Front Office Transactions - Winter 87 289 295 336 357 263 271 276 275 275 274 275 275 275 275 280 298 314 470 383 292 Front Office Transactions - Summer 750 893 466 1,101 907 484 317 407 468 80 92 92 89 88 123 126 192 373 427 400 394 Existing Unit Changes Coal Plant End-of-life Retirements - - - (82) - (253) (222) (148) - - - - - - - - - (330) - - (1,035) Coal Early Retirements - - - - - - - - - - - - - - - - - - - - - Coal - CCUS - - - - - (39) - - - - - - - - - - - (67) - - (106) Coal - SCR - - - - - - - - - - - - - - - - - - - - - Coal - SNCR - - - - - - - - - (418) (1,649) - - - - - - (268) - - (2,335) Coal - Duel Fuel - - - - - - - - - - - - - - - - - - - - - Coal - Gas Conversions - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - 0 Coal Plant ceases running as Coal - (713) - (357) - - - (699) - - - - - - - - - - - - (1,770) Gas Plant End-of-life Retirements 247 - - - - - - - - - (358) - - - (484) - - - - - (595) Retire - Non-Thermal (23) - - - - - - - - - - - - - - - - - - - (23) Expire - Wind PPA - - - - - - - - - - - - - - - - - - - - - Expire - Solar PPA - - - - - - - - - - - - - - - - - - - - - Expire - QF - - - - - - - - - - - - - - - - - - - - - Expire - Other - (22) - - - - - - - - - - - - - - - - - - (22) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Total 1,256 1,613 5,532 7,149 2,822 4,862 3,878 1,918 1,430 4,304 693 852 533 985 1,380 (624) 679 210 1,036 1,209 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 208 P22-DJ4 CCUS LT_24410_23I.LT.RP.20.PA1_.EP.MM.DJ4_CCUS+BAT v124.0 Summary Portfolio Capacity by Resource Type and Year, Installed MW Installed Capacity, MW Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Total Expansion Options Gas - CCCT - - - - - - - - - - - - - - - - - - - - - Gas - Peaking - - - - - - - - - - - - - - - - - - - - - NonEmitting Peaker - - - - - - - 606 - - - - - 345 289 - - - - - 1,240 DSM - Energy Efficiency 123 220 259 197 214 219 236 261 665 112 175 185 162 277 594 150 170 169 139 426 4,953 DSM - Demand Response 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - 929 Renewable - Wind - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - 9,113 Renewable - Utility Solar - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - 7,855 Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - - Renewable - Battery - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - 7,910 Renewable - Battery (Long Duration) - - - - - 99 - - - - 150 - - - 200 - - - - - 449 Storage - CAES - - - - - - - - - - - - - - - - - - - - - Storage - Pumped Hydro - - - 35 - - - - - - - - - - - - - - - - 35 Nuclear - - - - - - - 500 - 500 500 - - - - - - - - - 1,500 Front Office - Selected Markets - - - - - - - - - - - - - - - - - - - - - Front Office Transactions - Winter 88 288 295 336 358 263 271 276 275 275 274 275 275 275 275 280 298 314 470 383 292 Front Office Transactions - Summer 750 893 466 1,111 955 484 317 407 468 80 92 92 89 88 123 156 215 373 427 400 399 Existing Unit Changes Coal Plant End-of-life Retirements - - - (82) - (253) (328) (148) - - - - - - - - - - - - (811) Coal Early Retirements - - - - - - - - - - - - - - - - - - - - - Coal - CCUS - - - - - (99) - - - - - - - - - - - (330) - - (429) Coal - SCR - - - - - - - - - - - - - - - - - - - - - Coal - SNCR - - - - - - - - - (418) (1,649) - - - - - - (268) - - (2,335) Coal - Duel Fuel - - - - - - - - - - - - - - - - - - - - - Coal - Gas Conversions - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - 0 Coal Plant ceases running as Coal - (713) - (357) - - - (699) - - - - - - - - - - - - (1,770) Gas Plant End-of-life Retirements 247 - - - - - - - - - (358) - - - (484) - - - - - (595) Retire - Non-Thermal (23) - - - - - - - - - - - - - - - - - - - (23) Expire - Wind PPA - - - - - - - - - - - - - - - - - - - - - Expire - Solar PPA - - - - - - - - - - - - - - - - - - - - - Expire - QF - - - - - - - - - - - - - - - - - - - - - Expire - Other - (22) - - - - - - - - - - - - - - - - - - (22) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Total 1,257 1,612 5,532 7,159 2,871 4,901 3,772 1,918 1,430 4,304 693 852 533 985 1,380 (594) 702 277 1,036 1,209 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 209 P23-RET Coal 30/32 PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 210 P24-Gas 40-year Life PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 211 Sensitivity Portfolio Summaries S01 - High Load PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 212 S02 -Low Load PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 213 S03 -1 in 20 Load Growth PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 214 S05 - Low Private Generation PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 215 S06 - Business Plan PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 216 S07 - New Load PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 217 W10 - CETA PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 218 W11 - Climate Change Counterfactual PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 219 W12 - Max Customer Benefit PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 220 Annual Portfolio Resources by Technology Type Non-Emitting Peaking1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - - - - - - - 303 - - - - 1,240 - - - - - P-MN - - - - - - - - - - - 303 578 345 - - - - - P-MM - - - - - - - 606 - - - - - 345 289 - - - - - P-HH - - - - - - - - - - - - - - 951 - - - - - P-SC - - - - - - - - - 606 - - - - 634 - - - - - P01-JB3-4 GC - - - - - - - 606 - - - - - 345 289 - - - - - P02-JB3-4 EOL - - - - - - - 606 - - - - - 345 289 - - - - - P03-Hunter3-SCR - - - - - - - 606 - - - - - 345 289 - - - - - P04-Huntington RET28 - - - - - - - 606 - - - - - 345 289 - - - - - P05-No NUC - - - - - - - 895 - 303 303 - - 345 289 - - - - - P06-No Forward Tech - - - - - - - - - - - - - - - - - - - - P07-D3-D2 32 - - - - - - - 606 - - - - - 345 289 - - - - - P08-No D3-D2 - - - - - - - 606 - - - - - 345 289 - - - - - P09-No WY OTR - - - - - - - 606 - - - - - 345 289 - - - - - P10-Offshore Wind - - - - - - - 606 - - - - - - 289 - - - - - P11-Max NG - - - - - - - - - - - - - - - - - - - - P12-RET Coal 30 NG 40 - - - - - - - 606 - - - - - 345 1,790 - - - - - P13-Max DSM - - - - - - - 606 - - - - - 345 289 - - - - - P14-All GW - - - - - - - 606 - - - - - 345 289 - - - - - P15-No GWS - - - - - - - 606 - - - - - 345 289 - - - - - P16-No B2H - - - - - - - 606 - - - - - 345 289 - - - - - P17-Col3-4 RET25 - - - - - - - 606 - - - - - 345 289 - - - - - P18-Cluster East - - - - - - - 606 - - - - - 345 289 - - - - - P19-Cluster West - - - - - - - 606 - - - - - 345 289 - - - - - P20-JB3-4 CCUS - - - - - - - 606 - - - - - 345 289 - - - - - P21-DJ2 CCUS - - - - - - - 606 - - - - - 345 289 - - - - - P22-DJ4 CCUS - - - - - - - 606 - - - - - 345 289 - - - - - P23-RET Coal 30 - - - - - - - 606 - - - - - 345 289 - - - - - P24-Gas 40-year Life - - - - - - - - - - - - - 345 - - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 221 DSM Energy Efficiency Cumulative Energy, Gwh 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN 543 1,095 1,667 2,273 2,934 3,646 4,375 5,108 5,871 6,591 7,286 7,994 8,673 9,378 10,091 10,712 11,296 11,934 12,361 12,503 P-MN 543 1,095 1,667 2,274 2,937 3,651 4,383 5,120 5,882 6,613 7,308 8,017 8,696 9,413 10,124 10,745 11,330 11,968 12,397 12,536 P-MM 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P-HH 543 1,095 1,667 2,289 2,969 3,702 4,443 5,186 5,981 6,731 7,428 8,151 8,840 9,562 10,267 10,892 11,486 12,136 12,608 12,958 P-SC 543 1,095 1,667 2,285 2,961 3,689 4,425 5,168 5,926 6,671 7,368 8,077 8,758 9,475 10,182 10,806 11,392 12,031 12,480 12,636 P01-JB3-4 GC 543 1,095 1,667 2,280 2,954 3,665 4,394 5,128 5,890 6,634 7,338 8,055 8,737 9,454 10,123 10,744 11,334 11,974 12,404 12,564 P02-JB3-4 EOL 543 1,095 1,667 2,281 2,956 3,666 4,398 5,134 5,896 6,642 7,350 8,070 8,756 9,472 10,142 10,762 11,350 11,990 12,420 12,580 P03-Hunter3-SCR 543 1,095 1,667 2,274 2,935 3,647 4,376 5,110 5,873 6,603 7,284 7,992 8,672 9,389 10,100 10,720 11,312 11,954 12,396 12,559 P04-Huntington RET28 543 1,095 1,667 2,280 2,954 3,665 4,394 5,128 5,890 6,626 7,330 8,046 8,728 9,445 10,115 10,735 11,325 11,965 12,396 12,556 P05-No NUC 543 1,095 1,667 2,280 2,948 3,660 4,389 5,125 5,895 6,627 7,331 8,047 8,729 9,446 10,116 10,737 11,327 11,967 12,397 12,565 P06-No Forward Tech 543 1,095 1,667 2,280 2,948 3,660 4,389 5,125 5,895 6,627 7,331 8,047 8,729 9,446 10,116 10,737 11,327 11,967 12,397 12,569 P07-D3-D2 32 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P08-No D3-D2 543 1,095 1,667 2,274 2,934 3,646 4,368 5,098 5,886 6,618 7,324 8,044 8,727 9,438 10,149 10,767 11,351 11,998 12,429 12,577 P09-No WY OTR 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P10-Offshore Wind 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P11-Max NG 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P12-RET Coal 30 NG 40 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P13-Max DSM 543 1,095 1,667 2,413 3,246 4,144 5,098 6,097 7,231 8,232 9,175 10,109 10,994 11,904 12,767 13,530 14,256 15,043 15,698 16,429 P14-All GW 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P15-No GWS 543 1,095 1,667 2,274 2,934 3,646 4,368 5,098 5,886 6,618 7,324 8,044 8,727 9,438 10,149 10,767 11,351 11,998 12,429 12,577 P16-No B2H 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P17-Col3-4 RET25 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P18-Cluster East 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,575 P19-Cluster West 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P20-JB3-4 CCUS 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P21-DJ2 CCUS 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P22-DJ4 CCUS 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P23-RET Coal 30 543 1,095 1,667 2,272 2,932 3,644 4,366 5,096 5,884 6,616 7,322 8,042 8,725 9,436 10,147 10,765 11,349 11,996 12,427 12,579 P24-Gas 40-year Life 543 1,095 1,667 2,251 2,888 3,566 4,266 4,971 5,752 6,493 7,190 7,908 8,591 9,315 10,034 10,652 11,237 11,886 12,282 12,361 Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 222 DSM Demand Response Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN 72 39 143 38 161 120 33 16 33 - - - 51 - - 170 19 19 - - P-MN 72 39 152 99 126 94 27 13 35 - - - - - 1 228 19 19 - - P-MM 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P-HH 72 39 154 119 117 81 26 - 37 5 13 12 26 - - 239 22 19 - - P-SC 72 39 154 107 123 75 27 - 46 - - - 3 - - 246 19 19 - - P01-JB3-4 GC 72 220 199 12 77 64 43 9 11 - - 2 108 - - 125 20 39 - - P02-JB3-4 EOL 72 220 193 6 83 61 41 10 8 - - - 117 - - 121 21 20 - - P03-Hunter3-SCR 72 53 167 105 111 90 31 13 35 - - 2 - - - 225 19 38 - - P04-Huntington RET28 72 220 199 12 77 64 43 9 11 - - 2 108 - - 125 20 39 - - P05-No NUC 72 220 199 12 75 68 43 9 47 - - 2 76 - - 123 20 39 - - P06-No Forward Tech 72 220 199 12 75 68 43 9 47 - - 2 76 - - 123 20 39 - - P07-D3-D2 32 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P08-No D3-D2 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P09-No WY OTR 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P10-Offshore Wind 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P11-Max NG 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P12-RET Coal 30 NG 40 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P13-Max DSM 72 39 152 109 119 91 29 13 35 - 1 - 2 - 4 265 70 20 - 778 P14-All GW 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P15-No GWS 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P16-No B2H 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P17-Col3-4 RET25 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P18-Cluster East 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P19-Cluster West 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P20-JB3-4 CCUS 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P21-DJ2 CCUS 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P22-DJ4 CCUS 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P23-RET Coal 30 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - P24-Gas 40-year Life 72 39 152 109 133 81 27 16 22 - - - 7 - - 233 19 19 - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 223 Renewable Wind1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - 194 1,717 - - - 500 - 11 5,477 1,821 - - - - - - - - - P-MN - 194 1,717 - - - 500 - - 6,025 3,565 - 450 - - - - - - - P-MM - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P-HH - 194 1,717 - - 174 500 - - 7,922 2,321 - - - - - - - - - P-SC - 194 1,717 - - 457 500 - - 6,486 3,607 - - - - - - - - - P01-JB3-4 GC - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P02-JB3-4 EOL - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P03-Hunter3-SCR - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P04-Huntington RET28 - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P05-No NUC - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P06-No Forward Tech - 194 1,937 - 100 300 1,900 - - 2,883 1,359 - - - 540 - - - - - P07-D3-D2 32 - 194 1,937 - 100 300 - - - 4,800 1,755 - - - - - - - - - P08-No D3-D2 - 194 1,937 - 100 300 - - - 2,349 1,282 - - - - - - - - - P09-No WY OTR - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P10-Offshore Wind - 194 1,937 - 100 300 1,900 - - 2,683 1,459 - - - 540 - - - - - P11-Max NG - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P12-RET Coal 30 NG 40 - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 676 - - - - - P13-Max DSM - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P14-All GW - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P15-No GWS - 194 296 - 100 300 - - - 2,349 1,282 - - - - - - - - - P16-No B2H - 194 1,937 - 100 - 1,900 400 - 2,783 959 - - - 540 - - - - - P17-Col3-4 RET25 - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P18-Cluster East - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P19-Cluster West - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P20-JB3-4 CCUS - 194 1,937 - 100 300 1,900 - - 2,283 1,359 - - - 940 - - - - - P21-DJ2 CCUS - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P22-DJ4 CCUS - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - P23-RET Coal 30 - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 676 - - - - - P24-Gas 40-year Life - 194 1,937 - 100 300 1,900 - - 2,783 1,359 - - - 540 - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 224 Renewable Solar1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - 1,469 1,600 - 2,519 1,298 - 288 241 - - - - 1,400 - - - - - P-MN - - 1,469 1,600 - 2,470 1,298 - 254 941 - - - - 600 - - - - - P-MM - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P-HH - - 1,469 1,600 - 3,006 1,298 - 4 1,288 241 - - - - - - - - - P-SC - - 1,469 1,600 - 2,589 1,298 - 108 600 - 841 - - - - - - - - P01-JB3-4 GC - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P02-JB3-4 EOL - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P03-Hunter3-SCR - - 1,469 2,524 483 1,832 200 - - 972 - 300 - - - - - - - - P04-Huntington RET28 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P05-No NUC - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P06-No Forward Tech - - 1,469 2,524 483 1,907 200 - - 1,139 - 400 - - 600 - - - - - P07-D3-D2 32 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P08-No D3-D2 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P09-No WY OTR - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P10-Offshore Wind - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P11-Max NG - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P12-RET Coal 30 NG 40 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P13-Max DSM - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P14-All GW - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P15-No GWS - - 1,469 2,224 483 2,307 600 - 200 972 - 300 - - - - - - - - P16-No B2H - - 1,469 2,524 483 1,507 600 - - 972 600 300 - - - - - - - - P17-Col3-4 RET25 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P18-Cluster East - - 1,469 2,524 483 1,907 2,373 - - 972 - 300 - - - - - - - - P19-Cluster West - - 1,469 2,524 483 2,406 200 - - 972 - 300 - - - - - - - - P20-JB3-4 CCUS - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P21-DJ2 CCUS - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P22-DJ4 CCUS - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P23-RET Coal 30 - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - P24-Gas 40-year Life - - 1,469 2,524 483 1,907 200 - - 972 - 300 - - - - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 225 Battery Storage1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - 954 1,600 160 2,008 1,647 - - - 400 - - - 2,560 - - - - - P-MN - - 954 1,600 - 2,304 1,647 - - 600 - - - - 2,356 - - - - - P-MM - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P-HH - - 954 1,600 - 2,599 1,647 - - 600 - - - - 1,541 - - - - - P-SC - - 954 1,600 - 1,979 1,647 - - 600 - - - - 1,207 - - - - - P01-JB3-4 GC - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P02-JB3-4 EOL - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P03-Hunter3-SCR - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P04-Huntington RET28 - - 954 2,929 628 2,300 1,149 - - - - - - - 100 - - - - - P05-No NUC - - 954 2,929 628 1,900 1,149 - - 200 350 - - - 200 - - - - - P06-No Forward Tech - - 954 2,929 628 1,900 1,149 - - 200 350 - - - 400 - - - - - P07-D3-D2 32 - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P08-No D3-D2 - - 954 2,929 628 1,900 1,149 - - 800 150 - - - 200 - - - - - P09-No WY OTR - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P10-Offshore Wind - - 954 2,929 628 1,900 1,149 - - - 150 - - - 500 - - - - - P11-Max NG - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P12-RET Coal 30 NG 40 - - 954 2,929 628 1,900 1,149 - - - 150 - - - 1,323 - - - - - P13-Max DSM - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P14-All GW - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P15-No GWS - - 954 2,629 628 2,500 1,349 - - 800 150 - - - 200 - - - - - P16-No B2H - - 954 2,929 1,352 1,900 1,149 - - - 750 - - - 200 - - - - - P17-Col3-4 RET25 - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P18-Cluster East - - 954 2,929 628 1,900 3,322 - - - 150 - - - 200 - - - - - P19-Cluster West - - 954 2,929 628 2,399 1,149 - - - 150 - - - 200 - - - - - P20-JB3-4 CCUS - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P21-DJ2 CCUS - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P22-DJ4 CCUS - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - P23-RET Coal 30 - - 954 2,929 628 1,900 1,149 - - - 150 - - - 1,323 - - - - - P24-Gas 40-year Life - - 954 2,929 628 1,900 1,149 - - - 150 - - - 200 - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 226 Battery, Long Duration1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - - - 600 - - - - - - - - 200 - - - - - P-MN - - - - - 400 - - - - - - - - - - - - - - P-MM - - - - - - - - - - 150 - - - 200 - - - - - P-HH - - - - - 600 - - - - - - - - 200 - - - - - P-SC - - - - - 400 - - - - - - - - 784 - - - - - P01-JB3-4 GC - - - - - - - - - - 150 - - - 200 - - - - - P02-JB3-4 EOL - - - - - - - - - - 150 - - - 200 - - - - - P03-Hunter3-SCR - - - - - - - - - - 150 - - - 200 - - - - - P04-Huntington RET28 - - - - - - - - - - - - - - 200 - - - - - P05-No NUC - - - - - - - - - - 150 - - - 200 - - - - - P06-No Forward Tech - - - - - - - - - 300 650 - - - 400 - - - - - P07-D3-D2 32 - - - - - - - - - - 150 - - - 200 - - - - - P08-No D3-D2 - - - - - - - - - 600 150 - - - 200 - - - - - P09-No WY OTR - - - - - - - - - - 150 - - - 200 - - - - - P10-Offshore Wind - - - - - - - - - - 150 - - - 200 - - - - - P11-Max NG - - - - - - - - - - 150 - - - 200 - - - - - P12-RET Coal 30 NG 40 - - 600 - - - - - - - 150 - (600) - 200 - - - - - P13-Max DSM - - - - - - - - - - 150 - - - 200 - - - - - P14-All GW - - - - - - - - - - 150 - - - 200 - - - - - P15-No GWS - - - - - - - - - 600 150 - - - 200 - - - - - P16-No B2H - - - - - - - - - - 150 - - - 200 - - - - - P17-Col3-4 RET25 - - - - - - - - - - 150 - - - 200 - - - - - P18-Cluster East - - - - - - - - - - 150 - - - 200 - - - - - P19-Cluster West - - - - - - - - - - 150 - - - 200 - - - - - P20-JB3-4 CCUS - - - - - 200 - - - - 150 - - - 200 - - - - - P21-DJ2 CCUS - - - - - - - - - - 150 - - - 200 - - - - - P22-DJ4 CCUS - - - - - 99 - - - - 150 - - - 200 - - - - - P23-RET Coal 30 - - - - - - - - - - 150 - - - 200 - - - - - P24-Gas 40-year Life - - - - - - - - - - 150 - - - 200 - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 227 Nuclear1 1 – Positive values indicate installed capacity in the first full year of operations Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - - - - - 500 - 1,000 - - - - - - - - - - P-MN - - - - - - - 500 - 1,000 - - - - - - - - - - P-MM - - - - - - - 500 - 500 500 - - - - - - - - - P-HH - - - - - - - 500 - 1,000 - - - - 500 - - - - - P-SC - - - - - - - 500 - - 500 500 - - - - - - - - P01-JB3-4 GC - - - - - - - 500 - 500 500 - - - - - - - - - P02-JB3-4 EOL - - - - - - - 500 - 500 500 - - - - - - - - - P03-Hunter3-SCR - - - - - - - 500 - 500 500 - - - - - - - - - P04-Huntington RET28 - - - - - - - 500 - 500 500 - - - - - - - - - P05-No NUC - - - - - - - - - - - - - - - - - - - - P06-No Forward Tech - - - - - - - - - - - - - - - - - - - - P07-D3-D2 32 - - - - - - - 500 - 500 500 - - - - - - - - - P08-No D3-D2 - - - - - - - 500 - 500 500 - - - 1,000 - - - - - P09-No WY OTR - - - - - - - 500 - 500 500 - - - - - - - - - P10-Offshore Wind - - - - - - - 500 - 500 500 - - - - - - - - - P11-Max NG - - - - - - - - - - - - - - - - - - - - P12-RET Coal 30 NG 40 - - - - - - - 500 - - - - - - - - - - - - P13-Max DSM - - - - - - - 500 - 500 500 - - - - - - - - - P14-All GW - - - - - - - 500 - 500 500 - - - - - - - - - P15-No GWS - - - - - - - 500 - 500 500 - - - 1,000 - - - - - P16-No B2H - - - - - - - 500 - 500 500 - - - - - - - - - P17-Col3-4 RET25 - - - - - - - 500 - 500 500 - - - - - - - - - P18-Cluster East - - - - - - - 500 - 500 500 - - - - - - - - - P19-Cluster West - - - - - - - 500 - 500 500 - - - - - - - - - P20-JB3-4 CCUS - - - - - - - 500 - 500 500 - - - - - - - - - P21-DJ2 CCUS - - - - - - - 500 - 500 500 - - - - - - - - - P22-DJ4 CCUS - - - - - - - 500 - 500 500 - - - - - - - - - P23-RET Coal 30 - - - - - - - 500 - - - - - - - - - - - - P24-Gas 40-year Life - - - - - - - 500 - - - - - - - - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 228 Coal Retirements1 1 Negative values indicate retirement of coal fueled capacity 2 This table only represents actual retirement of a coal unit in the year of retirement. Retirements for gas converted units or those with installation of SNCR or CCUS technologies are shown in subsequent tables Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - (82) - (253) (328) (148) - - - - - - - - - - - - P-MN - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P-MM - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P-HH - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P-SC - - - (82) - (253) (328) (148) - (699) - - - - - - - (330) - - P01-JB3-4 GC - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P02-JB3-4 EOL - - - (82) - (253) (328) (148) - - - - - - - (699) - (330) - - P03-Hunter3-SCR - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P04-Huntington RET28 - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P05-No NUC - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P06-No Forward Tech - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P07-D3-D2 32 - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P08-No D3-D2 - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P09-No WY OTR - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P10-Offshore Wind - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P11-Max NG - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P12-RET Coal 30 NG 40 - - - (82) - (253) (328) (148) - - - - - - - - - - - - P13-Max DSM - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P14-All GW - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P15-No GWS - - - (82) - (253) (328) (148) - - - - - - (330) - - - - - P16-No B2H - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P17-Col3-4 RET25 - - - (230) - (253) (328) - - - - - - - - - - (330) - - P18-Cluster East - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P19-Cluster West - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P20-JB3-4 CCUS - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - P21-DJ2 CCUS - - - (82) - (253) (222) (148) - - - - - - - - - (330) - - P22-DJ4 CCUS - - - (82) - (253) (328) (148) - - - - - - - - - - - - P23-RET Coal 30 - - - (82) - (253) (328) (148) - - - - - - - - - - - - P24-Gas 40-year Life - - - (82) - (253) (328) (148) - - - - - - - - - (330) - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 229 Coal with CCUS Installation1,2 1 Negative Values first full year of operations with CCUS installed report the reductions in capacity rating 2 2040 negative values indicate retirement of coal fueled capacity with CCUS Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - - - - - - - - - - - - - - - - - - P-MN - - - - - - - - - - - - - - - - - - - - P-MM - - - - - - - - - - - - - - - - - - - - P-HH - - - - - - - - - - - - - - - - - - - - P-SC - - - - - - - - - - - - - - - - - - - - P01-JB3-4 GC - - - - - - - - - - - - - - - - - - - - P02-JB3-4 EOL - - - - - - - - - - - - - - - - - - - - P03-Hunter3-SCR - - - - - - - - - - - - - - - - - - - - P04-Huntington RET28 - - - - - - - - - - - - - - - - - - - - P05-No NUC - - - - - - - - - - - - - - - - - - - - P06-No Forward Tech - - - - - - - - - - - - - - - - - - - - P07-D3-D2 32 - - - - - - - - - - - - - - - - - - - - P08-No D3-D2 - - - - - - - - - - - - - - - - - - - - P09-No WY OTR - - - - - - - - - - - - - - - - - - - - P10-Offshore Wind - - - - - - - - - - - - - - - - - - - - P11-Max NG - - - - - - - - - - - - - - - - - - - - P12-RET Coal 30 NG 40 - - - - - - - - - - - - - - - - - - - - P13-Max DSM - - - - - - - - - - - - - - - - - - - - P14-All GW - - - - - - - - - - - - - - - - - - - - P15-No GWS - - - - - - - - - - - - - - - - - - - - P16-No B2H - - - - - - - - - - - - - - - - - - - - P17-Col3-4 RET25 - - - - - - - - - - - - - - - - - - - - P18-Cluster East - - - - - - - - - - - - - - - - - - - - P19-Cluster West - - - - - - - - - - - - - - - - - - - - P20-JB3-4 CCUS - - - - - (187) - - - - - - - - - - - (513) - - P21-DJ2 CCUS - - - - - (39) - - - - - - - - - - - (67) - - P22-DJ4 CCUS - - - - - (99) - - - - - - - - - - - (330) - - P23-RET Coal 30 - - - - - - - - - - - - - - - - - - - - P24-Gas 40-year Life - - - - - - - - - - - - - - - - - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 230 Coal with SNCR Installation1,2 1 Positive values indicate first full year of operations with SNCR installed 2 Negative values indicate retirement of coal fueled capacity with SNCR 3 Results for “P03-Hunter 3-SCR” reports a reduction in SNCR in 2026 compared to the preferred portfolio because the installation of SNCR is changed to SCR Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - - - 2,067 - - - - - (2,067) - - - - - - - - - - P-MN - - - 2,335 - - - - - (2,067) - - - - - - - (268) - - P-MM - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P-HH - - - 2,335 - - - - - (2,067) - - - - - - - (268) - - P-SC - - - 2,335 - - - - - (2,067) - - - - - - - (268) - - P01-JB3-4 GC - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P02-JB3-4 EOL - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P03-Hunter3-SCR - - - 1,864 - - - - - (418) (1,178) - - - - - - (268) - - P04-Huntington RET28 - - - 2,335 - (459) - - - (418) (1,190) - - - - - - (268) - - P05-No NUC - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P06-No Forward Tech - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P07-D3-D2 32 - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P08-No D3-D2 - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P09-No WY OTR - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P10-Offshore Wind - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P11-Max NG - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P12-RET Coal 30 NG 40 - - - 2,067 (450) - - - - (418) (1,199) - - - - - - - - - P13-Max DSM - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P14-All GW - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P15-No GWS - - - 2,335 - - - - - (418) (1,649) - - - (268) - - - - - P16-No B2H - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P17-Col3-4 RET25 - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P18-Cluster East - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P19-Cluster West - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P20-JB3-4 CCUS - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P21-DJ2 CCUS - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P22-DJ4 CCUS - - - 2,335 - - - - - (418) (1,649) - - - - - - (268) - - P23-RET Coal 30 - - - 2,067 (450) - - - - (418) (1,199) - - - - - - - - - P24-Gas 40-year Life - - - 1,595 - - - - - (909) - - - - - (418) - (268) - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 231 Coal to Natural Gas Conversions1,2 1 – Positive values indicate first full year of natural gas-fueled operation 2 – Negative values indicate retirement of gas-converted capacity Installed Capacity, MW 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 P-LN - 713 - 370 598 - - 699 - (330) - - - - (370) (1,413) - (268) - - P-MN - 713 - 370 - - - 340 (354) - - - - (160) (210) (699) - - - - P-MM - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P-HH - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P-SC - 713 - 370 - - - - - - - - - - (370) (713) - - - - P01-JB3-4 GC - 713 - 1,069 - - - - - - - - - - (370) (1,413) - - - - P02-JB3-4 EOL - 713 - 370 - - - - - - - - - - (370) (713) - - - - P03-Hunter3-SCR - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P04-Huntington RET28 - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P05-No NUC - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P06-No Forward Tech - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P07-D3-D2 32 - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P08-No D3-D2 - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P09-No WY OTR - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P10-Offshore Wind - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P11-Max NG - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P12-RET Coal 30 NG 40 - 713 - 370 598 - - 699 - - - - - - (370) (1,413) - (598) - - P13-Max DSM - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P14-All GW - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P15-No GWS - 713 - 370 - - - 699 - - - - - - (1,783) - - - - - P16-No B2H - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P17-Col3-4 RET25 - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P18-Cluster East - 713 - 370 - - - 699 - - - - - - (370) (1,413) - - - - P19-Cluster West - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P20-JB3-4 CCUS - 713 - 357 - - - - - - - - - - (357) (713) - - - - P21-DJ2 CCUS - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P22-DJ4 CCUS - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - P23-RET Coal 30 - 713 - 357 598 - - 699 - - - - - - (357) (1,413) - (598) - - P24-Gas 40-year Life - 713 - 357 - - - 699 - - - - - - (357) (1,413) - - - - Study PACIFICORP – 2023 IRP APPENDIX I – CAPACITY EXPANSION RESULTS 232 PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 233 APPENDIX J- STOCHASTIC SIMULATION RESULTS The following figures provide the cost summary detail comparing the MT (medium-term) model 95th percentile stochastic results to the stochastic mean results. This can indicate which cost categories pose the largest risks. Note that the 95th percentile sample is determined from the present value impact over the entire IRP study horizon, and is thus not illustrating the potential range of risk in each individual year. Medium-Term Stochastic Model Results 2023 IRP Preferred Portfolio (P01) Jim Bridger 3 & 4 GC 2026 PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 234 (P02) Jim Bridger 3 & 4 Coal EOL (P03) Hunter 3 SCR (P04) Retire Huntington 2028 PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 235 (P05) No NUC add Peaker (P06) No NUC No Forward Tech (P07) D3 and D2 in 2032 PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 236 (P08) No D3 and D2 (P09) WY No OTR (P-10) Offshore Wind PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 237 (P-11) Max Nat Gas ( No Nuclear/Peaker) (P12) Coal Retire end 2029 Gas end of 2039 (P13) - ALL Energy Efficiency PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 238 (P14) All Gateway (P15) No GWS (P16) No B2H PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 239 (P17) Col3-4 RET25 (P18) Cluster East (P19) Cluster West PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 240 (P20) JB3-4 CCUS (P21) DJ2 CCUS (P22) DJ4 CCUS PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 241 (P23) RET Coal 30 (P24) Gas 40-year Life PACIFICORP – 2023 IRP APPENDIX J - STOCHASTIC SIMULATION RESULTS 242 PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 243 APPENDIX K – CAPACITY CONTRIBUTION Introduction The capacity contribution of a resource is represented as a percentage of that resource’s nameplate or maximum capacity and is a measure of the ability of a resource to reliably meet demand. This capacity contribution affects PacifiCorp’s resource planning activities, which are intended to ensure there is sufficient capacity on its system to meet its load obligations inclusive of a planning reserve margin. Because of the increasing penetration of variable energy resources (such as wind and solar) and energy-limited resources (such as storage and demand response), planning for coincident peak loads is no longer sufficient to determine the necessary amount and timing of new resources. 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 load obligations and a planning reserve margin in all hours of each year. Because all resources provide both energy and capacity benefits, identifying the resource that can provide additional capacity at the lowest incremental cost to customers is not straightforward. A resource’s energy value is dependent on its generation profile and location, as well as the composition of resources and transmission in the overall portfolio. Similarly, a resource’s capacity value (or contribution to ensuring reliable system operation) is also dependent on both its characteristics and the composition of the overall portfolio. To further complicate the analysis, PacifiCorp’s portfolio composition changes dramatically over time, as a result of retirements and expiring contracts. In the 2019 IRP, PacifiCorp developed initial capacity contribution estimates for wind and solar capacity that accounted for expected declining contributions as the level of penetration increased. A key assumption in this analysis was that only a single variable was modified, for example, when evaluating solar penetration level, the capacity from wind and energy storage resources in the portfolio were held constant. As the preparation of the 2019 IRP continued, PacifiCorp identified that these initial estimates did not adequately account for the interactions between solar, wind, and energy storage and thus did not ensure that each portfolio was adequately reliable. Therefore, as part of the 2019 IRP PacifiCorp assessed each portfolio to verify that it would support reliable operation in each hour of the year. PacifiCorp has continued to perform this portfolio-wide reliability assessment as part of the 2021 and 2023 IRPs. PacifiCorp calculates the 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)1. The CF Method calculates a capacity contribution based on a resource’s expected availability during periods when the risk of loss of load events is highest, based on the loss of load probability (LOLP) in each hour. This CF Method analysis is performed using a portfolio that is comparable to the preferred portfolio. For the reasons discussed above, this analysis provides a reasonable estimate of capacity contribution value so long as the changes relative to the preferred portfolio are small, since in effect, the CF Method calculates the marginal capacity contribution of a one megawatt resource addition. Changes to the locations and quantities of wind, solar, and energy storage are key drivers of the marginal capacity contribution results. 1 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) at: www.nrel.gov/docs/fy12osti/54704.pdf PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 244 CF 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 a more computationally intensive reliability-based 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 a reliability-based metric. 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 to produce a capacity contribution value. The weighting factors based on LOLP are defined as: 𝑤𝑖=𝐿𝑂𝐿𝑃𝑖 ∑𝐿𝑂𝐿𝑃𝑗𝑇𝑗=1 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: 𝐶𝑉=∑𝑤𝑖𝐶𝑖 𝑇 𝑖=1 , where Ci is the capacity factor of the resource in hour i, and CV is the weighted capacity value of the resource. For fixed profile resources, including wind, solar, and energy efficiency, the average LOLP values across all iterations are sufficient, as the output of these resources is the same in each iteration. To determine the capacity contribution of fixed profile resources using the CF Method, PacifiCorp implemented the following three steps: 1. A multi-iteration hourly Monte Carlo simulation of PacifiCorp’s system was produced using the Plexos Short-Term (ST) model. The key stochastic variables assessed as part of this analysis are loads, thermal outages, and hydro conditions. The LOLP for each hour in the year is calculated by counting the number of iterations in which system load and/or reserve obligations could not be met with available resources and dividing by the total PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 245 number of iterations.2 For example, if in hour 19 on December 22nd there are three iterations with shortfalls out of a total of 50 iterations, then the LOLP for that hour would be 6 percent.3 2. Weighting factors were determined based upon the LOLP in each hour divided by the sum of LOLP among all hours within the same summer or winter season. In the example noted above, the sum of LOLP among all winter hours is 58 percent.4 The weighting factor for hour 19 on December 22nd would be 1.0417 percent.5 This means that 1.0417 percent of all winter loss of load events occurred in hour 19 on December 22nd and that a resource delivering in only in that single hour would have a winter capacity contribution of 1.0417 percent. 3. The hourly weighting factors are then applied to the capacity factors of fixed profile 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 percent in hour 19 on December 22nd, its weighted winter capacity contribution for that hour would be 0.4271 percent.6 For resources which are energy limited, such as energy storage or demand response programs, the LOLP values in each iteration must be examined independently, to ensure that the available storage or control hours are sufficient. Continuing the example of December 22nd described above, consider if hour 18 and hour 19 both have three hours with energy or reserve shortfalls out of 500 iterations. If all six shortfall hours are in different iterations, a 1-hour energy storage resource could cover all six hours. However, if the six shortfall hours are in the same three iterations in hour 18 and hour 19 (i.e. 2-hour duration events), then a 1-hour storage resource could only cover three of the six shortfall hours. Additional considerations are also necessary for hybrid resources which share an interconnection and cannot generate their maximum potential output simultaneously. The details of the wind and solar resource modeling in the study period are an important aspect of the results. The study includes specific wind and solar volumes by resource for each hour in the period and includes the effects of calm and cloudy days on resource output. Where data was available, the modeled generation profiles for proxy resources are derived from calendar year 2018 hourly generation profiles of existing resources, adjusted to align with the expected annual output of each proxy resource. The use of correlated hourly shapes produces variability across each month and a reasonable correlation between resources of the same type that are located in close proximity. It also results 2 While PacifiCorp participates in the Northwest Power Pool (NWPP) reserve sharing agreement, this only provides energy from other participants within the first hour of a contingency event, e.g. a forced outage of a generator or transmission line. Shortfalls in the 2023 IRP are much more likely to result from changes in load, renewable resource output, or energy storage limitations, which do not qualify as contingency events. In light of this, PacifiCorp’s analysis includes the first hour of every shortfall event. 3 0.6 percent = 3 / 500. 4 For each hour, the hourly LOLP is calculated as the number of iterations with ENS divided by the total of 500 iterations. There are 288 winter ENS iteration-hours out of total of 5,832 winter hours. As a result, the sum of LOLP for the winter is 288 / 500 = 58 percent. There are 579 summer ENS iteration-hours out of total of 2,928 summer hours. As a result, the sum of LOLP for the summer is 579 / 500 = 116 percent. 5 1.0417 percent = 0.6 percent / 58 percent, or simply 1.0417 percent = 3 / 288. 6 0.4271 percent = 1.0417 percent x 41.0 percent. PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 246 in days with higher generation and days with lower generation in each month. As one would expect, days with lower renewable generation are more likely to result in shortfall events. As a result, basing CF Method capacity contribution calculations on an average or 12-month by 24-hour forecast of renewable generation will tend to overstate capacity contribution, particularly if there is a significant quantity of similarly located resources of the same type already in the portfolio, or if an appreciable quantity of resource additions is being contemplated. Even if an hourly renewable generation forecast is used, capacity contributions can be overstated if the weather underlying the forecast is not consistent with that used for similarly located resources used to develop the CF Method results. Because similarly located resources of the same type would experience similar weather in actual operations, a mismatch in the underlying weather conditions used in renewable generation forecasting will create diversity in the generation supply than would not occur in actual operations. Because they are both influenced by weather, a relationship between renewable output and load is expected. To assess this relationship, PacifiCorp gathered information on daily wind and solar output from 2016-2019 and compared it to the load data from that period, the same load data that was used to determine stochastic parameters. Each of the days in the historical period was assigned to a tier based on the rank of its daily average load within that month. This was done independently for the east and west sides of the system. The seven tiers were defined as follows: Tier 1: The peak load day Tier 2: 2nd – 5th highest load days Tier 3: Days 6-10 Tier 4: Days 11-15 Tier 5: Days 16-20 Tier 6: Days 21-25 Tier 7: Days 26-31 The average wind and solar generation on the days in each tier was then compared to the average wind and solar generation for the entire month. The results indicated that west-side wind is often below average during the highest load days in a month, and above average during the lowest load days in a month. The results for other resource types were less pronounced, but do exhibit some patterns, as shown in Figure K.1 and Figure K.2. PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 247 Figure K.1 – Renewable Resources vs. High Load Conditions Figure K.2 – Renewable Resources vs. Low Load Conditions Standard stochastic evaluation of prices, loads, etc. is based on standard deviations and mean reversion statistics. The results indicate that wind and solar output does exhibit relationships with Month Ch a n g e i n C a p a c i t y F a c t o r v s M o n t h l y A v e r a g e Tier 1: Monthly Peak Load Day Tier 2: Top Days Ranked 2-5 •West wind is generally below average during high load days•East wind is often above average during high load days in the winter•Solar output is mostly near average during high load days Month Ch a n g e i n C a p a c i t y F a c t o r v s M o n t h l y A v e r a g e Tier 1: Low Days Ranked 21-25 Tier 2: Lowest Days Ranked 26-31 •All renewables tend to be above average during low load days •The impact is greatest for West wind PACIFICORP – 2023 IRP APPENDIX K – CAPACITY CONTRIBUTION 248 load, but they are poorly represented by standard deviations – a different modeling technique is necessary. Because of the complexity of the data, PacifiCorp did not attempt to develop wind and solar generation that varies by stochastic iteration for the 2023 IRP. Instead, PacifiCorp used a technique using the existing input framework: a single 8760 profile for each wind and solar resource that repeats every year. Because the load forecast rotates with the calendar, such that the peak load day moves to different calendar days, this creates differences in the alignment of load and renewable output across the IRP study horizon. The order of the 2018 historical days was rearranged so that the forecasted intra-month variation in renewable output was reasonably aligned with the intra-month variation observed in the historical period for the days in the same load tier. Each day of renewable resource output derived from the 2018 history is mapped to a specific day for modeling purposes – only the order of the day’s changes. To maintain correlations within wind and solar output, all wind and solar resources across the entire system are mapped using the same days. While this technique builds on previous modeling and produces a reasonable forecast that captures some of the relationships between wind, solar, and load, additional work is needed in future IRPs to explore the variation and diversity of solar and wind output and further relationships with load. PACIFICORP – 2023 IRP APPENDIX L – PRIVATE GENERATION STUDY 249 APPENDIX L – PRIVATE GENERATION STUDY Introduction DNV prepared the Private Long-Term Resource Assessment for PacifiCorp. A key objective of this research is to assist PacifiCorp in developing private generation resource penetration forecasts to support its 2023 Integrated Resource Plan. The purpose of this study is to project the level of private generation resources PacifiCorp’s customers might install over the next twenty years under low, base and high penetration scenarios. PACIFICORP – 2023 IRP APPENDIX L – PRIVATE GENERATION STUDY 250 DNV – www.dnv.com Page i PRIVATE GENERATION FORECAST Behind-The-Meter Resource Assessment PacifiCorp Date: February 2, 2023 DNV – www.dnv.com Page ii Table of Contents 1 EXECUTIVE SUMMARY .......................................................................................................................................... 8 1.1 Study Methodologies and Approaches ..................................................................................................................... 9 1.1.1 State-Level Forecast Approach .......................................................................................................................... 9 1.2 Private Generation Forecast .................................................................................................................................. 11 2 STUDY BACKGROUND ........................................................................................................................................ 14 3 STUDY APPROACH AND METHODS .................................................................................................................. 16 3.1 Technology Attributes............................................................................................................................................. 16 3.1.1 Solar PV ........................................................................................................................................................... 16 3.1.1.1 PV Only ....................................................................................................................................................... 17 3.1.1.2 PV + Battery ................................................................................................................................................ 18 3.1.2 Small-Scale Wind ............................................................................................................................................. 24 3.1.3 Small-Scale Hydropower .................................................................................................................................. 24 3.1.4 Reciprocating Engines ...................................................................................................................................... 25 3.1.5 Microturbines .................................................................................................................................................... 26 3.2 Customer Perspectives .......................................................................................................................................... 27 3.2.1 Customer Awareness ....................................................................................................................................... 28 3.2.2 Motivating Factors for Adoption ........................................................................................................................ 28 3.2.3 Barriers to Adoption .......................................................................................................................................... 28 3.2.4 Other Considerations ........................................................................................................................................ 28 3.2.5 Incentives Overview ......................................................................................................................................... 29 3.3 Current Private Generation Market .......................................................................................................................... 1 3.4 Forecast Methodology .............................................................................................................................................. 3 3.4.1 Economic Analysis ............................................................................................................................................. 3 3.4.2 Technical Feasibility ........................................................................................................................................... 5 3.4.3 Market Adoption ................................................................................................................................................. 6 4 RESULTS ................................................................................................................................................................. 9 4.1 Generation Capacity Results by State.................................................................................................................... 11 4.1.1 California .......................................................................................................................................................... 12 4.1.1.1 California PV Adoption by Sector ................................................................................................................ 15 4.1.2 Idaho ................................................................................................................................................................ 16 4.1.2.1 Idaho PV Adoption by Sector ...................................................................................................................... 19 4.1.3 Oregon.............................................................................................................................................................. 20 4.1.3.1 Oregon PV Adoption by Sector ................................................................................................................... 23 4.1.4 Utah .................................................................................................................................................................. 24 4.1.4.1 Utah PV Adoption by Sector ....................................................................................................................... 27 DNV – www.dnv.com Page iii 4.1.5 Washington ....................................................................................................................................................... 28 4.1.5.1 Washington PV Adoption by Sector ............................................................................................................ 30 4.1.6 Wyoming........................................................................................................................................................... 31 4.1.6.1 Wyoming PV Adoption by Sector ................................................................................................................ 33 APPENDIX A TECHNOLOGY ASSUMPTIONS AND INPUTS ......................................................................................... 34 APPENDIX B DETAILED RESULTS ................................................................................................................................. 35 APPENDIX C WASHINGTON COGENERATION LEVELIZED COSTS ............................................................................ 36 APPENDIX D OREGON DISTRIBUTION SYSTEM PLAN RESULTS .............................................................................. 38 D.1 Study Methodologies and Approaches ................................................................................................................... 39 D.1.1 State-Level Forecast Approach ........................................................................................................................ 39 D.1.2 Circuit-Level Forecasting Approach .................................................................................................................. 40 D.2 Private Generation Forecast Results ..................................................................................................................... 40 D.2.1 Circuit-Level and Substation-Level Results Findings ........................................................................................ 41 D.3 Conclusions ............................................................................................................................................................ 44 D.3.1 Future Work ...................................................................................................................................................... 45 APPENDIX E BEHIND-THE-METER BATTERY STORAGE FORECAST ........................................................................ 46 E.1 Study Methodologies and Approaches ................................................................................................................... 46 E.1.1 Battery Dispatch Modelling ............................................................................................................................... 47 E.2 Results ................................................................................................................................................................... 47 E.3 Storage Capacity Results by State ......................................................................................................................... 49 List of Figures Figure 1-1 Historic Cumulative Installed Private Generation Capacity, PacifiCorp, 2012-2021 .............................................. 8 Figure 1-2 Methodology to Determine Market Potential of Private Generation Adoption ...................................................... 10 Figure 1-3 Cumulative New Capacity Installed by Scenario (MW-AC), 2023-2042 ............................................................... 11 Figure 1-4 Cumulative New Capacity Installed by State (MW-AC), 2023-2042, Base Case ................................................. 12 Figure 1-5 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Base Case ....................................... 13 Figure 2-1 PacifiCorp Service Territory ................................................................................................................................. 14 Figure 3-1 Example Residential Summer Load Shape Compared to PV Only and PV + Battery Generation Profiles .......... 17 Figure 3-2 Cost of Residential PV Standalone, Battery Storage Retrofit to Existing PV, and PV + Battery Systems from DNV Bottom-up Cap-Ex Model, Utah .............................................................................................................................................. 21 Figure 3-3 Cost of Commercial PV Standalone, Battery Storage Retrofit to Existing PV, and PV + Battery Systems from DNV Bottom-up Cap-Ex Model, Utah .............................................................................................................................................. 21 Figure 3-4 Average Residential Solar PV System Costs, 2023-2042.................................................................................... 22 Figure 3-5 Average Non-Residential Solar PV System Costs, 2023-2042 ............................................................................ 23 DNV – www.dnv.com Page iv Figure 3-6 Average Residential Battery Energy Storage System (AC-Coupled) Costs, 2023-2042 ...................................... 23 Figure 3-7 Average Non-Residential Battery Energy Storage System (AC-Coupled) Costs, 2023-2042 .............................. 23 Figure 3-8 Historic Cumulative Installed Private Generation Capacity by Technology, YTD ................................................... 2 Figure 3-9 Methodology to Determine Market Potential of Private Generation Adoption ........................................................ 3 Figure 3-10 Bass Diffusion Curve Illustration .......................................................................................................................... 6 Figure 3-11 Willingness to Adopt Based on Technology Payback .......................................................................................... 8 Figure 4-1 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), 2023-2042 .................................. 9 Figure 4-2 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Base Case ....................................... 10 Figure 4-3 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Low Case ........................................ 10 Figure 4-4 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, High Case ........................................ 11 Figure 4-5 Cumulative New Capacity Installed by State (MW-AC), 2023-2042, Base Case ................................................. 12 Figure 4-6 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), California, 2023-2042 ............... 12 Figure 4-7 Cumulative New Capacity Installed by Technology (MW-AC), California Base Case, 2023-2042 ....................... 13 Figure 4-8 Cumulative New Capacity Installed by Technology (MW-AC), California Low Case, 2023-2042 ........................ 13 Figure 4-9 Cumulative New Capacity Installed by Technology (MW-AC), California High Case, 2023-2042 ........................ 14 Figure 4-10 Cumulative New PV Capacity Installed by Sector Across All Scenarios, California, 2023-2042 ........................ 15 Figure 4-11 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Idaho, 2023-2042 ................... 16 Figure 4-12 Cumulative New Capacity Installed by Technology (MW-AC), Idaho Base Case, 2023-2042 ........................... 17 Figure 4-13 Cumulative New Capacity Installed by Technology (MW-AC), Idaho Low Case, 2023-2042............................. 17 Figure 4-14 Cumulative New Capacity Installed by Technology (MW-AC), Idaho High Case, 2023-2042 ............................ 18 Figure 4-15 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Idaho, 2023-2042 .............................. 19 Figure 4-16 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Oregon, 2023-2042 ................ 20 Figure 4-17 Cumulative New Capacity Installed by Technology (MW-AC), Oregon Base Case, 2023-2042 ........................ 21 Figure 4-18 Cumulative New Capacity Installed by Technology (MW-AC), Oregon Low Case, 2023-2042 .......................... 21 Figure 4-19 Cumulative New Capacity Installed by Technology (MW-AC), Oregon High Case, 2023-2042 ......................... 22 Figure 4-20 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Oregon, 2023-2042 ........................... 23 Figure 4-21 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Utah, 2023-2042 .................... 24 Figure 4-22 Cumulative New Capacity Installed by Technology (MW-AC), Utah Base Case, 2023-2042 ............................ 25 Figure 4-23 Cumulative New Capacity Installed by Technology (MW-AC), Utah Low Case, 2023-2042 .............................. 25 Figure 4-24 Cumulative New Capacity Installed by Technology (MW-AC), Utah High Case, 2023-2042 ............................. 26 Figure 4-25 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Utah, 2023-2042 ............................... 27 Figure 4-26 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Washington, 2023-2042 ......... 28 Figure 4-27 Cumulative New Capacity Installed by Technology (MW-AC), Washington Base Case, 2023-2042 ................. 28 Figure 4-28 Cumulative New Capacity Installed by Technology (MW-AC), Washington Low Case, 2023-2042 ................... 29 Figure 4-29 Cumulative New Capacity Installed by Technology (MW-AC), Washington High Case, 2023-2042 .................. 29 Figure 4-30 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Washington, 2023-2042 .................... 30 Figure 4-31 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Wyoming, 2023-2042 ............. 31 DNV – www.dnv.com Page v Figure 4-32 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming Base Case, 2023-2042 ..................... 31 Figure 4-33 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming Low Case, 2023-2042 ....................... 32 Figure 4-34 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming High Case, 2023-2042 ...................... 32 Figure 4-35 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Wyoming, 2023-2042 ........................ 33 Figure D-1 Historic Cumulative Installed PG Capacity by Technology, PacifiCorp, Oregon, 2012-2021 ............................... 38 Figure D-2 Methodology to Determine Market Potential of Private Generation Adoption....................................................... 39 Figure D-3 Private Generation Forecast by Technology, PacifiCorp Oregon, All Cases ........................................................ 40 Figure D-4 Private Generation Forecast Disaggregation by Operating Area, PacifiCorp Oregon, Base Case ....................... 41 Figure D-5 Private Generation Forecast Disaggregation by Substation, PacifiCorp Oregon, Base Case .............................. 41 Figure D-6 Private Generation Forecast Disaggregation by Circuit, PacifiCorp Oregon, Base Case ..................................... 42 Figure D-7 Customer Mix of Top Five Substations Compared to the Average of All Substations .......................................... 42 Figure D-8 Customer Attributes of Selected Substations Compared to Average PacifiCorp Oregon Substation ................... 43 Figure D-9 Share of Residential Customers vs. Share of Residential PV Only Capacity in 2033, Klamath Falls Operating Area ........................................................................................................................................................................................ 44 Figure E-1 Historic Cumulative Installed Behind-the-Meter Battery Storage Capacity, PacifiCorp, 2012-2021 ..................... 46 Figure E-2 Cumulative New Battery Storage Capacity Installed by Scenario (MW), 2023-2042 ............................................ 48 Figure E-3 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, Base Case .................... 48 Figure E-4 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, Low Case ..................... 49 Figure E-5 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, High Case..................... 49 Figure E-6 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, Base Case .............................. 50 Figure E-7 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, Low Case ............................... 50 Figure E-8 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, High Case ............................... 51 Figure E-9 Cumulative New Battery Storage Capacity Installed by Scenario (MW), California, 2023-2042........................... 51 Figure E-10 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), California, 2023-2042 ............................................................................................................................................................................... 52 Figure E-11 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Idaho, 2023-2042 ............................... 53 Figure E-12 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Idaho, 2023-2042 ........................................................................................................................................................................................ 53 Figure E-13 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Oregon, 2023-2042 ............................ 54 Figure E-14 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Oregon, 2023-2042 ........................................................................................................................................................................................ 55 Figure E-15 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Utah, 2023-2042 ................................ 56 Figure E-16 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Utah, 2023-2042 ........................................................................................................................................................................................ 56 Figure E-17 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Washington, 2023-2042 ..................... 57 Figure E-18 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Washington, 2023-2042 ............................................................................................................................................................................... 58 Figure E-19 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Wyoming, 2023-2042 ......................... 59 Figure E-20 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Wyoming, 2023-2042 ............................................................................................................................................................................... 59 DNV – www.dnv.com Page vi List of Tables Table 3-1 Residential PV Only Representative System Assumptions .................................................................................... 17 Table 3-2 Non-Residential PV Only Representative System Assumptions ............................................................................ 18 Table 3-3 Residential PV + Battery Representative System Assumptions ............................................................................. 19 Table 3-4 Small Wind Assumptions ...................................................................................................................................... 24 Table 3-5 Small Hydro Assumptions ..................................................................................................................................... 24 Table 3-6 Reciprocating Engine Assumptions ...................................................................................................................... 25 Table 3-7 Microturbine Assumptions ...................................................................................................................................... 26 Table 3-8 Motivators and Barriers for Private Generation Technology Adoption .................................................................. 27 Table 3-9 Federal Investment Tax Credits for DERs ............................................................................................................... 1 Table 3-10 State Incentives for DERs ..................................................................................................................................... 1 Table 3-11 PG Forecast Economic Analysis Inputs ................................................................................................................. 4 Table 3-12 Solar Willingness-to-Adopt Curve used by State and Sector ................................................................................ 7 Table 4-1 Cumulative Adopted Private Generation Capacity by 2042, by Scenario ................................................................ 9 Table C-1 Reciprocating Engine LCOE Assumptions ............................................................................................................ 36 Table C-2 Microturbine Engine LCOE Assumptions .............................................................................................................. 36 Table C-3 LCOE Results for CHP Systems in Washington State .......................................................................................... 37 Table E-1 Cumulative Adopted Battery Storage Capacity by 2042, by Scenario ................................................................... 47 DNV – www.dnv.com Page vii ☐ Strictly Confidential For disclosure only to named individuals within the Customer’s organization. ☐ Private and Confidential For disclosure only to individuals directly concerned with the subject matter of the document within the Customer’s organization. ☐ Commercial in Confidence Not to be disclosed outside the Customer’s organization. ☐ DNV only Not to be disclosed to non-DNV staff ☒ Customer’s Discretion Distribution for information only at the discretion of the Customer (subject to the above Important Notice and Disclaimer and the terms of DNV’s written agreement with the Customer). ☐ Published Available for information only to the general public (subject to the above Important Notice and Disclaimer). DNV – www.dnv.com February 2, 2023 Page 8 1 EXECUTIVE SUMMARY DNV prepared the Long-Term Private Generation (PG) Resource Assessment for PacifiCorp (the Company) covering their service territories in Utah, Oregon, Idaho, Wyoming, California, and Washington to support PacifiCorp’s 2023 Integrated Resource Plan (IRP). This study evaluated the expected adoption of behind-the-meter (BTM) distributed energy resources (DERs) including photovoltaic solar (PV only), photovoltaic solar coupled with battery storage (PV + Battery), small wind, small hydro, reciprocating engines and microturbines over a 20-year forecast horizon (2023-2042) for all customer sectors (residential, commercial, industrial, and agricultural). The adoption model DNV developed for this study is calibrated to the current1 installed and interconnected capacity of these technologies, shown in Figure 1-1. Figure 1-1 Historic Cumulative Installed Private Generation Capacity, PacifiCorp, 2012-2021 Historic Cumulative Installed PG Capacity by State Historic Cumulative Installed PG Capacity by Technology To date, the majority of PG installed capacity and annual growth in capacity has been in Utah, which represents the largest portion go PacifiCorp’s customer population—about 50% of all PacifiCorp customers are in the Company’s Utah service territory. Roughly 99 percent of existing private generation capacity installed in PacifiCorp’s service territory is PV or PV + Battery. To inform the adoption forecast process, DNV conducted an in-depth review of the other technologies and did not find any literature to suggest that they would take on a larger share of the private generation market in the Company’s service territory in the future years of this study. For each technology and sector, DNV developed three adoption scenarios: a base case, a high case, and a low case. The base case is considered the most likely projection as it is based on current market trends and expected changes in technology costs and retail electricity rates; the high and low cases are used as sensitivities to test how changes in costs and retail rates impact customer adoption of these technologies. 1 PacifiCorp private generation interconnection data as of February 2022. 0 100 200 300 400 500 600 700 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Cu m u l a t i v e M W -AC WY WA UT OR ID CA PV Only95.7% PV + Battery3.8% Wind0.2%Small Hydro0.2% Reciprocating Engine0.0% Micro Turbine0.1% DNV – www.dnv.com February 2, 2023 Page 9 All scenarios use technology cost and performance assumptions specific to each state in PacifiCorp’s service territory in the base year (2022) of the study. The base case uses the 2022 federal income tax credit schedules2 and state incentives, retail electricity rate escalation from the AEO3 reference case, and a blended version of the NREL Annual Technology Baseline4 moderate and conservative technology cost forecasts as inputs to the modelling process. In the high case, retail electricity rates increase more rapidly, and technology costs decline at a faster rate compared to the base case. For the low case, retail electricity rates increase at a slower rate than the base case and technology costs decrease at a slower rate. 1.1 Study Methodologies and Approaches The forecasting methodologies and techniques applied by DNV in this analysis are commonly used in small-scale, behind- the-meter energy resource and energy efficiency forecasting. The methods used to develop the state and sector-level results are described in more detail below. 1.1.1 State-Level Forecast Approach DNV developed a behind-the-meter net economic perspective that includes, as costs, the acquisition and installation costs for each technology less the impact of available incentives and, as benefits, the customer’s economic benefits of ownership such as energy and demand savings and export credits. For this study we assumed that the current net metering or net billing policies and tariff structures in each state continued throughout the study horizon. This resulted in the model incorporating benefits associated with net metering in Oregon, Washington, and Wyoming and net billing in Utah and California. We assumed customers in Idaho would accrue benefits based on the net billing policy in Utah throughout the study. This analysis incorporated the current rate structures and tariffs offered to customers in PacifiCorp’s service territories. Time- of-use rates, tiered tariffs and retail tariffs that include high demand charges increased the value of PV + Battery configurations compared to PV-Only configurations while other factors such as load profiles and DER compensation mechanisms minimized the impact of such tariffs on the customer economics of PV + Battery systems. The DER compensation mechanism in Oregon, Washington, and Wyoming — traditional net metering — does not incentivize PV + Battery storage co-adoption. In net metering DER compensation schemes, customers receive export credits for excess PV generation at the same dollar-per-kWh rate that they would have otherwise paid to purchase electricity from the grid. Net billing—the mechanism modelled in California, Idaho, and Utah—does incentivize PV + Battery storage co-adoption, as customers can lower their electricity bills by charging their batteries with excess PV generation and dispatching their batteries to meet on-site load during times of day when retail energy prices are high. From the perspective of utility bill savings alone, PV + battery systems are often not the most cost-effective option for most customers. Customers who seek the reassurance and reliability of backup power show more of a willingness to pay for this product, especially if they reside in areas that are prone to outages and severe weather events. DNV combined technical feasibility characteristics of the identified PG technologies and potential customers with an economic analysis to calculate cost-effectiveness metrics for each technology, within each state that PacifiCorp serves, over the analysis timeframe. DNV then used a bass diffusion model to estimate customer PG adoption based on technical and 2H.R.5376 - Inflation Reduction Act of 2022 (https://www.congress.gov/bill/117th-congress/house-bill/5376/text). Since the passing of the Inflation Recovery Act of 2022, the federal Investment Tax Credit (ITC) has been extended past its original expiration date for ten years. For facilities beginning construction before January 1, 2025, the bill will extend the ITC for up to 30 percent of the cost of installed equipment for ten years and will then step down to 26 percent in 2033 and 22 percent in 2034. 3U.S. Energy Information Administration, Annual Energy Outlook 2022 (AEO2022), (Washington, DC, March 2022). 4NREL (National Renewable Energy Laboratory). 2021. 2021 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. DNV – www.dnv.com February 2, 2023 Page 10 economic feasibility and incorporated existing adoption of each PG technology by state and customer segment as an input to the adoption model. Technical feasibility characteristics were used to identify the potential customer base that could technically support the installation of a specific PG technology, or the maximum, feasible, adoption for each technology by sector. These factors included overall PG metrics such as average customer load shapes and system size limits by state, and specific technology factors such as estimated rooftop space and resource access based on location (for hydro and wind resource applicability). Simple payback was used in the customer adoption portion of the model as an input parameter to bass diffusion curves that determined future penetration of all PG technologies. The methodology and major inputs to the analysis are shown in Figure 1-2. Changes to technology costs and retail electricity rates used in the high and low cases impact the economic portion of the analysis. Figure 1-2 Methodology to Determine Market Potential of Private Generation Adoption DNV developed Bass diffusion curves customized for each technology, state, and sector that also accounted for variation in willingness-to-adopt as cost effectiveness changes over time. The Bass diffusion curves were used to model annual and cumulative market adoption. Bass diffusion curves are widely used for forecasting technology adoption. Diffusion curves typically take the form of an S-curve with an initial period of slow early adoption that increases as the technology becomes more mainstream and eventually tapers off amongst late adopters. The upper limit of the curve is set to the maximum level of market adoption. In this analysis, the long-term maximum level of market adoption was based on payback. As payback was calculated by year in the economic analysis to capture the changing effects of market interventions over time, the maximum level of market adoption in the diffusion curves vary by year in the study. The Bass diffusion curves used in the market potential analysis are characterized by three parameters—an innovation coefficient, an imitation coefficient, and the ultimate market potential. Together, these three parameters also determine the time to reach maximum adoption and overall shape of the curve. The innovation and imitation parameters were calibrated for each technology and sector, based on current market penetration and when PacifiCorp started to see the technology being adopted in each of its service territories. The calibrated curves show some segments still in the very early phases of adoption, while other markets are more mature. Market Potential Economic Analysis Technology costs Installation and O&M costs Local and federal incentives Benefits of ownership Energy savings Net billing, net metering export credits Technical Feasibility System performance constraints Customer load shapes System size limits Land-use requirements Non-shaded rooftop space Access to unprotected streams and dams, wind resource DNV – www.dnv.com February 2, 2023 Page 11 1.2 Private Generation Forecast In the base case scenario, DNV estimates 3,181 MW of new private generation capacity will be installed in PacifiCorp’s service territory over the next twenty years (2023-2042). Figure 1-3 shows the base, low and high case scenarios. The low case scenario estimates 2,028 MW of new capacity over the 20-year forecast while the high case estimates 3,196 MW of new private generation capacity installed by 2042. Figure 1-3 Cumulative New Capacity Installed by Scenario (MW-AC), 2023-2042 The sensitivity analysis showed a much greater margin of uncertainty on the low side than the high side. The Inflation Reduction Act of 2022 (IRA) extends tax credits for private generation that create very favorable economics for adoption, and those are embedded in the base case. We therefore limited our upper bound forecast to lower technology costs and higher retail electricity rates, and these produced only a small boost to adoption for technologies that were already cost effective under the IRA. In contrast, when we modelled our lower bound, we found that the increases to customer payback period were enough to tamp down adoption by a wider margin. The low case assumed higher technology costs and lower retail electricity rates than the other cases, reducing the economic appeal of private generation despite incentives being unchanged. The low case forecast is 36% less than the base case, while the high case cumulative installed capacity forecasted over the 20-year period is just 0.5% greater than the base case. Figure 1-4 shows the base case forecast by state, compared to the previous (2020) study’s total base case forecast.5 This figure indicates that Utah and Oregon will drive most PG installations over the next two decades, which is to be expected given these two states represent the largest share of PacifiCorp’s customers and sales. The base scenario estimates approximately 1,447 MW of new capacity will be installed over the next 10 years in PacifiCorp’s territory—55% of which is in Utah, 32% in Oregon, and 6% in Idaho. Since the 2020 study, the federal Investment Tax Credit (ITC) has been extended for ten years at its original base rate levels and expanded to include energy storage. The tax credit increase and extension lowered the customer payback period for all technologies, making the customer economics of this study’s base case more 5 Cumulative capacity is adjusted to account for the difference in the forecast starting years (2021 in the previous study, versus 2023 in this study). Source: Navigant. 2020. “Private Generation Long-Term Resource Assessment (2021-2040)” 0 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 12 similar to the previous study’s high case. In addition to the change in customer economics, projected PV capacity is expected to grow at a faster rate in the early years and at a slower rate towards the end of the forecast period. The key drivers of these differences include larger average PV system sizes, a steeper decline in PV + Battery costs at the start of the forecast period, and the maturity of rooftop PV technology. Figure 1-4 Cumulative New Capacity Installed by State (MW-AC), 2023-2042, Base Case In Figure 1-5 below, the base case forecast is presented by technology for all states in PacifiCorp’s service territory. First year PV Only is estimated to grow by 76 MW and PV + Battery by 3 MW. These two technologies make up 99% of new installed private generation capacity forecasted. The results section of the report contains results by technology for the high, base, and low sectors. Additionally, total PV capacity forecasted is presented by sector in that section as well. - 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC CA ID OR UT WA WY 2020 DNV – www.dnv.com February 2, 2023 Page 13 Figure 1-5 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Base Case . - 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 14 2 STUDY BACKGROUND DNV prepared this Private Generation Long-term Resource Assessment on behalf of PacifiCorp and representing their service territory in six states—shown in Figure 2-1—California, Idaho, Oregon, Utah, Washington, and Wyoming. In this study, private generation technologies provide behind-the-meter energy generation at the customer site and are designed for the purpose of offsetting customer load and/or peak demand. The purpose of this study is to support PacifiCorp’s 2023 Integrated Resource Plan by projecting the level of private generation resources PacifiCorp’s customers may install over the next two decades under base, low, and high adoption scenarios. In addition to private generation, DNV also considered the cost-effective potential for high-efficiency cogeneration in Washington, consistent with the 480-109-060 (13) and 480-109- 100 (6) of the Washington Administrative Code (WAC). Figure 2-1 PacifiCorp Service Territory Although there have been six previous studies involving private generation, DNV developed its assumptions, inputs, methodologies, and forecasts independently from these prior assessments that had been performed for PacifiCorp. The forecasting methodologies and techniques applied by DNV in this analysis are commonly used in small-scale, behind-the- meter energy resource and energy efficiency forecasting. This study evaluated the expected adoption of behind-the-meter technologies over the next 20 years, including: 1. Photovoltaic (Solar PV) Systems 2. Solar PV Paired with Battery Storage 3. Small Scale Wind 4. Small Scale Hydro 5. Reciprocating Engines Pacific Power Rocky Mountain Power W AS HI NGT ON I DAHO CALIF ORNIA W Y OMI NG UT AH ORE GON DNV – www.dnv.com February 2, 2023 Page 15 6. Microturbines Project sizes were determined based on average customer load across the commercial, irrigation, industrial and residential customer classes for each state. The project sizes were then limited by each state’s respective system size limits. Private generation adoption for each technology was estimated by sector in each state in PacifiCorp’s service territory. DNV – www.dnv.com February 2, 2023 Page 16 3 STUDY APPROACH AND METHODS DNV used applicability/ technical feasibility, customer perspectives towards PGs, and project economics as the basis for forecasting expected market adoption of each private generation technology. 3.1 Technology Attributes The technology attributes define the reference systems and their key attributes such as capacity factors, derate factors, and costs which are used in thepayback and adoption analyses. A full list of detailed technology attributes and assumptions by state and sector is provided in Appendix A. The following information provides a high-level summary of the key elements of the technologies assessed in this analysis. 3.1.1 Solar PV Solar photovoltaic (PV) systems convert sunlight into electrical energy. DNV modeled representative PV system energy output for residential and non-residential systems in each state to estimate first-year production. To model hourly production, DNV leveraged its SolarFarmer and Solar Resource Compass APIs. DNV’s Solar Resource Compass API accesses and compares irradiance data from multiple data providers in each region. Solar Resource Compass also generates monthly soiling loss estimates for both dust soiling and snow soiling, as well as a monthly albedo profile. By incorporating industry standard models and DNV analytics, precipitation and snowfall data is automatically accessed and used to estimate the impact on energy generation. Total PV capacity is forecasted by two different technology configurations: PV Only and PV + Battery.The PV technology in the PV + Battery systems were modeled using the same specifications as the PV Only technology, with the exception of nameplate capacity. DNV determined that average system sizes for PV + Battery configurations are on average larger than PV Only systems. DNV further segmented the PV + Battery technology by new PV + Battery systems installed together and a Battery Retrofit case—where a battery is added to an existing PV system. The PV Only forecast presented in the results section of this report is net of customers who later adopt an add-on battery system (Battery Retrofit), and therefore become a part of the PV + Battery forecast. DNV assumes that customers in the Battery Retrofit case do not represent new incremental PV MW- AC capacity, however the generation profile of the customer changes from PV Only to PV + Battery. An example residential customer load profile for two summer days is presented in Figure 3-1 to illustrate the difference between the generation profiles of PV Only and PV + Battery systems in this analysis. DNV – www.dnv.com February 2, 2023 Page 17 Figure 3-1 Example Residential Summer Load Shape Compared to PV Only and PV + Battery Generation Profiles 3.1.1.1 PV Only Table 3-1 provides the representative system specifications used to model residential standalone PV adoption. DC/AC ratio assumptions are derived from DNV's experience in the residential PV industry. Table 3-1 Residential PV Only Representative System Assumptions System Performance Units CA ID OR UT WA WY Nameplate Capacity kW-DC 6.5 6.0 6.8 5.5 10.0 5.5 Module Type n/a c-Si c-Si c-Si c-Si c-Si c-Si PV Inverter n/a Microinverter Installation Requirements n/a Fixed-tilt Roof Mounted Capacity Factor kWh/(kW-DC x 8760 hrs/yr) 13% 15% 16% 15% 13% 16% DC/AC Derate Factor n/a 1.118 1.123 1.121 1.129 1.132 1.118 0.00 1.00 2.00 3.00 4.00 5.00 6.00 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 Po w e r ( k W ) Hour of Day (Hour Ending MT) Customer Load (Gross)PV Only Generation (Gross)PV + Battery Generation (Net Effective) DNV – www.dnv.com February 2, 2023 Page 18 Table 3-2 provides the representative system specification used to model non-residential standalone PV adoption. DC/AC ratio assumptions are derived from Wood Mackenzie's H1 2022 US solar PV system pricing report. The nameplate capacity of the system is dependent on the average customer size for each non-residential sector and state. Table 3-2 Non-Residential PV Only Representative System Assumptions System Performance Units CA ID OR UT WA WY Nameplate Capacity kW-DC 30-150 37-100 30-115 60-750 20-100 18-25 Module Type n/a c-Si c-Si c-Si c-Si c-Si c-Si PV Inverter n/a Three-phase string inverter Installation Requirements n/a Flat Roof Mounted Capacity Factor kWh/(kW-DC x 8760 hrs/yr) 14% 13% 12% 14% 12% 12% DC/AC Derate Factor n/a 1.30 1.30 1.30 1.30 1.30 1.30 The full list of nameplate capacity assumptions by sector and state can be found in Appendix A. For all PV systems, DNV assumed a linear degradation rate of 0.5% across the expected useful life of the system. 3.1.1.2 PV + Battery Technology attributes consist of a representative system, operational data, cost assumptions, and capital costs which are used in conjunction to develop a total installed cost in dollars per kW. DNV reviewed PacifiCorp’s history of interconnected projects to develop its customer level assumptions for number of batteries, usable energy capacity, and rated power at the state level. The resulting representative composite system is used for operational parameters and costs to be used for long- term adoption and forecasting purposes. DNV assumes a fully integrated battery energy storage system (BESS) product for the residential sector, which will include a battery pack and a bi-directional inverter based on leading residential battery energy storage manufacturers such as Tesla, Enphase, and Sonnen providing fully integrated BESS solutions. Table 3-3 presents the representative residential PV + Battery system assumptions used in this analysis. The system specifications for the commercial, industrial, and irrigation sector are listed in Appendix A. DNV – www.dnv.com February 2, 2023 Page 19 Table 3-3 Residential PV + Battery Representative System Assumptions Technology System Performance Units CA ID OR UT WA WY PV Nameplate Capacity kW-DC 9.5 8.8 10.6 8.1 13.6 8.6 BESS Total Usable Energy Capacity kWh 12.5 12.5 14.0 12.5 14.0 10.0 Total Power kW 5.0 5.0 7.0 5.0 7.0 5.0 Battery Duration Hrs 2.5 2.5 2.0 2.5 2.0 2.0 Roundtrip Efficiency % 89% Battery Pack Chemistry n/a Lithium-ion NMC (Nickel, Manganese, Cobalt) Residential and non-residential BESS can be installed as a standalone system, added to an existing PV system, or the system can be installed with a new PV system. DNV assumed all battery installations would be co-located with a PV system in an AC-coupled configuration, as standalone systems are ineligible for the federal ITC—explained further in section 3.2.5. Battery adoption was forecasted separately for PV + Battery systems installed together, and the Battery Retrofit case— where a battery is added to an existing PV system. The basis of the Battery Retrofit forecast is the existing PV capacity in PacifiCorp’s service territories and the PV Only capacity forecasted in this analysis. For the purpose of forecasting private generation capacity, the Battery Retrofit forecast is presented in the results section as a part of the PV + Battery capacity forecast. In the behind-the-meter battery storage capacity forecast, presented in Appendix E, the Battery Retrofit case is split out in the presentation of the results. Battery degradation was modeled using DNV’s Battery AI, a data-driven battery analytics tool that predicts short-term and long-term useable energy capacity degradation under different usage conditions. It combines laboratory cell testing data with artificial intelligence (AI) technologies to provide an estimation for battery energy capacity degradation over time. In this analysis, Battery AI models several current-generation, commercially available Nickel Manganese Cobalt (NMC) cells were used to predict expected degradation performance of “generic” cells. These cells were tested in the lab over periods of 6 – 12 months at multiple temperatures, C-rates, SOC ranges, and cycling/resting conditions. Predictions are generally constrained to within the bounds of the testing data. DNV has not explicitly modeled battery end-of-life (EOL), due to a lack of testing data in this region of operation. Earlier of 20-years or 60% capacity retention is generally considered to represent EOL. Both cycling and calendar effects were considered in the degradation assessment. It is also assumed the battery cell temperature will be controlled to be around 25°C for majority of the time with proper thermal management (ventilation, HVAC). DNV notes that temperature plays a key role in battery degradation. Continuous operation under extreme low or high temperatures will accelerate degradation in battery state of health. Cost Assumptions Cost assumptions are used in conjunction with representative system parameters to develop system costs. The costs are developed for each state and sector, inclusive of hardware, labor, permitting and interconnection fees, as well as provisions for sales and marketing, overhead, and profit. For labor costs, we used state level data from the US Bureau of Labor Statistics (BLS) for electricians, laborers (construction), and electrical engineers. DNV – www.dnv.com February 2, 2023 Page 20 Total installed costs (or capital expenditures) are based on cost assumptions that were developed on a bottom-up basis— including hardware, installation/interconnection, as well as a provision for sales, general, and administrative costs and overhead. Capital expenditures (Cap-Ex) are expenditures required to achieve commercial operation in a given year. Pricing is indicative of a cash sale, not a lease or PPA, and it does not account for ITC or local rebates. Examples of total installed costs by category for residential and commercial customers in Utah are shown in Figure 3-2 and Figure 3-3, respectively. The full set of cost and incentive assumptions used in the analysis can be found in Appendix A. DNV – www.dnv.com February 2, 2023 Page 21 Figure 3-2 Cost of Residential PV Standalone, Battery Storage Retrofit to Existing PV, and PV + Battery Systems from DNV Bottom-up Cap-Ex Model, Utah Figure 3-3 Cost of Commercial PV Standalone, Battery Storage Retrofit to Existing PV, and PV + Battery Systems from DNV Bottom-up Cap-Ex Model, Utah DNV has estimated all CapEx categories for the projects based on Wood Mackenzie's US 2022 H1 cost model, which has been found to be reasonable relative to actual CapEx that DNV has observed on projects it's reviewed in the past. DNV estimated the benchmark CapEx values based on the project capacity, location, and technology assumptions for each state and sector. When technology assumptions were unavailable, DNV made reasonable assumptions. Combined PV + Battery $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 PV Only (8 kW)Battery Retrofit (5 kW/12.5kWh)PV (8 kW) + Battery (5kW/12.5 kWh) 20 2 2 U S D Overhead & Profit Sales Tax Supply Chain and Logistics Customer Acquisition Permitting, Interconnection, &InspectionDesign & Engineering Install Labor Balance of System Battery Inverter Battery Pack PV Inverter PV Module $0 $50,000 $100,000 $150,000 $200,000 $250,000 $300,000 $350,000 PV Only (156 kW)Battery Retrofit (35kW/140 kWh)PV (156 kW) + Battery(35 kW/140 kWh) 20 2 2 U S D EPC and DeveloperOverhead & Margin Sales Tax Permitting, Interconnection &Inspection Install Labor and Design &Engineering Balance of System Battery Inverter Battery Pack PV Inverter PV Module DNV – www.dnv.com February 2, 2023 Page 22 systems were assumed to have cost efficiencies in certain categories that would reduce the total cost of the system when installed at the same time. Cap-Ex categories assumed to have cost efficiencies for combined systems include electrical and structural balance of system, installation labor, design & engineering, permitting, interconnection & inspection costs, customer acquisition costs, supply chain and logistics, and overhead and profit costs. DNV used a blended version of the NREL Annual Technology Baseline6 moderate and conservative solar PV and battery energy storage system technology cost forecasts in the base case of this private generation forecast. The average residential and non-residential PV system cost forecasts are presented in Figure 3-4 and Figure 3-5, and the average residential and non-residential battery cost forecasts are shown in Figure 3-6 and Figure 3-7. DNV reviewed the costs presented in the NREL dataset and found that the moderate cost decline forecast for solar PV was much more aggressive than what DNV’s national cost models are predicting and what has been seen in the market historically. The technology cost forecast used in the base case has a 37% price decrease in the first 10 years, as opposed to the 50% decrease forecasted in the NREL moderate case. Figure 3-4 Average Residential Solar PV System Costs, 2023-2042 6NREL (National Renewable Energy Laboratory). 2021. 2021 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. - 500 1,000 1,500 2,000 2,500 3,000 3,500 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 20 2 2 $ / k W -DC Low Base High DNV – www.dnv.com February 2, 2023 Page 23 Figure 3-5 Average Non-Residential Solar PV System Costs, 2023-2042 Figure 3-6 Average Residential Battery Energy Storage System (AC-Coupled) Costs, 2023-2042 Figure 3-7 Average Non-Residential Battery Energy Storage System (AC-Coupled) Costs, 2023-2042 - 500 1,000 1,500 2,000 2,500 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 20 2 2 $ / k W -DC Low Base High - 200 400 600 800 1,000 1,200 1,400 1,600 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 20 2 2 $ / k W -DC Low Base High - 100 200 300 400 500 600 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 20 2 2 $ / k W -DC Low Base High DNV – www.dnv.com February 2, 2023 Page 24 3.1.2 Small-Scale Wind Distributed wind technology is a relatively mature DER. Small-scale wind systems typically serve rural homes, farms, and manufacturing facilities due to their size and land requirements. Wind turbines generate electricity by converting kinetic energy in the wind into rotating shaft power that spins an AC generator. Assumptions on system capacity sizes in each state and sector are detailed in Appendix A. Table 3-4 provides the cost and performance assumptions used in the small-scale wind forecast and the source for each. Table 3-4 Small Wind Assumptions Cost & Performance Metric Units Residential (20 kW or less) Commercial (21-100 kW) Midsize (101-999 kW) Sources Installed Cost 2022$/kW $6,185 $4,686 $3,015 NREL, 2022. Distributed Wind Energy Futures Study. https://www.nrel.gov/docs/fy22osti/82519.pdf Annual Installed Cost Change %, 2022-2042 -1.9% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Fixed O&M 2022$/kW-yr $38 $38 $38 NREL, 2022. Distributed Wind Energy Futures Study. https://www.nrel.gov/docs/fy22osti/82519.pdf Annual Fixed O&M Cost Change %, 2022-2042 -3.5% -1.9% -1.9% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Capacity Factor (dependent on state) % 7.7-10.8% 15.1%-18.5% 15.2%-18.4% System Advisor Model Version 2021.12.2. National Renewable Energy Laboratory. Golden, CO. https://sam.nrel.gov 3.1.3 Small-Scale Hydropower Hydroelectric power is an established, mature technology, but small-scale systems are a newer permutation of the technology and therefore are still quite costly compared to other private generation technologies. Small hydro systems generate electricity by transforming potential energy from a water source into kinetic energy that rotates the shaft of an AC generator. Assumptions on system capacity sizes in each state and sector are detailed in Appendix A. Table 3-5 provides the cost and performance assumptions used in the small hydro forecast and the source for each. Table 3-5 Small Hydro Assumptions Cost & Performance Metric Units Micro-hydro (100 kW or less) Mini-hydro (100 kW-1 MW) Sources Installed Cost 2022$/kW $5,190 $3,892 International Renewable Energy Agency (IRENA). 2012. "Renewable Energy Cost Analysis: Hydropower" DNV – www.dnv.com February 2, 2023 Page 25 Annual Installed Cost Change %, 2022-2042 -0.2% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Fixed O&M 2022$/kW-yr $208 $156 International Renewable Energy Agency (IRENA). 2012. "Renewable Energy Cost Analysis: Hydropower" Annual Fixed O&M Cost Change %, 2022-2042 -1.9% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Capacity Factor % 45% 45% International Renewable Energy Agency (IRENA). 2012. "Renewable Energy Cost Analysis: Hydropower" 3.1.4 Reciprocating Engines Combined heat and power (CHP), or cogeneration, is a mature technology that has been used in the power sector and as a private generation resource for decades. The two most common CHP technologies for commercial and small- to medium- industrial applications are reciprocating engines and microturbines, used to produce both onsite power and thermal energy. Reciprocating engines are a mature, reliable technology that perform well at part-load operation in both baseload and load following applications. Reciprocating engines can be operated with a wide variety of fuels; however, this analysis assumes natural gas is used to generate electricity as it is the most commonly used fuel in CHP applications. A reciprocating engine uses a cylindrical combustion chamber with a close-fitting piston that travels the length of the cylinder. The piston connects to a crankshaft that converts the linear motion of the piston into rotating motion. Reciprocating engines start quickly and operate on normal natural gas delivery pressures without additional gas compression. The thermal energy output from system operation can be used to produce hot water or low-pressure steam, or chilled water with the additional of an absorption chiller. Typical CHP applications for reciprocating engine systems in the Pacific Northwest include universities, hospitals, wastewater treatment facilities, agricultural applications, commercial buildings, and small- to medium-sized industrial facilities.7 Assumptions on system capacity sizes in each state and sector are detailed in Appendix A. Two representative reciprocating engine sizes were used in this analysis based on the ability to meet average customer minimum electric load, ranging from less than 100 kW to 1 MW. Table 3-6 provides the cost and performance assumptions used in the reciprocating engine forecast and the source for each. Table 3-6 Reciprocating Engine Assumptions Cost & Performance Metric Units Small (100 kW or less) Medium (100 kW-1 MW) Sources Installed Cost 2022$/kW $4,189 $3,183 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. Annual Installed Cost Change %, 2022-2042 -0.5% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ 7 U.S. Department of Energy Combined Heat and Power and Microgrid Installation Databases (2022). Available at: https://doe.icfwebservices.com/chp DNV – www.dnv.com February 2, 2023 Page 26 Variable O&M 2022$/MWh $28 $25 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. Annual Variable O&M Cost Change %, 2022-2042 -1.9% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Electric Heat Rate (HHV) Btu/kWh 11,765 9,721 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. 3.1.5 Microturbines Microturbines are another CHP application that are commonly used in smaller commercial and inustrial applications. They are smaller combustion turbines that can be stacked in parallel to serve larger loads and provide flexibility in deployment and interconnection at customer sites. Microturbines can use gaseous or liquid fuels, but for CHP applications natural gas is the most common fuel. Therefore for this analysis DNV assumed microturbines will use natural gas to generate electricity and thermal energy at customer sites. Microturbines operate on the Brayton thermodynamic cycle where atmospheric air is compressed, heated by burning fuel and then used to drive a turbine that in turn drives an AC generator. A microturbine can have exhaust temperatures in the range of 500 to 600⁰F, which can be used to produce steam, hot water, or chilled water with the additional of an absorption chiller in CHP applications. Microturbine efficiency declines significantly as load decreases, therefore the technology is best suited to operate in base load applications operating at or near full system load. Common microturbine CHP installations in the Pacific Northwestinclude small universities, commercial buildings, small manufacturing operations, hotels, and wastewater treatment facilities.7 Assumptions on system capacity sizes in each state and sector are detailed in Appendix A. Two representative microturbine sizes were used in this analysis based on the ability to meet average customer minimum electric load, ranging from less than 100 kW to 1 MW. Table 3-7 provides the cost and performance assumptions used in the reciprocating engine forecast and the source for each. Table 3-7 Microturbine Assumptions Cost & Performance Metric Units Small (less than 100 kW) Medium (100 kW-1 MW) Sources Installed Cost 2022$/kW $3,742 $3,686 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. Annual Installed Cost Change %, 2022-2042 -0.6% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ Variable O&M 2022$/MWh $19 $15 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. Annual Variable O&M Cost Change %, 2022-2042 -1.9% NREL. 2021. "2021 Annual Technology Baseline." Golden, CO: National Renewable Energy Laboratory. https://atb.nrel.gov/ DNV – www.dnv.com February 2, 2023 Page 27 Electric Heat Rate (HHV) Btu/kWh 13,648 11,566 "A Comprehensive Assessment of Small Combined Heat and Power Technical and Market Potential in California." 2019. California Energy Commission. 3.2 Customer Perspectives Customers’ attitudes towards, and general understanding of, private generation technologies, projects, and initiatives currently being promoted in the market today will vary based on a variety of factors covered in this section. DNV has combined internal expertise with an aggregation of customer-focused research from reputable sources to understand overall trends in customer sentiment and insights specifically related to private generation for residential or nonresidential buildings.. Some of the key motivators and barriers to private generation technology adoption are presented in Table 3-8. Table 3-8 Motivators and Barriers for Private Generation Technology Adoption TECHNOLOGY MOTIVATORS BARRIERS ALL • Cost savings • Reducing carbon footprint • Educational awareness • Proactive involvement from customer • Minimal understanding of technology applications SOLAR PV • Cost savings • Reducing carbon footprint • Attractive financing options • Initial investment • Infrastructure requirements i.e., physical space and roof quality • Perception as a technology for the affluent BATTERY STORAGE • Cost savings • Resilience/backup power • likelihood to experience to severe weather • Reduce peak consumption • Low levels of awareness and understanding • Short duration capability for backup • Limited monetization opportunities • Physical space and roof quality • Initial investment • Limited use cases for storage-only SOLAR + BATTERY • Resilience/backup power • ITC applicability window • Maximize solar generation • Cost savings • Reducing carbon footprint • Initial investment • Infrastructure requirements of solar Customer adoption of solar, storage, and other PG-related solutions is primarily influenced by financial viability of the overall project and the associated return on investment or payback period. However, while the financial parameters and payment options for a project are certainly an important feature, customers will also face different barriers or motivators that will either encourage or discourage them from adoption despite the financial benefits. For these reasons, research organizations have typically viewed adoption of new and innovative technologies by customer segments ranging from early adopters and enthusiasts to the majority and the laggards. Some customers may even be considered opposed to the innovation and will never adopt the technology. On the other hand, there also exists a consumer group that will move forward with adoption of DER offerings even when the financial numbers don’t show the most desirable ROI or payback. This consumer group is more easilyinfluenced by sales and marketing strategies even when the numbers don’t “add up” to a clear economic play. The following sections will provide further insights on how customer awareness, DNV – www.dnv.com February 2, 2023 Page 28 knowledge of energy costs and systems, and incentives can impact customer adoption of PG technologies. 3.2.1 Customer Awareness While DERs, the term most commonly used to describe PG technologies is a common term within the energy industry, it is not commonly understood by the average consumer. Less than 10% of residential customers are clear on exactly what the term means and how it applies to them. Consumers are lacking a sound understanding of how DERs work, the tangible benefits they provide, and how they would operate within a home or business. Customer education to build awareness is likely to lead to more growth of PG. Educational outreach and marketing should focus on accessible, feasible use-cases for technology applications in “real-world” settings that customers can relate to and see themselves using. Customers have a desire to improve their understanding of PG opportunities by obtaining quality information – most prefer their electricity provider as the source – about the savings potential of these technologies and details on how they work. 8 3.2.2 Motivating Factors for Adoption The primary motivators that prompt customers to consider implementing PG technologies are how much savings they can realize through a project and the level of incentives being awarded. Second to these financial motivators, customers are interested in PG opportunities as a method of reducing their environmental impact. Customers who are aware of PG opportunities often have a curiosity and desire to increase their understanding of the opportunities available to them as committing to a PG system or product requires the customer to have a greater level of involvement in their electricity generation, consumption, and management. While understanding and awareness of PG is a clear barrier to adoption, customers have the desire to obtain information to help them better understand these technologies. Energy providers can prioritize informative, engaging communication to increase the customers’ understanding of DER opportunities, thus increasing their likelihood of adoption and participation.7 3.2.3 Barriers to Adoption Trust and finances are common barriers to PG adoption– customers are often skeptical that these projects will perform as advertised and save the amount of money that is claimed. Customers need quality information to help them validate the investment in certain new technologies or programs that they do not have experience with. If the customer’s goal for a PG system is to save money and they express the need to understand how much money the projects will save, accurate information needs to be available to prove those cases to the customer. Successful implementation of PG technologies and solutions will require changing the behavior and perception of a large portion of the customers.7 3.2.4 Other Considerations Customers who participate in demand response programs are more likely to own a hybrid or electric vehicle, energy management system (EMS), or solar + storage system than customers who do not participate in demand response programs. A foundational piece for growing participation in DER initiatives can be first focusing on demand response programs as a way for customers to get started on their clean energy journeys. This concept of “DER stacking” enables a utility to prioritize targeting customers who are already participating in some form of demand response or PG-related program, thus giving the customer a more holistic solution for their energy management and consumption.7 8 SECC (Smart Energy Consumer Collaborative). 2019. Distributed Energy Resources: MEETING CONSUMER NEEDS. Pages 7 – 13. DNV – www.dnv.com February 2, 2023 Page 29 3.2.5 Incentives Overview Since the passing of the Inflation Recovery Act of 2022, the federal Investment Tax Credit (ITC) has been extended past its original expiration date for ten years. For facilities beginning construction before January 1, 2025, the bill will extend the ITC for up to 30 percent of the cost of installed equipment for ten years and will then step down to 26 percent in 2033 and 22 percent in 2034. For projects beginning construction after 2019 that are placed in service before January 1, 2022, the ITC would be set at 26 percent. In addition to the new federal ITC schedule for generating facilities, the updated ITC includes credits for standalone energy storage with a capacity of at least 3 kWh for residential customers and 5 kWh for non- residential customers. The bill also includes a 5-year MACRS depreciation schedule for non-residential energy storage. The federal tax credits in Table 3-9 were included in the economic analysis of all private generation forecast scenarios. DNV – www.dnv.com February 2, 2023 Page 1 Table 3-9 Federal Investment Tax Credits for DERs Cells in green represent the transition to a technology-neutral ITC for clean energy technologies with 0 gCO2e emissions per kWh, under section 48D. INCENTIVE SYSTEM SIZE (KW) TECHNOLOGY 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035+ Residential/ Business ITC < 1000 PV 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0% Residential/ Business ITC < 1000 Energy Storage 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 26% 0% Residential/ Business ITC < 1000 Small Wind 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0% Business ITC < 1000 Microturbines 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0% Business ITC < 1000 Reciprocating Engines 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0% Business ITC < 150 Small Hydro (hydropowered dams) 30% 30% 30% Business ITC < 25 Small Hydro (Hydrokinetic pressurized conduits) 30% 30% 30% Business ITC < 1000 Small Hydro 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0% A summary of the state incentives included in the economic analysis are provided below in Table 3-10. DNV – www.dnv.com February 2, 2023 Page 1 Table 3-10 State Incentives for DERs STATE RESIDENTIAL NON-RESIDENTIAL Oregon9 PV-Only: Up to $5,000 PV + Battery: Up to $2,500 $0.20/watt up to $20,000 Utah10 PV: 2022—$800 2023—$400 Non-PV: Up to $2,000 Up to 10 percent of the eligible system cost or up to $50,000* Idaho11 Annual maximum of $5,000, and $20,000 over four years** None California None None Washington None None Wyoming None None * Solar PV, wind, geothermal, hydro, biomass or certain renewable thermal technologies ** Mechanism or series of mechanisms using solar radiation, wind or geothermal resource 3.3 Current Private Generation Market To date, about 99 percent of existing private generation capacity installed in PacifiCorp’s service territory is PV or PV + Battery12. To inform the adoption forecast process, DNV conducted an in-depth review of the other technologies and did not find any literature to suggest that they would take on a larger share of the private generation market in the Company’s service territory in the future years of this study. Figure 3-8 shows the current share of private generation capacity by technology in each of PacifiCorp’s six-state service territory. 9 Incentives provided through Energy Trust of Oregon (Solar for Your Home, Solar Within Reach and Solar for Your Business) and Oregon Department of Energy (Solar + Storage Rebate Program for Low-Moderate Income and Non-Income Restricted Homeowners). https://energytrust.org/programs/solar/ https://www.oregon.gov/energy/Incentives/Pages/Solar-Storage-Rebate-Program.aspx 10 Incentives provided through Utah Office of Energy Development Renewable Energy Systems Tax Credit. https://energy.utah.gov/tax-credits/renewable-energy-systems-tax-credit/ 11 Incentives provided through the State of Idaho Renewable Alternative Tax Deduction. https://legislature.idaho.gov/statutesrules/idstat/title63/t63ch30/sect63-3022c/ 12 PacifiCorp private generation interconnection data as of February 2022. DNV – www.dnv.com February 2, 2023 Page 2 Figure 3-8 Historic Cumulative Installed Private Generation Capacity by Technology, YTD PG Capacity Installed: 12.5 MW-AC PG Capacity Installed: 13.4 MW-AC PG Capacity Installed: 117.4 MW-AC PG Capacity Installed: 452.3 MW-AC PG Capacity Installed: 24.2 MW-AC PG Capacity Installed: 4.1 MW-AC PV Only99% PV + Battery 1% Wind0% Small Hydro0% Reciprocating Engine0% Micro Turbine0% CA PV Only94% PV + Battery4% Wind2% Small Hydro0% Reciprocating Engine0% Micro Turbine0% ID PV Only97% PV + Battery 2% Wind0% Small Hydro0% Reciprocating Engine0% Micro Turbine1% OR PV Only95% PV + Battery5% Wind0% Small Hydro0% Reciprocating Engine0% Micro Turbine0% UT PV Only99% PV + Battery1% Wind0% Small Hydro0% Reciprocating Engine0%Micro Turbine0% WA PV Only 89% PV + Battery4% Wind7% Small Hydro0% Reciprocating Engine0% Micro Turbine0% WY DNV – www.dnv.com February 2, 2023 Page 3 Section 3.4.3 describes in further detail how the historic private generation adoption data is used in the private generation forecast modelling process. 3.4 Forecast Methodology DNV combined technical feasibility characteristics of the identified PG technologies and potential customers with an economic analysis to calculate cost-effectiveness metrics for each technology, within each state that PacifiCorp serves, over the analysis timeframe. DNV then used a bass diffusion model to estimate customer PG adoption based on technical and economic feasibility and incorporated existing adoption of each PG technology by state and customer segment as an input to the adoption model. Technical feasibility characteristics were used to identify the potential customer base that could technically support the installation of a specific PG technology, or the maximum, feasible, adoption for each technology by sector. These factors included overall PG metrics such as average customer load shapes and system size limits by state, and specific technology factors such as estimated rooftop space and resource access based on location (for hydro and wind resource applicability). Simple payback was used in the customer adoption portion of the model as an input parameter to bass diffusion curves that determined future penetration of all PG technologies. Figure 3-9 provides a visual representation of how different inputs were used in different portions of the model. Additional detail on the economic and adoption approaches used in this analysis are provided in the subsequent sections. Figure 3-9 Methodology to Determine Market Potential of Private Generation Adoption 3.4.1 Economic Analysis The economic analysis portion of overall customer adoption was used a key factor in the Bass diffusion model that calculated future PG adoption. DNV used simple payback as the preferred method of estimating economic viability for PG based on customer perspectives given its widespread use in similar adoption analyses, ability to reflect customer decision making in forecasting efforts, and ease of estimation. DNV developed a behind-the-meter net economic perspective that includes, as costs, the acquisition and installation costs for each technology less the impact of available incentives and, as benefits, the customer’s economic benefits of ownership such as energy and demand savings and export credits. For this study we assumed that the current net metering or net Market Potential Economic Analysis Technology costs Installation and O&M costs Local and federal incentives Benefits of ownership Energy savings Net billing, net metering export credits Technical Feasibility System performance constraints Customer load shapes System size limits Land-use requirements Non-shaded rooftop space Access to unprotected streams and dams, wind resource DNV – www.dnv.com February 2, 2023 Page 4 billing policies and tariff structures in each state continued throughout the study horizon. This resulted in the model incorporating benefits associated with net metering in Oregon, Washington, and Wyoming and net billing in Utah and California. We assumed customer’s in Idaho would accrue benefits based on the net billing policy in Utah throughout the study. DNV has been following the ongoing Idaho Public Utilities Commission (PUC) review of Idaho Power Company’s (Idaho Power) Value of Distributed Resources (VODER) study filing. Idaho Power’s VODER study found that excess power generated by rooftop solar owners is worth less than half of retail rate energy and serves as the basis of Idaho Power’s proposal for a new compensation rate structure for solar owners. If approved by the Idaho PUC, Idaho Power’s proposed compensation rate structure would more closely resemble the current net billing structure in place in Utah13 and DNV assumed PacifiCorp would implement a similar rate structure in their Idaho territory. A detailed breakdown of the simple payback calculation and different elements is shown below. 𝑺𝒊𝒎𝒑𝒍𝒆 𝑷𝒂𝒚𝒃𝒂𝒄𝒌= 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑁𝑒𝑡 𝐶𝑜𝑠𝑡𝑠 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑁𝑒𝑡 𝐵𝑒𝑛𝑒𝑓𝑖𝑡𝑠 𝑪𝒖𝒎𝒖𝒍𝒂𝒕𝒊𝒗𝒆 𝑵𝒆𝒕 𝑪𝒐𝒔𝒕𝒔=(𝑈𝑝𝑓𝑟𝑜𝑛𝑡 𝑆𝑦𝑠𝑡𝑒𝑚 𝐶𝑜𝑠𝑡−𝑌𝑒𝑎𝑟 𝑂𝑛𝑒 𝐼𝑛𝑐𝑒𝑛𝑡𝑖𝑣𝑒𝑠)+𝑁𝑃𝑉(𝐴𝑛𝑛𝑢𝑎𝑙 𝑂&𝑀 𝐶𝑜𝑠𝑡𝑠+𝐴𝑛𝑛𝑢𝑎𝑙 𝐹𝑢𝑒𝑙 𝐶𝑜𝑠𝑡𝑠) 𝑪𝒖𝒎𝒖𝒍𝒂𝒕𝒊𝒗𝒆 𝑵𝒆𝒕 𝑩𝒆𝒏𝒆𝒇𝒊𝒕𝒔=𝑁𝑃𝑉(𝑀𝐴𝐶𝑅𝑆 𝑆𝑎𝑣𝑖𝑛𝑔𝑠+ 𝑆𝑒𝑙𝑓 𝐶𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝑆𝑎𝑣𝑖𝑛𝑔𝑠+𝐸𝑥𝑝𝑜𝑟𝑡 𝐶𝑟𝑒𝑑𝑖𝑡𝑠+𝑃𝑒𝑎𝑘 𝐷𝑒𝑚𝑎𝑛𝑑 𝑆𝑎𝑣𝑖𝑛𝑔𝑠) DNV also used an annual hourly profile analysis to estimate electric bill savings and excess generation for each PG technology by customer segment. This analysis used hourly generation and customer load profiles, and tiered, time-of-use (TOU), and peak demand rates for each customer and technology permutation. DNV integrated the energy savings, excess generation, and peak demand benefits into the lifetime simple payback estimation using customer load and individual rate forecasts provided by PacifiCorp. A full breakdown of all inputs used in the economic analysis is provided in Table 3-11 below. Table 3-11 PG Forecast Economic Analysis Inputs INPUT TYPE COST / BENEFIT CATEGORY SOURCE TECHNOLOGY COST DATA – INSTALLED COST PG cost data compiled in $/kW (AC & DC) – used in determining year one installed system costs DNV TECHNOLOGY COST DATA – ANNUAL O&M PG fixed ($/kW) & variable ($/kWh) O&M data – used in determining annual system costs DNV FUEL COST DATA Natural gas cost data ($/MMBtu) EIA Annual Energy Outlook 2022 TECHNOLOGY GENERATION PROFILES Hourly generation profiles for each PG technology by state – used in calculating self-consumption savings, excess generation credits, and peak demand savings DNV CUSTOMER LOAD PROFILES Hourly average customer load profiles by state – used in calculating self- consumption savings, excess generation credits, and peak demand savings PacifiCorp 13 As of December 19, 2022, the Idaho Power VODER study has been approved by the Idaho PUC. https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2222/OrdNotc/20221219Final_Order_No_35631.pdf DNV – www.dnv.com February 2, 2023 Page 5 INPUT TYPE COST / BENEFIT CATEGORY SOURCE CUSTOMER RATES Customer tiered, TOU, and peak demand rates by size, segment, and state – used in calculating self-consumption savings, excess generation credits, and peak demand savings PacifiCorp TECHNOLOGY COST FORECASTS PG cost data forecasts for installed system costs and annual O&M costs – used in determining year one installed system costs and future year annual system costs NREL ATB CUSTOMER & LOAD FORECASTS Individual customer count and load (kWh) forecasts by segment and state – used in calculating future year system costs and benefits PacifiCorp CUSTOMER RATE FORECASTS Rate forecasts applied to each customer segment – used in calculating future year self-consumption savings, excess generation credits, and peak demand savings EIA Annual Energy Outlook 2022 DNV calculated simple payback for each PG technology (solar PV, solar PV + battery, wind, hydro, reciprocating engines, and microturbines) by applicable individual customer segments (residential, commercial, industrial, and irrigation) for each installation year in the analysis timeframe (2023 – 2035). These payback results were combined with technical feasibility by customer segment and integrated into the bass diffusion adoption model to determine annual PG penetration throughout PacifiCorp’s territory. 3.4.2 Technical Feasibility The maximum amount of technical feasible capacity of private generation was determined individually for each technology considered in the private generation forecast. Each technology was generally limited by customer access factors, system size limits, and energy consumption. The customer load shapes, provided by PacifiCorp, were used to calculate annual energy use (kWh) cutoffs used in identifying the total number of customers that could technically support the installation of a specific PG technology. Other data sources specific to each technology were used to determine the amount of capacity that can be physically installed within PacifiCorp’s service territory, such as: • Hydropower potential data and environmental attributes for all HUC10 watersheds in PacifiCorp’s service territory14 • Building rooftop hosting area and suitability for solar PV15 • Wind resource potential data by state16 14 Kao, Shih-Chieh, Mcmanamay, Ryan A., Stewart, Kevin M., Samu, Nicole M., Hadjerioua, Boualem, Deneale, Scott T., Yeasmin, Dilruba, Pasha, M. Fayzul K., Oubeidillah, Abdoul A., and Smith, Brennan T. New Stream-reach Development: A Comprehensive Assessment of Hydropower Energy Potential in the United States. United States: N. p., 2014. Web. doi:10.2172/1130425. 15 Gagnon, P., R. Margolis, J. Melius, C. Phillips, and R. Elmore. 2016. Rooftop Solar Photovoltaic Technical Potential in the United States: A Detailed Assessment. NREL/TP-6A20-65298. Golden, CO: National Renewable Energy Laboratory. 16 Draxl, C., B.M. Hodge, A. Clifton, and J. McCaa. 2015. "The Wind Integration National Dataset (WIND) Toolkit." Applied Energy 151: 355366. DNV – www.dnv.com February 2, 2023 Page 6 3.4.3 Market Adoption DNV modeled market adoption using Bass diffusion curves customized to each state, technology, and sector. The Bass diffusion model was developed in the 1960s and is widely used to model market adoption over time. The formula for new adoption of a technology in year t is given by17 𝑠(𝑡)=𝑚 (𝑝+𝑞)2 𝑝 𝑒−𝑡(𝑝+𝑞) (1 +𝑞 𝑝𝑒−𝑡(𝑝+𝑞))2 Where: s(t) is new adopters at time t m is the ultimate market potential p is the coefficient of innovation q is the coefficient of imitation t is time in years Figure 3-10 shows a generalized Bass diffusion curve. The cumulative adoption curve takes a characteristic “S” shape with a new unknown and unproven technology having relatively slow adoption that accelerates over time as the technology becomes more familiar to a wider segment of the population. As the pool of potential buyers who have not yet adopted the technology shrinks, the rate of adoption (as a percent of the total pool of potential adopters) decreases until eventually everyone who will adopt has adopted. The corresponding chart shows the rate of annual new adoption. Figure 3-10 Bass Diffusion Curve Illustration In the illustration, the cumulative curve approaches 60% market penetration asymptotically, corresponding to the value of m (ultimate market potential) that we chose for the illustration. For our adoption models, we tied the value of m to payback, 17 Bass, Frank (1969). "A new product growth for model consumer durables". Management Science. 15 (5): 215–227 0% 10% 20% 30% 40% 50% 60% 70% 0 5 10 15 20 25 30 35 40 45 50Cu m u l a t i v e a d o p t i o n ( % o f t o t a l ) Cumulative Adoption Cumulative adoption 0% 1% 1% 2% 2% 3% 3% 0 5 10 15 20 25 30 35 40 45 50 An n u a l a d o p t i o n ( % o f t o t a l ) Annual Adoption Annual adoption DNV – www.dnv.com February 2, 2023 Page 7 following Sigrin and Drury’s18 survey findings on willingness to pay for rooftop photovoltaics based on payback. Because payback varied by technology, state, and sector, so did the Bass diffusion curve. Due to regional and sectoral differences, we made significant adjustments to the willingness-to-adopt curves to better align with the observed relationship between historic cost effectiveness and current market adoption by technology, state, and sector in PacifiCorp’s service territory. Based on PacifiCorp data on current levels of PG adoption, Utah in particular showed higher adoption than published willingness-to-pay curves would suggest, which we believe may be due to regional variation in how customers value resilience. To account for this variation across states, we developed three willingness-to-adopt curves to capture observed state variation. Table 3-12 shows which willingness-to-adopt curve was used for solar for each state and sector. Current adoption for the other modeled technologies was too low to discern variation across state, so we assumed average propensity to adopt for wind, small hydro, reciprocating engines and microturbines. Table 3-12 Solar Willingness-to-Adopt Curve used by State and Sector AVERAGE PROPENSITY TO ADOPT HIGH PROPENSITY TO ADOPT LOW PROPENSITY TO ADOPT • California residential, commercial, irrigation • Idaho residential • Oregon residential • Washington all sectors • Utah all sectors • Oregon commercial, industrial, irrigation • Wyoming all sectors • Idaho commercial, industrial, irrigation • California industrial Figure 3-11 shows the willingness-to-adopt curves for residential, commercial, and industrial sectors assuming an average propensity to adopt (the “Mid” case). There was too little irrigation adoption to assess the sector independently, so we used the commercial curves for the irrigation sector. The right-hand chart in Figure 3-11 shows the high, mid, and low adoption curves for the residential sector only. The high and low curves for the other sectors show similar variation. 18 Sigrin, Ben and Easan Drury. 2014. Diffusion into New Markets: Economic Returns Required by Households to Adopt Rooftop Photovoltaics. Energy Market Prediction: Papers from the 2014 AAAI Fall Symposium DNV – www.dnv.com February 2, 2023 Page 8 Figure 3-11 Willingness to Adopt Based on Technology Payback Willingness to adopt by sector, average propensity to adopt Residential willingness to adopt, high-low-mid curves The willingness-to-adopt curves established a different m parameter for each diffusion curve. In addition to varying by technology, state, and sector, m also changed over time due to changing payback resulting from changing technology costs, incentives, and tax credits, among other economic factors). The timing of our modeled adoption also varied, as we set t0 for each diffusion curve based on the earliest adoption of each technology by state and sector. For example, the first residential PV installed in PacifiCorp’s Oregon service territory was in 2000, while the first commercial PV installation in its Idaho service territory wasn’t until 2010. For technology/state/sectors where there is currently no adoption, we assumed that the first adoption would occur in 2023. The p and q parameters of the Bass diffusion curves were calibrated so that the predicted cumulative adoption from t0 through 2021 was equal to the current market penetration of each technology by state and sector (we fixed the relationship between p and q at q = 10p to make it possible to solve for p). For technology/state/sectors where there is currently no adoption, we assumed average values for p and q. The result of this process were Bass diffusion curves customized for each technology, state, and sector that also accounted for variation in willingness-to-adopt as cost effectiveness changes over time. The calibrated curves show some segments still in the very early phases of adoption, while other markets are more mature. Our forecast of annual adoption reflects all of these differences. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 3 5 7 9 11 13 15 17 19 21 Pe r c e n t w i l l i n g t o a d o p t Payback Res Mid Com Mid Ind Mid 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 1 3 5 7 9 11 13 15 17 19 21 Pe r c e n t w i l l i n g t o a d o p t Payback Res Low Res Mid Res High DNV – www.dnv.com February 2, 2023 Page 9 4 RESULTS In the base case scenario, DNV estimates 3,181 MW of new private generation capacity will be installed in PacifiCorp’s service territory over the nest twenty years (2023-2042). Figure 4-1 shows the relationship between the base case and low and high case scenarios. The low case scenario estimates 2,028 MW of new capacity over the 20-year forecast period— compared to base case, retail rates increase at a slower rate and technology costs decrease at a slower rate. In the high case, retail rates increase at a faster rate and technology costs decrease at a faster rate—this results in 3,196 MW of new private generation capacity installed by 2042. Table 4-1 Cumulative Adopted Private Generation Capacity by 2042, by Scenario SCENARIO CUMULATIVE CAPACITY (2042 MW-AC) Base 3,181 Low 2,028 High 3,196 Figure 4-1 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), 2023-2042 The sensitivity analysis showed a much greater margin of uncertainty on the low side than the high side. The Inflation Reduction Act of 2022 (IRA) extends tax credits that for private generation that create very favorable economics for adoption, and those are embedded in the base case. We therefore limited our upper bound forecast to lower technology costs and higher retail electricity rates, and these produced only a small boost to adoption for technologies that were already cost effective under the IRA. In contrast, when we modelled our lower bound, we found that the decreases in cost effectiveness were enough to tamp down adoption. The low case assumed higher technology costs and lower retail electricity rates than the other cases, reducing the economic appeal of private generation despite incentives being unchanged. The low case forecast is 36% less than the base case, while the high case cumulative installed capacity forecasted over the 20-year period is just 0.5% greater than the base case. 0 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 10 Figure 4-2 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Base Case Figure 4-3 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, Low Case - 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 500 1,000 1,500 2,000 2,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 11 Figure 4-4 Cumulative New Capacity Installed by Technology (MW-AC), 2023-2042, High Case 4.1 Generation Capacity Results by State The following sections present the results by state for each forecast scenario. Additional exhibits for total PV capacity forecasted are provided by sector. PV Only and PV + Battery capacity make up at least 95% of each states’ projected private generation capacity, so providing results for the other technologies by sector would not provide useful context to the results. The full set of results by state, sector, and new/existing construction for the forecasts is provided in Appendix B. Figure 4-5 shows the base case forecast by state, compared to the previous (2020) study’s total base case forecast19. This figure indicates that Utah and Oregon will drive most PG installations over the next two decades, which is to be expected given these two states represent the largest share of PacifiCorp’s customers and sales. The base scenario estimates approximately 1,447 MW of new capacity will be installed over the next 10 years in PacifiCorp’s territory—55% of which is in Utah, 32% in Oregon, and 6% in Idaho. Since the 2020 study, the federal Investment Tax Credit (ITC) has been extended for ten years at its original base rate levels and expanded to include energy storage. The tax credit increase and extension lowered the customer payback period for all technologies, making the customer economics of this study’s base case more similar to the previous study’s high case. In addition to the change in customer economics, projected PV capacity is expected to grow at a faster rate in the early years and at a slower rate towards the end of the forecast period. The key drivers of these differences include larger average PV system sizes, decreases in PV + Battery costs, and the maturity of rooftop PV technology. The adoption model DNV developed for this study was calibrated to existing levels of technology adoption for each state and sector. Technology adoption follow an S-curve with adoption initially increasing at an increasing rate, but eventually passing an inflection point where adoption continues to increase at a decreasing rate. 19 Cumulative capacity is adjusted to account for the difference in the forecast starting years (2021 in the previous study, versus 2023 in this study). Source: Navigant. 2020. “Private Generation Long-Term Resource Assessment (2021-2040)” - 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 12 Figure 4-5 Cumulative New Capacity Installed by State (MW-AC), 2023-2042, Base Case 4.1.1 California Customers in PacifiCorp’s service territory in northern California are projected to install about 57 MW of new private generation capacity over the next two decades in the base case. The 20-year high projection is about 1% greater than the base case and the low projection is 24% less than the base case, or 57.4 MW and 43 MW, respectively. California does not currently have any state incentives available for private generation, and uses a net billing structure for DER compensation. The residential sector has the largest share of the private generation capacity, ranging from 59% in the low case to 67% in the high and base cases. The next largest share of the capacity is forecasted in the commercial sector, ranging from 31% in the low case to 24% in the base and high cases. Figure 4-6 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), California, 2023-2042 - 500 1,000 1,500 2,000 2,500 3,000 3,500 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC CA ID OR UT WA WY 2020 - 10 20 30 40 50 60 70 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 13 Figure 4-7 Cumulative New Capacity Installed by Technology (MW-AC), California Base Case, 2023-2042 Figure 4-8 Cumulative New Capacity Installed by Technology (MW-AC), California Low Case, 2023-2042 - 10 20 30 40 50 60 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 5 10 15 20 25 30 35 40 45 50 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 14 Figure 4-9 Cumulative New Capacity Installed by Technology (MW-AC), California High Case, 2023-2042 - 10 20 30 40 50 60 70 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 15 4.1.1.1 California PV Adoption by Sector The impact of the three different scenarios on PV adoption by sector is shown in the following charts, which present the differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors. In the residential sector, the share of PV + Battery capacity is about 8% of total PV capacity in 2042 for the high case. The share of PV + Battery capacity is about 20% of total commercial PV capacity in 2042 for the high case. The irrigation sector has a similar portion of its PV capacity in PV + Battery configurations, at 14% of total capacity in the high case. The industrial sector did not have any PV + Battery adoption forecasted. Figure 4-10 Cumulative New PV Capacity Installed by Sector Across All Scenarios, California, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation - 5 10 15 20 25 30 35 40 45 Cu m u l a t i v e M W -AC - 2 4 6 8 10 12 14 Cu m u l a t i v e M W -AC - 0.01 0.01 0.02 0.02 0.03 0.03 0.04 Cu m u l a t i v e M W -AC - 1.0 2.0 3.0 4.0 5.0 6.0 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 16 4.1.2 Idaho PacifiCorp’s customers in Idaho are projected to install about 179 MW of new private generation capacity over the next two decades in the base case. The 20-year high projection is about 1% greater than the base case and the low projection is 33% less than the base case, or 181 MW and 121 MW, respectively. Idaho has a fairly generous incentive program for residential customers that boosted the sector’s adoption, compared to the other sectors. The incentives are provided through the Residential Alternative Energy Income Tax Deduction, discussed in section 3.2.5. DNV assumed Idaho would use the same net billing structure for DER compensation as Utah for the study period (2023-2042). The residential sector has the largest share of the private generation capacity, ranging from 54% in the base and high cases to 48% in the low case. The next largest share of the capacity is forecasted in the commercial sector, ranging from 38% in the low case to 34% in the base and high cases. Figure 4-11 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Idaho, 2023-2042 - 20 40 60 80 100 120 140 160 180 200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 17 Figure 4-12 Cumulative New Capacity Installed by Technology (MW-AC), Idaho Base Case, 2023-2042 Figure 4-13 Cumulative New Capacity Installed by Technology (MW-AC), Idaho Low Case, 2023-2042 - 20 40 60 80 100 120 140 160 180 200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 20 40 60 80 100 120 140 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 18 Figure 4-14 Cumulative New Capacity Installed by Technology (MW-AC), Idaho High Case, 2023-2042 - 20 40 60 80 100 120 140 160 180 200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 19 4.1.2.1 Idaho PV Adoption by Sector The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are presented in the following charts. In the residential sector, the high case share of PV + Battery capacity is about 15% of total residential PV capacity in 2042. The share of PV + Battery capacity is about 8% of total commercial PV capacity in 2042. The irrigation sector has a slightly higher portion of its PV capacity in PV + Battery configurations, at 4% of total capacity. The industrial sector did not have any PV + Battery adoption forecasted. Figure 4-15 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Idaho, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation - 20 40 60 80 100 120 Cu m u l a t i v e M W -AC - 10 20 30 40 50 60 70 Cu m u l a t i v e M W -AC - 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 Cu m u l a t i v e M W -AC - 5 10 15 20 25 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 20 4.1.3 Oregon PacifiCorp’s customers in Oregon are projected to install about 1,020 MW of new private generation capacity over the next two decades in the base case. The 20-year high projection is slightly higher than the base case and the low projection is 39% less than the base case, or 1,022 MW and 623 MW, respectively. Oregon has incentives available through the Oregon Department of Energy (DOE) for PV + Battery systems and the Energy Trust of Oregon (ETO) for PV Only configurations. The ETO offers incentives for both residential and business customers, while the Oregon DOE provides incentives for residential customers only. Both the Oregon DOE and ETO provide increased incentives for households with low- to moderate-incomes. Oregon is the only state in PacifiCorp’s territory, at this time, that provides different incentives for residential customers by income level. As the residential private generation forecast was not segmented by income level, DNV had to develop a single incentive value for the economic analysis. In order to incorporate the higher incentives for the income-qualified customers, DNV developed a weighted average incentive for Oregon residential customers. The income-level weights were calculated from the demographic data of the pool of potential adopters for each technology, in order to best represent the total technology cost (net of incentives) that Oregon residential customers are making their purchasing decisions based off of. Annual household income was included in the census-tract-level demographic data that DNV incorporated into PacifiCorp’s Oregon Distribution System Plan circuit-level private generation forecast. While the higher incentive for income-qualified customers provides a boost to customer economics, it does not address the other larger barriers to adoption, such as lack of access to capital and home ownership status. Therefore representation of low- to moderate-income households in the pool of potential adopters for the PV and PV + Battery technologies is still very low. The PV + Battery incentives offered for residential customers by the Oregon DOE provided a boost to customer economics that led to the majority of PV + Battery adoption growth being in the residential sector. The majority of the PV Only adoption growth in the early years of the forecast is in the commercial sector, with the residential sector following closely behind and eventually overtaking the forecast in the later years. Oregon’s net metering policies were assumed to stay in place throughout the study, providing more favorable economics for PV Only—compared to PV + Battery systems. Figure 4-16 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Oregon, 2023-2042 - 200 400 600 800 1,000 1,200 2023 2024 20252026 2027 2028 2029 20302031 2032 2033 20342035 2036 2037 2038 20392040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 21 Figure 4-17 Cumulative New Capacity Installed by Technology (MW-AC), Oregon Base Case, 2023-2042 Figure 4-18 Cumulative New Capacity Installed by Technology (MW-AC), Oregon Low Case, 2023-2042 - 200 400 600 800 1,000 1,200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 100 200 300 400 500 600 700 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 22 Figure 4-19 Cumulative New Capacity Installed by Technology (MW-AC), Oregon High Case, 2023-2042 - 200 400 600 800 1,000 1,200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 23 4.1.3.1 Oregon PV Adoption by Sector The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are presented in the following charts. In the residential sector, the share of PV + Battery capacity is about 4% of total residential PV capacity in 2042. The share of PV + Battery capacity is about 2% of total commercial PV capacity in 2042. The irrigation sector has a similar portion of its PV capacity in PV + Battery configurations, at 3% of total capacity. The industrial sector did not have any PV + Battery adoption forecasted. Figure 4-20 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Oregon, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation - 100 200 300 400 500 600 700 Cu m u l a t i v e M W -AC - 50 100 150 200 250 300 350 400 450 Cu m u l a t i v e M W -AC - 1 1 2 2 3 3 4 4 5 Cu m u l a t i v e M W -AC - 2 4 6 8 10 12 14 16 18 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 24 4.1.4 Utah PacifiCorp’s customers in Utah are projected to install about 1,733 MW of new private generation capacity over the next two decades in the base case. The 20-year high projection is less than 1% greater than the base case and the low projection is 34% less than the base case, or 1,742 MW and 1,140 MW, respectively. Utah has an incentive program for residential and business customers, but the residential PV incentive expires in 2023. The incentives are provided through through Utah Office of Energy Development Renewable Energy Systems Tax Credit, discussed in section 3.2.5. DNV assumed Utah’s net billing policies would remain in place throughout the study. In all cases, the commercial sector has the largest share of the private generation capacity forecasted—ranging from 50% to 58% in the high and low cases, respectively. The residential sector represents the 42% of the capacity forecast in the high and base scenarios, but only 33% in the low case. Figure 4-21 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Utah, 2023-2042 - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High DNV – www.dnv.com February 2, 2023 Page 25 Figure 4-22 Cumulative New Capacity Installed by Technology (MW-AC), Utah Base Case, 2023-2042 Figure 4-23 Cumulative New Capacity Installed by Technology (MW-AC), Utah Low Case, 2023-2042 - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 200 400 600 800 1,000 1,200 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 26 Figure 4-24 Cumulative New Capacity Installed by Technology (MW-AC), Utah High Case, 2023-2042 - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 27 4.1.4.1 Utah PV Adoption by Sector The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are presented in the following charts. In the residential sector, the share of PV + Battery capacity is between 28 and 32% of total residential PV capacity in 2042. The share of PV + Battery capacity is about 4% of total commercial PV capacity in 2042. The industrial sector has a lower portion of its PV capacity in PV + Battery configurations, at 1% of total capacity. About 5% of the irrigation sector PV capacity forecasted in in a PV + Battery configuration. Figure 4-25 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Utah, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation - 100 200 300 400 500 600 700 800 Cu m u l a t i v e M W -AC - 100 200 300 400 500 600 700 800 900 1,000 Cu m u l a t i v e M W -AC - 10 20 30 40 50 60 70 80 90 100 Cu m u l a t i v e M W -AC - 5 10 15 20 25 30 35 40 45 50 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 28 4.1.5 Washington PacifiCorp’s customers in Washington are projected to install about 140 MW of new private generation capacity over the next two decades in the base case. The 20-year low projection is about 47% less than the base case, or 74 MW. The high case is nearly the same as the base case, seen in Figure 4-26. Washington state currently offers no incentives for private generation technologies. The residential sector has the largest share of the private generation capacity, ranging from 68% in the base and high cases to 55% in the low case. The next largest share of the capacity is forecasted in the commercial sector, ranging from 41% in the low case to 29% in the base and high cases. Washington’s net metering policies were assumed to stay in place throughout the study, providing more favorable economics for PV Only—compared to PV + Battery systems. Figure 4-26 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Washington, 2023-2042 Figure 4-27 Cumulative New Capacity Installed by Technology (MW-AC), Washington Base Case, 2023-2042 - 20 40 60 80 100 120 140 160 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High - 20 40 60 80 100 120 140 160 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 29 Figure 4-28 Cumulative New Capacity Installed by Technology (MW-AC), Washington Low Case, 2023-2042 Figure 4-29 Cumulative New Capacity Installed by Technology (MW-AC), Washington High Case, 2023-2042 - 10 20 30 40 50 60 70 80 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 20 40 60 80 100 120 140 160 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 30 4.1.5.1 Washington PV Adoption by Sector The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are presented in the following charts. In the residential sector, the share of PV + Battery capacity is about 4% of total residential PV capacity in 2042. The share of PV + Battery capacity is about 3% of total commercial PV capacity in 2042. The industrial sector has a higher portion of its PV capacity in PV + Battery configurations, at 8% of total capacity. In the irrigation sector, the share of PV + Battery capacity is between 2% and 4%, depending on the forecast scenario, of total irrigation PV capacity in 2042. Figure 4-30 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Washington, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation - 10 20 30 40 50 60 70 80 90 100 Cu m u l a t i v e M W -AC - 5 10 15 20 25 30 35 40 45 Cu m u l a t i v e M W -AC - 0.5 1.0 1.5 2.0 2.5 Cu m u l a t i v e M W -AC - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 31 4.1.6 Wyoming PacifiCorp’s customers in Wyoming are projected to install about 51 MW of new private generation capacity over the next two decades in the base case. The 20-year high projection is approximately 2% greater than the base case and the low projection is about 50% less than the base case, or 52 MW and 26 MW, respectively. Wyoming currently offers no incentives for private generation technologies. The residential sector has the largest share of the private generation capacity, ranging from 64% in the low case to 71% in the high and bae cases. The next largest share of the capacity is forecasted in the commercial sector, ranging from 28% in the high and base cases to 34% in the low case. Wyoming’s net metering policies were assumed to stay in place throughout the study, providing more favorable economics for PV Only—compared to PV + Battery systems. Figure 4-31 Cumulative New Private Generation Capacity Installed by Scenario (MW-AC), Wyoming, 2023-2042 Figure 4-32 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming Base Case, 2023-2042 - 10 20 30 40 50 60 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC Low Base High - 10 20 30 40 50 60 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 32 Figure 4-33 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming Low Case, 2023-2042 Figure 4-34 Cumulative New Capacity Installed by Technology (MW-AC), Wyoming High Case, 2023-2042 - 5 10 15 20 25 30 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine - 10 20 30 40 50 60 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W -AC PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine DNV – www.dnv.com February 2, 2023 Page 33 4.1.6.1 Wyoming PV Adoption by Sector The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are presented in the following charts. In the residential sector, the share of PV + Battery capacity is between 19% and 23% of total residential PV capacity in 2042, depending on the forecast scenario. The share of PV + Battery capacity is about 6% of total commercial PV capacity in 2042. The industrial sector has a lower portion of its PV capacity in PV + Battery configurations, at 5% of total capacity. The irrigation sector did not have any PV (PV Only or PV + Battery) adoption forecasted. Figure 4-35 Cumulative New PV Capacity Installed by Sector Across All Scenarios, Wyoming, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. Residential Commercial Industrial Irrigation N/A - 5 10 15 20 25 30 35 40 Cu m u l a t i v e M W -AC - 2 4 6 8 10 12 14 Cu m u l a t i v e M W -AC - 0.1 0.1 0.2 0.2 0.3 0.3 0.4 0.4 Cu m u l a t i v e M W -AC DNV – www.dnv.com February 2, 2023 Page 34 APPENDIX A TECHNOLOGY ASSUMPTIONS AND INPUTS Appendix A.xlsx DNV – www.dnv.com February 2, 2023 Page 35 APPENDIX B DETAILED RESULTS Appendix B.xlsx DNV – www.dnv.com February 2, 2023 Page 36 APPENDIX C WASHINGTON COGENERATION LEVELIZED COSTS Section 480.109.100 of the Washington Administrative Code establishes high-efficiency cogeneration as a form of conservation that electric utilities must assess when identifying cost-effective, reliable, and feasible conservation for the purpose of establishing 10-year forecasts and biennial targets. This appendix provides the levelized cost of energy (LCOE) for the two CHP technologies analyzed in this report for three 10-year periods. LCOE is defined as the present cost of electricity generation for the specified technology over its useful lifetime. Assumptions for the LCOE analysis of both reciprocating engines and microturbines in Washington state are provided in Table C-1and Table C-2 below, with additional information on the specific source for each metric. Similar to previous studies, the cost of system heat recovery was removed from the total system cost component, resulting in LCOE based only on electric power generation for each system. Where applicable, assumptions are presented nominally ($USD). Table C-1 Reciprocating Engine LCOE Assumptions METRIC EXPECTED USEFUL LIFE (EUL) INSTALLED COST (INCLUDES INCENTIVES) VARIABLE O&M COST FUEL COST WACC UNITS Years $/kW $/MWh $/MMBtu % 2022 20 $2,565 $23 $5.67 6.88% 2030 20 $2,655 $27 $4.34 6.88% 2040 20 $2,721 $32 $6.61 6.88% SOURCE EPA Catalog of CHP Technologies (Sep. 2017) DOE CHP Technology Fact Sheets (Reciprocating Engines) DOE CHP Technology Fact Sheets (Reciprocating Engines) PacifiCorp Natural Gas Forecast for Washington State PacifiCorp IRP Assumption Table C-2 Microturbine Engine LCOE Assumptions METRIC EXPECTED USEFUL LIFE (EUL) INSTALLED COST (INCLUDES INCENTIVES) VARIABLE O&M COST FUEL COST WACC UNITS Years $/kW $/MWh $/MMBtu % 2022 25 $3,135 $23 $5.67 6.88% 2030 25 $3,229 $27 $4.34 6.88% 2040 25 $3,294 $32 $6.61 6.88% SOURCE EPA Catalog of CHP Technologies (Sep. 2017) DOE CHP Technology Fact Sheets (Reciprocating Engines) DOE CHP Technology Fact Sheets (Reciprocating Engines) PacifiCorp Natural Gas Forecast for Washington State PacifiCorp IRP Assumption DNV – www.dnv.com February 2, 2023 Page 37 The results of the CHP LCOE analysis are shown below. The calculated levelized costs for both technologies are similar in each analysis year. Table C-3 LCOE Results for CHP Systems in Washington State TECH RECIPROCATING ENGINES MICROTURBINES UNITS $/MWh $/MWh 2022 $89.3 $92.8 2030 $99.4 $99.9 2040 $121.4 $116.3 DNV – www.dnv.com February 2, 2023 Page 38 APPENDIX D OREGON DISTRIBUTION SYSTEM PLAN RESULTS DNV prepared the Long-Term Private Generation (PG) Resource Assessment for PacifiCorp’s Oregon distributed energy resource (DER) adoption forecast at the circuit level to support PacifiCorp’s 2023 Oregon Distribution System Plan (DSP). This study evaluated the expected adoption of behind-the-meter DERs including photovoltaic solar (PV only), photovoltaic solar coupled with battery storage (PV + Battery), wind, small hydro, reciprocating engines and microturbines for a 20-year forecast horizon (2023-2042). The adoption model DNV developed for this study is calibrated to the current20 market penetration of these technologies, shown in Figure D-1. Figure D-1 Historic Cumulative Installed PG Capacity by Technology, PacifiCorp, Oregon, 2012-2021 To date, about 99 percent of existing private generation capacity installed in PacifiCorp’s Oregon service territory is PV or PV + Battery. To inform the adoption forecast process, the Company conducted an in-depth review of the other technologies and did not find any literature to suggest that they would take on a larger share of the private generation market in Oregon in the future years of this study. For each technology and sector, PacifiCorp developed three scenarios: a base case, a high case and a low case. The base case is considered the most likely projection as it is based on current market trends and expected changes in costs and retail rates; the high and low cases are used as sensitivities to test how changes in technology costs and retail rates impact customer adoption of these technologies. These scenarios use technology cost and performance assumptions specific to PacifiCorp’s Oregon service territory in the base year of the study. The base case assumes the current federal income tax credit schedules and state incentives, retail electricity rate escalation from the AEO21 reference case, and a blended version of the NREL Annual Technology Baseline22 moderate and conservative technology cost forecasts. In the high case, retail rates increase more rapidly, and technology costs decline at a faster rate compared to the base case to incentivize greater adoption of PG. For the low case, retail rates increase at a slower rate than the base case and technology costs decrease at a slower rate. 20 PacifiCorp private generation interconnection data as of February 2022. 21 U.S. Energy Information Administration, Annual Energy Outlook 2022 (AEO2022), (Washington, DC, March 2022). 22NREL (National Renewable Energy Laboratory). 2021. 2021 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. 0 20 40 60 80 100 120 140 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Cu m u l a t i v e M W -AC Micro Turbine Reciprocating Engine Small Hydro Wind PV + Battery PV Only DNV – www.dnv.com February 2, 2023 Page 39 D.1 Study Methodologies and Approaches The forecasting methodologies and techniques applied by PacifiCorp in this analysis are commonly used in small-scale, behind-the-meter energy resource and energy efficiency forecasting. To forecast private generation adoption at the circuit- level, the Company first developed an adoption model to estimate total PG potential for PacifiCorp’s Oregon service territory and then disaggregated these results to develop PG potential estimates for each circuit. The methods used to develop the territory and circuit level results are described in more detail below. D.1.1 State-Level Forecast Approach DNV developed a behind-the-meter net economic perspective that includes the acquisition and installation costs for each technology and incorporates the available incentives and economic benefits of ownership as offsets which assumed that the current net metering policies for Oregon remained in place throughout the study horizon. The economic analysis calculated payback by year for each technology by sector. A corresponding technical feasibility analysis determined the maximum, feasible, adoption for each technology by sector. The results of the technical and economic analyses were then used to inform the market adoption analysis. The methodology and major inputs to the analysis are shown in Figure D-2. Changes to technology costs, retail rates, and federal tax credits used in the high and low cases impact the economic portion of the analysis. Figure D-2 Methodology to Determine Market Potential of Private Generation Adoption PacifiCorp used technology and sector-specific Bass diffusion curves to model market adoption and derive total market potential. Bass diffusion curves are widely used for forecasting technology adoption. Diffusion curves typically take the form of an S-curve with an initial period of slow early adoption, adoption increasing as the technology becomes more mainstream, and eventually a tapering off among late adopters. The upper limit of the curve is set to maximum market potential, or the maximum share of the market that will adopt the technology regardless of the interventions applied to influence adoption. In this analysis, the long-term maximum level of market adoption was based on payback. As payback was calculated by year in the economic analysis to capture the changing effects of market interventions over time, the maximum level of market adoption in the diffusion curves vary by year in the study. The model is characterized by three parameters—an innovation coefficient, an imitation coefficient, and the ultimate market potential. The last of these we set equal to the payback-based maximum level of adoption. Together, these three parameters also determine the time to reach maximum adoption and overall shape of the curve. The innovation and Market Potential Economic Analysis Technology costs Installation and O&M costs Local and federal incentives Benefits of ownership Energy savings Net billing, net metering export credits Technical Feasibility System performance constraints Customer load shapes System size limits Land-use requirements Non-shaded rooftop space Access to unprotected streams and dams, wind resource DNV – www.dnv.com February 2, 2023 Page 40 imitation parameters were calibrated for each technology and sector, based on current market penetration and when PacifiCorp started to see the technology being adopted in the Company’s Oregon service territory. D.1.2 Circuit-Level Forecasting Approach PacifiCorp conducted a bottom-up approach to develop circuit-level adoption models for each sector and technology. The approach chosen for developing circuit-level forecasts was to disaggregate the state-level forecast described in the previous section. This was due to the use of adoption drivers from data at varying levels of geographic granularity. The circuit-level adoption models incorporated county-level private generation installation data and resource availability by technology23, census-tract-level demographic data24 and circuit-level reliability data. The Company used circuit-level customer counts by sector to further segment the localized adoption models by sector and technology. The Company ultimately used a bottom- up approach to develop circuit-level adoption models for each circuit, but due to the above data gaps, their purpose was only to develop factors to allocate the state-wide analysis to each circuit. D.2 Private Generation Forecast Results Figure D-3 compares the new service territory-level private generation capacity, in cumulative MW-AC by 2033, projected for each scenario evaluated. The capacity forecasted is incremental to what is already installed in PacifiCorp’s Oregon service territory, shown in Figure D-1. Figure D-3 Private Generation Forecast by Technology, PacifiCorp Oregon, All Cases Similar to the trends observed in current installed capacity, solar PV25 makes up 99% of the new PG capacity forecast throughout the study period in all cases. By 2033, the cumulative new PV Only capacity in the base case is 209 MW and PV + Battery capacity is 5 MW. Compared to the base case, the low case forecasts 31% less PV Only capacity, and about 40% percent less PV + Battery capacity. The PV Only cumulative new capacity in the high case in 2033 is 83% greater than the base case. In the high case, 2033 PV + Battery cumulative new capacity is forecasted to be more than double the base case, at 11 MW. 23 Conditions suitable for wind and hydro vary widely by region, and the economics of solar adoption is affected by local weather patterns. 24 Data including household income, education-level, and home ownership. 25 The term solar PV, here, is inclusive of PV Only and PV + Battery systems. 0 50 100 150 200 250 300 350 400 2023 2025 2027 2029 2031 2033 Base Case PV Only PV + Battery Wind Small Hydro Reciprocating Engine Micro Turbine 2033 Cumulative New Capacity Installed: 215 MW-AC 0 50 100 150 200 250 300 350 400 2023 2025 2027 2029 2031 2033 Cu m u l a t i v e M W -AC High Case 2033 Cumulative New Capacity Installed: 396 MW-AC 0 50 100 150 200 250 300 350 400 2023 2025 2027 2029 2031 2033 Low Case 2033 Cumulative New Capacity Installed: 148 MW-AC DNV – www.dnv.com February 2, 2023 Page 41 D.2.1 Circuit-Level and Substation-Level Results Findings The charts in Figure D-4, Figure D-5, and Figure D-6 show the distribution of new capacity in 2033 by operating area, substation, and circuit within the base case private generation forecast. Figure D-4 Private Generation Forecast Disaggregation by Operating Area, PacifiCorp Oregon, Base Case The top five (ranked by new capacity) of PacifiCorp’s 22 Oregon operating areas account for 65% of the total forecast capacity in 2033 while only accounting for 48% of total customers. Figure D-5 Private Generation Forecast Disaggregation by Substation, PacifiCorp Oregon, Base Case The top five of PacifiCorp’s 193 substations account for 15% of 2033 forecast capacity (compared to 7% of customers), with the entire top quartile (representing 49% of customers) accounting for 67%. Second quartile, 23% Third quartile, 8% Bottom Quartile, 4% Medford, 22% Bend/Redmond, 19% Klamath Falls, 12% Portland, 6% Madras, 6% Top quartile65% Distribution of New Capacity (2033) by Operating Area The top 5 operating areas account for 48% of total customers Rest of Top Quartile52% Second quartile21% Third quartile10%Bottom Quartile2%Redmond, 4% Cleveland Ave., 4% Prineville, 3% Medford, 2% Hood River, 2% Top 5 substations15% Distribution of New Capacity (2033) by Substation The top 5 substations account for 7.1% of total customers DNV – www.dnv.com February 2, 2023 Page 42 Figure D-6 Private Generation Forecast Disaggregation by Circuit, PacifiCorp Oregon, Base Case Of the 504 circuits analyzed, the top five (representing 2.6% of customers) account for 5.2% of total forecast capacity, with the top quartile (representing 36% of customers) accounts for 59%. Figure D-7 shows the breakdown of customers, by sector, at the top five substations. Because capacity sizes are larger for irrigation, commercial and industrial customers than for residential (four times larger for irrigation, nine times for commercial and 17 times for industrial), C&I customers contribute to capacity totals disproportionately to their share of the customer population. New construction has a two-fold impact on the capacity forecast: Directly, since there are customers on the substation who could adopt private generation, and indirectly, since new construction has a higher propensity to adopt solar (with and without storage) than existing buildings. All substations except Hood River are in areas where population growth is higher than the statewide average. Figure D-7 Customer Mix of Top Five Substations Compared to the Average of All Substations Rest of Top Quartile, 54.1% Second Quartile, 26.9%Third Quartile, 11.6% Bottom Quartile, 2.2%5D167, 0.8% 5D411, 1.0% 5D94, 1.1% 5D227, 1.1% 4M16, 1.2% Top 5 Circuits5.2% Distribution of New Capacity (2033) by Circuit The top 5 circuits account for 2.6%of total customers 0 2,000 4,000 6,000 8,000 10,000 12,000 Cleveland Ave.Redmond Hood River Prineville Medford Pac. OregonAverage Nu m b e r o f C u s t o m e r s Irrigation C&I Residential DNV – www.dnv.com February 2, 2023 Page 43 With 193 substations across the state and so many factors influencing the disaggregated forecast, it is not feasible to conduct a deep dive of each substation’s capacity forecast. Instead, we selected five substations to illustrate how different underlying factors affected their capacity allocations (see Figure D-8). These substations were chosen to illustrate a range of characteristics influencing adoption, not because they are of special interest for planning. Figure D-8 Customer Attributes of Selected Substations Compared to Average PacifiCorp Oregon Substation Substation Attribute Vernon Cleveland Ave. Mary's River Coquille Vilas Road Average Operating Area Portland Bed/ Redmond Corvallis Coos Bay/Coquille Medford -- Climate (for Solar) Less favorable More favorable Less favorable Less favorable More favorable -- Population Growth 1.0% 2.0% 1.3% 0.0% 1.7% 1.0% % Non-res. Customers 5% 20% 12% 13% 34% 16% Current Res. Solar Penetration 1.4% 3.0% 3.1% 0.9% 2.4% 1.8% Home Ownership Rate 70% 55% 61% 77% 75% 65% Avg. Household Income $108,604 $136,460 $102,301 $74,543 $58,752 $87,499 Vernon and Cleveland Avenue are among PacifiCorp’s top substations by number of customers but have very different climates and customer mixes. Cleveland Avenue lies on the east side of the Cascades and receives more sunshine, while Vernon is in the Portland operating area, which has more rain and more cloudy days which impacts solar generation and thus adoption. Nonresidential PV systems are larger than residential systems (modeled commercial systems are 9 times larger; industrial systems are 17 times larger), so Cleveland Ave’s higher share of nonresidential customers (20%) increases its capacity forecast compared to Vernon, with only 5% nonresidential customers. Cleveland Avenue also has double the rate of expected population growth that Vernon does over the next decade. 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Vernon Cleveland Ave.Mary's River Coquille Vilas Road Average Ca p a c i t y ( M W -AC ) # o f C u s t o m e r s Residential Customers Non-residential Customers 2033 Capacity DNV – www.dnv.com February 2, 2023 Page 44 The remaining three substations shown each have a total customer count close to the state-wide average, but very different capacity forecasts. Mary’s River has high historic adoption and higher-than-average population growth, but less non- residential and a lower home ownership rate than average resulted in a share of capacity almost proportional to the number of customers. Coquille has very low historic adoption, perhaps due to its less favorable climate for solar generation, and no expected population growth. Those factors, paired with lower-than-average income and low share of non-residential customers led to a very low level of forecast private generation capacity. The last substation we wish to highlight is Vilas Road in the Medford operating Area. This substation has a very high share of non-residential customers at 34%, and the higher capacity systems for these customers drives up the forecast. A favorable climate for solar with high historic adoption (residential and commercial) led to this substation being allocated a higher-than-proportional share of capacity. Figure D-9 zooms in on the Klamath Falls operating area to compare how the allocation of PV only capacity compares to the distribution of customers by circuit. For each circuit in the Klamath Falls operating area, the chart shows the share of residential customers to the corresponding share of the 2033 residential PV Only capacity forecast. The figure demonstrates visually that more favorable factors for adoption, such as higher rates of home ownership, higher income, higher education, etc. result in a higher than proportional allocation of capacity. Figure D-9 Share of Residential Customers vs. Share of Residential PV Only Capacity in 2033, Klamath Falls Operating Area D.3 Conclusions As part of the DSP, PacifiCorp evaluated each of the previously discussed private generation scenarios. However, as the baseline DSP private generation forecast, PacifiCorp considers the base case forecast to be most appropriate for planning, given current technology costs, incentive levels and net metering policies in place in Oregon. 0% 2% 4% 6% 8% 10% 12% % o f C u s t o m e r s o r C a p a c i t y Circuits Ordered by # of Customers Share of residential customers Share of residential solar capacity -Median Income: $50,035-% Owner Occupied: 69%-% w/ Bachelor's Degree: 27% -Median Income: $32,879-% Owner Occupied: 38%-% w/ Bachelor's Degree: 16% Circuit 5L45 DNV – www.dnv.com February 2, 2023 Page 45 Our analysis incorporated the current rate structures and tariffs offered to customers in Oregon. Time-of-use rates, tiered tariffs and retail tariffs that include high demand charges increased the value of PV + Battery configurations compared to PV-Only configurations while other factors such as load profiles and DER compensation mechanisms minimized the impact of such tariffs on the customer economics of PV + Battery systems. The DER compensation mechanism in Oregon — traditional net metering — does not incentivize PV + Battery storage co-adoption. The sensitivity analysis found a greater difference between the base case and the upper bound of private generation adoption than the base case and lower bound of adoption. The low case assumed higher technology costs and lower retail electricity rates than the other cases, reducing the economic appeal of private generation despite incentives being unchanged. For the high case, an assumed extension to the residential federal investment tax credit provided a significant boost to adoption alongside the lower technology costs and higher retail electricity rates used in that analysis. The resulting new capacity in 2033 is about 31% less than the base case, while the high case is 84% greater than the base. D.3.1 Future Work Developing the circuit-level adoption models within the Oregon adoption model revealed additional areas of research related to private generation and behind-the-meter battery storage adoption that would enhance future work. The following is a list of potential future enhancements to this study: 1. A more nuanced approach to the new construction forecast would consider the creation of new circuits in high- growth areas. The current study allocates new construction only to existing circuits. 2. The distribution analysis requires integrating data at different geographical resolutions (state, county, census tract and circuit). While PacifiCorp’s data mapped circuits geographically, there were challenges in matching customer billing data to circuits. This study also used existing customer counts by sector by circuit, but corresponding energy use could not be calculated at the circuit-level. Similarly, existing private generation could only be mapped at the county level since interconnection data had incomplete customer circuit information. Future studies will benefit from the circuit-level load forecasts PacifiCorp is developing for this DSP. 3. Storage dispatch modeling would benefit from a finer disaggregation of large commercial and industrial load shapes. Technology that is not broadly cost-effective could still be beneficial for customers with certain load profiles that were not visible using class-level load shapes. 4. Resilience appeared to be a significant driver of adoption. For PV + Battery storage, resilience could be a more significant driver of adoption than economics. A deeper understanding of what customer-types value resilience and how that affects their willingness to pay would help refine the forecast. DNV – www.dnv.com February 2, 2023 Page 46 APPENDIX E BEHIND-THE-METER BATTERY STORAGE FORECAST DNV prepared a behind-the-meter battery storage forecast as a part of the Long-Term Private Generation (PG) Resource Assessment for PacifiCorp covering their service territories in Utah, Oregon, Idaho, Wyoming, California, and Washington to support PacifiCorp’s 2023 Integrated Resource Plan (IRP). This study evaluated the expected adoption of behind-the-meter battery storage systems coupled with PV systems over a 20-year forecast horizon (2023-2042) for all customer sectors (residential, commercial, industrial, and agricultural). Residential and non-residential battery energy storage systems (BESS) can be installed as a standalone system, added to an existing PV system, or the system can be installed together with a new PV system. DNV assumed all battery installations would be paired with a PV system in an AC-coupled configuration, as standalone systems are ineligible for the federal ITC—explained further in section 3.2.5. The adoption model DNV developed for this study is calibrated to the current26 installed and interconnected behind-the- meter battery capacity that is paired with a PV system, shown in Figure E-1. Figure E-1 Historic Cumulative Installed Behind-the-Meter Battery Storage Capacity, PacifiCorp, 2012-2021 Historic Cumulative Installed Battery Capacity by State Historic Cumulative Installed Battery Capacity by Sector E.1 Study Methodologies and Approaches DNV modelled two technologies in the behind-the-meter battery storage forecast: 1. PV + Battery: BESS product installed together with a new PV system, 2. Battery Retrofit: BESS product installed as an add-on to an existing PV system. 26 PacifiCorp private generation interconnection data as of February 2022. 0 2 4 6 8 10 12 14 16 18 20 2015 2016 2017 2018 2019 2020 2021 Cu m u l a t i v e M W WY WA UT OR ID CA Residential93% Non-Residential7% DNV – www.dnv.com February 2, 2023 Page 47 DNV used the same forecasting methodologies and approaches for the BTM battery storage forecast as the private generation forecast. The methods used to develop the results of the forecast are described in detail in section 3.4 of the report. Data on battery system costs used in the BTM battery storage forecast is explained in detail in section 3.1.1.2 of the report. That section includes current and projected future costs of battery storage systems used in the forecast for the different sectors. The detailed assumptions for the system configurations, including system sizes, in each sector and state can be found in Appendix A. E.1.1 Battery Dispatch Modelling DNV utilized its proprietary solar plus storage operational modeling tool—Lightsaber—to model battery dispatch. Battery dispatch strategy dictates the flow of energy between the PV system, battery, and the grid. The battery dispatch model includes strategies such as peak shaving, energy arbitrage, and manual dispatch. Self consumption was modelled for all sectors’ BESS control strategy, which utilizes the battery by charging only from excess PV and discharging if PV production falls below load. For residential customers, the dispatch model used energy arbitrage to reduce time-of-use charges. For non-residential customers, the dispatch model used energy arbitrage to reduce demand charges and time-of-use charges, where applicable. E.2 Results In the base case scenario, DNV estimates 227 MW of new battery storage capacity will be installed in PacifiCorp’s service territory over the nest twenty years (2023-2042). Figure E-2 shows the relationship between the base case and low and high case scenario forecasts. The low case scenario estimates 151 MW of new capacity over the 20-year forecast period— compared to base case, retail rates increase at a slower rate and technology costs decrease at a slower rate. In the high case, retail rates increase at a faster rate and technology costs decrease at a faster rate—this results in 264 MW of new private generation capacity installed by 2042. The twenty year total new capacity forecasted in the high case is about 16% greater than the base case, while the low case is 34% less. Table E-1 Cumulative Adopted Battery Storage Capacity by 2042, by Scenario SCENARIO CUMULATIVE CAPACITY (2042 MW) Base 227 Low 151 High 264 DNV – www.dnv.com February 2, 2023 Page 48 Figure E-2 Cumulative New Battery Storage Capacity Installed by Scenario (MW), 2023-2042 Figure E-3, Figure E-4, and Figure E-5 show the forecasts by customer sector and technology for each scenario. In all scenarios of the forecast, the residential sector represents about 90% of the new battery storage capacity forecasted to be installed over the next twenty years. The commercial, industrial, and irrigation sectors have been bundled into a single “Non- Residential” sector for the purpose of presenting the results in the report, as the capacity forecasts in the individual sectors are very small relative to the total forecast. PV + Battery systems represent the greatest share of the new battery capacity forecasted in the base and high cases. Battery Retrofit systems representing a greater share of the new battery capacity forecasted in the low case indicates that customers are more likely to adopt a PV Only system over a PV + Battery system when technology costs are higher and electricity rates are lower. Figure E-3 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, Base Case - 50 100 150 200 250 300 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High - 50 100 150 200 250 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Residential Battery Retrofit Residential PV + Battery Non-Residential Battery Retrofit Non-Residential PV + Battery DNV – www.dnv.com February 2, 2023 Page 49 Figure E-4 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, Low Case Figure E-5 Cumulative New Battery Storage Capacity Installed by Technology (MW), 2023-2042, High Case E.3 Storage Capacity Results by State As was the case in the private generation forecast, Utah represents the largest share of the battery capacity forecast. To date, the majority of installed battery storage capacity and annual growth in storage capacity has been in Utah, which represents the largest portion go PacifiCorp’s customer population. Battery adoption is expected to continue to grow in Utah, with the state’s share of total new capacity reaching between 81% and 84%, depending on the scenario, over the next twenty years. The net billing structure in place in Utah incentivizes PV + Battery storage co-adoption more so than traditional net metering, as customers can lower their electricity bills by charging their batteries with excess PV generation and dispatching their batteries to meet on-site load during times of day when retail energy prices are high. Oregon represents the - 20 40 60 80 100 120 140 160 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Residential Battery Retrofit Residential PV + Battery Non-Residential Battery Retrofit Non-Residential PV + Battery - 50 100 150 200 250 300 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Residential Battery Retrofit Residential PV + Battery Non-Residential Battery Retrofit Non-Residential PV + Battery DNV – www.dnv.com February 2, 2023 Page 50 second largest portion of the new capacity forecasted, between 8% and 10%. Net metering is the DER compensation mechanism in place in Oregon, but customer economics are boosted by PV + Battery incentives provided through the Oregon Department of Energy27. Figure E-6 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, Base Case Figure E-7 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, Low Case 27https://www.oregon.gov/energy/Incentives/Pages/Solar-Storage-Rebate-Program.aspx - 50 100 150 200 250 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W CA ID OR UT WA WY - 20 40 60 80 100 120 140 160 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W CA ID OR UT WA WY DNV – www.dnv.com February 2, 2023 Page 51 Figure E-8 Cumulative New Battery Storage Capacity Installed by State (MW), 2023-2042, High Case The following figures show the state-level forecasts in more detail. Background and commentary on the individual states’ results can be found in section 4.1 of the report. California Figure E-9 Cumulative New Battery Storage Capacity Installed by Scenario (MW), California, 2023-2042 - 50 100 150 200 250 300 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W CA ID OR UT WA WY - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High DNV – www.dnv.com February 2, 2023 Page 52 Figure E-10 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), California, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. CA Residential PV + Battery CA Residential Battery Retrofit CA Non-Residential PV + Battery CA Non-Residential Battery Retrofit - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Cu m u l a t i v e M W - 0.05 0.10 0.15 0.20 0.25 Cu m u l a t i v e M W - 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Cu m u l a t i v e M W - 0.05 0.10 0.15 0.20 0.25 0.30 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 53 Idaho Figure E-11 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Idaho, 2023-2042 Figure E-12 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Idaho, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. ID Residential PV + Battery ID Residential Battery Retrofit - 2 4 6 8 10 12 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High - 1 2 3 4 5 6 7 8 9 Cu m u l a t i v e M W - 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 54 ID Non-Residential PV + Battery ID Non-Residential Battery Retrofit Oregon Figure E-13 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Oregon, 2023-2042 - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Cu m u l a t i v e M W - 0.005 0.010 0.015 0.020 0.025 0.030 0.035 0.040 0.045 0.050 Cu m u l a t i v e M W - 5 10 15 20 25 30 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High DNV – www.dnv.com February 2, 2023 Page 55 Figure E-14 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Oregon, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. OR Residential PV + Battery OR Residential Battery Retrofit OR Non-Residential PV + Battery OR Non-Residential Battery Retrofit - 2 4 6 8 10 12 14 16 18 Cu m u l a t i v e M W - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 Cu m u l a t i v e M W - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 Cu m u l a t i v e M W - 0.5 1.0 1.5 2.0 2.5 3.0 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 56 Utah Figure E-15 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Utah, 2023-2042 Figure E-16 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Utah, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. UT Residential PV + Battery UT Residential Battery Retrofit - 50 100 150 200 250 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High - 20 40 60 80 100 120 140 Cu m u l a t i v e M W - 10 20 30 40 50 60 70 80 90 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 57 UT Non-Residential PV + Battery UT Non-Residential Battery Retrofit Washington Figure E-17 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Washington, 2023-2042 - 1 2 3 4 5 6 7 Cu m u l a t i v e M W - 1 2 3 4 5 6 7 8 Cu m u l a t i v e M W - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High DNV – www.dnv.com February 2, 2023 Page 58 Figure E-18 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Washington, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. WA Residential PV + Battery WA Residential Battery Retrofit WA Non-Residential PV + Battery WA Non-Residential Battery Retrofit - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 Cu m u l a t i v e M W - 0.2 0.4 0.6 0.8 1.0 1.2 Cu m u l a t i v e M W - 0.2 0.4 0.6 0.8 1.0 1.2 Cu m u l a t i v e M W - 0.05 0.10 0.15 0.20 0.25 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 59 Wyoming Figure E-19 Cumulative New Battery Storage Capacity Installed by Scenario (MW), Wyoming, 2023-2042 Figure E-20 Cumulative New Battery Storage Capacity Installed by Technology Across All Scenarios (MW), Wyoming, 2023-2042 Upper and lower bounds (in blue) represent the high and low case forecasts, with a line for the base case. WY Residential PV + Battery WY Residential Battery Retrofit - 1 2 3 4 5 6 7 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Cu m u l a t i v e M W Low Base High - 1 2 3 4 5 6 Cu m u l a t i v e M W - 0.005 0.010 0.015 0.020 0.025 0.030 0.035 0.040 Cu m u l a t i v e M W DNV – www.dnv.com February 2, 2023 Page 60 WY Non-Residential PV + Battery WY Non-Residential Battery Retrofit - 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 Cu m u l a t i v e M W - 0.002 0.004 0.006 0.008 0.010 0.012 0.014 0.016 0.018 0.020 Cu m u l a t i v e M W About DNV DNV is a global quality assurance and risk management company. Driven by our purpose of safeguarding life, property and the environment, we enable our customers to advance the safety and sustainability of their business. We provide classification, technical assurance, software and independent expert advisory services to the maritime, oil & gas, power and renewables industries. We also provide certification, supply chain and data management services to customers across a wide range of industries. Operating in more than 100 countries, our experts are dedicated to helping customers make the world safer, smarter and greener. PACIFICORP – 2023 IRP APPENDIX M – RENEWABLE RESOURCES ASSESSMENT 343 APPENDIX M – RENEWABLE RESOURCES ASSESSMENT Introduction A study on renewable resources and energy storage was commissioned to support PacifiCorp’s 2023 Integrated Resource Plan (IRP). The “2023 Renewables IRP” Assessment, prepared by WSP is screening-level in nature and includes a comparison of technical capabilities, capital costs, and operations and maintenance costs that are representative of renewable energy and storage technologies. The WSP Assessment builds upon prior studies, updates cost and technical information and adds gravity energy storage options (other than Pumped Hydro Energy Storage, or PHES) and offshore wind (OSW). This report compiles the assumptions and methodologies used by WSP during the Assessment. Its purpose is to articulate that the delivered information is in alignment with PacifiCorp’s intent to advance its resource planning initiatives. PACIFICORP – 2023 IRP APPENDIX M – RENEWABLE RESOURCES ASSESSMENT 344 PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 389 APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION Introduction Energy storage resources can provide a wide range of grid services and can be flexibly sized and sited. Many of these grid services have been increasing in value with increasing penetration of variable energy resources such as wind and solar, while energy storage costs have been falling. As a result, storage resources are an increasing component of PacifiCorp’s least-cost, least-risk preferred portfolio. While the 2023 IRP portfolio analysis captures the system benefits of energy storage, it does not fully account for localized benefits and siting opportunities. This appendix provides details on how energy storage resources can be configured to maximize the benefits they provide. Because energy storage resources are highly flexible, with the ability to respond to dispatch signals and act as both a load and a resource, they can potentially provide any of the grid services discussed herein. Other types of resources, including distributed generation, energy efficiency, and interruptible loads can also provide one or more of these grid services, and can complement or provide lower-cost alternatives to energy storage. Given that broad applicability, Part 1 of this appendix first discusses a variety of grid services as generically and broadly as possible. Part 2 discusses the key operating parameters of energy storage and how those operating parameters relate to the grid services in Part 1. Finally, Part 3 discusses how to optimize the configuration and dispatch of energy storage and other distributed resources to maximize the benefits to the local grid and the system. Part 3 also provides examples of specific applications and examples of applications that may be cost-effective in the future. Part 1: Grid Services PacifiCorp must ensure that sufficient energy is generated to meet retail customer demand at all times. It also must maintain resources that can respond to changing system conditions at short notice, these operating reserves are held in accordance with reliability standards established by the National Electric Reliability Corporation (NERC) and Western Electricity Coordinating Council (WECC). Both energy and operating reserves are dispatch-based, and dependent on the specific conditions at a specific place and time. These values are generally independent from hour to hour, as removing a resource in a subset of hours may not impact the value in the remaining hours. Because load can be higher than expected and some resources may be unavailable at any given time, sufficient generation resources are needed to ensure that energy and operating reserve requirements can be met with a high degree of confidence. This is referred to as generation capacity. The transfer of energy from the locations where it is generated to the locations where it is delivered to customers requires poles, wires, and transformers, and the capability of these assets is referred to as transmission and distribution (T&D) capacity. Generation and T&D capacity are both generally asset-based and provide value by allowing changes in the resources and T&D elements. In general, assets cannot be avoided based on changes to a subset of the hours in which they are needed, and only limited changes are possible once constructed or contracted. It should PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 390 also be noted that the impact of asset or capacity changes on dispatch must also be included in any valuation. These obligations are broken down into the following grid services, which are discussed in this section: • Energy, including losses; • Operating reserves, including: o Spinning reserve; o Non-spinning reserve; o Regulation and load following reserves; and o Frequency response; • Transmission and distribution capacity; and • Generation capacity. Energy Value Background Because PacifiCorp’s load and resources must be always balanced, when an increment of generation is added to PacifiCorp’s system, an increment of generation must also be removed. This could take the form of a generator that is backed down, an avoided market purchase, or an additional market sale. The cost of the increment that is removed (or the revenue from the sale), represents the energy value, and this value varies by location and by time. Location can also impact line losses relative to the generation which would otherwise have been dispatched, with losses manifesting as a larger effective volume. Regarding time, there are two relevant time scales: hourly values, and sub-hourly values. The energy value in a location is dependent on PacifiCorp’s load and resource balance, the dispatch cost of its resources, and the transmission capability connecting those resources to load. Differences in energy value occur when the economic resources in area exceed the transmission export capability to an area that must then use higher cost resources to serve load. Once transmission is fully utilized, the higher cost resources must be deployed to serve the importing area and lower cost resources will be available in the exporting area. As a result, the value in each location will reflect the marginal resources used to serve load in each area. If transfers are not fully utilized in either direction, the marginal resource in both areas would be the same, and the energy value would be the same. Both load and resource availability change significantly across the day and across the year. Differences in value over time are driven by the cost of the marginal resource needed to serve load, which changes when load or resource availability change. When load goes up, or the supply of lower-cost resources goes down, the marginal resource needed to serve load will be more expensive. The value by location is also dependent on the losses relative to the generation which would otherwise have been dispatched. Losses occur during the transfer of energy across the T&D system to a customer’s location. As distance and voltage transformation increase, more generation must be injected to meet a customer’s demand. For example, a distributed resource that is close to customer load or located on the same voltage level can avoid both energy at its location as well as the losses which otherwise would have occurred in delivering energy to that location. As a result, PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 391 the marginal generation resource’s output may be reduced by an amount greater than the metered output of a distributed resource. This increase in volume due to losses is also relevant to generation and T&D capacity value. Modeling There are two basic sources of energy values: market price forecasts and production cost models. There are also two relevant time scales: hourly values, and sub-hourly values. PacifiCorp produces a non-confidential official forward price curve (OFPC) for the major market points in which it typically transacts on a quarterly basis. The OFPC represents the price at which power would be transacted today, for delivery in a future period. The OFPC contains prices for each month for heavy load hour (HLH) and light load hour (LLH) periods and goes forward approximately 20 years.1 However, not all hours in the HLH or LLH periods have equal value. To differentiate between hours, PacifiCorp uses scalars calculated based on historical hourly results. For PacifiCorp’s operations and production cost modeling, scalars are based on the California Independent System Operator’s day-ahead hourly market prices. Because these values are used in operations, the details on the methodology and the resulting prices are treated confidentially. To allow for transparency, PacifiCorp has also developed non-confidential scalars using historical Energy Imbalance Market prices. With either scalars, the result is a forecast of hourly market prices that averages to the values in the OFPC over the course of a month. Using hourly market price to calculate energy value implies that market transactions are either the avoided resource, or a reasonable representation of the avoided resource’s marginal cost in any given interval. Production cost models contain a representation of an electric power system, including its load, resources, and transmission rights, as well as markets where power can be bought or sold. They also account for operating reserve obligations and the resources held to cover those obligations. All models are simplified representations, and there are several key simplifying assumptions. The granularity of a model is its smallest calculated timestep. While calculating twice as many timesteps should take roughly twice as long from a mechanical standpoint, evaluating decisions that span multiple time steps (such as when to charge or discharge a battery, or when to start or shutdown a thermal resource) requires the evaluation of multiple timesteps at once, resulting in a larger more complicated problem that can take longer to solve. In addition, maintaining inputs to represent smaller timesteps is more complicated, and a model is only as good as its inputs. To simplify the representation of location, transmission areas can be defined by the key transmission constraints which separate them, with transmission within each area assumed to be unconstrained. Another simplifying assumption is to model all load and resources at a level equivalent to generator input. For instance, load is “grossed up” from the metered volume to a level that includes the estimated losses necessary to serve it. This allows for a one for one relationship between all volumes, which vastly simplifies the model. PacifiCorp’s production cost modeling for the 2023 IRP uses the Plexos model and reflects system dispatch at an hourly granularity. While the IRP modeling uses the hourly market prices from the OFPC as inputs, a distributed resource’s energy value will depend on its location and other characteristics and can be either higher or lower than the market price in a given hour. Generally, a resource’s value is based on the difference between two production cost model studies: one with the resource included, and one with the resource excluded. This explicitly identifies the marginal 1 HLH is 6:00 a.m. to 10:00 p.m. Pacific Prevailing Time Monday through Saturday, excluding NERC holidays. LLH is all other hours. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 392 resources dispatched in the absence of the resource being evaluated. The Plexos model offers an alternative in that it reports the value of energy produced by each resource, by multiplying that resource’s output by the marginal price in that resource’s location for each hour. A comparable calculation is performed for operating reserves. This provides an estimate of the marginal benefits from any resource in the portfolio, without the need for with and without studies. However, for large resources or significant portfolio changes, with and without studies may still be necessary, as the reported results reflect the marginal cost of the last increment of generation, rather than the average across all of the resource’s output. More detailed models of the electrical power system also exist, for instance PacifiCorp uses physical models for grid operations and planning that account for power flows and the loading of individual system elements. Similarly, the California Independent System Operator (CAISO) uses a “Full Network Model” with detailed representations of all resources and loads, as well as the transmission system. CAISO’s model includes a representation of PacifiCorp’s system for the purpose of dispatching resources in the Western Energy Imbalance Market (EIM), and models a five minute granularity for that purpose. The added detail these physical models produce comes from a significant increase in the complexity of inputs and computational requirements. Table N.1 contains nominal levelized energy margin values for various combinations of energy storage specifications, and reflects marginal values reported by the Plexos model, including both energy and operating reserves. Table N.1 - Energy Margin by Energy Storage Attributes Duration Efficiency Levelized Annual Dispatch Revenue ($/kw-yr) Description (hrs) % 2027-2029 2030-2037 2038-2042 Lower efficiency, 4hr 4 70% $39 $30 $39 Typical Li-ion, 4hr 4 85% $44 $32 $42 Higher efficiency, 4hr 4 99% n/a $36 $46 Typical Li-ion, 8hr 8 85% $68 $63 $79 100 hour storage 100 38% $34 $41 $52 These energy values will vary by location, volume, and operating reserve requirements, as well as with changes in the portfolio. Longer duration provides greater value, though it diminishes as more duration is added. As shown above, changes in efficiency have relatively small impact on dispatch revenue. The Plexos model identifies resources to carry operating reserves for each hour, but does not include the intra-hour changes that would cause those resources to be deployed. Because resources that are dispatchable within the hour can be dispatched up when marginal energy costs are high, and down when marginal energy costs are low, this can result in incremental value relative to an hourly market price or hourly production cost model result. In practice, sub-hourly dispatch benefits are largely derived from PacifiCorp’s participation in EIM, and the specific rules associated with that market. For instance, resources must be participating in EIM in order to receive settlement payments based on their five-minute dispatches. Resources that are not participating receive settlement payments based on their hourly imbalance. Furthermore, because PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 393 non-participating resources are not visible to the market, their sub-hourly dispatch would not impact the market solution. Because distributed resources can be aggregated for purposes of EIM participation, size should not be an impediment; however, the structure of the EIM may dictate some aspects of their use and would need to be aligned with the other services a distributed resource provides. While intra-hour dispatch is a key aspect of reliable system operation, and potentially an additional source of revenue for flexible resources, it is difficult to represent the interactions between hourly dispatch in Plexos and sub-hourly dispatch in EIM – since they have finite storage capability, a battery that is discharged in response to high prices in EIM is likely to forego dispatch at relatively high prices in a later interval. In addition, imbalance in the EIM is finite in both duration and magnitude and the battery resources added in PacifiCorp’s preferred portfolio could easily move the market thereby drastically reducing the frequency of price excursions and the associated intra-hour revenue. In addition to potential EIM revenue for intra-hour dispatch, dispatchable resources may receive additional revenue for their availability during day-ahead and hour-ahead market operations, for example as part of the Extended Day-Ahead Market (EDAM) being developed by the California Independent System Operator. Because the Plexos model has a single system dispatch solution for each hour, without day-ahead or hour-ahead resource commitments and uncertainty, the additional value associated with this type of uncertainty is not part of the reported results. For these reasons, PacifiCorp has not quantified the costs or benefits of intra-hour dispatch for the 2023 IRP but expects to continue evaluating them as its portfolio and the market itself continue to evolve. Operating Reserve Value Background Operating reserve is defined by NERC as “the capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages and local area protection.”2 Operating reserves are capability that is not currently providing energy, but which can be called upon at short notice in response to changes in load or resources. Operating reserves and energy are additive – a resource can provide both at the same time, but not with the same increment of its generating capability. Operating reserves can also be provided by interruptible loads, which have an effect comparable to incremental resources. Additional details on operating reserve requirements are provided in Volume II, Appendix F (Flexible Reserve Study). As with energy value, operating reserve value is based on the marginal resource that would otherwise supply operating reserves, and varies by both location, time, and the speed of the response. Because operating reserve requirements are primarily applied at the Balancing Authority Area (BAA) level, the associated value is typically uniform within each of PacifiCorp’s BAAs. An exception to this is that operating reserves must be deliverable to balance load or resources, so unused capability in a constrained bubble without additional export capability does not count toward the meeting the requirements. Operating reserve value is somewhat indirect in comparison to energy value, as it relates to the use of the freed-up capacity on units that would otherwise be holding reserves. If that resource’s incremental energy is less expensive that what is currently 2 Glossary of Terms Used in NERC Reliability Standards: https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf, updated March 8, 2023. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 394 dispatched, it can be dispatched up, and more expensive energy can be dispatched down. The value of the operating reserves in that instance is the margin between the freed-up energy and the resource that is dispatched down. Note that the dispatch price of the resource being evaluated does not impact the value, since holding operating reserves does not require dispatch. When the freed-up resource is more expensive than what is currently dispatched, it will not generate more when the operating reserve requirement is removed, and the value of operating reserves would be zero. Operating reserves are generally held on the resources with the highest dispatch price. Finally, operating reserve value is limited by the speed of the response: how fast a unit can ramp up in a specified period, and how soon it begins to respond after receiving a dispatch signal. Reliability standards require a range of operating reserve types, with response times ranging from seconds to thirty minutes. Modeling As discussed above, the value of incremental operating reserves is equal to the positive margin between the dispatch cost of the lowest cost resource that was being held for reserve, and the dispatch cost of the highest cost resource that was dispatched for energy. Similar to the value of energy, the price of different operating reserve types could be forecasted by hour, based on forecasts of reserve capability, demand, and resource dispatch costs. Given the range and variability in these components, this would be an involved calculation. In addition, because operating reserves are a small fraction of load, they are more sensitive to volume than energy. For instance, spinning reserve obligations are approximately three percent of load in each hour. As a result, resource additions may rapidly cover that portion of PacifiCorp’s requirement met by resources that could otherwise provide economic generation and which produce a margin when released from reserve holding. This is particularly true for batteries and interruptible load resources that can respond rapidly and thus count all or most of their output toward reserve obligations. While a market price for operating reserve products does not align well with PacifiCorp’s system, the specifics of the calculation described above are embedded within PacifiCorp’s production cost models. Those models allocate reserves first to energy limited resources in those periods where they could generate but are not scheduled to do so. Examples of energy limited resources include interruptible loads, hydro, and energy storage. If called on for reserves, these resources would lose the ability to generate in a different period, so the net effect on energy value for that resource is relatively small. As a result, the unused capacity on these resources can’t be used for generation, but that also means it can count as reserves without forgoing any generation and incurring a cost to do so. After operating reserves have been fully allocated to the available energy-limited resources, reserves are allocated to the highest cost generators with reserve capability in the supply stack, up to each unit’s reserve capability, until the entire requirement is met. This is generally done prior to generation dispatch and balancing because the requirements are input to the model or based on a formula and aren’t typically restricted based on transmission availability. After the reserve allocations are complete, the remaining dispatch capability of each unit is used to develop an optimized balance of load and resources. As part of the calculation of wind and solar integration costs reported in Volume II, Appendix F (Flexible Reserve Study), PacifiCorp assessed the cost of holding incremental operating reserves. That study identified a cost of approximately $41/kw-yr (2022$), based on a 2025-2042 study period. This value would be applicable to any resource that provided operating reserves uniformly throughout the year. Like reporting on energy values, the Plexos model also reports operating reserve revenues specific to each modeled resource, accounting for availability, location, and use PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 395 for energy dispatch (during which a resource could not also provide reserves with any portion of its capacity that was generating energy). As with the annual wind and solar costs shown in Appendix F, operating reserve value is projected to be highest in the near term and decline across the study horizon as the amount of battery resources on the system increases. Transmission and Distribution Capacity The 2021 IRP included endogenous transmission upgrades as part of portfolio selection. This allows the cost of transmission upgrades to be considered as part of the modeled cost of resources in each area. However, because energy efficiency and load control are customer-sited, they are not subject to these constraints, placing them at an advantage relative to both thermal and renewable resource options. For some sizes and locations, distributed resources can also potentially avoid significant transmission upgrades and may help to defer distribution system investments. While the cost of specific T&D projects varies, a generic system wide estimate of transmission upgrade costs is included as a credit to energy efficiency in the 2021 IRP and amounts to $6.34/kw-year (2020$). In practice, these costs would vary by project and some transmission upgrades would not be suitable for deferral by distributed resources. Because of the large scale of many transmission upgrades, and the binary nature of the expenditures, it may be difficult to procure adequate distributed resources to cover the need in a timely fashion and in accordance with reliability requirements, though it is always appropriate to consider the available options when considering expenditures on an upgrade. Distribution capacity upgrades are more likely to be suitable for deferral by a distributed resource, as the scale of the need is closer to that of these types of resources. To that end, PacifiCorp maintains an “Alternative Evaluation Tool” which is used to screen the list of projects identified during T&D planning to assess where distributed resources, including energy storage, could be both technically feasible and cost competitive as compared to traditional T&D solutions. If a study shows that distributed resource alternatives are feasible and potentially cost-competitive that project is flagged for detailed analysis. Generation Capacity Background To provide reliable service to customers, a utility must have sufficient resources in every hour to: • Serve customer load, including losses and any unanticipated load increase. • Hold operating reserves to meet NERC and WECC reliability standards, including contingency, regulation, and frequency response. • Replace resources that are unavailable due to: o Forced and planned outages o Dry hydro conditions o Wind and solar conditions o Market conditions PacifiCorp refers to “Generation Capacity” as the total quantity of resources necessary to reliably serve customers, after accounting for the items above. For the 2021 IRP, PacifiCorp identified a planning reserve margin of 13 percent over its hourly loads throughout the year. The planning reserve margin does not translate directly into either resources or need. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 396 All resources contribute to a reliable portfolio, but they do so in ways that are not straightforward to measure and are dependent on the composition of the portfolio. Removing a resource from a portfolio will make that portfolio less reliable unless it is replaced with something else, ideally in a quantity that provides an equal capacity contribution and results in equivalent reliability. For more details on capacity contribution, please refer to Volume II, Appendix K (Capacity Contribution). As a result, the most direct measurement of the generation capacity value of a resource is to build a portfolio that includes it and compare that portfolio to one without it. But even that analysis would identify more than just generation capacity value, as it would also include energy and operating reserve impacts related to both the resource being added and resources that were delayed or removed. This is an essential description of the steps used to develop portfolios in the IRP, and while powerful, the IRP models and tools do not lend themselves to ease of use, rapid turnaround, or the evaluation of small differences in portfolios. As an alternative, a simplified approach to generation capacity value can be used when the resources being evaluated are small or like the proxy resource additions identified in the IRP preferred portfolio. The premise of the approach is that the IRP preferred portfolio resources represent the least-cost, least-risk path to reliably meet system load. The appropriate level of generation capacity value is inherently embedded in the IRP preferred portfolio resource costs because those resources achieve the stated goal of reliable operation. Part 2: Energy Storage Operating Parameters This section discusses some of the key operating parameters associated with energy storage resources. Beyond just defining the basic concepts, it is important to recognize the specific ways in which these parameters are measured and ensure that any comparison of different technologies or proposals reports equivalent values. For example, many battery systems operate using direct current (DC) rather than the alternating current (AC) of most of the electrical grid. When charging or discharging from the grid, inverters must convert DC power to AC power, which creates losses that reduce the effective output when measured at the grid, rather than at the battery. To handle this distinction, PacifiCorp uses the AC measurement at the connection to the electrical grid for all parameters, as this aligns with the effective “generation input” of an energy storage resource. As previously discussed, an additional adjustment for line losses on the electrical grid may also be necessary, but that is dependent on the location and conditions on the electrical grid, rather than the energy storage resource. • Discharge capacity: The maximum output of the energy storage system to the grid, on an AC-basis, measured in megawatts (MW). This is generally equivalent to nameplate capacity. • Storage capacity: The maximum output of the energy storage system to the grid, on an AC-basis, when starting from fully charged, measured in megawatt-hours (MWh). • Hours of storage: The length of time that an energy storage system can operate at its maximum discharge capacity, when starting from fully charged, measured in hours. Generally, the hours of storage will be equal to storage capacity divided by discharge capacity. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 397 • Charge capacity: The maximum input from the grid to the energy storage system, on an AC-basis, measured in megawatts (MW). • Round-trip efficiency: The output of the energy storage system to the grid, divided by the input from the grid necessary to achieve that level of output, stated as a percentage. A storage resource with eighty percent efficiency will output eight MWh when charged with ten MWh. If charge and discharge capacity are the same, losses result in a longer charging time. For instance, an energy storage system with four hours of storage, eighty percent efficiency, and identical charge and discharge capacity would require five hours to fully charge (4 hours of discharge divided by 80 percent discharge MWh per charge MWh). • State of charge: This is a measure of how full a storage system is, calculated based on the maximum MWh of output at the current charge level, divided by the storage capacity when fully charged, and is stated as a percentage. One hundred percent state of charge indicates the storage system is full and can’t store any additional energy, while zero percent state of charge indicates the storage system is empty and can’t discharge any energy. As previously indicated, PacifiCorp’s state of charge metric is based on output to the grid. As a result, the entire round-trip efficiency loss is applied during charging before reporting the state of charge. For example, a storage system with a ten MWh storage capacity and eighty percent efficiency would only have an eighty percent state of charge after ten MWh of charging had been completed, starting from empty. • Station service: Round-trip efficiency is a measure of the losses from charging and discharging. Some energy storage systems also draw power for temperature control and other needs. This is typically drawn from the grid, rather than the energy storage resource. Some energy storage technologies experience degradation of their operating parameters over time and based on use. The following parameters are used to quantify the effects of degradation. • Storage capacity degradation: The primary impact of degradation is on storage capacity. Much of the degradation occurs as part of charge-discharge cycles and can be measured as the degradation per thousand cycles. After one thousand cycles, a four-hour storage system might only be capable of storing 3.5 hours of output. Some storage resources also experience degradation that isn’t tied to cycles, for instance based on differing state of charge levels or time. • Cycle life: This is the total number of full charge and discharge cycles that energy storage equipment is rated for. Three thousand cycles are common for lithium-ion resources, but operating under harsh conditions can also cause the effective cycle count to decline faster. Once storage capacity has degraded by thirty percent degradation per cycle may accelerate. • Depth of discharge: Operating at a very high or very low state of charge, particularly for an extended period, can cause more rapid degradation. This metric can be used to identify how particular operations impact the effective remaining cycle life. • Variable degradation cost: Lithium-ion energy storage equipment is composed of many battery modules, each of which experience degradation. These modules can be gradually replaced over time to maintain a more consistent storage capacity, or they can be replaced all at once when cycle limits are reached, at the expense of a reduced storage capacity in the interim. In either case, the replacement cost of storage equipment can be expressed per MWh of discharge and accounted for as part of resource dispatch. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 398 Part 3: Distributed Resource Configuration and Applications This section described the potential benefits of different distributed resource siting and configuration options. Due to economies of scale, distributed resource solutions generally higher cost relative to utility-scale assets. Many of PacifiCorp’s distribution substations have capacity more than fifteen megawatts, such that a battery of that size could be feasible at the distribution level, with the potential for incremental benefits relative to the transmission-connected battery resources modeled as part of the preferred portfolio. The most cost-effective locations for distributed resource deployment are likely to reflect a balance of local requirements and economies of scale. Secondary Voltage A distributed resource which is located downstream from the high voltage transmission grid will have a larger energy impact than its metered output would indicate, due to line losses. This is true for both charging and discharging. To the extent discharging is aligned with periods with higher load, and charging is aligned with periods with lower load, the benefits will be proportionately higher. For example, the marginal primary voltage losses for Oregon have been estimated at 9.5 percent on average across the year. Savings based on primary losses would be appropriate to apply to a resource connected at the secondary voltage level so long as it is not generating exports to the higher voltage system, as losses would still occur within that level, but would be reduced due to lower deliveries across the higher voltage system. For lithium-ion batteries, there is also an incremental benefit related to variable degradation costs. While the effect of losses makes the battery appear larger from a system benefits perspective, it discharges the same amount, so the variable cost component doesn’t scale with losses, creating an additional benefit that is captured in this energy margin. In addition to incremental energy value, resources connected at primary or secondary voltage will also have a proportionately higher generation capacity value and will have a higher capacity contribution based on their ability to avoid primary losses. Such adjustments to account for avoided losses are also applied to energy efficiency and demand response measures. T&D Capacity Deferral As indicated in the grid services section, distributed resources can allow for the deferral of upgrades by reducing the peak loading of the transmission and distribution system elements serving their area. For deferral to be achieved, a distributed resource must reliably reduce load under peak conditions. However, the timing of peak conditions for a given area is likely to vary from the peak conditions for the system. As a result, the energy or generation capacity value of energy-limited resources used for a T&D capacity deferral application are likely to be reduced. For instance, when energy-limited resources are reserved for local area requirements they would not be available for system reliability events or a period of high energy prices. Flexible Hydrogen Production Hydrogen has been proposed as a possible energy storage medium, due to its relative ease of production via electrolysis, particularly when paired with low-cost electricity supplied by renewable resources. While PacifiCorp’s modeling since the 2021 IRP has included non-emitting peaking resource options that could potentially use modest amounts of hydrogen fuel, other PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 399 industries including transportation and manufacturing may also have demand for hydrogen supply. This is particularly true considering tax incentives established in the Inflation Reduction Act, which provide credits for hydrogen production, as well as for electricity production, which is the primary cost input in the production of hydrogen. Because tax incentives significantly reduce the production cost of hydrogen, PacifiCorp’s 2023 IRP uses a hydrogen price that generally matches the cost of natural gas, inclusive of the greenhouse gas emissions cost associated with natural gas in that price-policy scenario. This continues until tax credit eligibility for hydrogen production phases out in 2040, at which point hydrogen is more expensive than natural gas, except in the Social Cost of Greenhouse Gases price- policy scenario, where their costs remain similar because of the very high cost of emissions. To assess the potential for flexible hydrogen production, PacifiCorp calculated how often marginal electricity prices would be below the marginal cost of hydrogen production at various locations across PacifiCorp’s system, as shown in Figure N.1. In Southern Oregon, the timing of production is heavily weighted toward the daytime and the spring, when solar and hydro generation are high and load is relatively low, as shown in Figure N.2. In Utah and Wyoming, shown in Figure N.3 and , potential hydrogen production is common during daylight hours, based on the availability of generation, and during the winter, based on the availability of wind. These figures assume an 80% electrolyzer efficiency, which is at the high end of today’s technology, but reasonable with significant expansion and technological progress with an expanded hydrogen electrolysis industry. To maximize tax credits associated with hydrogen, it must be produced from non-emitting generation sources. Figure N.5 shows the greenhouse gas emissions from the Company coal and gas resources during those hours in which hydrogen electrolysis load could be economic using the same 2033 data shown in Figure N.2. During 2033, hourly emissions during possible hydrogen electrolysis load hours were approximately 0.1% of the Company’s forecasted hourly emissions for 2023, i.e. a nearly 99.9% reduction. In contrast, the average emissions during 2033 were approximately 17% of the forecasted value for 2023, which equates to a still significant 83% reduction. Note that this analysis reflects total emissions, and not marginal emissions. As a result, thermal units that are operating at minimum due to limits on starts and shutdown are included in the reported totals but would not increase their output in response to modest increases in demand. As a result, the requirement that hydrogen production be supplied by assured non-emitting generation sources would be unlikely to have a significant impact on the load factor shown in Figure N.2. PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 400 Figure N.1 – Hydrogen Electrolysis Load Factor 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 20 2 4 20 2 5 20 2 6 20 2 7 20 2 8 20 2 9 20 3 0 20 3 1 20 3 2 20 3 3 20 3 4 20 3 5 20 3 6 20 3 7 20 3 8 20 3 9 20 4 0 20 4 1 20 4 2 An n u a l L o a d F a c t o r ( % ) MM Southern OR SC-GHG Southern OR MM Utah North SC-GHG Utah North MM Wyoming East SC-GHG Wyoming East PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 401 Figure N.2 – Hydrogen Electrolysis Load Factor by Month and Hour, Southern Oregon Month MM Price-Policy Southern OR 2033 Hour 1 2 3 4 5 6 7 8 9 10 11 12 Average 0 0% 7% 6% 13% 3% 0% 0% 0% 0% 0% 0% 0%2% 1 0% 7% 6% 13% 3% 0% 0% 0% 0% 0% 0% 0%2% 2 0% 7% 6% 13% 3% 0% 0% 0% 0% 0% 0% 0%2% 3 0% 7% 6% 13% 3% 0% 0% 0% 0% 0% 0% 0%2% 4 0% 7% 6% 13% 3% 0% 0% 0% 0% 0% 0% 0%2% 5 0% 7% 6% 17% 23% 13% 0% 0% 0% 0% 0% 0%5% 6 0% 7% 6% 57% 77% 40% 3% 0% 0% 0% 0% 0%16% 7 0% 7% 26% 60% 87% 47% 3% 0% 7% 0% 0% 0%20% 8 3% 7% 39% 73% 87% 50% 3% 0% 7% 0% 0% 0%22% 9 6% 21% 45% 87% 87% 50% 3% 0% 7% 0% 0% 0%25% 10 6% 25% 68% 97% 87% 50% 3% 0% 7% 0% 0% 0%28% 11 10% 50% 77% 97% 87% 50% 3% 0% 7% 0% 0% 0%32% 12 10% 54% 87% 97% 87% 50% 3% 0% 7% 0% 0% 0%33% 13 10% 54% 87% 97% 87% 50% 3% 0% 7% 0% 0% 0%33% 14 6% 54% 87% 97% 87% 50% 3% 0% 7% 0% 0% 0%32% 15 6% 29% 65% 97% 84% 37% 3% 0% 7% 0% 0% 0%27% 16 3% 14% 52% 97% 84% 33% 0% 0% 7% 0% 0% 0%24% 17 0% 11% 13% 47% 52% 17% 0% 0% 3% 0% 0% 0%12% 18 0% 11% 10% 10% 3% 0% 0% 0% 3% 0% 0% 0%3% 19 0% 11% 10% 10% 3% 0% 0% 0% 3% 0% 0% 0%3% 20 0% 11% 10% 10% 3% 0% 0% 0% 3% 0% 0% 0%3% 21 0% 11% 10% 10% 3% 0% 0% 0% 3% 0% 0% 0%3% 22 0% 11% 10% 10% 3% 0% 0% 0% 0% 0% 0% 0%3% 23 0% 11% 10% 10% 3% 0% 0% 0% 0% 0% 0% 0%3% Average 3% 18% 31% 48% 44% 22% 1% 0% 3% 0% 0% 0%14% PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 402 Figure N.3 – Hydrogen Electrolysis Load Factor by Month and Hour, Utah North Month MM Price-Policy Utah North 2033 Hour 1 2 3 4 5 6 7 8 9 10 11 12 Average 0 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 27% 32%19% 1 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 30% 32%19% 2 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 30% 32%19% 3 45% 54% 19% 13% 3% 0% 0% 3% 7% 32% 33% 32%20% 4 48% 54% 23% 13% 3% 0% 0% 3% 7% 35% 33% 32%21% 5 48% 54% 26% 40% 58% 27% 3% 3% 10% 35% 33% 32%31% 6 48% 61% 45% 70% 90% 67% 19% 26% 30% 42% 33% 32%47% 7 55% 71% 74% 93% 90% 67% 23% 35% 60% 58% 40% 35%58% 8 61% 82% 81% 97% 90% 70% 26% 35% 63% 61% 47% 48%63% 9 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 52%64% 10 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 52%64% 11 61% 86% 87% 97% 90% 70% 23% 35% 67% 61% 50% 52%65% 12 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 52%64% 13 61% 86% 87% 97% 90% 70% 23% 35% 63% 65% 50% 52%65% 14 61% 86% 87% 97% 90% 73% 26% 35% 63% 58% 50% 52%65% 15 61% 75% 84% 97% 90% 67% 19% 32% 60% 48% 47% 48%61% 16 48% 57% 71% 97% 90% 60% 10% 19% 33% 29% 30% 29%48% 17 42% 43% 32% 50% 58% 33% 3% 0% 10% 26% 30% 29%30% 18 42% 43% 19% 13% 3% 0% 0% 0% 10% 26% 30% 29%18% 19 42% 43% 19% 13% 3% 0% 0% 0% 10% 26% 30% 29%18% 20 42% 43% 19% 13% 3% 0% 0% 0% 10% 26% 30% 29%18% 21 42% 43% 19% 13% 3% 0% 0% 0% 10% 26% 30% 29%18% 22 42% 39% 19% 13% 3% 0% 0% 0% 10% 26% 30% 29%18% 23 42% 39% 19% 13% 3% 0% 0% 0% 10% 23% 27% 29%17% Average 51% 61% 48% 53% 48% 34% 10% 15% 31% 41% 37% 38%39% PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 403 Figure N.4 – Hydrogen Electrolysis Load Factor by Month and Hour, Wyoming East Month MM Price-Policy Wyoming East 2033 Hour 1 2 3 4 5 6 7 8 9 10 11 12 Average 0 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 30% 45%21% 1 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 33% 45%21% 2 45% 54% 19% 13% 3% 0% 0% 0% 7% 32% 33% 45%21% 3 45% 54% 19% 13% 3% 0% 0% 3% 7% 32% 37% 42%21% 4 52% 54% 23% 13% 3% 0% 0% 3% 7% 35% 37% 42%22% 5 52% 54% 26% 40% 58% 27% 3% 3% 10% 35% 37% 39%32% 6 48% 61% 45% 70% 90% 67% 19% 26% 30% 42% 37% 39%48% 7 55% 71% 74% 93% 90% 67% 23% 35% 60% 58% 40% 42%59% 8 61% 82% 81% 97% 90% 70% 26% 35% 63% 61% 47% 55%64% 9 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 58%65% 10 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 58%65% 11 61% 86% 87% 97% 90% 70% 23% 35% 67% 61% 50% 58%65% 12 61% 86% 87% 97% 90% 70% 23% 35% 63% 61% 50% 58%65% 13 61% 86% 87% 97% 90% 70% 23% 35% 63% 65% 50% 58%65% 14 61% 86% 87% 97% 90% 73% 26% 35% 63% 58% 50% 58%65% 15 61% 75% 84% 97% 90% 67% 19% 32% 60% 48% 47% 55%61% 16 48% 57% 71% 97% 90% 60% 10% 19% 33% 32% 40% 45%50% 17 48% 46% 32% 50% 58% 33% 3% 0% 10% 29% 40% 45%33% 18 52% 46% 19% 13% 3% 3% 0% 0% 10% 26% 40% 45%21% 19 48% 46% 19% 13% 3% 0% 0% 0% 10% 26% 40% 45%21% 20 48% 46% 19% 13% 3% 0% 0% 0% 10% 26% 37% 45%21% 21 48% 43% 19% 13% 3% 0% 0% 0% 10% 26% 37% 48%21% 22 48% 39% 19% 13% 3% 0% 0% 0% 10% 26% 37% 48%20% 23 48% 39% 19% 13% 3% 0% 0% 0% 10% 23% 33% 48%20% Average 53% 62% 48% 53% 48% 34% 10% 15% 31% 41% 41% 49%40% PACIFICORP – 2023 IRP APPENDIX N – ENERGY STORAGE POTENTIAL EVALUATION 404 Figure N.5 – Greenhouse Gas Emissions During Hydrogen Electrolysis Load Hours as Percentage of 2023 Average Month MM Price-Policy Southern OR System coal and gas 2033 Hour 1 2 3 4 5 6 7 8 9 10 11 12 Average 0 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 1 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 2 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 3 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 4 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 5 n/a 0.0% 0.0% 0.0% 0.0% 1.4% n/a n/a n/a n/a n/a n/a 0.3% 6 n/a 0.0% 0.0% 0.0% 0.0% 0.2% 1.8% n/a n/a n/a n/a n/a 0.1% 7 n/a 0.0% 0.1% 0.0% 0.0% 0.2% 1.8% n/a 0.9% n/a n/a n/a 0.1% 8 0.0% 0.0% 0.1% 0.0% 0.0% 0.3% 1.8% n/a 0.9% n/a n/a n/a 0.1% 9 0.0% 0.1% 0.1% 0.0% 0.0% 0.3% 1.8% n/a 0.9% n/a n/a n/a 0.1% 10 0.0% 0.8% 0.0% 0.0% 0.0% 0.3% 1.8% n/a 0.9% n/a n/a n/a 0.1% 11 0.0% 0.1% 0.0% 0.0% 0.0% 0.3% 1.8% n/a 0.9% n/a n/a n/a 0.1% 12 0.0% 0.3% 0.2% 0.0% 0.0% 0.3% 1.8% n/a 0.9% n/a n/a n/a 0.1% 13 0.6% 0.2% 0.1% 0.0% 0.0% 0.7% 6.6% n/a 0.9% n/a n/a n/a 0.2% 14 0.0% 0.3% 0.4% 0.3% 0.0% 1.5% 4.6% n/a 3.3% n/a n/a n/a 0.5% 15 0.0% 0.5% 0.8% 0.6% 0.0% 1.7% 3.8% n/a 1.5% n/a n/a n/a 0.6% 16 0.0% 0.0% 0.5% 0.4% 0.3% 0.8% n/a n/a 1.6% n/a n/a n/a 0.4% 17 n/a 0.0% 0.0% 0.1% 0.0% 0.6% n/a n/a 0.0% n/a n/a n/a 0.1% 18 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a 0.0% n/a n/a n/a 0.0% 19 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a 0.0% n/a n/a n/a 0.0% 20 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a 0.0% n/a n/a n/a 0.0% 21 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a 0.0% n/a n/a n/a 0.0% 22 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% 23 n/a 0.0% 0.0% 0.0% 0.0% n/a n/a n/a n/a n/a n/a n/a 0.0% Average 0.1% 0.1% 0.1% 0.1% 0.0% 0.7% 2.8% n/a 0.9% n/a n/a n/a 0.1% PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 405 APPENDIX O – WASHINGTON 2021 IRP TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS Introduction Washington passed the Clean Energy Transformation Act (CETA) in 2019, which combines directives for utilities to pursue a clean energy future with assurances that benefits from a transformation to clean power are equitably distributed among all Washingtonians.1 The Washington Utilities and Transportation Commission began rulemakings to implement CETA in June 2019, and the first phase concluded in December 2020. As directed by the legislation and the new CETA rules, beginning January 1, 2023, the Company must file a two-year progress report at least every two years after PacifiCorp has filed its IRP.2 This two-year progress report must include the following: - Updated load forecast, demand-side resource assessment, including a new conservation potential assessment; resource costs; and portfolio analyses and preferred portfolios; - Other updates necessary due to changing state or federal requirements, or significant changes to economic or market forces; and - Update any elements found in the utility’s current clean energy implementation plan (CEIP).3 The Company’s updated load forecast can be found in Volume 1, Appendix A; demand-side resource assessment and new conservation potential assessment can be found in Chapter 6 and the Specific Actions section below; resource costs can be found in Volume I, Chapter 7; and relevant portfolio analyses can be found in Volume I, Chapters 8 and 9, and the Interim and Specific Targets section below.4 Relevant state and federal policy updates, as well as changes to economic or market forces, can be found in Volume I, Chapter 3.5 Aligned with the refiled CEIP,6 this 2021 IRP Two-Year Progress Report includes updates on the following CEIP elements: Interim and Specific Targets; Updated Inputs, including portfolio analysis and preferred portfolios; Customer Benefit Indicators; Specific Actions, including both supply and demand-side actions; Incremental Costs; Public Participation; and Annual Reporting. 1 2019 WA Laws Ch. 288. 2 WAC 480-100-625. 3 Id. -625(4). 4 Id. -625(4)(a). 5 Id. -625(4)(b). 6 PacifiCorp filed its first Clean Energy Implementation Plan (CEIP) on December 29, 2021, with the Washington Utilities and Transportation Commission (WUTC) in docket UE-210289. The Company filed a Revised Errata to the CEIP to make a small correction to a workpaper that resulted in a change in the calculated incremental cost. Consistent with UE-220376, Order 06, the Company refiled its 2021 CEIP on March 13, 2023, and relevant CEIP elements are included in this 2021 IRP Two-Year Progress Report. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 406 Each of these updated CEIP elements are discussed below. Additionally, consistent with WAC 480-100-650, more detailed and specific reporting on CEIP targets, actions, and CBIs will be included in the Company’s annual clean energy progress report due this summer, and CEIP biennial update due later this fall. Interim and Specific Targets CETA’s clean energy transformation requires Washington utilities to eliminate coal-fired resources from its allocation of electricity to Washington retail electric customers by 2026; ensure all retail sales of electricity to Washington electric customers are greenhouse gas neutral by 2030; and ensure that non-emitting electric generation and electricity from renewable resources supply one hundred percent of all retail sales of electricity to Washington electric customers by 2045.7 Prior to 2045, CETA allows for up to 20 percent of the greenhouse gas neutral standard to be met with alternative compliance in the form of alternative compliance payments, unbundled RECs, energy transformation projects, or energy recovery from a municipal solid waste facility.8 To achieve the 2045 target, the clean energy standard must be met with 100 percent non-emitting generation or electricity from renewable energy resources. Furthermore, PacifiCorp must demonstrate that it “has made progress toward and has met the standards in this section at the lowest reasonable cost.”9 Consistent with these requirements and WAC 480-100-640, the Company proposes interim targets to demonstrate its trajectory toward meeting CETA’s decarbonization targets. Updated interim targets are based on data and methodologies consistent with portfolio development and modeling in Volume 1, Chapters 8 and 9, and with CEIP requirements. Specifically, CEIP targets are demonstrated for a least-cost, least-risk portfolio optimized under the price policy assumption that includes societal cost of greenhouse gas emissions (SCGHG).10 As shown in Volume I, Chapter 8 (Modeling and Portfolio Evaluation), Figure 8.4 – the SCGHG starts at just over $80/ton in 2023 and reaches about $170/ton in 2042. In addition to the assumed carbon dioxide price, there is an additional forecasted cost of allowances under the cap-and-invest program established in the Climate Commitment Act passed by Washington Legislature in 2021. This forecasted allowance cost is applied to all emissions from the Chehalis natural gas plant located in Washington. The modeled allowance cost reflects analysis conducted by Vivid Economics for the Washington Department of Ecology and starts at $58/ton in 2023.11 For more discussion of the system-wide portfolio impacts of the SC price-policy assumptions and CETA-related portfolio impacts, see results in Volume I, Chapter 9 (Modeling and Portfolio Selection Results). 7 WAC 480-100-610(1-3). 8 RCW 19.405.040(1)(b). 9 WAC 480-100-610(5). 10 The SCGHG dispatch adder is modeled in both the resource acquisition decision (capacity expansion in the LT model), and in operations (dispatch in the MT and ST models) as described in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). 11 Washington DOE Summary of market modeling and analysis of the proposed Cap and Invest Program, at 4 (Jun. 2022) (available here: https://ecology.wa.gov/DOE/files/4a/4ab74e30-d365-40f5-9e8f-528caa8610dc.pdf; accessed Mar. 31, 2023). PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 407 Based on these updated portfolio inputs, the Company anticipates supplying 26 percent renewable and non-emitting energy to serve Washington retail sales in 2023, increasing to 33 percent in 2025, to 82 percent in 2030, and finally over 100 percent beginning in 2032 and maintaining this percentage for the remainder of the Company’s planning period. Interim Targets This section includes PacifiCorp’s interim compliance targets for the first CETA action period (2022-2025), and to achieve CETA’s 2030 and 2045 targets. Figure O.1 reports PacifiCorp’s updated interim targets that are derived from the portfolio denoted W-10 CETA.12 This portfolio was developed to meet CETA’s 2030 and 2045 decarbonization targets under the SCGHG price policy assumption. In the figure interim targets are divided into two forecast ranges: the first focuses on meeting CETA’s 100 percent GHG neutrality standard by 2030, and the second focuses on meeting the 100 percent non-emitting and renewable energy target by 2045. As shown in the figure, the Company expects to have achieved CETA’s ambitious decarbonization targets well over a decade in advance of the 2045 deadline. Post-2030, the last three years to reach the 2045 objective are beyond the Company’s current 20- year study period. Rather than creating extrapolated and imprecise forecasts for every data point underlying the analysis to extend into 2045, the company has extrapolated the last three years of data based on the already optimized and established trajectory. However, this exercise was unnecessary given that the portfolio shows 100 percent clean energy as a percentage of Washington retail sales by 2032. Figure O.1 – Interim Targets 12 Several portfolios were developed to analyze the impacts of CETA in various planning scenarios, and are defined in Volume I, Chapter 8 (Modeling and Portfolio Evaluation). PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 408 Table O.1 below reports updated interim targets for the Company’s first CEIP action period for years 2022 through 2024, reported as annual megawatt hours of energy rather than as percentages. Since this two-year IRP progress report is forward-looking, portfolio inputs, outputs, and interim targets begin from year 2023. However given the Company’s current CEIP focuses on the CEIP compliance period from 2022 to 2025, this same compliance period is reflected below. The values for 2022 are from the Company’s March 13, 2023 Refiled CEIP and have not been updated, and are informed by the company’s historical performance under median water conditions, a factor in developing expected resource behaviors and Washington retail sales. Table O.1 - Interim Compliance Targets (MWh) 20221 2023 2024 2025 Total Retail Electric Sales 4,051,128 4,128,751 4,141,107 4,106,386 16,427,372 Projected Renewable and Non-emitting Energy 1,262,111 1,081,277 1,028,236 1,367,667 4,739,291 Net Retail Sales 2,789,017 3,047,474 3,112,871 2,738,719 11,688,081 Target Percentage 31% 26% 25% 33% Interim Compliance Target 1,262,111 1,081,277 1,028,236 1,367,667 4,739,291 1 Originally estimated target for 2022 based on Refiled 2021 CEIP, March 13, 2023 These updated interim targets reflect both updates from the Company’s portfolio results, as well as updated resource allocation assumptions. Importantly, increases in system load, changes in price curves and fuel inputs, and development in federal regulation like the Ozone Transport Rule, have driven significant growth in system renewable resources across the planning horizon. However, ongoing wholesale energy market volatility has forced the Company to consider options to mitigate increasing net power costs that adversely affect PacifiCorp’s near-term CETA targets. Compliance with CETA continues to be supported by the IRP with the addition of non-emitting system resources. Ongoing negotiations in MSP, updated REC assumptions, and a realignment of assumptions about uncertain future Washington resource allocations have all led to a lower percentage of system renewable energy for Washington customers in the near-term as compared to the Company’s current CEIP. Given these updates, the Company estimates by 2025 that 33 percent of Washington retail sales will be served by renewable and non-emitting energy, and as discussed above, the Company will substantially decarbonize its system and achieve CETA’s 2045 requirements almost a decade early. Target Development Updated interim target development is consistent with PacifiCorp’s Refiled 2021 CEIP, Chapter 1, where the Company’s Washington allocation of the updated CEIP-compliant portfolio of resources was analyzed based on an updated forecast of retail electric sales to Washington.13 This section discusses the assumptions that informed these updated interim targets. To estimate the amount and mix of energy forecasted to serve Washington customers for the 2023-2045 period, PacifiCorp summed annual generation from its qualifying resources allocated to 13 PacifiCorp’s Revised 2021 CEIP can be found at: https://apiproxy.utc.wa.gov/cases/GetDocument?docID=277&year=2021&docketNumber=210829. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 409 Washington customers under the Washington Inter-Jurisdictional Allocation Methodology (WIJAM) for existing resources and generally assumed that these assumptions hold into the future, in the absence of an agreed upon future allocation methodology.14 The allocations assumed for Washington in this update are the Company’s best estimate of future allocations at this time, and are best aligned with other ongoing filings in Washington. To calculate the energy and the total amount of renewable and carbon non-emitting energy allocated to Washington customers, the company made the assumptions set forth below. Generally, where a resource is assumed to generate RECs, where one REC is generated for one megawatt-hour of renewable energy, the resource was assumed to generate CETA-compliant energy. In addition to REC-generating resources, it was assumed that all Washington-allocated energy from non-emitting resources was also CETA compliant, namely hydroelectric, nuclear and hydrogen non-emitting peaking plants.15 In summary, the resource allocation assumptions are: 1. Allocation of energy for all system renewable resources, existing and proxy, are allocated according to system-generation (SG) factors, consistent with the WIJAM. 2. Allocation of energy for new non-emitting proxy resources are allocated on SG factors, consistent with the WIJAM. 3. Allocation of energy for all Washington qualifying-facilities (QFs) are assumed to be situs to Washington. No energy is allocated from QFs not originating in Washington, consistent with Washington Utilities and Transportation Commission policy. 4. Washington customers are assumed to participate in a limited set of emitting resources as defined under the West Control Area Inter-Jurisdictional Allocation Methodology (WCA): a. Washington customers receive costs and benefits from PacifiCorp’s interest in the Colstrip Unit 4 and Jim Bridger Unites 1-4 thermal resources, subject to elimination of all costs and benefits from coal-fueled Colstrip 4 and Jim Bridger Units 3 and 4 until by the end of 2025. It is assumed that in the event a coal-fueled resource converts to gas before 2026, that Washington customers can participate until the end 2029. b. Washington customers participate in two gas-fired units, Chehalis and Hermiston, through the end-of-life. Given the assumed allocations of resource energy and costs to Washington, CETA-compliant energy is determined given the following: 1. For REC-generating resources, generation of CETA-compliant energy is consistent with the company’s REC entitlement start and end date. 14 The WIJAM and the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol (2020 Protocol) define how resources and costs are allocated to Washington customers through December 21, 2023. The Washington Utilities and Transportation Commission approved the WIJAM and 2020 Protocol in its Final Order 09/07/12 in docket UE-191024 et. al., effective January 1, 2021. The company is in the process of negotiating its Multi-State Process (MSP) cost allocation methodology with the commissions and stakeholders in the six states it serves. More information can be found in Volume I, Chapter 3. 15 WAC 480-100-610(3) states that by January 1, 2045, each utility must ensure that “non-emitting electric generation and electricity from renewable resources supply one hundred percent of all retail sales of electricity to Washington electric customers”. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 410 2. Customer preference and voluntary renewable resources were not assumed to generate RECs for the system or the state of Washington and thus are not included in the allocation of renewable energy. 3. All renewable and non-emitting resources were assumed to be CETA compliant, including wind, solar, geothermal, hydro, nuclear and hydrogen non-emitting peaking plants. For renewable resources co-located with battery storage, RECs were assumed to be generated pre-storage; no RECs are generated at battery discharge. 4. Emitting generation (coal or gas-fueled resources) are not CETA compliant. Washington retail electric sales were defined as total energy served to customers annually, net of distributed generation, existing and optimized energy efficiency and demand-side management (DSM) resources. Retail electric load does not include MWh delivered from Washington qualifying facilities under the federal Public Utilities Regulatory Policies Act of 1978 (PURPA).16 CETA compliance targets were calculated annually as a percentage of Washington retail electric sales. Annual targets for CETA’s 2030 and 2045 requirements were calculated as a percentage of Washington retail electric sales to be the total renewable and carbon non-emitting energy the Company estimates will be provided to Washington customers. For purposes of this CEIP, PacifiCorp relies on the use of unbundled RECs to satisfy the alternative compliance component of the 2030 and 2031 greenhouse gas neutral standard. PacifiCorp may meet up to 20 percent of its aggregate retail electric sales over the four-year compliance period with alternative compliance from January 1, 2030, through December 31, 2044. For further discussion specific to development of the CETA-compliant portfolio and interim targets, please see subsection Interim Target Shortfall Resolution. Specific Targets Renewable energy targets, energy efficiency and demand response targets will evolve from the ongoing CEIP, based on updated outputs and analysis from this IRP Progress Report. The Company’s November 1, 2023 Biennial CEIP Update will provide updates to all general CEIP requirements, including specific targets. Customer Benefit Indicators As part of its CEIP compliance report to be filed July 1, 2023, PacifiCorp will report and track customer benefit indicators (CBIs) that are identified in Chapter 2 of the Company’s CEIP. These metrics will report on the progress made in each CBI as PacifiCorp moves through the four-year CEIP cycle. Furthermore, PacifiCorp is considering additional input on the Company’s CBIs in response to public comment and stakeholder feedback received in Docket UE-210829. Of note, the Washington Department of Health (DOH) recently updated the agency’s highly-impacted communities (HIC) analysis in January 2022.17 Based on this DOH update, the Company concluded there is one additional HIC located within PacifiCorp’s Washington service territory compared to what was considered in the Company’s 2021 CEIP. The Company is in the process 16 RCW 19.405.020(36)(a) 17 See generally, Washington Department of Health, Information by Location (IBL) (available here: https://doh.wa.gov/data-and-statistical-reports/washington-tracking-network-wtn/information-location). PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 411 of including this additional HIC within the baseline and will account for it when developing metrics for the July 1, 2023, compliance report. The process of updating the metrics for the July 1, 2023, filing will be based largely on survey results. As was the case with the Company’s December 30, 2021, filing, the CBI metrics will require PacifiCorp to use survey responses to identify energy burden for vulnerable populations in the Washington service area. This survey is expected to launch in April 2023 and will include both an email and telephone effort to accumulate necessary data. Specific Actions This section provides updates on the Company’s supply- and demand-side resource actions taken over the past two-year period. As discussed below, the Company has procured substantial non-emitting and renewable resources and taken significant steps to improve or expand its demand-side resource programs and opportunities. Supply-Side Resource Actions The 2020AS RFP has concluded with the procurement of 1,792 MW of wind resources, 495 MW of solar additions, and 200 MW of battery storage capacity paired with solar. All of these resources have 2024 or 2025 CODs and will contribute to PacifiCorp’s renewable energy and carbon reduction goals. PacifiCorp procures for its system needs across its six-state territory. Prior to the passage of CETA and with the 2020 procurement effort, there were no cost-competitive Washington bids and therefore limited alignment with the CBIs that resulted from a 2021 stakeholder engagement process. Following the 2021 IRP filing, PacifiCorp issued its first request for proposal to take into consideration the requirements of CETA. The ongoing 2022 all source request for proposals (2022AS RFP) was filed in Washington and received approval in three states after a lengthy stakeholder process. It was subsequently issued to the market on April 29, 2022. PacifiCorp hired an independent evaluator (IE) to oversee the process, with the oversight of the Washington Commission. In December 2022, PacifiCorp bid twelve eligible self-build (benchmark) resources into the 2022AS RFP, and on March 14, 2023, PacifiCorp received 302 bids from 74 developers and 93 different projects sites across six states. A final shortlist is expected to be released by late Q2 2023 or early Q3 2023, with resources contracted by the end of Q4 2023. PacifiCorp will consider its Washington CBIs before making a final shortlist decision. Demand-Side Resource Actions Since the original CEIP filing, PacifiCorp has made the following changes and updates to demand-side resource programs to help increase benefits to named communities and achieve goals informed by our Equity Advisory Group (EAG):18 18 These changes and updates were identified as CEIP Utility Actions in the 2022-2023 DSM Business Plan filed with the 2022-2023 Biennial Conservation Plan on November 1, 2021 (Docket UE-210830). The same actions were PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 412 Residential Energy Efficiency • Enhanced incentives for windows in multi-family units on residential rate schedules. Initial focus on buildings in highly impacted communities. • Continued direct install residential lighting in multi-family units with focus in highly impacted communities. • Maintained and expanded general purpose lamp buy down in “dollar stores” in highly impacted communities. • Continued manufactured home direct install duct sealing and lighting. Continue focus in highly impacted communities. • Continued promoting new construction offerings for multifamily, and single family units. Continue focus in highly impacted communities. • Develop pathways for non-electric, non-natural gas upgrades in named communities. o Serve named community residential customers who use non-electric and non-natural gas fuel sources in their primary heating systems by offering incentives for decommissioning these systems and installing ductless heat pumps. Low Income Weatherization • Increased funds available for repairs from 15 percent to 30 percent. • Permitted installation of electric heat to replace permanently installed electric heat, space heaters or any fuel source except natural gas with adequate combustion air as determined by the Agency. The changes are designed to promote the installation of electric heat and minimize use of wood heat, solid fuels or natural draft equipment in specific applications where combustion safety (and indoor air quality) cannot be maintained. Non-residential energy efficiency • Increased outreach and participation for small businesses and named community small businesses identified by census tract and rate schedule. o Created a new offer within the current small business enhanced incentive offer targeting the smallest businesses using less than 30,000 kilowatt-hours per year and Named Community small businesses on Schedule 24. o Targeted a portion of company initiated proactive outreach to small businesses located in highly impacted communities. Continued to tie proactive outreach to approved small business vendor capacity to respond to customer inquiries. • Offered approved small business lighting vendors a higher vendor incentive for completed lighting retrofit projects with small businesses located in highly impacted communities. • For 2023, the program seeks to create a new offer within the current small business offer to include enhanced incentives for select non-lighting measures. • Continue development of program materials in Spanish and increase outreach to Latinx and Tribal community groups. Specific to energy efficiency actions, the company will document its progress regarding the CBIs and energy savings targets in its annual clean energy progress report filed on July 1st each year included in the CEIP, and the 2023 Annual Conservation Plan filed November 15, 2022 (Docket UE-210830), included an update on the Utility Actions. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 413 Specific to energy efficiency targets, PacifiCorp filed its 2023 Annual Conservation Plan on November 15, 2022 (Docket UE-210830). This plan includes an updated forecast for 2022-2023 which indicates a shortfall relative to the two-year target established via the process for target setting established by the Energy Independence Act (WAC 480-109-100). The final results for 2022-2023 will be in PacifiCorp’s Biennial Conservation Report due June 1, 2024. On November 1, 2023, PacifiCorp will file its Biennial Conservation Plan with the targets for 2024-2025. Those targets will be based on updated information relative to the CEIP and will align with those accepted from this ongoing two-year Energy Independence Act target setting process. PacifiCorp also has also taken actions to develop demand response resources to work towards stated interim targets. Since the original CEIP, PacifiCorp received approval for Schedule 106, which is an enabling demand response tariff that supports multiple market driven programs. Schedule 106 provides a regulatory framework that includes a fast and flexible change process while at the same time enabling transparent customer information for the benefit of all stakeholders. Each new demand response program will use Schedule 106 for enablement, communication, and tracking. The Company has taken the following program-specific demand response actions in Washington: Commercial and Industrial Curtailment A commercial and industrial program was approved and effective in December 2022. The program focuses on enrolling connected end use loads available during various dispatch periods. Event communication and control occurs through a Program Administrator-provided, two-way communications device (communicating via cellular signals) installed at the customer site. Irrigation Load Control This program was approved and became effective in August 2022. It focuses on enrolling agricultural irrigation pumps with the highest connected loads during the available dispatch hours in the summer during the irrigation season with incentives differentiated based on dispatch notification option. The program relies on field-installed direct load control (DLC) devices to send signals to pumping equipment for reduction of irrigation loads for participating customers. Bring your own Thermostat and Water Heater Direct Load Control The company is preparing to file, for approval, a program to deliver curtailable end-use loads from residential HVAC equipment communicating through customers’ web-enabled thermostats and electric water heaters via Wi-Fi enabled communication devices. The Company is currently estimating an effective date in 2023 for this program. Batteries This program is under consideration and is currently in the preliminary stages of planning. The program would potentially target residential – and possibly commercial – customers who have Wi- Fi connection to incentivize the use of individual batteries for system wide-integration in support of overall grid management. While the Company has made progress on these demand response actions since filing the CEIP, as described above, program implementation is just beginning to ramp up. As noted in the CEIP, “Total demand response volume is subject to change based on timing of programs and contract negotiations.”19 As implementation and development of these new programs continues, progress 19 See CEIP page 22. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 414 toward and change to the interim targets will likely occur as expectations regarding demand response volumes are informed by actual effective program dates, leading to improved planning estimates. Volumes attained by the end of the CEIP period, 2025, will likely be different from the initial CEIP forecast of 37.4 MW. Specific to demand response actions, the company will document its progress regarding the CBIs and capacity savings targets in its annual clean energy progress report filed on July 1st each year. Time-of-Use Pilots Beginning in May 2021, PacifiCorp launched residential and non-residential service time of use pilots. The residential pilot (Schedule 19) targets single family residential customers and is available for up to 500 customers on a first-come, first-served basis. The non-residential time of use pilot (Schedule 29) targets non-residential customers with loads under 1,000 kW and is available for up to 100 customers on a first-come, first-served basis. Incremental Cost An update to the incremental cost calculation is provided for the remaining years in the CEIP period, 2023 – 2025. The CEIP portfolio, W-10 CETA, was specifically optimized and designed to meet CETA standards. This portfolio is contrasted to the alternative lowest reasonable cost portfolio as defined in rule and is denoted P-SC or referred to as the Alternative Portfolio.20 Any differences in cost between the CEIP portfolio and the Alternative Portfolio are considered incremental costs, costs directly resulting from actions taken to comply with requirements under RCW 19.405.040 or 19.405.050. These incremental costs include items like CETA-driven impacts to electricity generation, energy efficiency, new programs to support customers, and program management, that can be measured for the current CEIP period. The methodology to calculate the updated incremental cost is consistent with the methods described in the refiled 2021 CEIP. Only the modeled IRP-based costs were updated at this time. Given the updated portfolio outcomes, the incremental costs to comply with CETA is $2.13 million on average per year. Interim Target Shortfall Resolution To develop the CEIP portfolio, the base portfolio, P-SC, was evaluated against CETA requirements that Washington-supplied energy would be 100% greenhouse gas neutral with up to 20 percent of this amount supplied by unbundled RECs beginning in 2030, and 100 percent clean and non-emitting by 2045. Given the system optimized portfolio under the SCGHG price policy assumption and assumed resource allocations to Washington customers, the Company identified a small compliance shortfall in 2030 and 2031. In years 2032 and beyond, the portfolio resources generated enough renewable and non-emitting energy to Washington to meet 100 percent of need. These compliance shortfalls were identified by calculating the amount of additional renewable or non-emitting energy that would be needed to meet at least 80 percent of Washington retail sales. 20 Several portfolios were developed specific to Washington CETA legislation and are defined in Volume I, Chapter 8. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 415 A compliance shortfall of 67 MW of average annual capacity was identified in 2030, and a slightly larger shortfall of 72 MW average annual capacity resulted for 2031. To reach the target of at least 80 percent non-emitting energy in 2030-2031 at least-cost, and without the need for additional transmission lines, small-scale renewable capacity was added in Yakima, Washington. Specifically, 120 MW of installed capacity of small-scale solar and 120 MW of installed capacity of small-scale wind was added in Washington in 2030. The incremental small-scale resources were added only for CETA-compliance, on top of an optimized system portfolio developed under the SCGHG price policy assumption, as shown in Figure O.2. Thus, the incremental small-scale solar and wind was allocated situs to Washington and would represent an incremental cost in 2030 and 2031. Figure O.2 - Incremental Portfolio Change: W-10 CETA Delta P-SC These incremental actions resulted in the CEIP-compliant portfolio, W-10 CETA, and the associated interim targets and incremental costs. Revenue Requirement Methodology Incremental costs included for consideration in this CEIP can be broadly considered in two categories – IRP modeled incremental costs, and non-IRP modeled incremental costs. IRP modelled incremental costs were identified through the comparison of changes in investment costs between the CEIP portfolio and the Alternative Portfolio, described above, for the years 2023 - 2025. Per rule WAC 480-100-660(1), the only differences in investment decisions between the two portfolios described are a direct result of CETA requirements, determined to be met in a least-cost least-risk manner. Incremental investments and expenses were identified from the comparison of the two portfolios and summarized on an annual, nominal and levelized basis for the remaining compliance years in the CEIP. Table O.2 summarizes the resource-driven incremental expenses identified. However, note that the column for 2022 was not updated and is equivalent to the modeled incremental cost shown in the Company’s current CEIP. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 416 Table O.2 - Annual Modeled Impacts of CETA There are no incremental resource additions in the CETA-compliant portfolio during the CEIP compliance window. Any differences in the annual modeled costs over the period are due to negligible movements in dispatch. It is assumed that other non-modeled costs, as presented previously in the revised 2021 CEIP, have not changed and are shown in Table O.3. Table O.3 - Non-modeled Impacts of CETA ($million) Taking the estimated incremental costs identified based on methodologies described in this report, the company calculated an annual revenue requirement using the standard revenue requirement formula: Revenue Requirement = Rate of Return x (Net Rate Base) + Operating Costs Using the above formula, the estimated annual revenue requirement for the remaining years in the compliance period is as follow, presented in ($million)2022 2023 2024 2025 Fuel Costs - (0) 0 (1) Other Variable - 0 0 0 Energy Efficiency - - 0 - Net Market Purchases - (0) (0) (3) Emissions - 1 0 2 Deficiency - - (0) (0) Fixed Costs - - (0) 0 Total - 0 (0) (2) Compliance Year PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 417 Table O.4 - Revenue Requirement of Cost Estimates Compliance Year $-Millions 2022 2023 2024 2025 Revenue Requirement Fixed Costs1 - - (0.00) 0.00 Variable Costs Fuel Costs - (0.03) 0.03 (0.68) Variable O&M - 0.00 0.01 0.04 Energy Efficiency - - 0.00 - Net Market Purchase - (0.04) (0.12) (3.11) Emissions - 0.54 0.10 2.16 Deficiency - - (0.07) (0.06) Total Variable Costs - 0.47 (0.04) (1.64) Administrative & General DSM Program Costs 1.24 1.26 1.29 1.32 Outreach Costs 0.40 0.37 0.38 0.39 Materials 0.01 0.01 0.01 0.01 Staffing 0.56 0.57 0.59 0.60 Data Support 0.17 0.17 0.18 0.18 Total Revenue Requirement 2 2.38 2.86 2.40 0.86 Average Revenue Requirement 2.13 Notes: 1. Incremental fixed cost are identical between the CEIP portfolio (W-10 CETA) and Alternative Portfolio (P-SC) during the CEIP compliance window. Fixed costs are reported in the respective portfolios at a nominal and levelized basis, which reflects both a return on and return of component. 2. Estimated revenue requirement is calculated based on incremental costs derived by comparing IRP portfolios. Actual cost recovery will ultimately be determined by the prevailing cost allocation methodology approved in Washington at the time recovery is sought. The annual threshold for Alternative Means of Compliance as stated and calculated in the Revised CEIP filed March 13, 2023, has not changed and is equal to $16,667 million. Thus, based on current forecasts, the estimated incremental costs identified for implementation of CETA from 2022 to 2025 are within the annual threshold amount. As such, the Company will not rely on RCW 19.405.060(3) as a means of alternate compliance to achieve CETA’s requirements. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 418 Public Participation The Company has engaged in various activities to increase public participation in the Company’s IRP and CEIP processes. These specific actions, outreach methods and timing, and addressing barriers to participation and internal stakeholder development are discussed below. Specific Actions The Company has taken the following actions to promote equity and engagement within its Washington service area. These include: Formed Equity Advisory Group (EAG): The EAG was assembled in 2021 to help inform and advise the Company on the issues most important to the communities that PacifiCorp serves in Washington. The EAG comprises nine representatives from highly impacted communities and vulnerable populations within the Company’s Washington service area, including Yakima, Yakama Nation, and Walla Walla. These members have expertise on equity-related topics, such as the health of vulnerable populations and programs for low-income customers. The EAG meets regularly and provides significant input on the Company’s CBIs, metrics included in the CEIP, and how the Company plans and operates within its Washington service area. Development of CBIs: Consistent with CETA, the Company is committed to ensuring that the benefits from the transition to clean energy are broadly shared and equitably distributed among all customers, with a specific focus on named communities. PacifiCorp has partnered with stakeholders and advisory groups, including the EAG, to identify the highest priority benefits to customers and identify potential barriers and burdens that may prevent some customers from receiving those benefits. These efforts have resulted in nine CBIs and associated weighting factors to evaluate the equitable distribution of benefits. This allows the Company to assess and monitor the impacts of each proposed program, action, and investment. In addition, the CBIs were included in the Company’s most recent CEIP to inform utility action, focusing on the named communities that were identified within the Company’s Washington service area. Established Utility Actions within the CEIP: PacifiCorp committed to and made several changes to residential and non-residential customer energy efficiency programs to increase the focus on delivery of benefits to named communities. These utility actions were informed on input received from the EAG and CBIs. The same utility actions will be included in the 2022-2023 Biennial Conservation Plan, and updates for 2023 will be included in the 2023 Annual Conservation Plan. These utility actions include modifications to the low-income weatherization program that the Company filed on December 21, 2021. These changes included, but were not limited to, expanding tariff applicability for the installation of energy efficiency improvements. Funds available for repairs were also increased from 15 percent to 30 percent of the annual reimbursement on energy efficient measures and income guidelines were updated to be consistent with RCW 19.405.020(25). Before these changes, some income-qualified homes could not receive energy efficiency improvements due to the extent of critical maintenance needed before the energy efficiency improvements could be made. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 419 Establish an Electric Vehicle (EV) grant program: PacifiCorp established EV programs detailed in PacifiCorp’s Washington Transportation Electrification Plan. On May 20, 2022, PacifiCorp filed its 2022 “Washington State Transportation Electrification Plan” with the Washington Utilities and Transportation Commission under Docket UE-22035921. PacifiCorp supplemented its original filing with an addendum filed on September 28, 2022. This is PacifiCorp’s first filed TEP since enabling legislation was enacted in 2019. The Commission acknowledged the plan on October 27, 2022, enabling PacifiCorp to begin development of the proposed programs in the TEP inclusive of a communities grant program, outreach and education program, and managed charging pilot program. These programs would broaden the previous EV programs by allowing for multiple project types to participate with benefits and preference targeted towards named communities. The overall goal is to provide exploratory programs that will help to plan, promote, or deploy electric transportation technology and projects within Named Communities. Looking ahead, PacifiCorp is working with its Equity Advisory Group and the Washington Utility and Transportation Commission and other stakeholders to review draft program and pilot application prior to filing in Q2 of 2023. PacifiCorp anticipates launch of program and pilots in Q3 of 2023. Modified the Low-Income Bill Assistance Program: PacifiCorp’s low-income bill assistance (LIBA) program was established in 2003. LIBA provides a tiered discount based on income levels. Previously, LIBA was designed to provide credits to income- eligible households on monthly usage over 600 kWh and included an annual enrollment cap. Consistent with the requirements in RCW 19.505.120 and consultation with the Low-Income Advisory Group, the Company proposed modifications to its program. In particular, the Company proposed to (1) increase the maximum income threshold for the program consistent with RCW 19.405.020(25), (2) modify the discount from a per kWh above 600 kWh, to a percentage discount of the net bill, with the discount level based on household size and income; and (3) eliminate the annual enrollment cap. These changes were allowed to go into effect on August 1, 2021. PacifiCorp also hired Empower Dataworks to prepare a 2022 Energy Burden Assessment (EBA) for the Company’s residential customers in Washington. In the EBA, Empower Dataworks highlighted that the LIBA program design is very good at targeting benefits to higher burden customers and program administration. It also noted that the overhead costs are very efficient relative to other programs in the state, and praised the great coordination between PacifiCorp and the local community action agencies on providing culturally appropriate marketing and program designs. PacifiCorp partners with three agencies to administer and deliver the program: Blue Mountain Action Council (BMAC) serves Columbia, Garfield, and Walla Walla counties, Opportunities Industrialization Center of Washington (OIC) serves Upper Yakima County, and Yakima Valley Farm Workers Clinic dba Northwest Community Action Center (NCAC) serves Lower Yakima County. Continued and Expanded Outreach To ensure consistent outreach, PacifiCorp continues to use all of the engagement methods included in its CEIP, including PacifiCorp’s CEIP and IRP dedicated website; email updates; fact sheet and 21 Materials available online at UTC Case Docket Document Sets | UTC (wa.gov) PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 420 flyers; bill inserts and bill messages; interactive voice response; social media, paid and press media; text message notices; partner channels; community surveys; CEIP Public Meetings and Technical Conferences; EAG Meetings; existing advisory groups and EAG pre-meeting materials; and meeting summaries. These engagement methods attempt to further facilitate durable community relationships. Examples of specific continued outreach include: - PacifiCorp’s Washington EAG began meeting in 2021 and has continued to hold meetings to, in part, support CEIP development and implementation. These meetings have continued into 2023, and have offer in-person and virtual meeting opportunities throughout the year; - PacifiCorp’s initial public participation outreach included both telephone and email and was designed to inform existing advisory groups (including the IRP Public Input Process) of the opportunity to provide feedback, as well as to form the Washington EAG; - PacifiCorp continues to utilize its Washington Clean Energy Transformation Act & Equitable Distribution of Benefits webpage and the Integrated Resource Plan webpage to provide information to the public regarding how to participate in meetings, the development of the CEIP and the development of the IRP; - PacifiCorp’s outreach for both the DSM Advisory Group and the Low-Income Advisory Group continues to occur by email to participants on the distribution list; and - The company has set up a dedicated email address, CEIP@pacificorp.com, that is posted on the webpage to facilitate timely responses to any stakeholder questions. Additionally, PacifiCorp encouraged members of the public who wanted to participate in the development of the CEIP to join the company’s email list, which was used to communicate upcoming meetings, meeting materials, and other opportunities for education and feedback. In addition to continued outreach, the Company has expanded its Public Participation outreach methods to draw in more diverse customer interests. For example: - PacifiCorp developed a survey that targets our broader Washington customer base to gather input on the development of the CEIP. The survey was made available in English and Spanish between July 2, 2021, and August 10, 2021. There were separate versions for residential and non-residential customers. Survey results were prepared, summarized, and posted on the Washington Clean Energy Transformation Act & Equitable Distribution of Benefits webpage. Customer feedback was incorporated into the Customer Benefit Indicator (CBI) weighting process. PacifiCorp continues to explore methods to improve these surveys, and plans to use similar outreach methods in 2023. - PacifiCorp held 3 technical conferences on the CEIP development process that were targeted for parties interested in a deeper examination of the CEIP. PacifiCorp is open to additional CEIP technical conferences. The Company welcomes continues to explore—and welcomes helpful suggestions—for expanded public participation methods for future CEIP planning cycles. Addressing Barriers to Participation The Company continues to address barriers to participation, and support inclusion and accessibility in the Company’s CEIP and IRP planning processes. For example PacifiCorp: PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 421 - Now offers hybrid meeting formats for its EAG meetings, where members can attend meetings online or in-person. Initially, the COVID-19 pandemic prevented in-person gatherings from taking place, making virtual meetings necessary. Over time, the need for virtual meeting formats lessened, giving the group space to explore other ways to connect, and various stakeholders expressed an interest for in-person meeting options as well. PacifiCorp held its first hybrid meeting for the Washington EAG in March 2023. The majority of the participants attended in person. The company intends to continue to offer a mix of online and in-person meeting options in the future. - Continues to offer Spanish translation of meeting materials, and have interpreters present at public participation meetings. - Continues to seek input from the EAG and public to foster inclusion, equity, and continuing to learn about the ways that the company can better communicate to meet the cultural needs of its communities. - Continuing to ensure that information is available in broadly understood terms for all in the community, and ensuring that customers have access to information through various accessible formats. - Has continued engagement with its on-going EAG, and stakeholders interested in the CEIP development process. These actions to address barriers to participation help PacifiCorp identify specific actions that support initiatives to improve health, safety, and well-being of its communities, and PacifiCorp continues its CEIP public participation process to ensure open, transparent, and accessible processes. Internal Stakeholder Development PacifiCorp is also making efforts to promote equity through internal stakeholder development. To achieve results in this arena, PacifiCorp is developing and equipping internal stakeholders with adaptive leadership skills, education to build intercultural competency, and access to a devoted core team supporting an equity lens on stakeholder engagement. This has included: • Outside subject matter expertise and facilitation. The Company has engaged E Source as its stakeholder facilitator and content support developer, who acts as an accountability partner for internal stakeholder development. This accountability allows a value chain that creates and strengthens our internal equity decision-making lens and ensures that it bears fruit in our deliverables and stakeholder engagement, and this consequently will help achieve equitable results in the communities the Company serves. • Building adaptive leadership skills. The Company held an adaptive leadership in equity workshop for key PacifiCorp employees who work on external engagement and customer and community solutions. This workshop was held in December 2022 and focused on acknowledging and finding agreement on the value of building a safe and supportive space to grow individual’s adaptive leadership skills and provide tools, resources, and guidance in our shared journey. This workshop is important because developing an equity decision-making lens requires understanding and acceptance on the individual and corporate level of intercultural competency. Further, it requires a commitment to self- awareness, learning, application (success and lessons learned), and growth. PACIFICORP – 2023 IRP APPENDIX O – WASHINGTON TWO-YEAR PROGRESS REPORT ADDITIONAL ELEMENTS 422 • Building intercultural communication skills. The Company plans to host an internal workshop in the spring of 2023, that will equip its employees with the tools necessary for effective intercultural communication. While it is expected that most subscribe to the Golden Rule – do unto others as you would like done unto you – in communications, this stops short of intercultural competency. The golden rule is based on a monocultural worldview and assumes all groups value the same thing. This workshop aims to support trust building and the adaption of individual perspective and behaviors to connect better, communicate and engage others. • Benchmarking and building intercultural competency. The Company will administer the Intercultural Development Inventory (IDI) Survey, considered an international benchmark, in the fall of 2023. Core team members will be debriefed privately on their scores and given individual development and coaching plans PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 423 APPENDIX P – ACRONYMS AB = Assembly Bill AC = alternating current ACE = Affordable Clean Energy Rule ACE = Area Control Error AEG = applied energy group AFSL = average feet (above) sea level AFUDC = allowance for funds used during construction AGC = Automatic Generation Control AH = Ampere hour A/m = Amperes per Meter AMI = Advance Metering Infrastructure AMR = Automated Meter Reading ARO = asset retirement obligation ATC = Available Transmission Capacity (Available Transfer Capacity?) AVR = Automatic Voltage Regulator AWEA = American Wind Energy Association BA – Balancing Authority BAA = Balancing Authority Area BART = Best Available Retrofit Technology BCF/D = billion cubic feet per day BES = Bulk Electric System BLM = Bureau of Land Management BMcD = Burns and McDonnell BPA = Bonneville Power Administration BSER = best system of emission reduction Btu = British thermal unit CAES = compressed air energy storage CAGR = compounded annual average growth rate CAIDI = Customer Average Interruption Duration Index PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 424 CAISO = California Independent System Operator CAP = Community Action Program CARB = California Air Resources Board CARI = Control Area Reliability Issues CCCT = Combined Cycle Combustion Turbine CCGT = Combined Cycle Gas Turbine CCR = coal combustion residual CCS = carbon capture and sequestration / Utah Committee of Consumer Services CEC = California Energy Commission CETA = Clean Energy Transformation Act CF = capacity factor CFL = Compact Fluorescent Light Bulb CIPS = Critical Infrastructure Protection Standards CIS = Corporate Information Security CO = carbon monoxide CO2 = carbon dioxide Cogen = Cogeneration COMPASS = Coordinated Outage Management Planning and Scheduling System? CPA = Conservation Potential Assessment CPU = Clark Public Utilities / cost per unit CPUC = California Public Utilities Commission CREA = Columbia Rural Electric Association CSP = concentrated solar power CTG = Combustion Turbine Generator CUB = (Oregon) Citizen’s Utility Board DC = direct current DF = duct firing DG = Distributed Generation DOE = Department of Energy DPU = Utah Division of Public Utilities / Distribution Protection Unit (relay) DR = Demand Response PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 425 DRA = Division of Ratepayer Advocates DSM = demand-side management EBIT = Earnings before Interest and Taxes EDAM = extended day-ahead market EE = Energy Efficiency EEI = Edison Electric Institute EIA = Energy Information Administration EIM = Energy Imbalance Market ELCC = Effective Load Carrying Capacity EPA = Environmental Protection Agency EPC = engineering, procurement, and construction EPM = Energy Portfolio Management System ERC = emission rate credit ETO = Energy Trust of Oregon EUBA = Electric Utility Benchmarking Association EUI = Energy Utilization Index EUL = effective useful life EV = Electric Vehicle FCC = Federal Communications Commission FCRPS = Federal Columbia River Power System FERC = Federal Energy Regulatory Commission FIP = federal implementation plan FIT = Feed-In Tariff FLPMA = Federal Land Policy Management Ace FOTs = Front Office Transactions FRAC = Flexible Resource Adequacy Capacity GAAP = Generally Accepted Accounting Principles GBP = Great Britain Pound GE = General Electric GFCI = Ground Fault Circuit Interrupter GHG = Greenhouse Gas PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 426 GIC = Generation Interconnection Contract GIS = Geographic Information System GPS = Global Positioning System GRC = General Rate Case GRID = Generation and Regulation Decision Model (used for net power cost pricing calc and QF avoided cost calc) GT = Gas Turbine GW = Gigawatt GWh = gigawatt-hours (gigawatt) H = Hour HB = House Bill HCC = Hydro Control Center HRSG = Heat Recovery Steam Generator HVAC = heating, ventilation, and air conditioning Hz = Hertz IBEW = International Brotherhood of Electrical Workers IC = internal combustion ICE = Intercontinental Exchange IECC = International Energy Conservation Code IEEE = Institute of Electrical and Electronic Engineers IGCC = integrated gasification combined cycle IHS = Information Handling Services ILR = Inverter Loading Ratio IOU = Investor Owned Utility IPC = Idaho Power Company IPP = Independent Power Producer IPOC = Idaho Power Company IPUC = Idaho Public Utility Commission IRA = Inflation Reduction Act IRP = Integrated Resource Plan IS = Information Systems PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 427 ISO = international organization for standardization / Independent System Operator IT = Information Technology ITC = Investment Tax Credit K = kilo (thousand) Kv = kiloVolt kW = kilowatt kWh = kilowatt-hour kW-yr = Kilowatt-Year kV = kilovolt kVa = kilovolt-ampere kVAr = kilovolt-ampere-reactive kVArh = kilovolt-ampere-reactive-hour Lb = Pound LCOE = Levelized Cost of Energy LED = light emitting diode Li-Ion = lithium-ion battery Lm = lumens LNG = Liquefied Natural Gas LOLH = loss of load hour LRA = Local Regulatory Authority LSE = load serving entities MATS = Mercury and Air Toxics Standards MEHC = MidAmerican Energy Holdings Company MMBpd = Million barrels of oil per day MMBtu = Million British thermal units MSP = Balancing Authority Area / Multi-State Process MVA = megavolt-ampere MVAr = megavolt-ampere-reactive MVA LTC = megavolt-ampere, load tap changing MW = Megawatt MWh = megawatt hour PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 428 $MWh = dollars per megawatt hour NAAQS = National Ambient Air Quality Standards NAPEE = National Action Plan for Energy-Efficiency NCM = nickel cobalt manganese (sub-chemistry of Li-Ion) NEEA = Northwest Energy Efficiency Alliance NEEP = Northeast Energy Efficiency Partnerships NEMA = National Electrical Manufacturer’s Association NEMS = National Energy Modeling System NERC = North American Electric Reliability Corporation NH3 = Ammonia NOAAF = National Oceanic and Atmospheric Administration Fisheries NRC = Nuclear Regulatory Commission NOx = Nitrogen Oxides NPV = net present value NQC = Net Qualifying Capacity NSPS = new source performance standards NTTG = Northern Tier Transmission Group NWEC = NW Energy Coalition NWPCC = Northwest Power and Conservation Council O&M = operations and maintenance OAR = Oregon Administrative Rules OASIS = Open Access Same Time Information System OATT = Open Access Transmission Tariff ODOE = Oregon Department of Energy ODOT = Oregon Department of Transportation OE = Owner’s Engineer OEM = Original Equipment Manufacturer OFPC = Official Forward Price OMS = Outage Management System / Operations Mapping System OPUC = Oregon Public Utility Commission ORS = Oregon Revised Statutes PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 429 OTR = Ozone Transport Rule PAC = PacifiCorp PACE = PacifiCorp East? PaR = Planning and Risk Model PC = pulverized coal PCB = Polychlorinated Biphenyls PC CCS = pulverized coal equipped with carbon capture and sequestration PDDRR = Partial displacement differential revenue requirement methodology (OR QF) PG&E = Pacific Gas & Electric PGE = Portland General Electric PHES = pumped hydro energy storage PJM = no definition PM = particulate matter PM2.5 = Particulate Matter 2.5 microns and larger PM10 = Particulate Matter 10 microns and larger PNUCC = Pacific Northwest Utility Coordinating Council POU = Publicly Owned Utility PP = Pacific Power PPA = Power Purchase Agreement Ppb = parts per billion PP&L = Pacific Power & Light Co. ppmvd@15%02 = parts per million, dry-volumetric basis, corrected to 15% Oxygen (O2) PRM = Planning Reserve Margin PSC = Public Service Commission PSE = Purchasing-Selling Entity Psia = Pounds per Square Inch-Absolute PTC = Production tax credit PTO = Participating Transmission Owner PTP = point to point PUC = Public Utility Commission PURPA = Public Utility Regulatory Policies Act PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 430 PV = photovoltaic PVRR(d) = present value revenue requirement (delta) PWC = PricewaterhouseCoopers QC = Qualifying Capacity RA = Resource Adequacy RCRA = Resource Conservation and Recovery Act RCW = Revised Code of Washington REA = Rural Electrical Administration / Rural Electrification Administration REC = renewable energy credit (certificate) / Rural Electric Cooperative RFI = request for information RFM = Rate Forecasting Model RFP = Request for Proposal RH = Relative humidity RICE = Reciprocating Internal Combustion Engine RMP = Rocky Mountain Power / Resource Management Plan RPS = Renewable Portfolio Standard RTO = Regional Transmission Organization RTF = Regional Technical Forum RTP = real-time pricing RVOS = Resource Value of Solar SAIDI = System Average Interruption Duration Index SAIFI = System Average Interruption Frequency Index SB = Senate Bill SCCT = Simple Combined Cycle Turbine SCPC = Super-critical pulverized coal SCPPA = Southern California Public Power Authority SCR = selective catalytic reduction system SEC = Securities and Exchange Commission SEEM = Simple Energy Enthalpy Model SEPA = Solar Electric Power Association SIP = state implementation plan PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 431 SF = Senate File SF6 = Sulfur Hexafluoride SNCR = selective non-catalytic reduction SO = System Optimizer SO2 = Sulfur Dioxide SOx = Sulfur Oxide / Sarbanes-Oxley Act SRSG = Southwest reserve sharing group SSR = supply side resource (table) STEP = Sustainable Transportation and Energy Plan STG = Steam turbine generator SWEEP = Southwest Energy Efficiency Project T&D = Transmission & Distribution th = Therm TPL = transmission planning assessment UAE = Utah Association of Energy Consumers UDOT = Utah Department of Transportation UMPA = Utah Municipal Power Agency UNIDO = United Nations Industrial Development Organization UP&L = Utah Power & Light Co. UPC = Use per Residential Customer UCE = Utah Clean Energy UCT = Utility Cost Test VERs = Variable Energy Resources V = volt VA = Volt-ampere VDC = Volts Direct Current VOC = volatile organic compounds W = Watts WAC = Washington Administrative Code WACC = weighted average cost of capital WAPA = Western Area Power Administration PACIFICORP – 2023 IRP APPENDIX P – ACRONYMS 432 WCA = West Control Area WECC = Western Electricity Coordinating Council Wh = Watt-hour WIEC = Wyoming Industrial Energy Council WPSC = Wyoming Public Service Commission WRA = Western Resource Advocates WREGIS = Western Renewable Generation Information System WSEC = Washington State Energy Code 2015 WSPP = Western Systems Power Pool WTG = wind turbine generator WUTC = Washington Utilities and Transmission Commission