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Home My WebLink About20240401IRP Update.pdf _ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330 POWER. Salt Lake City,UT 84116 A DIVISION OF PACIFICORP RECEIVED Monday,April 1,2024 4:14:08 PM April 1, 2024 IDAHO PUBLIC UTILITIES COMMISSION VIA ELECTRONIC DELIVERY Commission Secretary Idaho Public Utilities Commission 11331 W. Chinden Blvd Building 8 Suite 201A Boise, ID 83714 RE: CASE NO. PAC-E-23-10 - PACIFICORP'S APPLICATION FOR ACKNOWLEDGEMENT OF THE 2023 INTEGRATED RESOURCE PLAN Attention: Commission Secretary Please find enclosed PacifiCorp's 2023 Integrated Resource Plan Update ("2023 IRP Update"). Copies of the 2023 IRP Update are also available electronically on PacifiCorp's website, at www.pacificorp.com/iM. Confidential and non-confidential workpapers and supporting information for the 2023 IRP Update will be submitted by April 5, 2024. PacifiCorp's 2023 IRP Update provides a number of updates including a description of resource planning, procurement activities, an updated load and resource balance, an updated resource portfolio reflecting updates to load forecast and other model inputs, and a status update on action items from the 2023 IRP. All formal correspondence and data requests regarding this filing should be addressed as follows: By E-mail (preferred): datarequestgpacificorp.com irp(cr�,pacificorp.com mark.aldergpacific orp.com j oseph.dallasgpacificorp.com By regular mail: Data Request Response Center PacifiCorp 825 NE Multnomah, Suite 2000 Portland, OR 97232 Informal inquiries, including requests to receive a copy of the 2023 IRP Update filing or non- disclosure agreement, may be directed to Mark Alder, Idaho Regulatory Affairs Manager, at (801) 220-2313. Idaho Public Utilities Commission April 1, 2024 Page 2 Very truly yours, G-� Joe Steward 9L Senior Vice President, Regulation and Customer& Community Solutions cc: Ed Schriever, Idaho Governor's Office Brad Heusinkveld, Idaho Conservation League Ryan Adelman, Idaho Power Company Teri Carlock, Idaho Public Utilities Commission staff Thomas J. Budge, (Bayer) Nancy Kelly, Western Resource Advocates f r Ar 2023 Integrated Resource Plan Update April 1 , 2024 AW Aii _. PACIFICORP tt �f11 .� , This 2023 Integrated Resource Plan Update is based upon the best available information at the time of preparation. The IRP action plan status update described herein 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. For more information, contact: PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 irp@pacificorp.com http://www.pacificorp.com PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS TABLE OF CONTENTS TABLEOF CONTENTS.................................................................................i TABLE OF TABLES ....................................................................................v TABLEOF FIGURES .................................................................................vii CHAPTER 1 - EXECUTIVE SUMMARY CUSTOMERFOCUS ....................................................................................................................... 1 2023 IRP UPDATE ROADMAP ......................................................................................................2 PACIFICORP'S INTEGRATED RESOURCE PLAN APPROACH............................................ 3 2023 IRP UPDATE PREFERRED PORTFOLIO HIGHLIGHTS.................................................4 TRANSMISSIONUPGRADES .......................................................................................................... 5 NEWSOLAR RESOURCES ............................................................................................................. 6 NEWWIND RESOURCES............................................................................................................... 7 NEWSTORAGE RESOURCES......................................................................................................... 7 PEAKINGCAPACITY..................................................................................................................... 7 NUCLEARCAPACITY.................................................................................................................... 8 DEMAND-SIDE MANAGEMENT..................................................................................................... 8 WHOLESALE POWER MARKET PRICES AND MARKET ACTIVITY................................................ 10 COAL AND GAS RETIREMENTS/GAS CONVERSIONS................................................................... 12 RESOURCE PROCUREMENT AND REQUESTS FOR PROPOSALS ..................................................... 14 CARBON DIOXIDE EMISSIONS.................................................................................................... 14 RENEWABLE PORTFOLIO STANDARDS........................................................................................ 16 CHAPTER 2 - INTRODUCTION ......................................................... 19 CHAPTER 3 - THE PLANNING ENVIRONMENT MATERIAL CHANGES TO KEY PLANNING ASSUMPTIONS ............................................ 21 FEDERAL POLICY UPDATE.................................................................................................... 21 FEDERAL CLIMATE CHANGE LEGISLATION................................................................................21 NEW SOURCE PERFORMANCE STANDARDS FOR CARBON EMISSIONS FROM NEW AND EXISTING SOURCES—CLEAN AIR ACT § I I I(B)AND(D)...........................................................................21 CLEAN AIR ACT CRITERIA POLLUTANTS—NATIONAL AMBIENT AIR QUALITY STANDARDS ....22 OzoneNAAQS....................................................................................................................... 22 REGIONALHAZE........................................................................................................................24 UtahRegional Haze.............................................................................................................. 24 WyomingRegional Haze....................................................................................................... 24 Colorado Regional Haze....................................................................................................... 25 MERCURY AND HAZARDOUS AIR POLLUTANTS.........................................................................26 i PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS COAL COMBUSTION RESIDUALS ................................................................................................26 INFLATION REDUCTION ACT......................................................................................................27 Clean Energy Financing Program—Inflation Reduction Act.............................................. 28 New Credits and Considerations for Customer Resources................................................. 28 Inflation Reduction Act......................................................................................................... 28 STATE POLICY UPDATE..........................................................................................................29 CALIFORNIA...............................................................................................................................29 OREGON..................................................................................................................................... 30 WASHINGTON............................................................................................................................ 30 UTAH......................................................................................................................................... 31 WYOMING.................................................................................................................................. 31 GREENHOUSE GAS EMISSION PERFORMANCE STANDARDS........................................................ 33 ENERGY GATEWAY TRANSMISSION PROGRAM PLANNING........................................ 33 ENERGY GATEWAY TRANSMISSION PROJECT UPDATES............................................................. 35 Wallula to McNary (Segment A)........................................................................................... 35 Gateway West (Segments D and E) ...................................................................................... 35 GatewayWest (SegmentE)................................................................................................... 35 GatewaySouth (Segment F).................................................................................................. 35 Boardman to Hemingway (Segment H)................................................................................ 35 In-Service Dates.................................................................................................................... 36 REGIONALMARKETS.............................................................................................................. 36 CHAPTER 4 - LOAD-AND-RESOURCE BALANCE INTRODUCTION........................................................................................................................ 39 SYSTEM COINCIDENT PEAK LOAD FORECAST................................................................ 39 RESOURCE UPDATES............................................................................................................... 40 UPDATED CAPACITY LOAD-AND-RESOURCE BALANCE............................................... 41 LOAD-AND-RESOURCE BALANCE COMPONENTS .......................................................................41 ExistingResources................................................................................................................ 41 Obligation............................................................................................................................. 42 SystemPosition..................................................................................................................... 43 CAPACITY BALANCE DETERMINATION AND RESULTS................................................................ 43 Methodology......................................................................................................................... 43 Capacity Balance Results..................................................................................................... 44 CHAPTER 5 - MODELING AND ASSUMPTIONS GENERAL ASSUMPTIONS....................................................................................................... 51 INFLATIONRATES...................................................................................................................... 51 DISCOUNTFACTOR.................................................................................................................... 51 FRONT OFFICE TRANSACTIONS.................................................................................................. 51 11 PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS STOCHASTIC PARAMETERS ........................................................................................................ 52 FLEXIBLE RESERVE STUDY........................................................................................................ 52 NATURAL GAS AND POWER MARKET PRICE UPDATES................................................. 52 CARBON DIOXIDE EMISSION POLICY................................................................................. 53 SUPPLY-SIDE RESOURCES ..................................................................................................... 55 NATURALGAS........................................................................................................................... 56 PEAKING TYPE RESOURCES ....................................................................................................... 56 DEMAND SIDE MANAGEMENT ................................................................................................... 56 MODELING ENHANCEMENTS AND RESOURCE UPDATES............................................. 67 SUSPENSION OF THE 2022 ALL-SOURCE RFP............................................................................. 67 TRANSMISSION OPTION UPDATES.............................................................................................. 67 OTHERCONTRACTS ................................................................................................................... 68 CHAPTER 6 - MODELING AND ASSUMPTIONS INTRODUCTION ........................................................................................................................ 69 UPDATES..................................................................................................................................... 69 KEYUPDATES............................................................................................................................ 69 OTHERUPDATES........................................................................................................................ 70 PORTFOLIO DEVELOPMENT PROCESS OVERVIEW......................................................... 70 OVERVIEW OF STEPS.................................................................................................................. 71 Step1..................................................................................................................................... 71 Step2..................................................................................................................................... 71 Step3..................................................................................................................................... 72 Step4..................................................................................................................................... 72 Step5..................................................................................................................................... 72 Step6..................................................................................................................................... 72 GRANULARITY ADJUSTMENT DETAIL........................................................................................ 72 RELIABILITY ADJUSTMENT DETAIL........................................................................................... 73 PREFERRED PORTFOLIO DEVELOPMENT .......................................................................... 74 SYSTEMWIDE PORTFOLIO........................................................................................................... 75 OREGON AND WASHINGTON POLICY PORTFOLIOS..................................................................... 75 OregonIntegration............................................................................................................... 76 WashingtonIntegration ........................................................................................................ 76 PREFERRED PORTFOLIO INTEGRATION OUTCOMES.................................................................... 77 PREFERRED PORTFOLIO RESULTS....................................................................................... 79 PRESENT VALUE REVENUE REQUIREMENT................................................................................ 80 TRANSMISSIONUPGRADES ........................................................................................................ 81 NEWSOLAR RESOURCES ........................................................................................................... 82 NEWWIND RESOURCES............................................................................................................. 82 iii PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS NEWSTORAGE RESOURCES....................................................................................................... 83 PEAKINGCAPACITY................................................................................................................... 83 NUCLEARCAPACITY.................................................................................................................. 84 DEMAND-SIDE MANAGEMENT................................................................................................... 84 MARKETACTIVITY.................................................................................................................... 85 COAL AND GAS RETIREMENTS/GAS CONVERSIONS................................................................... 87 CARBON DIOXIDE EMISSIONS.............................................................................................. 97 OREGON AND WASHINGTON EMISSIONS COMPLIANCE.............................................................. 99 RENEWABLE PORTFOLIO STANDARDS............................................................................ 100 PROJECTED ENERGY MIX.................................................................................................... 102 ADDITIONALSTUDIES.......................................................................................................... 103 CCUS VARIANT(No CCUS)................................................................................................... 104 JIM BRIDGER 3 AND 4 GAS CONVERSION VARIANT ................................................................. 104 NUCLEAR VARIANT(NO NUCLEAR) ........................................................................................ 105 UTAH STAY OTR VARIANT..................................................................................................... 106 OREGON OFFSHORE WIND VARIANT....................................................................................... 107 OREGON HB 2021 VARIANT (OREGON POLICY STUDY) ......................................................... 108 WASHINGTON SC CETA VARIANT(WASHINGTON POLICY STUDY) ....................................... 109 PVRR TABLES BY PRICE-POLICY SCENARIO............................................................................................110 CHAPTER 7 -ACTION PLAN STATUS UPDATE EXISTING RESOURCE ACTIONS ................................................................................................ 115 NEWRESOURCE ACTIONS........................................................................................................ 118 TRANSMISSION ACTION ITEMS................................................................................................. 120 DEMAND-SIDE MANAGEMENT(DSM)ACTIONS...................................................................... 123 MARKET PURCHASES............................................................................................................... 124 RENEWABLE ENERGY CREDIT(REC)ACTIONS....................................................................... 125 APPENDIXA ........................................................................................ 127 iv PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS TABLE OF TABLES CHAPTER 1 - EXECUTIVE SUMMARY TABLE 1.1 -COAL UNIT RETIREMENTS IN THE 2023 IRP AND 2023 IRP UPDATE..................... 13 CHAPTER 2 - INTRODUCTION ......................................................... 19 CHAPTER 3 - THE PLANNING ENVIRONMENT TABLE 3.1 -ENERGY GATEWAY SEGMENT IN-SERVICE DATES................................................. 36 CHAPTER 4 - LOAD-AND-RESOURCE BALANCE TABLE 4.1 -NEW POWER PURCHASE AGREEMENTS.................................................................. 40 TABLE 4.2-SUMMER PEAK-SYSTEM CAPACITY LOAD AND RESOURCE BALANCE WITHOUT RESOURCE ADDITIONS,2023 IRP UPDATE(2024-2033)(MEGAWATTS)................................... 45 TABLE 4.3-WINTER PEAK-SYSTEM CAPACITY LOAD AND RESOURCE BALANCE WITHOUT RESOURCE ADDITIONS,2023 IRP UPDATE(2024-2033)(MEGAWATTS) .................................47 CHAPTER 5 - MODELING AND ASSUMPTIONS TABLE 5.1 -MAXIMUM AVAILABLE FRONT OFFICE TRANSACTION QUANTITY BY MARKET HUB ................................................................................................................................................... 52 TABLE 5.2-2023 IRP UPDATE SUPPLY SIDE RESOURCES (2022$)........................................... 59 TABLE 5.3-2023 IRP UPDATE SUPPLY SIDE RESOURCES(2022$) .......................................... 61 TABLE 5.4-2023 IRP UPDATE SUPPLY SIDE RESOURCES(2022$) .......................................... 64 CHAPTER 6 - MODELING AND ASSUMPTIONS TABLE 6.1 -PREFERRED PORTFOLIO RESOURCE INTEGRATIONS(INSTALLED CAPACITY,MW) 78 TABLE 6.2-COAL UNIT RETIREMENTS IN THE 2023 IRP AND 2023 IRP UPDATE..................... 88 TABLE 6.3-COMPARISON OF 2023 IRP UPDATE WITH 2O23 IRP PREFERRED PORTFOLIO (MEGAWATTS)........................................................................................................................... 91 TABLE 6.4-2023 IRP UPDATE SUMMER CAPACITY LOAD AND RESOURCE BALANCE (MEGAWATTS)........................................................................................................................... 93 TABLE 6.5-2023 IRP UPDATE WINTER CAPACITY LOAD AND RESOURCE BALANCE (MEGAWATTS) .......................................................................................................................... 95 TABLE 6.6-VARIANT PORTFOLIOS......................................................................................... 104 TABLE 6.7-CASES UNDER MN .............................................................................................. 110 TABLE 6.8-CASES UNDER MM.............................................................................................. 110 TABLE 6.9-CASES UNDER SC-GHG...................................................................................... 110 TABLE 6.10-CASES UNDER LN.............................................................................................. III TABLE 6.11 -CASES UNDER HH............................................................................................. III CHAPTER 7 - ACTION PLAN STATUS UPDATE TABLE 7.1 -2023 IRP ACTION PLAN STATUS UPDATE ........................................................... 115 V PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS APPENDIX A TABLE A.1 -FORECASTED ANNUAL LOAD GROWTH,2024 THROUGH 2O42(MEGAWATT- HOURS),AT .............................................................................................................................. 127 TABLE A.2-FORECASTED ANNUAL COINCIDENT PEAK LOAD(MEGAWATTS)AT GENERATION, PRE- ......................................................................................................................................... 128 TABLE A.3-ANNUAL LOAD GROWTH CHANGE: 2023 IRP UPDATE FORECAST LESS 2023 IRP FORECAST MEGAWATT-HOURS AT GENERATION,PRE-DSM................................................. 129 TABLE A.4-ANNUAL COINCIDENT PEAK GROWTH CHANGE: 2023 IRP UPDATE FORECAST LESS 2023 IRP FORECAST(MEGAWATTS)AT GENERATION,PRE-DSM........................................... 130 TABLE A.5-SYSTEM ANNUAL RETAIL SALES FORECAST 2024 THROUGH 2O42(MEGAWATT- HOURS),POST-DSM................................................................................................................. 131 TABLE A.6-FORECASTED RETAIL SALES GROWTH IN OREGON,POST-DSM .......................... 132 TABLE A.7-FORECASTED RETAIL SALES GROWTH IN WASHINGTON,POST-DSM................. 133 TABLE A.8-FORECASTED RETAIL SALES GROWTH IN CALIFORNIA,POST-DSM.................... 134 TABLE A.9-FORECASTED RETAIL SALES GROWTH IN UTAH,POST-DSM.............................. 135 TABLE A.10-FORECASTED RETAIL SALES GROWTH IN IDAHO,POST-DSM........................... 136 TABLE A.I I -FORECASTED RETAIL SALES GROWTH IN WYOMING,POST-DSM..................... 137 Vl PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS TABLE OF FIGURES CHAPTER 1 - EXECUTIVE SUMMARY FIGURE 1.1 -KEY ELEMENTS OF PACIFICORP'S 2023 IRP UPDATE APPROACH.................................4 FIGURE 1.2-2023 IRP UPDATE ALL-STATE PREFERRED PORTFOLIO CUMULATIVE CHANGES IN INSTALLEDCAPACITY.........................................................................................................................................4 FIGURE 1.3-NEW INTERCONNECTION CAPACITY BY LOCATION...........................................................6 FIGURE 1.4-2023 IRP UPDATE PREFERRED PORTFOLIO NEW SOLAR CAPACITY.............................6 FIGURE 1.5-2023 IRP UPDATE PREFERRED PORTFOLIO NEW WIND CAPACITY...............................7 FIGURE 1.6-2023 IRP UPDATE PREFERRED PORTFOLIO NEW STORAGE CAPACITY........................7 FIGURE 1.7-2023 IRP UPDATE PREFERRED PORTFOLIO PEAKING RESOURCES CAPACITY...........8 FIGURE 1.8-2023 IRP UPDATE PREFERRED PORTFOLIO NEW NUCLEAR CAPACITY.......................8 FIGURE 1.9-FORECASTED ANNUAL LOAD..................................................................................................9 FIGURE 1.10-FORECASTED ANNUAL COINCIDENT PEAK LOAD............................................................9 FIGURE 1.11 -2023 IRP UPDATE PREFERRED PORTFOLIO ENERGY EFFICIENCY AND DEMAND RESPONSECAPACITY........................................................................................................................................10 FIGURE 1.12-POWER AND NATURAL GAS PRICE FORECASTS...............................................................10 FIGURE 1.13-2023 IRP UPDATE PREFERRED PORTFOLIO SUMMER MARKET PURCHASES..........11 FIGURE 1.14 -2023 IRP UPDATE PREFERRED PORTFOLIO SUMMER MARKET PURCHASES.........11 FIGURE 1.15-PREFERRED PORTFOLIO CO2E EMISSIONS COMPARISON............................................15 FIGURE 1.16-2023 IRP UPDATE PREFERRED PORTFOLIO CO2E EMISSIONS TRAJECTORY....... 16 FIGURE 1.17-ANNUAL STATE RPS COMPLIANCE FORECAST..............................................................17 CHAPTER 2 - INTRODUCTION CHAPTER 3 - THE PLANNING ENVIRONMENT FIGURE 3.1 -ENERGY GATEWAY MAP...................................................................................... 34 CHAPTER 4 - LOAD-AND-RESOURCE BALANCE FIGURE 4.1 -FORECASTED ANNUAL LOAD(GWH)................................................................... 39 FIGURE 4.2-FORECASTED ANNUAL COINCIDENT PEAK LOAD(MW) ......................................40 FIGURE 4.3-SUMMER SYSTEM CAPACITY POSITION TREND..................................................... 49 FIGURE 4.4-WINTER SYSTEM CAPACITY POSITION TREND...................................................... 50 CHAPTER 5 - MODELING AND ASSUMPTIONS FIGURE 5.1 -NOMINAL WHOLESALE ELECTRICITY AND NATURAL GAS PRICE SCENARIOS...... 53 FIGURE 5.2-MEDIUM,HIGH AND SOCIAL COST OF GREENHOUSE GAS CO2 PRICES................ 54 FIGURE 5.3-INFLATION REDUCTION ACT AND FUTURE TECHNOLOGY COSTS ......................... 56 CHAPTER 6 - MODELING AND ASSUMPTIONS FIGURE 6.1 -THE SIX STEPS OF ONE PORTFOLIO DEVELOPMENT PHASE.................................. 71 FIGURE 6.2-GRANULARITY ADJUSTMENT DETERMINATION.................................................... 73 Vll PACIFICORP-2023 IRP UPDATE TABLE OF CONTENTS FIGURE 6.3-INTEGRATED PORTFOLIO STRATEGY .................................................................... 74 FIGURE 6.4-2023 IRP UPDATE SYSTEM AND SITUS RESOURCE ALLOCATIONS ....................... 77 FIGURE 6.5-ALLOCATION OF THE 2023 IRP UPDATE PREFERRED PORTFOLIO THROUGH 2032 78 FIGURE 6.6-2023 IRP UPDATE ALL-STATE PREFERRED PORTFOLIO CUMULATIVE CHANGES IN INSTALLEDCAPACITY................................................................................................................ 79 FIGURE 6.7-CUMULATIVE INCREASE/(DECREASE)IN 2023 IRP UPDATE LESS ........................ 80 FIGURE 6.8-NEW INTERCONNECTION CAPACITY BY LOCATION,2023 IRP UPDATE PREFERRED PORTFOLIO................................................................................................................................. 82 FIGURE 6.9-2023 IRP UPDATE PREFERRED PORTFOLIO NEW SOLAR CAPACITY..................... 82 FIGURE 6.10-2023 IRP UPDATE PREFERRED PORTFOLIO NEW WIND CAPACITY .................... 83 FIGURE 6.11 -2023 IRP UPDATE PREFERRED PORTFOLIO NEW STORAGE CAPACITY............... 83 FIGURE 6.12-2023 IRP UPDATE PREFERRED PORTFOLIO PEAKING RESOURCES CAPACITY .... 84 FIGURE 6.13-2023 IRP UPDATE PREFERRED PORTFOLIO NEW NUCLEAR CAPACITY.............. 84 FIGURE 6.14-2023 IRP UPDATE PREFERRED PORTFOLIO ENERGY EFFICIENCY AND DEMAND RESPONSECAPACITY................................................................................................................. 85 FIGURE 6.15-2023 IRP UPDATE PREFERRED PORTFOLIO MARKET PURCHASES...................... 86 FIGURE 6.16-PREFERRED PORTFOLIO CO2E EMISSIONS COMPARISON..................................... 98 FIGURE 6.17-2023 IRP UPDATE PREFERRED PORTFOLIO CO2E EMISSIONS TRAJECTORY....... 99 FIGURE 6.18-ANNUAL STATE RPS COMPLIANCE FORECAST................................................. 101 FIGURE 6.19-PROJECTED ENERGY MIX WITH PREFERRED PORTFOLIO RESOURCES............... 102 FIGURE 6.20-PROJECTED CAPACITY MIX WITH 2023 IRP UPDATE PREFERRED PORTFOLIO RESOURCES.............................................................................................................................. 103 FIGURE 6.21 -INCREASE/(DECREASE)IN SYSTEM COSTS WHEN CCUS IS REMOVED ............. 104 FIGURE 6.22-INCREASE/(DECREASE)IN SYSTEM COST ASSUMING JIM BRIDGER 3 AND 4..... 105 FIGURE 6.23-INCREASE/(DECREASE)IN PROXY RESOURCES WHEN THE NATRIUMTM DEMONSTRATION PROJECT IS REMOVED ................................................................................. 105 FIGURE 6.24-INCREASE/(DECREASE)IN SYSTEM COSTS WHEN NUCLEAR IS REMOVED ........ 106 FIGURE 6.25-INCREASE/(DECREASE)IN PROXY RESOURCES WHEN UTAH OTR STARTING IN 2027 IS ASSUMED..................................................................................................................... 106 FIGURE 6.26-INCREASE/(DECREASE)IN SYSTEM COSTS ASSUMING UTAH OTR STARTING 2027 ................................................................................................................................................. 107 FIGURE 6.27-INCREASE/(DECREASE)IN PROXY RESOURCES ASSUMING............................... 107 FIGURE 6.28-INCREASE/(DECREASE)IN SYSTEM COST OREGON OFFSHORE WIND IS SELECTED ................................................................................................................................................. 108 FIGURE 6.29-INCREASE/(DECREASE)IN PROXY RESOURCES ASSUMING OREGON ................ 108 FIGURE 6.30-INCREASE/(DECREASE)IN SYSTEM COST ASSUMING OREGON HB 2021.......... 109 FIGURE 6.31 -INCREASE/(DECREASE)IN PROXY RESOURCES ASSUMING WASHINGTON........ 109 FIGURE 6.32-INCREASE/(DECREASE)IN SYSTEM COST ASSUMING WASHINGTON ................ 110 Vlll PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY CHAPTER I - EXECUTIVE SUMMARY PacifiCorp submitted its Amended Final 2023 Integrated Resource Plan (IRP) on May 31, 2023. That plan provides a framework for future actions PacifiCorp will take to provide reliable and valuable electric service for customers with a least-cost, least-risk resource portfolio. The 2023 IRP Update reflects resource planning and procurement activities since the 2023 IRP,presents an updated load-and-resource balance, and an updated resource portfolio consistent with changes in the planning environment. The 2023 IRP Update also provides a status update for the action plan filed with the 2023 IRP. In presenting the updated load-and-resource balance and updated resource portfolio, PacifiCorp highlights changes in the 2023 IRP Update preferred portfolio' relative to the 2023 IRP preferred portfolio,which covers the 2024 to 2042 planning horizon. Consistent with the 2023 IRP,the 2023 IRP Update's preferred portfolio demonstrates reliable service will require investment in transmission infrastructure, new wind and solar resources, the conversion of two coal units to natural gas peaking units,growth in demand response and energy efficiency programs, the addition of carbon capture technology on identified coal resources,the addition of an advanced nuclear resource,the addition of energy storage resources, and the addition of natural gas peaking resources that are capable of converting to non-emitting fuels. The 2023 IRP Update preferred portfolio includes resources necessary for individual state policy compliance and assumes those resources are allocated to the state whose policy necessitated the addition. Key changes in this 2023 IRP Update are driven by U.S. Environmental Protection Agency's (EPA) approval of Wyoming's state Ozone Transport Rule (OTR) plan, the stay of EPA's disapproval of Utah's state OTR plan, extensions to the assumed operational life of new natural gas generating resources, energy storage acquisition strategy, forecast load demand, higher coal prices, and natural gas and wholesale power market price updates. In addition, PacifiCorp has advanced its modeling strategy to address regulatory and stakeholder feedback,using a robust iterative process to refine the optimization process.For example,the 2023 IRP Update preferred portfolio includes system-allocated resources as well as resources that are needed to meet the requirements of specific states. Resources needed to meet specific state policy compliance requirements may need to be assigned,in their entirety,to a single state to avoid adding unnecessary cost burdens to customers in other states, which could raise other potential issues related to operations and resource adequacy that have not been addressed in the system approach of the 2023 IRP Update preferred portfolio. Future allocations of any incremental costs associated with both system resources and resources included in the plan solely to meet state-specific policy objectives will need to be addressed to ensure alignment of costs and benefits. Customer Focus At PacifiCorp, we're committed to meeting the demands of our customers and communities throughout the West to deliver safe, affordable, reliable energy and a resilient, modern grid. Our integrated system connects and brings new opportunities to the West, building on a foundation of infrastructure designed to handle extreme weather and enhance the energy resilience of communities from the Pacific Coast to the Rocky Mountains, all while continuing to deliver valuable energy solutions for our customers at prices that are below national and regional averages. ' The preferred portfolio is the least-cost,least-risk resource plan over the 20-year IRP study horizon. 1 PACIFICORP-2023 IRP UPDATE CHAPTER I-EXECUTIVE SUMMARY Together with the communities we serve and our regional partners, it is time to act, with targeted, strategic investments that will position us to continue delivering safe, valuable, reliable power to our customers. Our customer-centered vision embodies four core themes: Reliable Power: We strive to deliver energy safely during all hours, and plan extensively to ensure that we have sufficient supply and the ability to deliver to the communities we serve. We understand that electricity is an essential service, and work around the clock to ensure that we are dependable, and that our communities can rely on us. Resilient Infrastructure: We live in times of rapid change, with more extreme weather and challenging conditions. We are working to minimize disruptions, implement strategies to recover quickly when they occur, and deploy upgrades that will strengthen our critical infrastructure. Valuable Service: PacifiCorp is proud to be one of the lowest-cost electricity providers in the nation and the region and we are committed to continue doing so as we make new and much needed investments in generation and transmission infrastructure. As we plan for new resources, we are prioritizing actions that are necessary to support customer needs and the reliability of the system while reflecting the policy values of each of our states at the lowest cost possible. Clean Energy: Through strategic, customer-focused investments in diverse resources, PacifiCorp's plan continues to show a reduction in carbon emissions. The 2023 IRP Update preferred portfolio indicates that carbon emissions will decrease by more than 60% from 2005 levels by 2030. Although a higher load forecast and the removal of OTR compliance requirements has extended our emissions reduction timeline in comparison to the 2023 IRP, the 2023 IRP Update resource plan continues to include significant new renewable additions among other diverse, advanced technologies. This path of renewables additions and advanced technologies achieves even deeper decarbonization beyond 2030. 2023 IRP Update Roadmap We're advancing our critical infrastructure to meet the challenges of a rapidly changing economy, while laying the groundwork for long-term value and reliability through building a more resilient grid. The 2023 IRP Update preferred portfolio includes: • Resources 0 9,818 megawatts of new wind resources (including 443 megawatts for Washington and 239 megawatts of small-sale wind for Oregon). 0 4,016 megawatts of storage resources, including batteries collocated with solar generation, standalone batteries, and pumped hydro storage resources (including 101 megawatts of standalone batteries for Oregon and Washington). 2 PACIFICORP-2023 IRP UPDATE CHAPTER I-EXECUTIVE SUMMARY 0 3,763 megawatts of new solar resources, mostly paired with battery storage, (including 483 megawatts of small-scale solar for Oregon). 0 4,326 megawatts of capacity saved through energy efficiency programs. 0 1,123 megawatts of capacity saved through demand response programs. 0 500 megawatts of advanced nuclear(NatriumTM reactor demonstration project) in 2030. 0 5,385 megawatts of natural gas convertible peaking resources that meet high- demand energy needs (including 224 megawatts of renewable-fueled peaking resources for Oregon). o Installation of carbon capture technology on Jim Bridger Units 3 and 4. • Transmission o As supported by needs established in previous IRPs, PacifiCorp is finalizing construction of the Energy Gateway South and Energy Gateway West Sub- Segment D1 transmission projects and partnering with Idaho Power to build the Energy Gateway Sub-Segment H (Boardman-to-Hemingway or 132H) transmission project. o Additional transmission upgrades to increase transfer capability and/or enable renewable resource requests to connect to the transmission system in southeast Idaho, central and northern Utah, eastern Wyoming, throughout Oregon, and in Yakima and Walla Walla, Washington. Approximately two gigawatts of additional interconnection capacity are added through 2032, in addition to the amounts directly associated with Energy Gateway South, Energy Gateway West Sub-Segment D1, and B2H. NoWntegrated Resourgorla In the 2023 IRP Update,PacifiCorp presents a preferred portfolio that builds on its vision to deliver valuable energy service,reliably, and responsibly. We are achieving this vision while meeting our customers' growing energy needs through near-term investments in transmission infrastructure and continued growth in new generation and storage resource capacity as well as maintaining substantial investment in energy efficiency and demand response programs. The primary objective of the IRP is to identify the best mix of resources to serve customers in the future. The best combination of resources is determined through analysis that measures cost and risk. The least-cost, least-risk resource portfolio—defined as the "preferred portfolio"—is the portfolio that can be delivered through specific action items at a reasonable cost and with manageable risks while delivering reliable service to customers and ensuring compliance with state and federal regulatory obligations without cost-shifting amongst states for compliance. The full planning process is completed every two years, with a review and update completed in the off years. Consequently,these plans,particularly the longer-range elements,can and do change over time. 3 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY Figure 1.1 —Key Elements of PacifiCorp's 2023 IRP Update Approach Resource Inpul Resource Preferred Action AssumptionsPortfolios w Portfolio • �. Portfolio Plan 2 ferred P�rtf�lilysis ts and o Highligh PacifiCorp's selection of the 2023 IRP Update preferred portfolio is supported by comprehensive data analysis, described in the chapters that follow. Figure 1.2 shows that PacifiCorp's 2023 IRP Update preferred portfolio continues to include substantial new renewables facilitated by incremental transmission investments, along with demand-side management (DSM) resources, significant storage resources,NatriumTM advanced nuclear,and dispatchable peaking resources.A more detailed summary of preferred portfolio resources by resource type is presented later in this section. Figure 1.2—2023 IRP Update All-State Preferred Portfolio Cumulative Changes in Installed Capacity 30000 25000 20000 15000 ■ 10000 5000 _5000 e e e -10000 ■Coal ■Gas ■Contracts ■QF Hydro Nuclear ■Hydro Storage ■Battery ■Solar ■Solar+Storage ■Wind ■Geothermal ■Energy Efficiency ■Demand Response ■Peaking ■Converted Gas *Note: "Coal"includes both minority and majority owned coal resources,including Jim Bridgers 3 &4 with carbon capture technology."Coal"does not include coal resources converted to gas.Coal resources converted to gas are categorized under"Converted Gas"and are only shown at retirement,as the conversion does not increase the installed capacity of the resource."Gas"includes only existing gas resources.New gas peaking and new hydrogen peaking resources are grouped under"Peaking". "Nuclear"includes only the NatriumTM advanced nuclear project. 4 PACIFICORP-2023 IRP UPDATE CHAPTER I-EXECUTIVE SUMMARY Transmission Upgrades To facilitate the delivery of new resources to PacifiCorp customers across the West, the 2023 IRP Update preferred portfolio includes additional transmission investment. As supported by needs established in previous IRPs, PacifiCorp is finalizing construction of the Energy Gateway South and Energy Gateway West Sub-Segment D1 transmission projects and partnering with Idaho Power to build the B2H transmission project, which is expected to come online in the 2026-2027 timeframe. B2H is a 290-mile high-voltage 500 kilovolt transmission line that connects the Longhorn substation near the town of Boardman in Oregon to the Hemingway substation in Idaho. By exchanging certain transmission assets with Idaho Power Company, PacifiCorp will receive additional transmission rights between Hemingway and the Populus substation in Idaho, which is closely tied to existing and future PacifiCorp transmission connecting to Utah and Wyoming. At the Oregon end of the B2H line, additional transmission upgrades are planned to connect B2H to growing loads. In the 2023 IRP Update, many transmission upgrades and the accompanying resources reflect the results of PacifiCorp's generator interconnection "cluster study" process for evaluating proposed resource additions. By evaluating all newly proposed resource additions in an area at the same time, the cluster study process identifies collective solutions that can allow projects that are ready to move forward to do so in a timely fashion. As a result, transmission upgrades and resource additions in the 2023 IRP Update preferred portfolio consider cluster study requests submitted in the past several years. Figure 1.3 summarizes the new interconnection capacity selected to facilitate new generation resources identified as part of the 2023 IRP Update preferred portfolio. In addition to providing increased interconnection capacity, transmission upgrades are also expected to allow for increased transfer capability between different areas of PacifiCorp's system. The 2023 IRP Update preferred portfolio includes portions of the following transmission upgrades between the following areas within the IRP topology. Note that modeling for the 2023 IRP Update allowed for partial selection of lines, though that does not indicate that these lines would be uneconomic if built in their entirety. Given the timing identified primarily in the second half of the IRP study horizon, these opportunities will continue to be explored in the future. - Walla Walla to Yakima. - Gateway Sub-Segment D3: provides direct transfers between Jim Bridger and Borah (Populus), but with supporting projects, also facilitates transfers between Wyoming East and Jim Bridger and between Borah and Utah North. - Incremental Gateway Segments: Segments D2.2,D1.2, and Gateway South 2 would be the second iteration of existing or soon to be in service segments from the original Gateway plan, and would provide additional transfer capability between Wyoming East and Bridger and between Wyoming East and Clover. - Oregon 500 kilovolt upgrades: several 500 kilovolt upgrades and supporting projects would connect Portland-North Coast, Willamette Valley, Southern Oregon, and Central Oregon. - East-West transfers: together, B2H 2 and Gateway Segment E would further increase transfer capability between PacifiCorp's east and west balancing authority areas. 5 PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY Figure 1.3—New Interconnection Capacity by Location 8,000 o 61000 o 0 0 ■ ■ ■ ■ L J 41000 ' 2,000 z ro ■ U 0 Ln lD I- M M O N M I Ln lA I- W M O r-1 N N N N N N M M M M M M M M M M qtlz�_ qt O O O O O O O O O O O O O O O O O O CV N N N N N N r 4 N N N N N r q N CV N N ■ Wyoming Idaho Utah Oregon Washington New Solar Resources The 2023 IRP Update preferred portfolio includes 2,084 megawatts of solar by the end of 2030, and 3,749 megawatts of new solar is online by 2037, as shown in Figure 1.4 While not shown in Figure 1.4, the company has previously contracted for one gigawatt of solar resources with commercial operation dates between 2024 and 2026 for customer-directed voluntary renewable procurement programs. Figure 1.4—2023 IRP Update Preferred Portfolio New Solar Capacity"' 10,000 8,000 j 6,000 n3 � 4,000 U 2,000 ' 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 I RP Update ■2023 I RP * 2023 IRP Update solar capacity shown in the figure includes committed solar resources shown in 2025 and 2026. Resources are shown in the first full year of operation(the year after the year-online dates). This total includes 374 megawatts of small scale solar to meet Oregon requirements. 6 PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY New Wind Resources As shown in Figure 1.5,by 2032,PacifiCorp's 2023 IRP Update preferred portfolio includes 6,034 megawatts of new wind resources,and more than 9,800 megawatts of new wind resources by 2037. Figure 1.5—2023 IRP Update Preferred Portfolio New Wind Capacity* 12,000 10,000 v8,000 ' > 6,000 � 4,000 I U 2,000 0600 ■ JrJn . I + I 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 I RP Update ■2023 I RP *Note: Wind additions shown are incremental to Energy Vision 2020 and other projects that have come online over the past few years.Resources are shown in the first full year of operation(the year after year-end online dates). This figure includes 254 megawatts of small-scale wind to meet Oregon requirements,and an additional 443 megawatts of utility scale wind to meet Washington requirements. New Storage Resources As shown in Figure 1.6,the 2023 IRP Update preferred portfolio includes 1,626 megawatts of new storage capacity by the end of year 2029 and more than 4,000 megawatts by 2037. Figure 1.6—2023 IRP Update Preferred Portfolio New Storage Capacity* 10,000 8,000 > 6,000 n3 � 4,000 E U 2,000 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 1 RP Update ■2023 1 RP *Note: Resources are shown in the first full year of operation(the year after the year-end online dates). This figure includes a total of 101 megawatts of storage resources required for Oregon and Washington for compliance. Peaking Capacity The 2023 IRP Update continues to indicate the need for flexible peaking capacity to achieve reliability and minimize risk. A key change since the filing of the 2023 IRP is the addition of peaking capacity in the form of natural gas resources capable of operating with 100% hydrogen fuel.The inclusion of this technology also guards against the future risk of increasingly constrained emissions and future policy requirements. 7 PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY Figure 1.7—2023 IRP Update Preferred Portfolio Peaking Resources Capacity* 6,000 �j 5,000 4,000 3,000 F 2,000 U 1,000 - ■ ■ ■ 7 ■ ' ' 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 1 RP Update 2023 1 RP *Note: Resources are shown in the first full year of operation(the year after the year-end online dates). This figure includes 224 megawatts of peaking units for Oregon compliance that can only run on renewable fuel. Nuclear Capacity The 2023 IRP Update continues to show the value associated with the NatriumTM Demonstration Project which provides a significant non-emitting resource. A key change since the filing of the 2023 IRP is the stay of the EPA's disapproval of Utah's OTR plan and subsequent ability of the existing thermal fleet to operate with fewer restrictions as a dispatchable resource. Although additional advanced nuclear resources beyond the NatriumTM Demonstration Project are not selected in this update, PacifiCorp is continually updating advanced nuclear resource cost estimates as they become available. Figure 1.8—2023 IRP Update Preferred Portfolio New Nuclear Capacity* 1,600 1,400 1,200 1,000 800 7 600 � 400 .. U 200 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2023 I RP Update ■2023 I RP *Note:Resources are shown in the first full year of operation(the year after the year-end online dates). Demand-Side Management PacifiCorp evaluates new DSM opportunities, which includes both energy efficiency and demand response programs, as a resource that competes with traditional new generation and wholesale power market purchases when developing resource portfolios for the IRP. The optimal determination of DSM resources results in selecting all cost-effective DSM as a core function of IRP modeling. Consequently, the load forecast used as an input to the IRP does not reflect any incremental investment in new energy efficiency programs; rather,the load forecast is reduced by the selected additions of energy efficiency resources in the IRP Update. 8 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY Figure 1.9 indicates that PacifiCorp's load forecast before incremental energy efficiency savings has decreased over the 2024 to 2027 timeframe and increased from 2028 and on relative to projected loads used in the 2023 IRP. In the near term, lower projected demand from data centers results in a lower forecast, while data center expectations over the long-term result in a higher forecast. On average, the forecasted system load is up 0.8% and the forecasted coincident system peak is up 1.2%over the 20-year planning horizon when compared to the 2023 IRP. Over the 2024 to 2042 timeframe, the average annual growth rate, before accounting for incremental energy efficiency improvements, is 2.13% for load and 1.80% for peak. Figure 1.9—Forecasted Annual Load Before Incremental Energy Efficiency Savings) 100,000 90,000 80,000 70,000 60,000 rn 50,000 0 40,000 30,000 R R 20,000 G� 10,000 V'1 �O [- 00 O\ O -- N M V1 �O l- 00 O• O �--� CAN N N N N N M M M M M M M M M M IT O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N (4 N N N N N N N +2023 IRP f 2023 IRP Update Figure 1.10—Forecasted Annual Coincident Peak Load 16.000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 V) NO [- 00 ON O - N M l- 00 ON O N O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N +2023 IRP f2023 IRP Update DSM resources continue to play a key role in PacifiCorp's resource mix. The chart to the left in Figure 1.11 compares total energy efficiency capacity savings in the 2023 IRP Update preferred 9 PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY portfolio relative to the 2023 IRP preferred portfolio and includes 4,326 megawatts by the end of the planning period. In addition to continued investment in energy efficiency programs, the preferred portfolio shows a need for incremental demand response programs. The chart to the right in Figure 1.11 compares cumulative demand response program capacity in the 2023 IRP Update preferred portfolio relative to the 2023 IRP preferred portfolio and does not include capacity from existing programs. The 2023 IRP Update has a cumulative capacity of incremental demand response programs reaching 1,123 megawatts by 2042 which represents a 21% increase relative to the 2023 IRP. Figure 1.11 —2023 IRP Update Preferred Portfolio Energy Efficiency and Demand Response Capacity Energy Efficiency Demand Response 6,000 1,500 5,000 4,000 1,000 3,000 ° ,000 a 500 1 ,00 U 0 0 V Vl b r- 00 (7\ O N M V V) b e` 00 D\ O N V V1 b r- 00 01 O N M V h 10 r- 00 01 In N O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O C O N (V N N " N " N N N N N N N N N N N N N N N N N N N N N . N N N N N N N N N ■2023 IRP Update -1 2023 IRP ■2023 IRP Update 2023 IRP Wholesale Power Market Prices and Market Activity Figure 1.12 illustrates the electricity and natural gas price forecasts used in the 2023 IRP Update. These forecasts are based on prices observed in the forward market and on projections from third- party experts. Figure 1.12—Power and Natural Gas Price Forecasts Wholesale Electricity Prices Natural Gas Prices Average of Palo Verde and Mid-C(Flat) Henry Hub $120 $14 $110 ' $13 $100 i $12 $90 $11 $80 $10 $70 .�' $9 $60 $40 ............ i $5 i ffiO i ---- $0 $1 M Y1 10 1, 00 01 O �"� N M -e V1 1O l� 00 Qt O N M V't 10 l� 00 Qt O " N M V1 10 r 00 01 O N N N N N N N N M M M M M M M M M M 7 N N N N N N N M M M M M M M M M M 7 N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N N •• ••Mgms_MCO2(Sep 2023) ———Lgas 00O2(Sep 2023) Mgas 00O2(Sep 2023) —A—Hgas HCO2(Sep 2022) —Medium(Sep 2023)———Lon(Sep 2023)—A--High(Sep 20M) —Mps SCO2(Sep 2023) Subsequent to the filing of the 2023 IRP, the EPA's approval of Wyoming's state OTR plan and the stay of EPA's disapproval of Utah's state OTR plan removed the restrictions that limit energy 10 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY production in the summer from natural gas and coal-fueled resources in Wyoming and Utah. In the absence of the OTR driver, market purchases can cost-effectively replace some of the incremental renewable resources that were indicated in the 2023 IRP preferred portfolio, leading to higher relative market activity, as shown in Figure 1.13 and Figure 1.14 below. In addition, a 500 megawatt capacity Wyoming market has been added in the 2023 IRP update,representing the ongoing ability to access diverse (and potentially new) regional markets as discussed in Chapter 3. Figure 1.13 —2023 IRP Update Preferred Portfolio Summer Market Purchases Summer Market Purchases 1400 1200 1000 800 v ao 600 Q 400 - 200 � 1 0 tioti° ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti 020231RPUpdate 02023IRP Figure 1.14 —2023 IRP Update Preferred Portfolio Summer Market Purchases Winter Market Purchases 1400 1200 1000 - 800 v 00 600 Q 400 200 'I An 0 -- -- - - ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ■2023IRPUpdate ■20231RP *Note: "Summer Market Purchases" includes purchases from June through September while "Winter Market Purchases"includes purchases from December and January.While most data for tables and figures in this document comes from LT capacity expansion model results,this figure uses ST model results.For market data,it is appropriate 11 PACIFICORP—2023 IRP UPDATE CHAPTER I—EXECUTIVE SUMMARY to use ST model results because the ST model is run with an hourly granularity which more accurately represents the energy needed to meet load obligations compared to the less granular LT capacity expansion model. Coal and Gas Retirements/Gas Conversions Coal resources have been an important resource in PacifiCorp's resource portfolio for many years. The operating capabilities of these facilities have been able to adapt to changes in the planning environment. For example, PacifiCorp has been able to lower operating minimums and optimize coal dispatch through the Western Energy Imbalance Market (WEIM or EIM). This in turn has enabled the company to both reduce fuel consumption and associated costs and emissions by increasingly buying low-cost, zero-emissions renewable energy from market participants across the West, which is accessed by our expansive transmission grid. PacifiCorp's coal resources will continue to play a pivotal role in following fluctuations in renewable energy as the remaining coal units approach retirement dates. EPA's approval of Wyoming's ozone plan and the stay of EPA's disapproval of Utah's ozone plan results in fewer restrictions on coal-fired operation than were assumed in the 2023 IRP. With these updates, Utah coal resources are no longer planned to retire early, as shown in Table 1.1 Hunter and Huntington coal unit retirements, specifically, have returned to the schedule that had been previously indicated by PacifiCorp's 2021 IRP. 12 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY Table 1.1 —Coal Unit Retirements in the 2023 IRP and 2023 IRP Update Coal 2023 IRP 2023 IRP Update Retirement Retirement Delta to 2023 Unit Year (12/31/_j Year (12/31/_j IRP (Years) As Selected As Selected Colstrip 3 2025 2025 - Colstrip 4 2029 2029 - Craig 1 2025 2025 - Craig 2 2028 2028 - DaveJohnston 1 2028 2028 - DaveJohnston 2 2028 2028 - DaveJohnston 3 2027 2027 - DaveJohnston 4 2039 2039 - Hayden 1 2028 2028 - Hayden 2 2027 2027 - Hunter 1 2031 2042 11 Hunter 2 2032 2042 10 Hunter 3 2032 2042 10 Huntington 1 2032 2036 4 Huntington 2 2032 2036 4 JimBridger 1 2037 2037 - JimBridger 2 2037 2037 - JimBridger 3 2037 2039 2 JimBridger 4 2037 2039 2 Naughton 1 2036 2036 - Naughton 2 1 2036 2036 - Wyodak 1 2039 2039 - Coal unit exits, retirements, gas conversions, and retrofits scheduled under the preferred portfolio include: • 2023 = Jim Bridger Units 1-2, converted to natural gas in 2024 (same as in the 2023 IRP) • 2025 = Craig Unit I retirement(same as in the 2023 IRP) • 2026=Naughton Units 1-2, converted to natural gas in 2026, operates through 2036 (same as in the 2023 IRP) • 2027 = Dave Johnston Unit 3 retirement (same as in the 2023 IRP) • 2027 = Hayden Unit 2 retirement(same as in the 2023 IRP) 13 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY • 2028=Jim Bridger Units 3-4,retrofitted with carbon capture technology in 2028,operates through 2039 (converted to gas conversion in 2030 and retired in 2037 in the 2023 IRP; unit life is extended by 2 years to capture 12 full years of investment tax credits) • 2028 =Dave Johnston Units 1-2 retirement(same as in the 2023 IRP) • 2028 =Craig Unit 2 retirement(same as in the 2023 IRP) • 2028 =Hayden Unit I retirement (same as in the 2023 IRP) • 2029 = Colstrip Unit 4 exit, Colstrip Unit 3 share is consolidated into Colstrip Unit 4 in 2025 (same as in the 2023 IRP) • 2036=Huntington Units 1-2 retirement,no emissions controls(SNCR installation in 2026, operating through 2032 in the 2023 IRP) • 2039 =Dave Johnston Unit 4 retirement (same as in 2023 IRP) • 2039 = Wyodak retirement, no emissions controls (SNCR installation in 2026, operating through 2039 in the 2023 IRP) • 2042 = Hunter Units 1-3 retirement, no emissions controls (SNCR installation in 2026, operating through 2031 and 2032 in the 2023 IRP) Resource Procurement and Requests for Proposals As evaluated in the 2023 IRP, the OTR significantly restricted energy production in the summer among natural gas and coal-fueled resources in Wyoming and Utah, which triggered a need for incremental resources. EPA's approval of Wyoming's state OTR plan and the stay of EPA's disapproval of Utah's state OTR plan removes the restrictions that limit energy production in the summer from natural gas and coal-fueled resources in Wyoming and Utah. The 2023 IRP Update preferred portfolio demonstrates that with limited procurement of battery resources in the near- term, which can be achieved outside of a request for proposals process, there is a material benefit to scaling down and delaying resource acquisition until after 2030. This outcome supports the company's decision to suspend the 2022 All-Source Request for Proposals, which will be terminated. The proposed small-scale renewable request for proposal will not be issued until additional stakeholder outreach can be completed. The 2025 IRP will inform the next steps for incremental resource acquisition. Carbon Dioxide Emissions The 2023 IRP Update preferred portfolio reflects PacifiCorp's on-going efforts to provide valuable energy solutions for our customers that reflects a continued trajectory of declining carbon dioxide (CO2) and other carbon dioxide equivalent (CO2e) emissions resulting in a measure of total emissions. PacifiCorp's emissions have been declining and continue to decline related to several factors including PacifiCorp's participation in the EIM and commitment to CAISO's Extended Day- Ahead Market (EDAM), which reduces customer costs and maximizes use of non-emitting renewable resources that have no fuel cost and that generate tax credits. The chart below in Figure 1.15 compares projected annual CO2e emissions between the 2023 IRP Update and 2023 IRP preferred portfolios. In this graph, emissions are assigned to market purchases at a rate of 0.428 metric tons CO2 equivalent per megawatt-hour. 14 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY In the 2023 IRP Update, emissions are higher than projected in the 2023 IRP starting in 2026. Removal of the OTR, which limited summer generation from gas and coal-fueled resources, is a significant driver. Further, over the longer-term the load forecast in the 2023 IRP Update is higher than in the 2023 IRP. Importantly, the 2023 IRP Update preferred portfolio continues to show a continued downward trajectory in emissions over time. By 2030, average annual CO2e emissions in the 2023 IRP Update preferred portfolio are reduced by 63% against the year 2005 baseline versus a reduction of 78% against the baseline in the 2023 IRP preferred portfolio. By the end of the planning horizon, system CO2e emissions are projected to fall from 35.1 million metric tons in 2023 to 9.3 million tons in 2042—a reduction of 73.5%. Figure 1.15—Preferred Portfolio CO2e Emissions Comparison* 45 v 40 N 0 35 0 30 — L 25 v 20 c °_ 15 10 5 LL 0 M RT Ul W n W M O r-1 N M RT Ul W I�- W M O ri N O O O O O O O O O O O O O O O O O 8 a a N N N N N N N N N N N N N N N N N N N N ■ 2023 Update IRP CO2e ■ 2023 CO2e IRP * PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2022 from owned facilities, specified sources and unspecified sources. From 2023 through the end of the twenty-year planning period in 2042, emissions reflect those from the 2023 IRP Update preferred portfolio with emissions from specified sources reported in CO2 equivalent.Market purchases are assigned a default emission factor(0.428 metric tons CO2e/megawatt-hour). Emissions from sales are not removed.Beyond 2042,emissions reflect the rolling average emissions of each resource from the 2023 IRP update preferred portfolio through the life of the resource. Figure 1.16 includes historical data,assigns emissions at a rate of 0.428 metric tons CO2 equivalent per megawatt-hour to market purchases (with no credit to market sales), includes emissions associated with specified purchases, and extrapolates projections out through 2050. This graph demonstrates that relative to a 2005 baseline, of 54.6 million metric tons, system CO2e emissions are down 47%in 2025, 63%in 2030, 80% in 2035, 84% in 2040, 84%in 2045, and 100%in 2050 (assuming that by 2050, new gas-fired resources added in the preferred portfolio are fueled with a non-emitting fuel alternative. 15 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY Figure 1.16—2023 IRP Update Preferred Portfolio CO2e Emissions Trajectory* 60 100% a� 50 80% N 40 V) � m 30 60% 0 40% 20 o 0 10 20% 0 0% r-I RZT r- 0 m 1,D rn N Ln oo r-1 IZ31 r 0 r-1 r-i r 1 N N N N m m m �Ir IZI- IzT Ln 0 0 0 0 0 0 0 0 0 0 0 0 0 0 fV N rV fV fV fV N r1J fV N fV N N fV PacifiCorp Emissions (Million MT) —2005 Base Emission •••••• % Reduction from 2005 Base *The emissions trajectory does not incorporate clean energy targets set forth in Oregon House Bill 2021 or any other state-specific emissions trajectories. Renewable Portfolio Standards Figure 1.17 shows PacifiCorp's renewable portfolio standard (RPS) compliance forecast for California,Oregon,and Washington after accounting for new renewable resources in the 2023 IRP Update preferred portfolio. While these resources are included in the preferred portfolio as cost- effective system resources and are not included to specifically meet RPS targets, they nonetheless contribute to meeting RPS targets in PacifiCorp's western states. The California RPS compliance position will be met through year 2030 with owned and contracted renewable resources, as well as REC purchases. Beyond 2030,the company may need to purchase approximately—175,000 RECs per year to meet the RPS target of 60% in years where a shortfall is projected. Oregon RPS compliance is achieved through 2042 with the addition of new renewable resources in the 2023 IRP Update preferred portfolio. Under PacifiCorp's 2020 Protocol and the Washington Interjurisdictional Allocation Methodology, Washington's RPS position is improved by receiving a system share of renewable resources across PacifiCorp's system, and there are no anticipated shortfalls. 16 PACIFICORP—2023 IRP UPDATE CHAPTER 1—EXECUTIVE SUMMARY While not shown, PacifiCorp meets the Utah 2025 state target to supply 20% of adjusted retail sales with eligible renewable resources with existing owned and contracted resources and new renewable resources. Figure 1.17—Annual State RPS Compliance Forecast California RPS 3,000 y b Q y 2,000 a WU 1,000 — a 0 ti o'1o'��O - ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ®Unbundled Surrendered Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered —Year-end Unbundled Bank Balance Year--end Bundled Bank Balance t Shortfall Requirement 80,000 Oregon RPS a 60,000 ez e 40,000 77 W 20,000 P4 0 oti�` oti�' oti�0 oti^ otiCL. otia' ti o')° o�� o�� o��' o�°` o��' orb o�^ o'�� o'��' c4° o°~ o°�' ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ®Unbundled Surrendered Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance �Shortfall Requirement 10,000 Washington RPS 8,000 R c 6,000 4,000 y U wx 2,000 0 o o'��' o' 'o ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ®Unbundled Surrendered Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance �Shortfall Requirement 17 PACIFICORP-2023 IRP UPDATE CHAPTER 1-EXECUTIVE SUMMARY [This page is intentionally left blank] 18 PACIF'ICORP-2023 IRP UPDATE CHAPTER 2-INTRODUCTION CHAPTER 2 - INTRODUCTION This 2023 Integrated Resource Plan(IRP)Update describes resource planning activities following the filing of the Amended Final 2023 IRP on May 31, 2023, and continues the company's commitment to develop a long-term resource plan that considers cost, risk, uncertainty, and the long-run public interest. As the owner of the IRP Update and its action plan, all policy judgments and decisions concerning the IRP Update are made by PacifiCorp considering its obligations to its customers, regulators, and shareholders. PacifiCorp's 2023 IRP Update preferred portfolio reflects updates to load, existing resources, signed contracts, transmission options, and modeling improvements. The 2023 IRP Update also includes variant analysis for carbon capture and nuclear technologies, a range of future market and environmental policy environments, and updated analysis of state-specific planning, such as Oregon's Clean Energy Plan and Washington's Clean Energy Implementation Plan. PacifiCorp's selection of the 2023 IRP Update preferred portfolio is supported by comprehensive data analysis described in the chapters that follow. Chapter 3 describes the current planning environment, load updates, resource updates, state and federal policy updates, and transmission upgrades. Chapter 4 provides updated load-and-resource balance information. Chapter 5 describes changes to key inputs and assumptions relative to those used for the 2023 IRP. Chapter 6 presents the updated preferred portfolio, variant study results, and additional price-policy studies. This chapter also confirms that PacifiCorp's 2023 IRP Update preferred portfolio continues to include substantial new renewables facilitated by incremental transmission investments, along with demand-side management resources, significant storage resources, the NatriumTM Demonstration Project,and peaking resources.A status update on the 2023 IRP Action Plan is provided in Chapter 7. Finally, Appendix A provides additional load forecast details. 19 PACIF'ICORP-2023 IRP UPDATE CHAPTER 2-INTRODUCTION [This page is intentionally left blank] 20 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT CHAPTER 3 - THE PLANNING ENVIRONMENT The 2023 Integrated Resource Plan (IRP) Update reflects changes to the planning environment and assumption updates since the Amended Final 2023 IRP was filed on May 31,2023. PacifiCorp highlights these changes relative to the 2023 IRP conditions and assumptions impacting the 2024 to 2042 planning horizon. Material Changes to Key Planning Assumptions Key planning assumptions that have changed from the 2023 IRP filing include: • EPA's approval of Wyoming's OTR plan • Stay of EPA's disapproval of Utah's OTR plan Additional items are discussed in summary below,with details provided further within this chapter. Federal Policy Update V Federal Climate Change Legislation To date, no federal legislative climate change proposal has been passed by the U.S. Congress. Federal climate change legislation is not anticipated in the near term but remains possible in the mid-to long-term. New Source Performance Standards for Carbon Emissions from New and Existing Sources — Clean Air Act § 111(b) and (d) New Source Performance Standards are established under the Clean Air Act for certain industrial sources of emissions determined to endanger public health and welfare, including thermal electric generating units. After two previous iterations, in May 2023, the EPA proposed new rules addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion turbines (Clean Air Act Section 111(b) rule) and existing coal- and gas- or oil-fueled steam units and natural gas-fueled combustion turbines (Clean Air Act Section 111(d) rule). Requirements for new combustion turbines are subcategorized based on capacity factor, where low-load units would be required to meet an emission limit, intermediate-load units would be required to use a blend of low-emitting hydrogen and natural gas, and base-load units would be required to use carbon capture and sequestration(CCS) technology or a high-percentage blend of low-emitting hydrogen. The proposed requirements for existing units would take effect January 1, 2030, through state implementation plans.Requirements for existing gas and oil-fueled steam units are subcategorized based on capacity factor, where low-load units would be subject to routine maintenance to demonstrate no increase in emissions, intermediate-load units would be subject to an emission limit of 1,500 pounds of CO2 per megawatt-hour-gross, and base-load units would be subject to an 21 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT emission limit of 1,300 pounds of CO2 per megawatt-hour-gross. Control equipment requirements for existing combustion turbines only apply to large, high load turbines that are greater than 300 megawatts in capacity and operate at a 50% capacity factor that is greater than 50%. These units would be required to begin using CCS with a 90% capture rate by 2035 or use a blend of low- emitting hydrogen starting in 2032. Requirements for existing coal-fueled units are subcategorized based on retirement date. Units with earlier retirement dates would be subject to less stringent requirements while units that commit to later retirement dates would be subject to annual capacity factor limits or natural gas co-firing requirements. Units that will continue operating after December 31, 2039, would be required to use CCS with a 90% carbon capture rate. Clean Air Act Section 111 establishes a cooperative approach between the EPA and the states. The EPA establishes nationwide standards based on the best system of emissions reductions it identifies for a source category. States are then expected to develop plans to implement those standards at affected units. States may adopt the EPA's standards or develop state-specific standards that achieve the same air quality results. The EPA accepted comments on the proposal through August 8, 2023. Given the extensive comments submitted, it is uncertain how the final greenhouse gas rule will change. The scope and impacts of the final rule are uncertain until EPA takes final action on the proposals, the states submit any required state implementation plans (SIP), and any related litigation is exhausted. Clean Air Act Criteria Pollutants —National Ambient Air Quality Standards The Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) for six criteria pollutants that have the potential of harming human health or the environment. The six pollutants are carbon monoxide, lead, ground-level ozone, nitrogen dioxide (NOx), particulate matter (PM), and sulfur dioxide (S02). The standards are set at a level that protects public health with an adequate margin of safety. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area determined to contribute to the nonattainment are required to reduce emissions. If an area is determined to be out of compliance with an established NAAQS standard, the state is required to develop a state implementation plan to bring that area into compliance, and that plan must be approved by EPA. The plan is developed so that once implemented, the NAAQS for the pollutant of concern will be achieved. Ozone NAAQS In October 2015, EPA issued a final rule modifying the standards for ground-level ozone from 75 parts per billion(ppb)to 70 ppb. In addition to meeting the ozone NAAQS for areas within a state, states must also conduct an analysis of cross-state air pollution to determine whether emissions from the state have a significant impact on neighboring states attaining or maintaining the ozone NAAQS. On April 6, 2022, EPA proposed its"Good Neighbor Rule" for the 2015 ozone NAAQS (the "Ozone Transport Rule" or "OTR"), which contained a federal implementation plan (FIP) with proposed revisions to the existing Cross-State Air Pollution Rule (CSAPR) framework. The CSAPR FIP is intended to address cross-state ozone transport for the 2015 ozone NAAQS through uniform federal requirements and jurisdiction. EPA's proposed FIP focused on reducing NOx, which are precursors to ozone formation. The proposed rule covered 26 states, including four western states included in the cross-state program for the first time—Wyoming,Utah,Nevada and 22 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT California. Utah and Wyoming would be included in the program based on alleged significant impacts on ozone levels in Colorado. On May 24, 2022, the EPA proposed to disapprove the cross-state ozone transport state implementation plans (CSAPR SIPS) of numerous states to mitigate interstate ozone transport, including plans by Utah and Wyoming. Disapproval of the SIPs is a necessary prerequisite before EPA can finalize the expanded CSAPR FIP to federally regulate the western states for the first time. The proposed SIP disapprovals were made as part of a settlement agreement with environmental groups. For both Utah and Wyoming, the agency determined that, among other failings, the states should have used a 1% threshold instead of the one ppb threshold previously suggested by EPA that the states used to determine downwind impacts. Final disapproval of the SIPs would subject the states to the proposed CSAPR FIP for the 2015 ozone standard. On January 31, 2023, EPA delayed final action on Wyoming's CSAPR SIP until December of 2023 and indicated a supplemental SIP decision may be necessary. Until a final disapproval of Wyoming's SIP,Wyoming would not be subject to the CSAPR FIP. EPA finalized disapproval of Utah's CSAPR SIP along with 18 other states and issued a partial disapproval for two additional states. EPA finalized the CSAPR FIP March 15, 2023, with some updates and timeline changes from the proposed rule but included the stringent NOx emission reduction and control equipment requirements of the proposed rule. Numerous states and industries challenged certain provisions of the CSAPR SIP disapprovals and the final CSAPR FIP, including PacifiCorp. The state of Utah and PacifiCorp filed petitions and motions for stay of EPA's denial of the Utah state plan with EPA and the U.S. Tenth Circuit Court of Appeals (Tenth Circuit), and the motion for stay was granted by the Tenth Circuit on July 27, 2023. The stay will remain in place while the case is litigated, or until further order of the court. The court held that the agency may not enforce the CSAPR FIP while the stay remains in place. The EPA also issued several interim final rules stating that the federal rule will not take effect in states in which the SIP disapprovals have been deferred or stayed. The EPA finalized approval of Wyoming's interstate CSAPR SIP on December 19, 2023. Given the approval of the Wyoming SIP,PacifiCorp facilities in Wyoming are not subject to the CSAPR FIP. Given the court stay of the Utah SIP disapproval, PacifiCorp was not subject to the CSAPR FIP requirements during the 2023 ozone season. The Utah ozone case was transferred to the D.C. Circuit on February 16, 2024, for adjudication of the merits, leaving the stay in place. Requirements for the 2024 ozone season and beyond will depend on the outcome of litigation. In granting the stay,the court indicated that PacifiCorp and the other petitioners are likely to succeed on the merits. In addition to litigation over SIP disapprovals, numerous appeals of the final CSAPR FIP were filed in four different circuit courts, and at least four motions to stay the final rule have been filed in those courts. On September 25, 2023, the D.C. Circuit denied the motion to stay the CSAPR FIP filed by several state and industry parties. The denial means that states that do not have stays on their SIP disapprovals are subject to the CSAPR FIP requirements. The states of Ohio, Indiana and West Virginia filed a request for an emergency stay of the CSAPR FIP Rule with the U.S. Supreme Court on October 13, 2023. Several industry groups representing utilities as well as pipeline, paper, cement and other industries affected by the rule filed supportive requests for stay 23 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT on the same day. The U.S. Supreme Court heard oral arguments on the emergency stay requests February 21, 2024. Regional Haze EPA's regional haze rule, finalized in 1999, requires states to develop and implement plans to improve visibility, by 2064, in certain national park and wilderness areas. Many of these areas are in the western United States where PacifiCorp owns and operates several coal-fired generating units(Utah,Wyoming, Colorado and Montana as well as Arizona,where a PacifiCorp-owned coal unit ceased operating in 2020). The states are required to update their regional haze rule plans approximately every ten years, with second planning period revisions due in August of 2022. Utah Regional Haze Environmental advocacy groups filed a petition for review in the Tenth Circuit on January 19, 2021, objecting to the revised Utah regional haze SIP which included EPA's withdrawal for FIP requirements at Hunter Units 1 and 2 and Huntington Units 1 and 2 to install SCR. Briefing concluded on June 16,2022,with EPA,Utah,PacifiCorp and the Hunter co-owners supporting Utah and EPA's determinations to approve the SIP. The Tenth Circuit set the date for oral argument on March 21, 2023. The EPA defended the SIP, with PacifiCorp and the state of Utah in support. On August 14, 2023, the Tenth Circuit denied the petition to vacate Utah's first planning period regional haze plan. Utah Regional Haze Second Planning Period—The Utah Air Quality Division proposed, and the Utah Air Quality Board approved, final adoption of a SIP for the regional haze second planning period on July 6, 2022. The SIP differs from PacifiCorp's initial submission and requires updated mass-based NOx limits as well as a SO2 rate-based limit for the Hunter and Huntington plants. EPA notified Utah on August 22, 2022,that its SIP submittal was complete. EPA failed to make a final determination on the Utah SIP within 12 months as required under the Clean Air Act. Utah and PacifiCorp filed a deadline suit in the Utah Federal District Court in the fall of 2023,requesting the court to order EPA to make a final determination. Environmental advocacy groups also filed several deadline suits in the D.C. Federal District Court requesting EPA to make final determinations for numerous states, including Utah. PacifiCorp intervened in the D.C. Federal District Court and requested the case be transferred to the Utah Court. Those suits are pending in the two different courts. Wyoming Regional Haze Naughton—In its 2014 rule, EPA approved Wyoming's determination that BART for Units I and 2 was low-nitrous oxide burners (LNB) and over-fired air(OFA). EPA also indicated support for the conversion of the Naughton Unit 3 to natural gas in lieu of retrofitting the unit with SCR and stated that it would expedite consideration of the gas conversion once the state of Wyoming submitted the requisite SIP amendment. Wyoming submitted its regional haze SIP amendment regarding Naughton Unit 3 to EPA on November 28, 2017. On March 7, 2017, Wyoming issued PacifiCorp a permit for Unit 3's conversion to natural gas, which allowed operation of Unit 3 on coal through January 30, 2019. PacifiCorp ceased coal operation on Unit 3 on January 30, 2019, as required by the permit.EPA's final rule approval of Wyoming's SIP revision for Naughton Unit 3 gas conversion was published in the Federal Register on March 21, 2019, with an effective date of April 22, 2019. Naughton Unit 3 currently operates on natural gas. Environmental groups petitioned EPA's approval of LNB/OFA as BART for Units I and 2 in the Tenth Circuit. On 24 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT August 15, 2023, the court determined EPA properly approved Wyoming's Naughton determination and denied environmental groups'petition. Jim Bridger—On December 30, 2022,Wyoming submitted a state-approved revised regional haze SIP requiring natural gas conversion of Jim Bridger Units 1 and 2 to EPA for approval. The SIP conversion replaces the previous requirement for SCR at the units. Wyoming also issued an air permit for the natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. EPA is reviewing the Wyoming SIP submission for Jim Bridger and is expected to conduct a separate federal public comment process on the plan. On March 9, 2023, PacifiCorp submitted a notice of compliance and request for termination of the EPA order. The Wyoming consent decree remains in effect. The conversion process is underway at the units. Wyodak—PacifiCorp and the state of Wyoming petitioned EPA's FIP requiring SCR at Wyodak in the Tenth Circuit. PacifiCorp and other parties successfully requested a stay of EPA's final rule relating to EPAs FIP pending court resolution of the petition. PacifiCorp subsequently submitted a request for reconsideration to EPA and engaged in a settlement process with EPA and Wyoming. The EPA, state of Wyoming and PacifiCorp signed a Settlement Agreement for Wyodak on December 16, 2020. EPA published the Settlement Agreement in the Federal Register requesting public comment on January 4,2021. PacifiCorp submitted formal comments to the EPA on March 5, 2021, in support of the Wyodak Settlement Agreement. However, EPA did not proceed with final approval of the Settlement Agreement and re-engaged with Wyoming and PacifiCorp in mediation through the Tenth Circuit regarding paths for resolution. Litigation for the Wyodak case recommenced when the mediation process was not successful. PacifiCorp and Wyoming challenged EPA's denial of the Wyoming SIP and imposition of a FIP requiring Wyodak to install SCR equipment. On August 15, 2023, the Tenth Circuit found EPA's disapproval of Wyoming's SIP for Wyodak unlawful and remanded the SIP to EPA for further review in accordance with the requirements of the Clean Air Act Wyoming Regional Haze Second Planning Period— On March 31, 2020, PacifiCorp submitted a four-factor reasonable progress analysis to Wyoming,which analyzed PacifiCorp's Naughton,Jim Bridger, Dave Johnston, and Wyodak plants. The four-factor analysis was used by the state in its development of the SIP for the regional haze second planning period. Wyoming required emission limits and recognized planned unit retirements during the second planning period but did not require new controls to make reasonable progress. Wyoming submitted the state's regional haze SIP for the second planning period to the EPA before the August 15,2022,statutory deadline.EPA notified Wyoming that its submittal was complete in August of 2022. EPA failed to make a final determination on the Wyoming SIP within 12 months, as required under the Clean Air Act. Wyoming and PacifiCorp filed a deadline suit in the Wyoming Federal District Court in the fall of 2023, requesting the court to order EPA to make a final determination. Environmental advocacy groups also filed several deadline suits in the D.C. Federal District Court requesting EPA to make final determinations for numerous states, including Wyoming. PacifiCorp intervened in the D.C. Federal District Court and requested the case be transferred to the Wyoming Court. Those suits are pending in the two different courts. Colorado Regional Haze Colorado Second Planning Period—Colorado's regional haze SIP for the second planning period was adopted in phases in 2020 and 2021 by the Colorado Air Quality Control Commission. The SIP includes retirements of Craig Units 1 and 2 by 2025 and 2028,respectively, and Hayden Units 25 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT 1 and 2 by 2028 and 2027, respectively. Colorado submitted its second planning period regional haze SIP to EPA. However, EPA has not yet acted on the Colorado SIP. The Colorado SIP is part of the deadline suit filed by environmental advocacy groups in the federal D.C. District Court. Mercury and Hazardous Air Pollutants On April 5, 2023, the EPA released a proposal to revise several aspects of the Mercury and Air Toxics Standards rule following the agency's review of the 2020 Residual Risk and Technology Review. The EPA proposes two specific standard changes-one applicable to all covered units and one specific to the existing lignite subcategory. The EPA proposes a more stringent standard for emissions of filterable particulate matter, the surrogate standard for non-mercury metals for coal- fueled electric generating units. The EPA proposes to reduce the filterable particulate matter emission standard by two-thirds based on a demonstration that 9 1%of coal-based capacity,which has not been identified as retiring before the proposed compliance period, has an emission rate at or below the proposed limit. The EPA also proposes to require continuous emissions monitoring for filterable particulate matter to demonstrate compliance with the revised standard. Compliance would be due no later than three years after the effective date of a final rule. the EPA accepted comments on the proposal through June 23, 2023. PacifiCorp is not included in the lignite subcategory. PacifiCorp has determined that compliance can be achieved with existing controls. Until the EPA takes final action on the proposal,the full impacts of the rule cannot be determined. Coal Combustion Residuals EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule") in September 2020. A provision in Part A allows demonstrations to be submitted to the EPA allowing for operation of unlined Coal Combustion Residual(CCR)ponds beyond the April 11,2021,deadline for initiation of closure. PacifiCorp has submitted alternative closure demonstrations for the Naughton South Ash Pond and the Jim Bridger flue gas desulfurization (FGD) Pond 2. On October 12, 2023, Jim Bridger FGD Pond 2 ceased receiving waste, and the newly constructed FGD Pond 3 came into service. The EPA was notified on October 12, 2023, of PacifiCorp's withdrawal of its pending Part A alternative closure demonstration request. The Naughton South Ash Pond alternative closure demonstration remains under EPA review. Separately,on August 10,2017,the EPA issued proposed permitting guidance on how states'CCR permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. To date, of the states in which PacifiCorp operates, only Wyoming has submitted an application to the EPA for approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that the state of Utah will submit an application to EPA for approval of its CCR permit program.Wyoming finalized its rule in late 2020 and received legislative approval in 2022. Wyoming submitted a primacy package to the EPA on February 6, 2023, and is awaiting primacy approval. The state of Wyoming filed a deadline suit in Wyoming federal district court on October 8, 2023, asking the court to require EPA to act on its application in accordance with the requirements of Resource Conservation and Recovery Act, which requires EPA to make a determination within 180 days of submission. 26 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT On May 18,2023,the EPA proposed the legacy surface impoundments rule and accepted comment on the proposal through July 17, 2023. The proposal encompasses legacy surface impoundments, which are inactive surface impoundments at inactive facilities; and CCR management units,which include CCR surface impoundments and landfills that closed prior to October 19, 2015, inactive CCR landfills, and other areas where CCR has been or is managed directly on the land. CCR management units include all units meeting that definition at active CCR facilities,as well as those at inactive facilities with one or more legacy surface impoundment. EPA proposes to impose substantially the same regulatory obligations for both legacy surface impoundments and CCR management units as are applicable to currently regulated units,including groundwater monitoring and corrective action. All legacy surface impoundments and CCR management units would be required to initiate closure, including reclosure, within one year after the rule is finalized. The EPA includes lists of potential legacy surface impoundments and CCR management units in the rulemaking docket, and those lists include several PacifiCorp facilities. The EPA also specifically identifies PacifiCorp's Huntington Power Plant as a potential CCR management unit damage cases based on the EPA's review of compliance information. PacifiCorp submitted comments on the proposed rule under Berkshire Hathaway Energy, and corrected the record, noting that: (1) historical impoundments, which were closed according to state requirements and no longer contain CCR or liquids, should be removed from the list of CCR management units; (2) the EPA erroneously identified the Old Landfill at PacifiCorp's Huntington generating facility as a potential damage case; and (3) two impoundments at PacifiCorp's former Carbon generating facility are incorrectly included on the list of legacy impoundments because PacifiCorp never managed or disposed of CCR materials in wastewater ponds at the former Carbon generating facility. Until the proposals are finalized and fully litigated, PacifiCorp cannot determine whether additional action may be required. The EPA published a Notice of Data Availability (NODA) on November 14, 2023, seeking additional data in support of its legacy proposed rule. The NODA sought comments and information on two specific issues: (1) an updated list of legacy impoundments and CCR management units, based on information received from environmental groups during the comment period for the proposed rule; and (2) a risk assessment for legacy impoundments and CCR management units. The EPA included lists of potential legacy surface impoundments and CCR management units in the rulemaking docket, and those lists included several PacifiCorp facilities. Berkshire Hathaway Energy identified a number of obvious errors and inaccuracies in those lists and submitted its comments on December 11, 2023. The EPA has indicated it intends to finalize the legacy surface impoundment rule by May 2024. Inflation Reduction Act The Inflation Reduction Act of 2022 (IRA) is a comprehensive set of clean energy legislation, substantive details of which are still being fleshed out in the form or regulations and other guidance. The IRA contains newly structured technology-specific and technology-neutral tax credits for electric generating facilities and other clean energy incentives such as credits for Energy Storage Technology, Carbon Capture Use and Sequestration (CCUS), and hydrogen production. Furthermore, the IRA contains incentives that may affect demand such as tax credits for electric vehicles. Features of the IRA include: 27 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT • In August 2022, President Biden signed the IRA into law. The bill directs $437b in spending towards climate and healthcare investments with over $300b dedicated to deficit reduction. • The bill extends existing and creates new energy investment tax credit (ITC) and production tax credits (PTC) and institutes a new technology-neutral zero emission generation tax credit in 2025, supplanting the extended generation-specific credits. Eligibility expires upon meeting economy-wide emissions reduction targets. The bill also establishes a new 15% corporate minimum book tax and a new 1%excise tax on corporate stock buybacks. • Key Energy Provisions: o Extends wind, geothermal, and solar investment and PTCs at full value through December 31, 2024. Solar projects are newly eligible to apply the PTC to energy generated. Additional 10% bonus credits each are available for both locating projects in communities with retired coal operations and meeting certain domestic content requirements; achieving full credit value is also conditioned on meeting wage and apprenticeship requirements. o Establishes new tax credits for clean hydrogen, microgrids, electric vehicle purchases, existing nuclear generation, and the domestic manufacture of solar, wind,and battery components.Value and eligibility for existing carbon capture and sequestration credits are also enhanced and expanded. o Institutes a new technology-neutral, zero emission generation tax credit in 2025, supplanting the extended technology-specific credits. The technology-neutral credits phase down upon meeting economy-wide emissions reduction targets. In the 2023 IRP, resources in Utah South and all of Wyoming are assumed to receive the 10% Energy Community bonus, resulting in a 110%PTC (wind, solar, other energy resources) or 40% ITC (energy storage and peaking resources). Clean Energy Financing Program—Inflation Reduction Act Under the Title 17 Clean Energy Financing Program,the Loan Program Office(LPO)can finance projects in the United States that support clean energy deployment and energy infrastructure reinvestment to reduce greenhouse gas emissions and air pollution. Title 17 was created by the Energy Policy Act of 2005 and has since been amended, most recently by the Infrastructure Investment and Jobs Act in 2021 and the Inflation Reduction Act in 2022.The legislation expanded the scope of Title 17 to include certain state-supported projects and projects that reinvest in legacy energy infrastructure, and it leverages additional loan authority and funding available for projects involving innovative energy technologies. New Credits and Considerations for Customer Resources — Inflation Reduction Act Beginning January 1,2023,the Clean Vehicle Credit(CVC)provisions remove manufacturer sales caps, expand the scope of eligible vehicles to include both electric vehicles and fuel cell electric vehicles, and require a traction battery that has at least seven kilowatt-hours. An available tax credit under the CVC may be limited by the vehicle's manufacturer suggested retail price and the buyer's modified adjusted gross income. Once the Treasury Department issues the critical mineral and battery component guidance, vehicles that meet the critical mineral requirements are eligible for $3,750 tax credit, and vehicles that meet the battery component requirements are eligible for a 28 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT $3,750 tax credit. Vehicles meeting both the critical mineral and the battery component requirements are eligible for a total tax credit of$7,500. The IRA also extends federal ITC for small scale solar systems through 2034 and expands credit to include standalone energy storage systems as well. Since the passing of the IRA, the 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%of the cost of installed equipment for ten years and will then step down to 26% in 2033 and 22% in 2034. For projects beginning construction after 2019 that are placed in service before January 1, 2022, the ITC would be set at 26%.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 kilowatt-hours for residential customers and 5 kilowatt-hours for non-residential customers. The IRA funds multiple programs and tax incentives to improve the energy efficiency for residential and non-residential buildings and equipment. For non-residential buildings, the IRA provides tax deductions of $0.50-5.00 per square foot (/sf) of floor area to owners of new and improved energy-saving commercial buildings depending on the percentage of energy savings and whether the contractor pays prevailing wages. Even larger broad greenhouse gas emission reduction programs under the IRA could be used to reduce emissions from commercial buildings. The IRA also provides more than$25 billion for programs and tax incentives to improve the energy efficiency of existing and new homes. In addition to program funding, the IRA enhances the 25C Energy Efficient Home Improvement Credit. This long-standing federal tax credit applies to home energy improvements such as insulation,windows,heat pumps,and furnaces. Starting in 2023,the IRA increases the credit to 30%of cost,with an annual cap of$1,200 along with smaller limits for most items, but it also allows up to $2,000 for a heat pump (in 2022 the credit is under the old rules, with lower amounts and a lifetime cap of$500). Ftate Policy Update California Under the authority of the Global Warming Solutions Act, the California Air Resources Board (CARB) adopted a greenhouse gas cap-and-trade program in October 2011, with an effective date of January 1, 2012; compliance obligations were imposed on regulated entities beginning in 2013. The first auction of greenhouse gas allowances was held in California in November 2012, and the second auction in February 2013. PacifiCorp is required to sell, through the auction process, its directly allocated allowances and purchase the required amount of allowances necessary to meet its compliance obligations. In May 2014, CARB approved the first update to the Assembly Bill (AB) 32 Climate Change scoping plan, which defined California's climate change priorities for the next five years and set the groundwork for post-2020 climate goals. In April 2015, Governor Brown issued an executive order to establish a mid-term reduction target for California of 40% below 1990 levels by 2030. CARB was subsequently directed to update the AB 32 scoping plan to reflect the new interim 2030 target and previously established 2050 target. In July 2017, California Governor Jerry Brown signed AB 398, extending the state's California Cap and Trade program from January 1, 2021, through December 31, 2030. In 2022, CARB issued a revised scoping plan establishing emissions 29 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT reduction targets post-2030.In 2023,CARB held two workshops discussing cap and trade program changes the agency could consider. The agency is expected to open a formal rulemaking process in 2024. In 2002, California established a renewable portfolio standard (RPS) requiring investor-owned utilities to increase procurement from eligible renewable energy resources. California's RPS requirements have been accelerated and expanded a number of times since its inception. Most recently, in September 2018, Governor Jerry Brown signed into law the 100% Clean Energy Act of 2018, Senate Bill (SB) 100, which requires utilities to procure 60% of their electricity from renewables by 2030 and enabled all the state's agencies to work toward a longer-term planning target for 100% of California's electricity to come from renewable and zero-carbon resources by December 31, 2045. Oregon In 2007, Oregon enacted SB 838 establishing an RPS requirement in Oregon. Under SB 838, utilities are required to deliver 25% of their electricity from renewable resources by 2025. On March 8,2016,Governor Kate Brown signed SB 1547-B,the Clean Electricity and Coal Transition Plan, into law. SB 1547-B extends and expands the Oregon RPS requirement to 50%of electricity from renewable resources by 2040 and requires that coal-fueled resources are eliminated from Oregon's allocation of electricity by January 1, 2030. The increase in the RPS requirements under SB 1547-B is staged27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040. The bill changes the renewable energy certificate (REC) life to five years, while allowing RECs generated from the effective date of the bill passage until the end of 2022 from new long-term renewable projects to have unlimited life. The bill also includes provisions to create a community-solar program in Oregon and encourage greater reliance on electricity for transportation. On March 10, 2020, Oregon Governor Kate Brown issued Executive Order 20-04 (EO 20-04), which directs state agencies to take actions to reduce and regulate greenhouse gas emissions. EO 20-04 establishes emissions reduction goals for Oregon and directs certain state agencies to take specific actions to reduce emissions and mitigate the impacts of climate change. EO 20-04 also provides overarching direction to state agencies to exercise their statutory authority to help achieve Oregon's climate goals. In 2021, Oregon passed House Bill (HB) 2021, which directs utilities to reduce emissions levels below 2010-2012 baseline levels by 80%by 2030, 90%by 2035, and 100%by 2040. Utilities will also convene a Community Benefits and Impacts Advisory Group. PacifiCorp's 2023 IRP and 2023 IRP Update include modeling as appropriate to support HB 2021. HB 2021 also increases state requirements for small-scale renewable energy projects, to 10% of aggregate electrical capacity by 2030 and provides policy support for community-based renewable energy projects, though without specific requirements. HB 2021 is complementary to — but does not modify — Oregon's longstanding RPS requirements. Washington In November 2006, Washington voters approved Initiative 937 (I-937), the Washington Energy Independence Act, which imposes targets for energy conservation and the use of eligible 30 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT renewable resources on electric utilities. Under I-937, utilities must supply 15% of their energy from renewable resources by 2020. Utilities must also set and meet energy conservation targets starting in 2010. In 2008,the Washington Legislature approved the Climate Change Framework Engrossed Second Substitute House Bill (E2SHB) 2815, which establishes the following state greenhouse gas emissions reduction limits: (1) reduce emissions to 1990 levels by 2020; (2) reduce emissions to 25%below 1990 levels by 2035; and (3)by 2050, reduce emissions to 50% below 1990 levels or 70%below Washington's forecasted emissions in 2050. In July 2015, Governor Inslee released an executive order that directed the Washington Department of Ecology to develop new rules to reduce carbon emissions in the state. In December 2017, Washington's Superior Court concluded that the Department of Ecology did not have the authority to impose the Clean Air Rule without legislative approval. As a result, the Department of Ecology has suspended the rule's compliance requirements. In 2019, the Washington Legislature approved the Clean Energy Transformation Act (CETA) which requires utilities to eliminate coal-fired resources from Washington rates by December 31, 2025,be carbon neutral by January 1, 2030, and establishes a target of 100%of its electricity from renewable and non-emitting resources by 2045. Finally, in 2021, Washington passed the Climate Commitment Act, which establishes a cap-and- trade program to be implemented by no later than January 1, 2023, through the regulatory rulemaking process. The Climate Commitment Act does not modify any of PacifiCorp's obligations under CETA,and utility allowances within the cap-and-trade program are aligned with the CETA renewable energy requirements. The legislation allows—but does not require—linkage with cap-and-trade programs in jurisdictions outside of Washington state. Utilities are provided allowances at no cost to "mitigate the cost burden" of the program on customers, Utah In March 2008, Utah enacted the Energy Resource and Carbon Emission Reduction Initiative, which includes provisions to require utilities to pursue renewable energy to the extent that it is cost effective. It sets out a goal for utilities to use eligible renewable resources to account for 20% of their 2025 adjusted retail electric sales. PacifiCorp filed its most recent progress report with the Public Service Commission of Utah on December 29, 2023. On March 11,2020,the Utah Legislature passed HB 396,Electric Vehicle Charging Infrastructure Amendments,that enables PacifiCorp to create an Electrical Vehicle Infrastructure Program,with a maximum funding from customers of $50 million for all costs and expenses. The legislation allows PacifiCorp to own and operate electric vehicle charging stations and to provide investments in make-ready infrastructure to interested customers. The Public Service Commission of Utah approved a program on December 20, 2021. In March 2024, Utah passed S.B. 224, Energy Independence Amendments. Utah's S.B. 224 does not become effective until May 1,2024,and as such was not included in the planning environment for the 2023 Update. Portfolio modeling was well advanced by the 2024 legislative sessions and proceeded independently of those actions. 31 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT Wyoming In March 2019, Wyoming Senate File 0159 (SF 159) was passed into law. SF 159 limits the recovery costs for the retirement of coal fired electric generation facilities, provides a process for the sale of an otherwise retiring coal fired electric generation facility,exempts a person purchasing an otherwise retiring coal fired electric generation facility from regulation as a public utility; requires purchase of electricity generated from purchased retiring coal fired electric generation facility (as specified in final bill); and provides an effective date. Cost recovery associated with electric generation built to replace a retiring coal fired generation facility shall not be allowed by the Wyoming Public Service Commission unless the Commission has determined that the public utility made a good faith effort to sell the facility to another person prior to its retirement and that the public utility did not refuse a reasonable offer to purchase the facility or the Commission determines that, if a reasonable offer was received, the sale was not completed for a reason beyond the reasonable control of the public utility. Under SF 159 electric public utilities, other than cooperative electric utilities, shall be obligated to purchase electricity generated from a coal fired electric generation facility purchased under agreement approved by the Commission, provided the otherwise retiring coal fired electric generation facility offers to sell some or all of the electricity from the facility to an electric public utility, the electricity is sold at a price that is no greater than the purchasing electric utility's avoided cost, the electricity is sold under a power purchase agreement, and the Commission approves a 100% cost recovery in rates for the cost of the power purchase agreement and the agreement is 100% allocated to the public utility's Wyoming customers unless otherwise agreed to by the public utility. In March 2020, the Wyoming legislature passed House Bill 200 (HB 200), Reliable and Dispatchable Low-Carbon Energy Standards. HB 200 requires the Wyoming Public Service Commission to put in place a standard for each public utility specifying a percentage of electricity to be generated from coal-fired generation utilizing carbon capture technology by 2030. The requirement would only apply to generation allocated to Wyoming customers.HB 200 will require each public utility to demonstrate in its IRP the steps taken to achieve the electricity generation standard established by the Commission and will allow rate recovery of costs incurred by a public utility that utilizes coal-fired generation with carbon capture technology installed. The Commission finalized administrative rules to implement HB 200, which became effective in January 2022. The administrative rules require public utilities to file an initial application to establish intermediate standards for compliance by March 31,2022, and an application to establish the final plan for compliance by March 31, 2024. PacifiCorp filed the initial application with the Commission on March 31, 2022, its first update to the initial application on March 31, 2023, and PacifiCorp's final plan on March 29, 2024 as required. During the 2024 legislative session, the Wyoming Legislature passed SF 42, low-carbon reliable energy standards amendments that has been signed into law. PacifiCorp is currently analyzing the amendments to determine how it will affect the company's plan to implement low-carbon energy portfolio standards utilizing carbon capture technology. 32 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT During the 2022 legislative session,the Wyoming Legislature passed HB 131,nuclear power plant and storage amendments, that will help facilitate development of the Natrium nuclear demonstration project. The bill modifies existing laws to clarify the authority of the United States Nuclear Regulatory Commission. The bill also requires the operator of the facility, at least 30 days prior to construction, to submit a report identifying the number of jobs expected to be created by the project, the amount of local and state taxes estimated to be generated by the project, and the anticipated benefits and impacts that will accrue to the state and local community from the project. With respect to SF 159, the bill provides that the requirements of that law shall not apply to a public utility that replaces a coal-fired generation facility with an advanced nuclear reactor. Finally, the bill exempts tax payments, but provides that, beginning July 1, 2035, the exemption only applies if not less than 80% of the uranium is sourced in the United States. Several bills were recently signed into law from the 2024 Wyoming legislative session that PacifiCorp is evaluating that include SF 22, public service commission electricity reliability; SF 23, public service commission energy resource procurement; and SF 24, public service commission integrated resource plans. These new statutes will go into effect in 2024 and may be considered further in the next IRP. Greenhouse Gas Emission Performance Standards California, Oregon and Washington have greenhouse gas emission performance standards applicable to all electricity generated in the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined cycle natural gas generation facility. The standards for Oregon and California are currently set at 1,100 pounds CO2 per megawatt-hour, which is defined as a metric measure used to compare the emissions from various greenhouse gases based on their global warming potential. In September 2018, the Washington Department of Commerce issued a new rule lowering the emissions performance standard to 925 pounds CO2 per megawatt-hour. Energy Gateway Transmission Program Planning The Energy Gateway transmission project continues to play an important role in PacifiCorp's commitment to provide safe, reliable, reasonably priced electricity to meet the needs of our customers. Energy Gateway's design and extensive footprint provides needed system reliability improvements and supports the development of a diverse range of cost-effective resources required for meeting customers' energy needs. The IRP has incorporated Energy Gateway as part of a solution for delivering the least cost resource portfolio for multiple IRP planning cycles. PacifiCorp continues to develop methods, in parallel with current industry best practices and regional transmission planning requirements,to better quantify all the benefits of transmission that are essential to serve customers. For example, Energy Gateway is designed to relieve operating limitations, increase capacity, and improve operations and reliability in the existing electric transmission grid. Figure 3.1 shows a high-level geography of the Energy Gateway transmission project. 33 PACIFICORP—2023 IRP UPDATE CHAPTER 3—THE PLANNING ENVIRONMENT Figure 3.1 —Energy Gateway Map --ee"el W A S H I N G T O N MONTANA McNary O•Wallula Boardman • i H A 0A�'ft0N IDAHO Hemingway G A,r E WA Y WEST W Y O M I N G Midpoint Wnd,tar Borah D• $Arley Bain Cedar Hill Poplus 1 Aeolus M Yne o D<3 Q 3 a Terminal q'r C A L I F O R N I A <W Limber Oquirrh SOJ v u C OF PA S follrl� NEVADA Meb G P COLORADO PacifiCorp retail service area Sigurd New transmission Imes: G U T A H —500 kV minimum voltage Red Butte — 345 kV minimum voltage 230 kV minimum voltage • Existing substation O New substation A R I Z O N A NEW MEXICO This map is for general reference only and reflects current plans. It may not reflect the final routes,construction sequence or exact line configuration_ 34 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT Energy Gateway Transmission Project Updates Wallula to McNary (Segment A) This project was placed in service in January 2019. Gateway West (Segments D and E) Under the National Environmental Policy Act (NEPA), the U.S. Bureau of Land Management (BLM) has completed the environmental impact statement (EIS) for the Gateway West project. The BLM released its final EIS on April 26, 2013, followed by the record of decision (ROD) on November 14, 2013, providing a right-of-way grant for all of Segment D and for all but two segments of Segment E, followed with a record of decision on these two segments of the line on April 19, 2018: • Gateway West (Segment Dl): The project includes a new single-circuit 230 kilovolt line that will run approximately 76 miles between the existing Windstar substation in eastern Wyoming and the Aeolus substation near Medicine Bow, Wyoming, which includes a loop-in to the existing Shirley Basin 230 kilovolt substation. The Aeolus — Shirley Basin 230 kilovolt line section (16.7 miles of the 76 miles) was energized in November 2020. This project was included in the 2021 IRP for acknowledgement, and is currently under construction with an in-service date of 2024. • Gateway West (Segment D2): This single-circuit 500 kilovolt segment was placed in service November 2020. • Gateway West(Segment D3):A single-circuit 500 kilovolt line running approximately 200 miles between the new Anticline substation which was placed in-service in November 2020 with the energization of Gateway West Segment D.2 and the Populus substation in southeast Idaho. The line is scheduled in service 2031 at the earliest. Gateway West (Segment E) The Populus-to-Hemingway transmission project consists of two single-circuit 500 kilovolt lines that run approximately 500 miles between the Populus substation in eastern Idaho to the Hemingway substation in western Idaho. The estimated line in service for customers is 2036 at the earliest. Gateway South (Segment F) This 416-mile,high-voltage 500 kilovolt transmission line and associated infrastructure runs from the new Aeolus substation near Medicine Bow, Wyoming, to the Clover substation near Mona, Utah. This project was included in the 2021 IRP for acknowledgement, and is currently under construction with an in-service date of 2024. Boardman to Hemingway (Segment H) The Boardman to Hemingway project represents a significant improvement in the connection between PacifiCorp's east and west control areas and will help deliver more diverse resources to serve its customers in Oregon, Washington, and California. Idaho Power leads the permitting efforts on this project and PacifiCorp continues to support the permitting efforts under the conditions of the Boardman to Hemingway Transmission Project Joint Permit Funding Agreement. 35 PACIFICORP—2023 IRP UPDATE CHAPTER 3—THE PLANNING ENVIRONMENT The BLM's ROD was issued in November of 2017, followed by the U.S. Forest Service ROD issued on November 9,2018. The Oregon Energy Facilities Siting Council's final order on the Site Certificate is currently under process.In January 2020,the three parties signatory to the permitting agreement entered a non-binding term sheet that addresses the terms required to move the project to the next step of construction. In-Service Dates Table 3.1 summarizes the in-service dates for segments of the Energy Gateway transmission project. Table 3.1 -Ener Gateway Segment In-Service Dates Approximate Segment&Name Description Mileage Status and Scheduled In-Service (A) 230 kV,single circuit 30 mi • Status: completed Wallula-McNary • Placed in-service:January 2019 (B) 345 kV double circuit 135 mi • Status: completed Populus-Terminal • Placed in-service:November 2010 (C) 500 kV single circuit 100 mi • Status: completed Mona-Oquirrh 345 kV double circuit • Placed in-service:May 2013 • Status:rights-of-way acquisition underway Oquirrh-Terminal 345 kV double circuit 14 mi . Scheduled in-service:2026 New 230 kV single circuit (D1) Re-built 230 kV single 118 mi • Status: under construction Windstar-Aeolus circuit • Scheduled in-service:December 2024 (D2) • Status: completed Aeolus- 500 kV single circuit 140 mi Placed in-service:November 2020 Bridger/Anticline (D3) • Status:permitting underway Bridger/Anticline- 500 W single circuit 200 mi , Scheduled in-service:2031 earliest Populus (E) 500 kV single circuit 500 mi • Status:permitting underway Populus-Hemingway • Scheduled in service:2036 earliest (F) 500 kV single circuit 416 mi • Status: under construction Aeolus-Mona/Clover • Scheduled in-service:December 2024 (G) 345 kV single circuit 170 mi • Status: completed Sigurd-Red Butte • Placed in-service: May 2015 (H) • Status:pursuing joint-development and/or firm Boardman- 500 W single circuit 290 mi capacity opportunities with project sponsors Hemingway • Scheduled in-service:2026-2027 Regional Markets Increased renewable generation has contributed to the need for balancing sub-hourly demand and supply across a broader and more diverse market. For balancing purposes, PacifiCorp combined its resources with those of the CAISO through the creation of the EIM. The EIM became operational November 1, 2014, and currently has 22 utilities participating with Berkshire 36 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT Hathaway Energy Montana planning to enter in 2026.1 The multi-service area footprint brings greater resource and geographical diversity allowing for increased reliability and cost savings in balancing generation with demand using fifteen-minute interchange scheduling and five-minute dispatch.The CAISO's role is limited to the sub-hourly scheduling and dispatching of participating EIM generators.The CAISO does not have any other grid operator responsibilities for PaciftCorp's service areas. In December 2022, PacifiCorp announced its plan to join the CAISO's Extended Day-Ahead Market which is an extension of the EIM with planning practices that are done in the day-ahead timeframe. In December 2021, it was announced that the Western Resource Adequacy Program (WRAP), administered by the Western Power Pool (WPP), formerly known as the Northwest Power Pool, had entered the first stage of implementation. The WRAP consists of 22 participants, including PacifiCorp, who are working on the remaining program design questions and outstanding issues. The WPP has partnered with the Southwest Power Pool (SPP) to provide program operation services, including facilitating the collection of participants data to perform modeling for the upcoming seasons.2 This program includes two components, a forward showing (FS) planning program and an operational program to help participants that are experiencing extreme events meet customer demand. The program is intended to be a starting point and does not solve every issue facing the region but is an incremental step toward increased regional coordination. The WRAP will create a capacity resource adequacy(RA)program with a demonstration of deliverability. The region may also benefit from other forms of coordination, and while the structure and process associated with the program may serve as foundational building blocks to additional regional coordination, WPP and WRAP participants are only working to implement the capacity RA program at this time. The WRAP does not replace or supplant the resource planning processes used by states or provinces or the regulatory requirements of the Federal Energy Regulatory Commission , North America Electric Reliability Corporation or Western Electricity Coordinating Council. The program is designed to be supplemental and complementary to those processes and requirements. 1 https://www.westemeim.com/Pages/About/default.aspx 2 https://www.westeMpowerpool.org/news/wrap-announces-full-participation-of-phase-3a 37 PACIFICORP-2023 IRP UPDATE CHAPTER 3-THE PLANNING ENVIRONMENT [This page is intentionally left blank] 38 PACIFICORP—2023 IRP UPDATE CHAPTER 4—LOAD-AND-RESOURCE BALANCE CHAPTER 4 - LOAD-AND-RESOURCE BALANCE Introduction This chapter presents an update to PacifiCorp's load-and-resource balance. Updates to PacifiCorp's long-term load forecasts (both energy and coincident peak load) for each state and the system as a whole are summarized in Appendix A. Updates to PacifiCorp's load forecast, resources, and capacity position are presented and summarized in this chapter. System Coincident Peak Load Forecast The 2023 Integrated Resource Plan (IRP) Update relies on PacifiCorp's May 2023 load forecast. Figure 4.1 compares PacifiCorp's most recent load forecast to the forecast used for the 2023 IRP. Figure 4.2 compares PacifiCorp's most recent coincident system peak load forecast to the forecast used for the 2023 IRP. Considering that PacifiCorp analyzes incremental energy efficiency and direct-load control programs as demand-side resource options in its IRP, both figures exclude incremental energy efficiency savings and direct-load control capacity included in the updated resource portfolio.The compounded average annual growth rate(CAGR)for system load is 2.13% over the period 2024 through 2042. The CAGR for system coincident peak is 1.80% over the period 2024 through 2042. Over the 2024 to 2027 timeframe, lower projected demand from data centers results in a lower energy and peak load forecast, while data center expectations over the long-term results in a higher forecast from 2028 and on relative to projected loads used in the 2023 IRP. Figure 4.1 —Forecasted Annual Load GWh 100,000 90,000 80,000 70,000 G7 60,000 v 50,000 40,000 a 30,000 a 20,000 IF 10,000 l- 00 ON O M V 1 %O I- 00 ON O N O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N 2023 IRP f 2023 IRP Update 39 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Figure 4.2—Forecasted Annual Coincident Peak Load (MW) 16,000 ■ 14,000 ■ ■ - 12,000 ■ 10,000 8,000 6,000 4,000 2,000 N tn N N N N N M M M M M M M M M M N N N N N N N N N N N N N N N N N N N -0--2023 IRP f2023 IRP Update Resource Updates Table 4.1 summarizes recent long-term contracts that have been executed and modeled in PLEXOS since the 2023 IRP was prepared. Table 4.1 —New Power Purchase Agreements Resource Capacity COD Power Purchase Agreements Type (MW) State Year Customer Preference/Oregon Schedule 272 Hornshadow Solar Solar 100 Utah 2025 Hornshadow Solar II Solar 200 Utah 2025 Sub-total 300 Oregon Community Solar 7 Mile Solar Solar 1.0 Oregon 2024 Antelope Creek Solar Solar 2.3 Oregon 2024 Orchard Knob Solar Solar 2.3 Oregon 2024 Pine Grove Solar Solar 1.4 Oregon 2024 Round Lake Solar Solar 1.0 Oregon 2024 Sunset Ridge Solar Solar 2.3 Oregon 2024 Sub-total 10.1 Total 310.1 40 PACIFICORP—2023 IRP UPDATE CHAPTER 4—LOAD-AND-RESOURCE BALANCE pdated Capacity Load-and-Resource Balance Load-and-Resource Balance Components The capacity balance makes use of the following main component categories: resources, obligations, reserves, system position, and available front-office transactions (FOTs). The resource categories include resources by typethermal, peaker, hydroelectric, wind, solar, other renewable, storage, qualifying facilities, purchases, and sales. Categories in the obligation section include load, private generation, existing demand response (includes interruptible contracts), and new energy efficiency from the updated preferred portfolio. A description of each of the resource categories is provided below. Existing Resources Capacity contribution is a measure of the ability for a resource to reliably meet demand. There are many possible ways to attribute capacity to specific resources and the portfolio modeling in the 2023 IRP Update does not rely on a specific capacity contribution for each resource during portfolio development, in part because the reliability benefits of the next resource of a given type may not be the same as the reliability benefits from resources of that type already included in a portfolio. Assumptions used to calculate capacity contribution in the load and resource balance presented in this chapter are described below. Thermal and Peakers These categories include all thermal plants. The capacity balance counts these plants at their expected availability.' This includes the existing fleet of coal-fueled units, coal-fueled units that have converted to natural gas-fueled, and natural gas combustion turbines and combined cycle combustion turbines. Presently, these thermal resources account for approximately three quarters of the firm capacity available in the PacifiCorp system. Energy Storage Energy storage resources can be called upon as needed,but only for a limited duration before they must be recharged. PacifiCorp's recent capacity contribution analysis in the 2021 IRP (Appendix K: Capacity Contribution) indicated that a four-hour duration energy storage resource would have a contribution of around 80%. For the purpose of the load and resource balance in the 2023 IRP Update, capacity contribution is based on the effective load carrying capability (ELCC) and the relationship between duration and contribution was assumed to be linear, so that energy storage with a five-hour duration would have a contribution of around 100% (less forced outages), and energy storage with a two-hour duration would have a contribution of around 40%. PacifiCorp anticipates that the capacity contribution of energy storage will fall over time as it makes up a greater portion of supply. With four gigawatts of energy storage in the 2023 IRP Update preferred portfolio, the contribution from four-hour duration energy storage may fall from 80% to 50% or lower.However, for the 2023 IRP Update load and resource balance,the current contribution level applies throughout the horizon. 'After derating for forced outages and maintenance during critical hours. 41 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Variable Energy Resources: Wind and Solar The availability of wind and solar resources is dependent on weather conditions. With access to wind and solar technologies and a broad geographic area, PacifiCorp's system is better suited to utilizing the capacity provided by wind and solar than most other utilities. However,many periods still exist in which both wind and solar output is at low levels, both in individual hours, and over an extended length of time. While short-duration energy storage can help to address a few hours of shortfalls, weather events which result in low variable energy resource output over multiple days limit the capacity contribution of these resources,as well as the contribution of short-duration energy storage. The contribution of wind and solar presented in the 2023 IRP Update load and resource balance is based on the ELCC of these resource types and is further allocated to individual resources based on their expect output during capacity critical hours, when the remaining load after netting out variable energy resources is highest. As with energy storage, PacifiCorp anticipates that the capacity contribution of wind and solar will fall over time as it makes up a greater portion of supply.With many gigawatts of wind and solar additions in the 2023 IRP Update preferred portfolio, the total contribution from these resources is likely to rise slowly from levels achieved in the next few years as the incremental benefit of each additional increment of wind and solar in critical hours will be lower than the benefits of previous additions. However, for the 2023 IRP Update load and resource balance, the current contribution level applies throughout the horizon. Sales Contracts for the sale of firm capacity and energy are treated the same as all other resources,except that they have a negative capacity value. Obligation The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted retail load, private generation, new energy efficiency from the preferred portfolio, and existing demand response (including interruptible contracts). The following are descriptions of each of these components: Load and Private Generation The largest component of the obligation is retail load. In the 2023 IRP Update, the hourly retail load at a location is first reduced by hourly private generation at the same location. The system coincident peak is determined by summing the net loads for all locations (topology bubbles with loads) and then finding the highest hourly system load by year and season. Loads reported by east and west Balancing Authority Areas thus reflect loads at the time of PacifiCorp's coincident system summer and winter peaks. The energy balance counts the average load on a monthly basis. For simplicity, load net of private generation is referred to as load in the following sections. Energy Efficiency An adjustment is made to load to remove the projected embedded energy efficiency as a reduction to load. Due to timing issues with the vintage of the load forecast,there was a level of 2022 energy efficiency that was not incorporated in the forecast for the 2023 IRP. The 2022 energy efficiency forecast of 100 megawatts was accounted for by adding an existing energy efficiency resource in the load-and-resource balance; this adjustment was not required for the 2023 IRP Update because the 2022 projected embedded energy efficiency is included in the load forecast. The energy efficiency line includes the selected energy efficiency from the 2023 IRP Update preferred portfolio. 42 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Demand Response Existing demand response program capacity is categorized as a reduction to peak load. Demand response programs are those for which capacity savings occur because of active company control or advanced scheduling. Once customers agree to participate in these programs, the load reduction's timing and persistence is involuntary on their part within the agreed upon limits and parameters of the program. Program examples include residential and small commercial central air conditioner load control programs that are dispatchable, and irrigation load management and interruptible or curtailment programs (which may be dispatchable or scheduled firm, depending on the program design or event noticing requirements). Also included in the demand response category are existing interruptible contracts. PacifiCorp has had interruptible contracts for approximately 203 megawatts of peak load interruption capability for many years. These contracts are a key aspect of the retail service provided to the associated customers and absent from these contracts their demand would be different from that included in the load forecast. To maintain an alignment with the load forecast, these contracts are assumed to continue indefinitely under their current structure. Planning Reserve Margin Planning reserve margin (PRM) represents an incremental capacity requirement, applied as an increase to the obligation to ensure that there will be sufficient capacity available on the system to manage uncertain events(i.e.,weather,outages)and known requirements(i.e.,operating reserves). System Position The system position is the resource surplus or deficit after subtracting obligation plus required reserves from total resources. While similar, the position calculation is slightly different for the capacity and energy views of the load and resource balance. Thus,the position calculation for each of the views will be presented in their respective sections. Capacity Balance Determination and Results Methodology The capacity balance is developed by first determining the system coincident peak load for each of the first ten years of the planning horizon. Then the annual firm-capacity availability of the existing resources is determined for each of these annual system summer and winter peak periods, as applicable, and summed as follows: Existing Resources = Thermal + Peaker+ Hydro + Wind+ Solar + Other Renewables + Storage +Purchases +Qualifying Facilities—Firm Sales The peak load,private generation, existing demand response, and new energy efficiency from the preferred portfolio are netted together for each of the annual system summer and winter peaks, as applicable,to compute the annual peak obligation: Obligation =Load—Private Generation—Demand Response—New Energy Efficiency 43 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE The volume of reserves to be added to the obligation is then calculated. This is accomplished by the net system obligation calculated above multiplied by the 13% PRM adopted for the 2023 IRP Update. The formula for this calculation is: Planning Reserves = Obligation x PRM Finally, the annual system position is derived by adding the computed reserves to the obligation, and then subtracting this amount from existing resources, as shown in the following formula: System Position= (Existing Resources)—(Obligation+Planning Reserves) Capacity Balance Results Table 4.2 and Table 4.3 show the annual capacity balances and component line items for the summer peak and winter peak, respectively, using a target PRM of 13% to calculate the planning reserve amount. Balances for PacifiCorp's system and the east and west control areas are shown. While east and west control area balances are broken out separately, the PacifiCorp system is planned for and dispatched on a system basis. 44 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Table 4.2 -Summer Peak- System Capacity Load and Resource Balance without Resource Additions, 2023 IRP Update (2024-2033) (Megawatts)' E2024 2025 2026 028 2029 2030 2031 Thermal 6,805 6,852 6,769 6,769 6,546 6,234 6,234 6,234 6,234 6,234 Peaker 352 352 352 352 352 352 352 352 352 0 Hydroelectric 60 60 60 60 60 60 60 60 60 60 Wind 504 716 701 701 701 701 681 649 649 649 Solar 279 356 600 595 591 586 582 578 574 570 Other Renewable 41 41 41 41 41 41 41 41 41 41 Storage 1 1 496 496 496 496 496 496 496 496 Purchase 120 120 120 120 120 120 120 120 120 120 Qualifying Facilities 359 358 356 354 352 350 348 346 343 334 Sale 0 0 0 0 0 0 0 0 0 0 East Existing Resources 8,521 8,855 9,495 9,489 9,260 8,941 8,914 8,877 8,869 8,505 Load 7,679 7,947 7,877 8,137 8,556 8,727 8,906 9,181 8,972 9,105 Private Generation (102) (143) (111) (141) (174) (213) (256) (304) (151) (175) Frosting-Demand Response (494) (494) (494) (494) (494) (494) (494) (494) (494) (494) New Energy Efficiency (132) (217) (269) (343) (450) (534) (614) (743) (814) (932) East Total obligation 6,951 7,092 7,003 7,160 7,437 7,486 7,541 7,639 7,511 7,504 Planning Reserve Margin(13%) 904 922 910 931 967 973 980 993 976 975 East Obligation+Res erves 7,854 8,014 7,913 8,090 8,404 8,459 8,522 8,632 8,488 8,479 East Position 666 842 1,582 1,399 855 482 393 245 381 25 Available Market Purchases 825 825 825 825 500 500 500 500 500 500 Thennal 878 878 872 872 872 872 736 736 736 736 Peaker 0 0 0 0 0 0 0 0 0 0 Hydroelectric 691 695 692 700 700 699 699 699 699 699 Wind 56 56 56 56 56 56 56 56 56 56 Solar 54 54 54 53 53 53 53 52 52 52 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 0 Purchase 0 0 0 0 0 0 0 0 0 0 Qualifying Facilities 146 193 192 192 191 190 190 190 183 183 Sale (7) (7) (7) (7) (7) (7) (7) (7) (7) (7) West Rdsting Resources 1,818 1,868 1,860 1,866 1,866 1,864 1,727 1,726 1,720 1,719 Load 3,667 3,842 3,931 4,111 4,257 4,466 4,593 4,817 4,813 4,870 Private Generation (45) (69) (68) (89) (111) (137) (166) (201) (111) (130) Existing-Demand Response (21) (21) (21) (21) (21) (21) (21) (21) (21) (21) New Energy Efficiency (64) (123) (134) (142) (176) (205) (211) (263) (252) (269) West Total obligation 3,538 3,629 3,708 3,859 3,949 4,104 4,195 4,331 4,429 4,450 Planning Reserve Margin(13%) 460 472 482 502 513 533 545 563 576 578 West Obligation+Reserves 3,998 4,101 4,190 4,361 4,462 4,637 4,740 4,895 5,005 5,028 West Position (2,179) (2,232) (2,331) (2,495) (2,596) (2,773) (3,013) (3,169) (3,285) (3,309) Available Market Purchases 3,000 3,000 3,000 3,000 500 500 500 500 500 500 Total Resources 10,339 10,724 11,355 11,355 11,125 10,804 10,642 10,603 10,589 10,224 Obligation 10,489 10,721 10,711 11,019 11,386 11,589 11,736 11,970 11,940 11,954 Planning Reserves(13%) 1,364 1,394 1,392 1,432 1,480 1,507 1,526 1,556 1,552 1,554 Obligation+Reserves 11,852 12,114 12,103 12,451 12,867 13,096 13,262 13,527 13,492 13,508 System Position (1,513) (1,391) (748) (1,096) (1,741) (2,292) (2,621) (2,924) (2,904) (3,284) Available Market Purchases 3,825 3,825 3,825 3,825 1,000 1,000 1,000 1,000 1,000 1,000 Uncommitted FOTs to meet remaining Need 1,513 1,391 748 1,096 1,000 1,000 1,000 1,000 1,000 1,000 Net Surplus/(Deficit) 0 0 0 0 (741) (1,292) (1,621) (1,924) (1,9(A) (2,284) 2 The DSM line includes selected Class 2 DSM from the 2023 IRP Update resource portfolio. 45 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Table 4.2 (cont.)-Summer Peak- System Capacity Load and Resource Balance without Resource Additions, 2023 IRP Update (2034-2042) (Megawatts)3 203 2038 2 2 �2 Thermal 6,234 6,234 6,234 4,802 4,104 4,104 2,890 2,890 2,890 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 60 60 60 60 60 59 60 60 60 Wind 649 649 649 649 649 649 649 547 547 Solar 567 563 559 525 521 518 515 511 508 Other Renewable 41 41 41 41 13 13 13 13 13 Storage 495 495 495 495 495 495 495 495 495 Purchase 120 120 120 120 120 120 120 120 120 Qualifying Facilities 330 328 323 272 270 263 262 261 259 Sale 0 0 0 0 0 0 0 0 0 Fast Ddsting Resources 8,496 8,490 8,481 6,965 6,233 6,221 5,003 4,897 4,892 Load 9,223 9,361 9,564 9,726 9,867 9,980 10,112 10,248 10,428 Private Generation (197) (220) (242) (265) (287) (309) (330) (352) (374) EAsting-Demand Response (494) (494) (494) (494) (494) (494) (494) (494) (494) New Energy Efficiency (1,037) (1,124) (1,209) (1,317) (1,400) (1,498) (1,589) (1,653) (1,752) Fast Total obligation 7,494 7,523 7,618 7,649 7,686 7,679 7,699 7,749 7,808 Planning Reserve Margin(13%) 974 978 990 994 999 998 1,001 1,007 1,015 Fast Obligation+Reserves 8,468 8,501 8,608 8,644 8,685 8,677 8,699 8,756 8,823 Fast Position 27 (11) (127) (1,679) (2,452) (2,456) (3,696) (3,860) (3,931) Available Market Purchases 500 500 500 500 500 500 500 500 500 Thermal 736 736 736 500 500 500 500 500 500 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 699 699 699 699 699 699 699 699 707 Wind 56 56 56 56 56 56 56 56 56 Solar 52 51 51 51 51 50 50 50 48 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 Purchase 0 0 0 0 0 0 0 0 0 Qualifying Facilities 182 182 181 162 160 159 159 158 159 Sale (7) (7) (7) (7) (7) (7) (7) (7) (7) West Existing Resources 1,718 1,718 1,717 1,461 1,459 1,457 1,457 1,456 1,464 Load 4,929 4,995 5,068 5,176 5,246 5,318 5,384 5,461 5,647 Private Generation (148) (163) (178) (193) (208) (222) (236) (250) (264) Faosting-Demand Response (21) (21) (21) (21) (21) (21) (21) (21) (21) New Energy Efficiency (299) (322) (314) (357) (355) (366) (396) (391) (429) West Total obligation 4,461 4,489 4,555 4,605 4,662 4,709 4,731 4,799 4,933 Planning Reserve Margin(13%) 580 584 592 599 606 612 615 624 641 West Obligation+Reserves 281 262 278 242 251 247 219 233 213 West Position 1,438 1,456 1,439 1,219 1,208 1,211 1,238 1,223 1,251 Available Market Purchases 500 500 500 500 500 500 500 500 500 Total Resources 10,214 10,208 10,198 8,426 7,691 7,679 6,460 6,353 6,355 Obligation 11,956 12,012 12,173 12,254 12,347 12,389 12,430 12,547 12,741 Planning Reserves(13%) 1,554 1,562 1,583 1,593 1,605 1,611 1,616 1,631 1,656 Obligation+Reserves 13,510 13,574 13,756 13,848 13,952 13,999 14,045 14,179 14,398 System Position (3,296) (3,366) (3,558) (5,422) (6,261) (6,320) (7,586) (7,826) (8,042) Available Market Purchases 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 Uncommitted FOTs to meet remaining Need 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 Net Surplus/(Deficit) (2,296) (2,366) (2,558) (4,422) (5,261) (5,320) (6,586) (6,826) (7,042) 3 The DSM line includes selected Class 2 DSM from the 2023 IRP Update resource portfolio. 46 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Table 4.3 -Winter Peak-System Capacity Load and Resource Balance without Resource Additions, 2023 IRP Update (2024-2033) (Megawatts) 4 2024 2025 2026 028 2029 2030 2031 Themnl 6,828 6,875 6,795 6,795 6,578 6,264 6,264 6,264 6,264 6,264 Peaker 323 323 323 323 323 323 323 323 323 0 Hydroelectric 36 36 36 36 36 36 36 36 36 36 Wind 442 602 594 594 594 594 579 552 552 552 Solar 197 288 408 405 402 399 396 393 391 388 Other Renewable 34 34 34 34 34 34 34 34 34 34 Storage 1 1 468 468 468 468 468 468 468 468 Purchase 172 172 172 172 172 172 172 172 172 172 Qualifying Facilities 284 283 281 279 278 276 275 273 271 263 Sale 0 0 0 0 0 0 0 0 0 0 East D isting Resources 8,317 8,613 9,111 9,107 8,884 8,566 8,547 8,515 8,510 8,177 Load 5,724 6,097 6,171 6,444 6,754 6,700 6,872 7,145 7,214 7,387 Private Generation (2) 0 0 0 0 (8) (10) 0 0 0 Ddsting-Demand Response (463) (463) (463) (463) (463) (463) (463) (463) (463) (463) New Energy Efficiency (102) (111) (172) (232) (299) (470) (569) (529) (615) (693) Fast Total obligation 5,158 5,523 5,536 5,749 5,993 5,760 5,830 6,153 6,137 6,232 Planning Reserve Margin(13%) 671 718 720 747 779 749 758 800 798 810 Fast Obligation+Res erves 5,829 6,241 6,256 6,496 6,772 6,508 6,588 6,953 6,934 7,042 Fast Position 2,488 2,372 2,855 2,610 2,112 2,058 1,958 1,563 1,575 1,135 Available Market Purchases 825 825 825 825 800 800 800 800 800 800 Thenml 878 878 874 874 874 874 736 736 736 736 Peaker 0 0 0 0 0 0 0 0 0 0 Hydroelectric 538 544 542 555 556 555 555 553 554 554 Wind 74 74 74 74 74 74 74 74 74 74 Solar 44 43 43 43 42 42 42 41 40 40 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 0 Purchase 1 1 1 1 1 1 1 1 1 1 Qualifying Facilities 116 127 127 127 127 126 126 126 120 120 Sale (12) (12) (12) (12) (12) (12) (12) (12) (12) (12) West Fxisting Resources 1,639 1,657 1,650 1,662 19662 1,660 1,522 1,520 19514 1,513 Load 3,711 3,577 3,676 3,858 4,024 4,476 4,539 4,419 4,475 4,524 Private Generation (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) Existing-Demand Response (11) (11) (11) (1 1) (11) (11) (1 1) (11) (11) (11) New Energy Efficiency (89) (96) (126) (167) (221) (324) (378) (341) (368) (415) West Total obligation 3,611 3,470 3,539 3,681 3,792 4,142 4,151 4,068 4,095 4,098 Planning Reserve Margin(13%) 469 451 460 479 493 538 540 529 532 533 West Obligation+Reserves 4,081 3,921 3,999 4,160 4,285 4,680 4,691 4,596 4,628 4,630 West Position (2,441) (2,265) (2,350) (2,497) (2,623) (3,020) (3,169) (3,076) (3,114) (3,117) Available Market Purchases 3,000 3,000 3,000 3,000 700 700 700 700 700 700 Total Resources 9,956 10,270 10,761 10,769 10,547 10,226 10,069 10,035 10,024 9,690 Obligation 8,769 8,993 9,076 9,430 9,785 9,901 9,981 10,220 10,232 10,329 Planning Reserves(13%) 1,140 1,169 1,180 1,226 1,272 1,287 1,298 1,329 1,330 1,343 Obligation+Reserves 9,909 10,162 10,255 10,656 11,057 11,189 11,279 11,549 11,562 11,672 System Position 47 108 505 113 (511) (962) (1,210) (1,514) (1,538) (1,982) 4 The DSM line includes selected Class 2 DSM from the 2023 IRP Update resource portfolio. 47 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Table 4.3 (cont.)-Winter Peak-System Capacity Load and Resource Balance without Resource Additions, 2023 IRP Update (2034-2042) (Megawatts)5 Eir20036 Themral 6,264 6,264 6,264 4,815 4,117 4,117 2,854 2,854 2,854 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 36 36 36 36 36 36 36 36 36 Wind 552 552 552 552 552 552 552 470 470 Solar 385 383 380 357 354 352 350 347 345 Other Renewable 34 34 34 34 8 8 8 8 8 Storage 467 467 467 467 467 467 467 467 467 Purchase 172 172 172 172 172 172 172 172 172 Qualifying Facilities 259 257 254 213 212 207 206 205 204 Sale 0 0 0 0 0 0 0 0 0 East Existing Resources 8,169 8,165 8,159 6,645 5,918 5,911 4,645 4,560 4,556 Load 7,329 7,518 7,607 7,745 7,870 8,007 8,186 8,326 8,472 Private Generation (19) (21) (23) (25) (28) (30) (32) (0) (36) Existing-Demand Response (463) (463) (463) (463) (463) (463) (463) (463) (463) New Energy Efficiency (1,024) (1,147) (1,263) (1,464) (1,573) (1,658) (1,743) (1,868) (2,048) Fast Total obligation 5,823 5,887 5,858 5,793 5,807 5,857 5,949 5,995 5,925 Planning Reserve Margin(13%) 757 765 761 753 755 761 773 779 770 Fast Obligation+Reserves 6,580 6,652 6,619 6,546 6,562 6,618 6,722 6,774 6,695 East Position 1,590 1,513 1,540 99 (644) (707) (2,077) (2,215) (2,138) Available Market Purchases 800 800 800 800 800 800 800 800 800 Thermal 736 736 736 499 499 499 499 499 499 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 554 554 554 554 554 554 554 554 565 Wind 74 74 74 74 74 74 74 74 74 Solar 39 39 39 39 39 38 38 38 38 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 Purchase 1 1 1 1 1 1 1 1 1 Qualifying Facilities 120 120 119 105 104 103 103 103 103 Sale (12) (12) (12) (12) (12) (12) (12) (12) (12) West Existing Resources 1,513 1,513 1,512 1,261 1,260 1,259 1,258 1,258 1,269 Load 4,770 4,917 4,986 4,938 5,058 5,133 5,273 5,285 5,394 Private Generation (0) (0) (0) (0) (0) (0) (0) (0) (0) Existing-Demand Response (11) (11) (11) (11) (11) (11) (11) (11) (11) New Energy Efficiency (588) (634) (678) (720) (755) (801) (844) (838) (943) West Total obligation 4,171 4,272 4,297 4,207 4,293 4,321 4,418 4,436 4,440 Planning Reserve Margin(13%) 542 555 559 547 558 562 574 577 577 West Obligation+Reserves (46) (79) (120) (173) (196) (239) (269) (261) (365) West Position 1,559 1,591 1,632 1,433 1,456 1,498 1,528 1,519 1,634 Available Market Purchases 700 700 700 700 700 700 700 700 700 Total Resources 9,683 9,678 9,671 7,906 7,178 7,169 5,903 5,818 5,825 Obligation 9,994 10,159 10,155 10,001 10,100 10,178 10,367 10,431 10,365 Planning Reserves(13%) 1,299 1,321 1,320 1,300 1,313 1,323 1,348 1,356 1,347 Obligation+Reserves 11,293 11,480 11,475 11,301 11,413 11,501 11,715 11,787 11,712 System Position (1,611) (1,802) (1,803) (3,395) (4,235) (4,332) (5,811) (5,970) (5,887) Available Market Purchases 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Uncommitted FOTs to meet remaining Need 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Net Surplus/(Deficit) (111) (302) (303) (1,895) (2,735) (2,832) (4,311) (4,470) (4,387) 5 The DSM line includes selected Class 2 DSM from the 2023 IRP Update resource portfolio. 48 PACIFICORP-2023 IRP UPDATE CHAPTER 4-LOAD-AND-RESOURCE BALANCE Figure 4.3 and Figure 4.4 are graphic representations of the above tables for the 2023 IRP Update annual capacity position for the summer system, winter system respectively. Also shown in the system capacity position graphs are the capacity contribution from uncommitted FOTs, which as discussed above, are provided for informational purposes. Figure 4.3—Summer System Capacity Position Trend 14,000 13%Reserves 12,000 10,000 8,000 3 on d 6,000 East Existing Resources 4,000 2,000 West Existing Resources ML 0 West Existing Resources East Existing Resources Uncommitted FOTs to meet remaining Need tObligation+Reserves f Obligation 49 PACIFICORP—2023 IRP UPDATE CHAPTER 4—LOAD-AND-RESOURCE BALANCE Figure 4.4 —Winter System Capacity Position Trend 14,000 12,000 13%Rese 10,000 ' ' 8,000 No 6,000 East Existing Resources 4,000 2,000 0 'L 'ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ^. ^� West Existing Resources East Existing Resources Uncommitted FOTs to meet remaining Need t Obligation+Reserves f Obligation 50 PACIFICORP—2023 IRP UPDATE CHAPTER 5—MODELING AND ASSUMPTIONS CHAPTER 5 - MODELING AND ASSUMPTIONS General Assumptions The study period for the 2023 IRP Update is 2024-2042, with a focus on the 2024-2028 planning horizon.' While many assumptions are unchanged from the 2023 IRP, PacifiCorp has materially updated certain assumptions in the 2023 IRP Update as discussed below. Inflation Rates The 2023 IRP Update model simulations and cost data reflect PacifiCorp's corporate inflation rate schedule unless otherwise noted. A single annual escalation rate value of 2.28% is assumed, consistent with the 2023 IRP. The annual escalation rate reflects the average of annual inflation rate projections for the 20-year study period, using PacifiCorp's September 2023 inflation curve. PacifiCorp's inflation curve is a straight average of forecasts for Gross Domestic Product inflator and Consumer Price Index. Discount Factor The discount rate used in present-value calculations is based on PacifiCorp's after-tax weighted average cost of capital(WACC). The value used for the 2023 IRP Update is 6.69%. The use of the after-tax WACC complies with the Public Utility Commission of Oregon's IRP guideline la, which requires that the after-tax WACC be used to discount all future resource costs.2 Present- value revenue requirement values reported in the 2023 IRP Update are reported in 2023 dollars. Front Office Transactions Although PacifiCorp's understanding of likely market purchase availability is evolving with the emergence of Western Region Adequacy Program (WRAP) relationships with other utilities, as well as the expansion of regional energy markets, no added information has emerged to justify changing assumptions from the existing markets modeled in the 2023 IRP. However, for the 2023 IRP Update, PacifiCorp is now modeling additional potential for market purchases in Wyoming to reflect its increased transmission system connectivity to other utilities. Table 5.1 reports the available FOT modeling assumptions; identifying the market hub, product type, annual capacity limit, and availability associated with the product. PacifiCorp develops its front office transaction (FOT) planning limits based upon its active participation in wholesale power markets, its view of physical delivery constraints, market liquidity and depth, and with consideration of regional resource supply. 'As year 2023 has passed into history,it is not generally reported in this 2023 IRP Update;however,some workpapers will still contain 2023 information as an artifact of developing data for the remainder of the 20-year modeling horizon. 2 Public Utility Commission of Oregon,Order No.07-002,Docket No.UM 1056,January 8,2007. 51 PACIFICORP—2023 IRP UPDATE CHAPTER 5—MODELING AND ASSUMPTIONS Table 5.1 -Maximum Available Front Office Transaction Quantity by Market Hub Availability Limit (\IN`) Chance from 2023 2023 IRP ti Vate IRP Market Hub Pd Short-term Long-term(2028-2042) Summer Winter (2023-202,) Summer Winter '-NIid-Columbia (ltid-C:) " 500 350 California Oregon Border(COB) --- 0 -)50 evada Oregon Border(.10B) - 0 100 4 Corners (4C) - 0 1 Mona _ 0 - Wyoming i 500 Total 3S26 lnnn 1M;00 Stochastic Parameters Stochastic parameters assumed in the 2023 IRP Update are consistent with those applied in the 2023 IRP. PacifiCorp provided a detailed description of its stochastic parameters and their development in Volume II, Appendix H of the 2023 IRP—Amended Final, filed May 31, 2023. Flexible Reserve Study PacifiCorp applied its Flexible Reserve Study methodology from the 2023 IRP in its 2023 IRP Update. PacifiCorp provided a detailed description of its Flexible Reserve Study in Volume II, Appendix F of the 2023 IRP. Portfolio modeling for the 2023 IRP Update was prepared using five market price forecasts. This includes the official forward price curve (OFPQ and four scenarios. Figure 5.1 summarizes the five wholesale electricity price forecasts and three natural gas price forecasts used in the base and variant studies for the 2023 IRP Update. Power prices are higher in the near term. All five power price scenarios trend higher beginning in different years in the forecast but escalate at different increasing rates.Natural gas prices start low then grow at different escalation rates depending on the scenario. 52 PACIFICORP—2023 IRP UPDATE CHAPTER 5—MODELING AND ASSUMPTIONS Figure 5.1 —Nominal Wholesale Electricity and Natural Gas Price Scenarios Wholesale Electricity Prices Natural Gas Prices Average of Palo Verde and Mid-C(Flat) Henry Hub $120 $14 $110 $13 $100 $12 $90 $11 $80 $10 L $70 $9 $8 $60 cq � $7 es $50 — '� �• �'� $6 $40 — ——--- -- ds $5 $30 $4 —— $20 $3 ——————— $10 $2 $0 $1 $O M 7 h N M V Vt D l� W O O N N N N N N N N M M M M M M M M M M 7 7 V N N N N N N N N N N M M M M M M M M M M O O O O O O O O O O O O O O O O O O O O O O O O IDO O O O ID ID O O O O O O O N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N •• ••Mgas_MCO2(Sep 2023) ———Lga"CO2(Sep 2023) Mga"CO2(Sep 2023) —�Hgas_HCO2(Sep 2022) —Medium(Sep 2023)———Low(Sep 2023)—�High(Sep 2022) Mgas_SCO2(Sep 2023) PacifiCorp's September 30, 2023, OFPC is used to represent medium natural gas price assumptions with no CO2 prices for the"MN"price-policy scenario. OFPCs are produced for both natural gas and power prices by point of delivery. For both gas and electricity, starting with the prompt month, the front 36 months of the OFPC reflect market forwards at the close of a given trading day.3 As such, these 36 months are market forwards as of September 2023. The blending period (months 37 through 48) is calculated by averaging the month-on-month market forward from the prior year with the month-on-month fundamentals-based price from the subsequent year. The fundamentals portion of the natural gas OFPC reflects an expert third-party multi-client"off- the-shelf' price forecast. The fundamental portion of the electricity OFPC reflects prices as forecast by AURORAxmp4 (Aurora), a WECC-wide market model. Aurora uses the expert third- party natural gas price forecast to produce a consistent electricity price forecast for market hubs in which PacifiCorp participates. PacifiCorp updates its natural gas price forecasts in this quarter for the OFPC and, as a corollary,the electricity OFPC is also updated. [Carbon—Wioxide Emission Polic Consistent with the 2023 IRP, PacifiCorp used four different CO2 price scenarios in the 2023 IRP Update—zero, medium, high, and a price forecast that aligns with the social cost of greenhouse gases. The modeled CO2 price scenarios are not intended to explicitly account for a future monetary tax on CO2 emissions. Instead, these costs capture the trend of federal policies that incentivize reduced emissions through benefits (i.e., production tax credits) or impose restrictions or costs or other market dynamics that drive the need for zero-emission resources and the relative ability for such resources to be developed and procured. Such scenarios reflect the reality of the current federal regulatory landscape,as illustrated in Chapter 3,and ensure that the PacifiCorp's preferred portfolio is least-cost for its customers over time. This treatment further allows the IRP analysis to examine the costs, risks and robustness of portfolios when viewed under a range of futures. Figure 5.2 illustrates the CO2 proxy price curves used in the 2023 IRP Update. 3 The September 2023 OFPC prompt month is November 2023;October 2023 would be traded as"balance of month"when the OFPC is released. 4 AURORAxmp is a proprietary production cost simulation model,developed by Energy Exemplar,LLC. 53 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Fi ure 5.2—Medium,High and Social Cost of Greenhouse Gas CO2 Prices 180 160 00 i 140 0*0 d i a120 � awdw � [� dop dop / 100 � � � dopdw amp o � � U 80 U 60 40 20 0 o`)' Z"� o"^ ZV Z� oho o"~ ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti Medium — •High — — SC-GHG The medium and high scenario are derived from a variety of sources, including government and electric utility forecasts, and expert third-parry multi-client "off-the-shelf" subscription services. PacifiCorp grouped these forecasts around the median low and median high forecast. The highest grouping,consisting of six different forecasts,was averaged to form the high price case.The lowest grouping, also consisting of six different forecasts, was averaged to form the medium case. These scenarios apply a CO2 proxy price beginning 2025. PacifiCorp also incorporated the social cost of greenhouse gas in compliance with Washington Revised Code of Washington 19.280.030. The 2023 IRP Update includes an adjusted cost of greenhouse gas emission reflecting inflation, defined by the Washington Utilities and Transportation Commission.5 The social cost of greenhouse gas emissions (SC-GHG) is assumed to apply in all years of the study horizon. The SC-GHG is applied such that the price for the SC-GHG is reflected in market prices and dispatch costs for the purposes of developing each portfolio (i.e., incorporated into capacity expansion optimization modeling).Aligned with Washington Staff s suggested treatment, in SC-GHG studies, system operations also include the SC-GHG once the portfolios are determined, presenting the risk that this operational assumption will not be aligned with actual market forces (i.e., market transactions at the Mid-Columbia market do not reflect the social cost of greenhouse gases and PacifiCorp does not directly incur emission costs at the price assumed for the social cost of greenhouse gases). In all scenarios, emissions from the Chehalis natural gas plant incur the forecasted cost of allowances under the cap-and-invest program established in the Climate Commitment Act passed 5 Washington Utilities and Transportation Commission,Order 04,Docket No.U-190730,July 27,2023 54 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS by the Washington Legislature in 2021. This is in addition to the assumed federal CO2 policy represented in the zero, medium, high, and social cost of greenhouse gas scenarios described above. The modeled allowance cost reflects analysis conducted by Vivid Economics for the Washington Department of Ecology and starts at $58 per ton in 2023. Supply-Side Resour Proxy resource costs and operating characteristics are generally unchanged from assumptions used in the 2023 IRP. However, in response to stakeholder comments, PacifiCorp incorporated a modified cost-escalation rate for geothermal resources based on the National Renewable Energy Laboratory's 2023 Annual Technology Baseline. Whereas geothermal costs were previously modeled as escalating at inflation,the updated escalation rate results in lower costs throughout the study horizon. As a result, geothermal joins wind, solar, and lithium-ion battery storage in using resource cost escalation rates that are lower than the standard estimate based on inflation, though near-term wind and solar costs are aligned with recent offers with bidders in PacifiCorp's 2020 All-Source Request for Proposals, from summer 2022. In conjunction with tax credits,this results in variation in costs over time, as presented in Figure 5.3. Several modifications were made to clarify the assumptions within the supply-side resource table. Hydrogen resources were split out to report whether they use hydrogen on-site storage or pipeline supply. Inflation Reduction Act (IRA) credits were included in the 2023 IRP and have now been identified for each resource type within the supply-side table below for the 2023 IRP Update. Within the supply-side table detail, all costs remain in real levelized 2022 dollars. As in the 2023 IRP,near term resource selections in the 2023 IRP update are limited through 2028 to technology types and locations of pending requests that have received interconnection study results. Starting in 2029,proxy resources can be selected in any size and combination at any location, with hourly generation limited by available transmission. As an example, if a selected transmission upgrade allows for 400 additional megawatts of resources, the model is allowed to select 600 megawatts of wind resources, 300 megawatts of battery resources, 300 megawatts of solar resources, and 200 megawatts of gas peaking resources. This would cause the location to have 1400 megawatts of nameplate resources, of which only 400 megawatts could be generating into the system at any point in time. Any excess generation could flow into storage resources or would otherwise be curtailed. 55 PACIFICORP—2023 IRP UPDATE CHAPTER 5—MODELING AND ASSUMPTIONS Figure 5.3-Inflation Reduction Act and Future Technology Costs $250 3 $200 a �_ $175 o $90 $150 M 0 U U $75 ........... ^ $60 U $30 o $15 Pricing based End of Full on 2020AS RFP NREL ATB I IRA Eligibility $o M V) %0 r- 00 ON O .--i N M � it) �0 r` 00 as O •-- N O O O O O O O O con con con con O O O O (V N N " N N N N (V N N N N N N N N N N N WY Wind wPTC - WY Wind xPTC UT Solar wPTC - UT Solar xPTC Geothermal wPTC •••••- Geothermal xPTC Reference Inflation Battery wITC --- Battery xITC Natural Gas In the 2023 IRP proxy natural gas plants were given an assumed economic life of 10 years, reflecting the risk that plants fueled by natural gas could have future policies limiting their effective use. In the 2023 IRP Update, given that new natural gas plants are assumed capable of converting to alternative fuels such as green hydrogen in the future, PacifiCorp is now modeling these resources using their full economic and technical lives. Manufacturers have confirmed this as a supportable assumption. The risk of early closures and derates due to emissions is mitigated by the ability to switch to non-emitting fueling in the future. Peaking Type Resources Related to the natural gas discussion, above, in the 2023 IRP new proxy peaking units were assumed to be non-emitting. In the 2023 IRP Update, peaking units will be selected on the basis of natural gas fueling assumptions but will have the ability to convert to hydrogen or other renewable fuel. Demand Side Management PacifiCorp evaluates new demand side management (DSM) opportunities, which includes both energy efficiency and demand response programs,as a resource that competes with traditional new generation and wholesale power market purchases when developing resource portfolios for the IRP. The optimal determination of DSM resources therefore results in the selection of cost- effective DSM as a core function of IRP modeling. As in the 2023 IRP, DSM for Washington in the 2023 IRP Update preferred portfolio reflects selections from the Washington compliance scenario, under SC-GHG price-policy assumptions. In the 2023 IRP Update, energy efficiency 56 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS shapes for heating and cooling measures have been updated to align with updated load, representing the relative effectiveness of these bundles to meet system need. 57 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS [This page is intentionally left blank] 58 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.2 - 2023 IRP Update Supply Side Resources (2022$) Information Presented is Illustrative Description Resource Characteristics Costs Operating Characteristics Environmental Net A-p Full Load Elevation Capacity Commercial Design We Base Capital Demolition Fixed O&M Heat R..(HHV Water Consumed 502 NO. Fuel Resource (AFSL) (MWI Op-ion Year (rs) ($/KWI Cost($/kW) Var O&M($/MWh) ($/KW-yr) Btu/KWhf/fffiden EFOR(%) POR I%f (U/MWh) (Ibs/MMBtu) (Ibs/MMBtu) H(lbsMTu)002(Ibs/MMBtuI Naaval Cs SCCTAerox4 0 229 2027 30 $ 1,530 S 34.67 $ 0.28 $ 18.68 9241 0.7 2.0 23 0.0014 0.0910 0.2550 118.9000 No-I C ame s SCCT Fr "P'xl 0 354 2027 40 $ 814 $ 20.80 $ 2.32 $ 14.09 W73 5.6 7.2 0 0.0 () 0.0570 0.2550 118.9000 No-I Cs SCCT Frame"1"x1,30142-ovsho hydrogen productov aM 4qutled s o,,, 0 337 2028 40 $ 3,932 $ N M $ 2.44 $ 44.80 9191 5.6 7.2 122 0.0018 0.0550 0.1785 112.0000 Natural Cs SCCT Frame"1"XI,100H2-Done hydrogen prod fie.and Iquified storage 0 362 2035 40 $ 6588 $ 31.32 $ 2.23 $ 69.00 9459 5.6 7.2 406 0.0000 RW5 0.0000 0.0000 Neural Gas SCCT Frame"P'X1,ROH2-pipeline WdMmette Valley 0 362 2035 40 $ 930 S 31.32 $ 1'n $ 14.09 9489 5.6 7.2 406 0.0000 RW5 R0000 0.0(W Natural Cs SCCT Frame"J"XI,IWH2-pipeline McNary 0 362 2035 40 $ 930 S 31.32 $ 2.23 $ 14.09 000 9489 5.6 7.2 406 0.0 0.0655 OA000 0.0000 Na-I Cs SCCT Frame"1"XI,IOOH2,IF--k hydrogen prodwtion and W d-go 0 362 2033 40 $ 5,894 S 31.32 $ 2.27 $ 66.37 9489 5.6 7.2 406 0.0DD0 0.0655 0.0000 0.0000 NatwalC s CCCT Dry"P"1X1 0 548 2028 40 $ 1,361 S 20.97 $ 1.61 $ M.72 6227 5.6 7.2 8 0.0020 0.0076 0.2550 118.9000 Nanval Cs CCCT "1",DF,IxI 0 63 2028 40 $ $ $ 1.is $ 8726 5.6 7.2 8 0.0020 0,0076 0.2550 11&9000 Nanval Gas SCCTAerox4 1,500 216 2027 30 $ 1,619 S 45.W $ 0.30 $ 19.77 W58 0.7 2.0 24 0.00W 0.0910 0.2550 118.9000 Nanaal Cs SCCT R.-I".] I,SW 338 2027 40 S 853 S 28.29 $ 2.43 S 14.76 9066 5.6 7.2 0 OD020 0.0570 0.2550 118.9000 Natural Cs SCCT Farce"J"x1,30H2-owns hydogen production and fi fied s[oage IOW 322 2028 40 $ 4,118 S 37.95 $ 2.55 S 46.92 91M 5.6 7.2 122 0.6018 0.0550 0.1785 113.0000 Neural Cs SCCT Frame"U,, :WH2-uu,ft hydrogenp,,dw andbquf dstorage ISm M5 2035 40 $ 6,903 S 41.21 $ 2.38 $ 73.77 9481 5.6 7.2 406 0.0000 RW4 00000 00000 Neural Cs SCCT Frame"1"XL ZOOM pipeline Southern OR I,500 345 2035 40 $ W5 S 41.21 $ 2.38 $ 14.76 9481 5.6 7.2 406 0.(M 0.0654 0,0000 0.0000 Neural Cs SCCT Frame"1"XI,IOOH2,IF-mile hydrogen production a Wdsumge 1,500 345 2033 40 $ 6,176 S 41.21 $ 2.38 $ 69.M 9481 5.6 7.2 406 0.0000 0.0654 0.0000 0.00W Nawal Cs CCCT Dry"P"IXl 1,500 523 2028 40 $ 1,427 S 27.74 $ 1.68 $ 23.81 6227 5.6 7.2 8 0.0020 0.0076 0.2550 118.9DD0 Nanval Cs CCCI'D "1",DF,Ix1 1,500 63 2028 40 S $ $ 1.15 $ 8688 5.6 7.2 9 0.0020 0,0076 0.2550 118.9000 Nenval Gaa SCCT Forme"1"x1,30H2-ovsite hydrogen prodctiou and hqudx;da ,,, 3,000 305 2027 40 $ 4J55 $ 37.87 $ 2.70 S 11 9119 5-6 7.2 122 0.0018 0.0550 0.1785 113.0000 Nanval Gaa SCCT Frame"1"XI,lWH2-Doane hydrogen production and liqud d storage 3," 327 2034 40 $ ],297 $ 4256 $ 2.52 S 7].98 9456 5.6 7.2 4W O.0000 RW5 0.0000 0.0000 Neural Ca SCCT Franc"1"XI,ROM,IF-ovsk hydrogen production and EquHed storage 3,000 327 .14 40 $ 6,529 S 42.56 $ 2.52 S 1.52 9456 5.6 7.2 4W 0.0000 RW5 0.0000 0.0000 Neural Cs CCCT Dry"J",1X1 3,000 495 2027 40 $ 1,507 S 27.3] $ 1.78 $ 25.15 6226 5.6 7.2 8 0.0 () RM6 R2550 118.9000 Neural Cs CCCT "P',OF,1,1 3,000 63 2028 40 S $ $ 1.15 $ 8705 5.6 7.2 9 0.0020 Q()076 R2550 118.9000 Neural Cs SCCTAerox4 5,050 190 2028 30 $ 1,844 S 41.83 S 0.34 $ 22.54 9326 0.7 2.0 28 0.0014 0.0914 0.2550 118.9g10 Neural Cs SCCT Frame"1"xl 5,050 296 2029 40 T 971 S 24.85 $ 2.78 $ 16.83 9080 5.6 7.2 0 0.0020 0.0571 0.2550 118.9000 Neural Ca SCCT Frame"1"x1,30H2-mfte hydrogen production and lgtWbd storage 5,050 282 2029 40 $ 4,696 S 33.72 $ 2.91 $ 53.53 9197 5.6 7.2 122 0.0018 0,0550 0.1785 112.0000 Natural Cs SCCTFrtime"1"X1,lWM-awnshydrogenpraductanuo,lquifidstarage 5'050 303 2035 40 $ 7,80 $ 37.42 $ 2.72 $ 84.10 9493 5.6 7.2 406 0.00110 RW5 00000 0.00110 Naaval Ca SCCT Frame"1"XI,lWH2-pipelhre Utah No 5,050 303 2035 40 $ 1,1W S 37.42 $ 2.72 S 16.83 9493 5-6 7.2 406 0-00110 0.0655 0.0000 0.00110 Neural Cs SCCT Fr.T'XI,lWH2,BF-ovsk hydrogen prodetiou and liqutled storage 5,050 303 .35 40 $ 7,Nl S 37.42 $ In S 79.29 9493 5.6 7.2 4W 0.00gI RW5 0.0000 0.WCO Natural Cs SCCT Frame"1"XL lWH2,IF pgieetine Dave Johnston 5,050 303 11 40 $ I,109 S 37.42 $ 2.72 $ 16.83 9493 5.6 7.2 406 0.0000 RW5 0.0000 0.0000 Neural Cs SCCT Frame"J"XL IMM,BF-pipeline H-, 5,050 303 2035 lD $ I,109 S 3T42 $ 2.72 $ 16.83 9493 5.6 7.2 t06 0.00110 RW55 0.0000 0.0000 Naneal Cs CCCT Dry'7",IXl 5,050 459 2029 40 $ 1,625 S 25.05 $ 1.92 $ 27.13 6234 5.6 7.2 8 0.0019 0.00176 0.2550 118.9000 Neural Cs CCCT "J",DF,Ixl 5,050 63 2029 40 S - $ - $ 1.15 $ 8652 5.6 7.2 9 0.0020 0.0076 0.2550 118.9000 Neural Ca SCCTAerox4 6$00 171 2028 30 $ 2,044 S 49.31 $ 0.38 $ 24.98 9208 0.7 2.0 30 0.0000 0,0913 0.2550 118.9WO Naaval Cs SCCT Frame"P'xl 6,500 283 2028 40 $ 1,017 S 28.M $ 2.91 $ 17.63 9076 5.6 7.2 0 0.Og10 0.0571 0.25% 118.9000 Naaval Cs SCCT Frame"1"X1,100H2,IF-o-fte hydogen production aM liqutled storage 6,500 289 2034 40 $ ]J74 S *l 16 $ 2.M $ 17.63 9489 5.6 7.2 406 0.00W RW4 0.0000 0.0000 Nanaal Cs SCCTFra 'J XI,100H2,BF-Pie-Naughton 6$5 289 2034 40 $ 1,162 $ *l 16 $ 2.M $ 17.63 9459 5.6 7.2 406 0.WW RW4 0.0000 0.00110 Natural Cs SCCT Frame"1"XL 100H2,BF-'l,00 Jun Bridge, 6,500 289 2034 40 $ 1,162 $ 44.16 $ 2.M $ 17.63 9459 5.6 7.2 K)6 0.0000 RW4 0.0000 0.0000 Neural Cs CCCT Dry"P',1X1 6,500 437 2027 40 $ 1,704 $ 43.32 $ 2.01 $ 28.46 6241 5.6 7.2 8 0. 0.00'/6 R2550 118.9000 N.-I Cs CCCT "J.,DF,Ixl 6,500 63 2027 40 $ - $ - $ 1.15 $ 8590 5.6 7.2 9 0.0D00 ROW6 0.2550 118.9000 Coal PC CCUS Oxy-Combustion-fit @ 100 MW pre-retrof¢basis 5,000 -39 2028 30 $ 4,673 S 37.00 S 18.68 $ 54.24 18321 5 5.0 193 0.0040 0.0420 1.2000 6.2400 Coal PC CCUS oeb fa @ 330 MW pre-retrofit bass 6,500 -99 2028 20 $ 2,826 S 37.00 $ 21.70 $ 32.71 15632 5 5.0 450 Rm 0 0.0700 1.20W 20.5352 Coal PCCCUSretrofit 700 MW -retrofit basic 6,500 -10 2028 20 $ 1,932 S 37A0 $ 20.79 $ I&M 14656 5 5.0 450 R0050 0.07W 1.2000 20,5352 Storage L,, ,4fw,200 MW N/A 200 2025 20 $ 1,827 $ 24.00 IrcWded $ 42.32 Na 0 0.0 Na 0.00110 ROW) 0.0000 0.00110 Storage Ircremonuo,double enegy-a Ay(L-o,4hr,2011MW) N/A 200 2025 20 $ I,495 S 24.00 JrchWed $ 42.32 da 0 0.0 o/a 0.Og10 O.000 0.0000 0.0000 Storage L41on,4-haa,500 MW N/A 500 2025 20 $ 1,785 $ 24.M Included $ 41.36 n/a 0 0.0 Na 0.0000 RGCKK) 0.0000 0.0000 Storage Irerem 1,double energy capacity(L-bm 4hr,500MPU N/A 500 2025 20 $ I,468 $ 24.00 l eluded $ 41.36 n/a 0 0.0 Na 0.0000 ROCK)D 0.00(o 0.0000 Storage Ltlory 4-hour,1000 MW N/A 11000 2025 20 $ 1,738 $ 24.00 Included $ 40.31 Na 0 0.0 Na 0.0000 0.0000 0,0000 0.0000 Stom Incremental,double ener c L-bit,4hr,1000 N/A 1,000 2025 20 $ 1,430 S 24.00 Icekrded $ 40.31 Na 0 0.0 Na 0.OD00 0.0000 0.00 OADDO Storage Flow Battery,4 b-,200 MW c N/A 200 2025 25 $ 2,472 S 34.00 $ 0.03 $ M.27 Na 0 0.0 Na 0.0000 0.0000 0.0000 0.0DW Storage Ircremernal,double energy capacity(Flew,4hr,200MW) N/A 200 2025 25 $ 2,071 $ 34.00 $ - $ 7.00 Na 0 0.0 n/a 0.00110 0.01100 0.0000 0.0000 Suage Fbw Battery,4 how,1000 MW N/A 1," 2025 25 $ 2,2% S 12.M $ 0.13 $ 54.86 Na 0 0.0 Na 0.00110 0.0000 0.0000 0.0000 Store a Irrremerna double ens, c low 41a 1000 N/A I M 2025 25 $ 1 S 32.1 $ $ 1.66 u/a 0 0.0 v/a 0.00g1 RCW) 0.0000 0.0om Suage Gavity Battery,4 how, N/A 2W 2025 50 $ 3,493 E 0.30 Included $ 80.97 n/a 0 0.0 Na 0.0000 O.000 0.0000 0.0000 Storage Ircr-edok double energy eapacity(Grevny,4hr,200MW) N/A 200 2025 50 $ I,904 S 0.30 Inc' $ - n/a 0 0.0 Na 0.0000 O.000 0.0000 0.0000 Storage Gravity Ratury,4fw, N/A 500 2025 50 $ " S 0.24 Included S 75.]5 W. 0 0.0 Na 0.0000 0.0W) 00000 0.0000 Storage Incremental,double energy c,pu,ity(Gavity,4u,500MW) N/A 500 2021 50 $ 1,705 S 0.24 Included $ - W. 0 0.0 Na 0.00110 O.ODDO 00000 0.0000 Storage Gravity Battery,4 bow, N/A 1,000 2025 50 $ 2,037 f 0.18 Included S 121 W. 0 0.0 Na 0.0000 RODDO 0.0000 0.0000 Store Ircremeinzl,double ener c Gre ,4hr,1000 N/A 1,000 2025 50 $ 993 S 0.18 Incuded $ Na 0 0.0 Na DOOM 0.0t100 0.0W0 0.0000 Suage Adiabadc CAES,RESC,125MW,]OOOMWh 6,500 125 2026 30 $ 2J3M S 49.31 $ 1.05 $ 16.91 Na O.OII 0.0 n/a 0.0000 0.0000 0.0000 0.0000 Storage Adabaf CAE:,RE:C,:11 12501 6,500 125 2026 30 $ 2;343 S 49.31 $ 1.05 $ 16,95 da O.OII 0.0 Na O.001)0 0 D000 0.0000 0.moo Sromge Adabaf CAE:,RE:C,12 MW,1500MWh 6,500 125 2027 30 $ 2,588 $ 49.31 5 1.M S 16.99 n/a 0.11 0.0 v/a ROCCO O.000 0.0000 0.0000 Stone Adixbatb CAES,RESC 125 MW,2000MWh 6,5W 125 2027 30 $ 2,673 $ 49.31 $ 1.05 S 1].07 n/e O.OII 0.0 Na 0.0000 O.000 0.0000 0.0000 59 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.2 - 2023 IRP Update Supply Side Resources (2022 $) (Continued) Information Presented is Illustrative Description Resource Characteristics Costs Operating Characteristics Environmental Net Average Full Load Elevation Capacity Commercial Design life Base Capital Demolition Fixed O&M Heat R..(HHV Water Consumed 502 NO. Fuel Resource (AF50 (MWl 0 eretiov Year (rs) ($/KW) Cost($/kW) Var O&M I$/MWh) ($/KW-r) Btu/KWhf/fffid EFOR(%I POR I%f (U/MWh) (Ibs/MMBtu) (Ibs/MMBtuI H IlbsMTu)CO2fbs/MMBtuI Storage Adiabatic CAES,RESC,125MW,30011MWh 6,500 125 2027 30 $ 2,869 $ 49.M $ 1.05 $ 17.23 da Ro 0.0 da R. 00000 0.0000 0.0000 Store Adiahmk CAE:,RESC,125MW,6000MWh 6,5m 125 2029 30 $ 3,887 S 49.31 $ LM $ 17.71 Na 0.0 0.0 Na OD000 0MO RMO 0.0000 Storege Adhmk CAES,RESC,250 MW,4000 MWh 65W 250 2028 30 $ 2,453 S 49.31 $ 1.05 S 12.65 da 0.011 0.0 Na RMO 0.0000 0.0000 0.0000 Storage Adbatie CAES,RESC,250 MW,6000 MWh 655 250 2029 30 $ 2,74 $ 49.31 $ 1.05 $ 12.81 W. 0.011 0.0 Na R. 0.0000 0.0000 0.0000 Story a Adabatk CAES,RESC 250 MW,12M h 65M 250 2032 30 $ 3,678 $ 49.31 $ 1.05 $ 13.29 Na 0.011 0.0 Na 0.0000 0.0000 O.UOW 0.0000 Storage Adi, CA ES,RE SC,500 MW,400I1 MWh 6,500 5W M8 30 $ 2,024 S 49,31 $ 1.05 $ 10.28 Na Roll 0.0 Na 000 0.0000 0.0000 0.0000 Storage Adabatk CAE S,RESC,500 MW,5000 MWh 6500 500 2028 30 $ 2,037 $ 49.31 $ 1.05 $ 10.32 Na 0.011 0.0 Na 0.0000 0.0000 0.0000 0.0000 Storage Adiabmk CAES,RESC,500 MW,6000 MWh 6,500 500 2029 30 $ 2,180 S 49.31 $ 1.05 $ 10.36 Na 0.011 0.0 Na 0.0000 0.0000 OA000 0.0000 Storege Adiabatic CAES,RESC,500 MW,8000 MWh 6500 500 2030 30 $ 2,327 S 49.31 $ 1.05 $ 10.44 W. 0.011 0.0 Na 0.00110 0.0000 0.0000 0.0000 Storege Adiahade CAES,RESC,500 MW,12WOMWh 6500 5W 2032 30 $ 2,645 S 49.31 $ I.OS $ 10.60 da 0.it 0.0 da 0.00110 0.0000 RMO 0.00110 Store A&twtm CAES RESC,500 MW 24110pMWh 6 m 5W 2035 30 $ 3629 S 49.31 $ 1.05 $ 11.08 da 0.011 0.0 Na 0.0000 0.0000 RMO 0.00110 Storage Pa wd Hydro,Southern OR N/A 400 2028 ]W $ 4}33 S 485.W $ 0.51 $ ISM I 2 4.0 da O.00W 0.0000 0.0000 0.0000 Storage Punymd Hydro,Porthnd North Ccaat N/A 400 2028 ]W $ 4'3 S 485.00 $ 0.51 $ ISM 1 2 4.0 Na 0.0000 0.0000 0.0000 0.0000 Storage P,d Hydro,C.-I WY N/A 400 2028 1W $ 4303 5 485.00 $ 0.51 $ 18.00 I 2 4.0 Na 0.0000 ROM 0.0000 0.0000 Storage Putrryed Hydro,Eastern WY N/A 400 2028 ]00 $ 4,303 S 485.00 $ 0.51 $ I8.00 1 2 4.0 Na 0.0000 0.0000 0.0000 0.0000 Story P dH dro,Cevtral UT N/A 400 2028 ]00 $ 4,303 S 485.00 $ 0.51 $ 18.00 1 2 4.0 Na BMW 0.0000 0.0000 0.0000 Store 100-hma Iron Air Ba max CF:17% N/A 200 2025 20 $ 5367 S 16RW 1nchWed $ 20.77 0 0 0.0 0 0.00110 0.0000 0.0000 0.0000 Solar Solar-Idaho Falk,ID,20 MW,26.1%CP 4,700 20 2025 25 $ 1,427 $ 29.40 $ - $ 20.87 Na Iremded whh CP OD da W. W. W. Na Solar Solar-I.akeview,OR,20 MW,27.6°o CF 4,800 20 .3 25 $ 1527 $ 31.50 $ - S 20.87 Na Includedw CF 0.0 Na W. Na Na Na Sohr Solar-MBfmd,UT,MMW, .2'/.CF 5,000 20 2023 25 $ 1,412 $ 29.10 $ - $ 20.87 Na Included wdh CF 0.0 da W. W. da da Soler Solar-Milford,BE,200 MW,M.2%CF 5,000 200 2023 25 $ I,140 $ "' $ - $ 20.87 Na Incuded whh CF 0.0 Na de Na Na Na Solar Solar-Rock Springs,WY,20 MW,27.9%CF 6,400 2W 2023 25 $ I,IB] $ 30.30 $ - $ 20.87 Na I Wed wdh CF 0.0 Na da Na de Na Soh' Solar-Y.Id-,WA,200 MW,24.2%CF 1,000 200 2025 25 $ 1211 S 30.90 $ S 20.87 Na Incmded wdh CF 0.0 Na W. Na Na Na Sohr+Smrge Sohr+Storege-Idaho Falk,ED,200 MW,K.I%CF+BESS:100%pwr,4 houre 4,700 200 2025 25 $ 2,879 S 54.06 $ - $ 63.19 1 Incuded wdh CF 0.0 Na Na Na Na Na Solar+Storege Solar+Storege-Lakeview,OR,200MW,r.6%CF+BESS:100%pwr,4h=, 4,800 21p 2M5 25 $ 2,864 S 56.16 $ - $ 63.19 1 hmWddwdh CF 0.0 Na da da Na Na Solar+Smrge Sohr+Storege-M� d,UT,2011MW,30.2%CF+BESS:100°/pwr,4haas 5,1N10 2m 2025 25 $ 2,881 $ 53.76 $ - $ 63.19 t hmhded wdh CF 0.0 da da da Na Na Sohr+Sorge Solar+Smrge-Rork Spmp,WY,20 MW,27.9%CP+BESS:1WI. wr,4hovrs 6,400 2W 2025 25 $ 2y02 $ m% $ - $ 63.19 1 I-Wed wM CF 0.0 Na da da da Na Sohr+Stour Sohr+Stour -Yakuna,WA 2W N.2%CF+BESS:10/. 4hays I000 20 2025 25 $ 2,977 $ 55.56 $ $ 63.19 I hkhaled with CF 0.0 da da da da Na Wind Wind-Pocatello,ID,W MW,CF:37.1% 45W 20 2026 30 $ 2,161 S 59.46 $ - S 43.W Na Incuded with CF 0.0 Na da W. Na IV. Wmd Wmd-Pocatelo,m,200 MW,CF:37.1% 4500 2W 2026 30 $ 15W $ 59.46 $ - $ 43.00 Na hmlWed wdh CF 00 Na da Na Na Na Wmd W. Arlington,OR,20MW,CF:3]A% 1500 20 2026 30 $ 2,149 $ 59.46 $ - S 43.00 Na 1."d wdh CF 0.0 Na Na Na Na Na Wmd Wmd-Arfmglon,OR,200MW,CF:37.1% 1,500 200 2026 30 $ 1567 $ 59.46 $ - $ 43.00 Na IvekWed whh CF 0.0 Na Na Na Na Na Wmd Wmd-Montbedo,UT,20MW,CF:29.5% 4$lp 20 2026 30 $ 2,186 $ 59.46 $ - $ 43.. Na 1aki&d wdh CF 0.0 Na da Na Na Na Wind Wind-Monticevo,UT,2IXIMW,CF:29.5% 451p 200 2026 30 $ 1,626 $ 59.46 $ - $ 43.00 Na Incmded wdh CF 0.0 Na da da Na Na Wmd Wind-Medicine Bow,WY,20 MW,CF:43.6% 655 20 2M6 30 $ 2,129 S 59.46 $ - S 43M Na 1-w dwnh CF 0.0 Na da Na Na Na Wmd Wmd-Medkme Bow,WY,M MW,CF:43.6% 655 2W 2026 30 $ 1568 S 59.46 $ - 8 43.M da Inohded wn CF 1-a dwilh CF Na da da da Na Wind Wind-Gokkvdak,WA,MMW,CF:37.1% 15m 20 2M6 30 $ 22]4 S 59.4 $ - S 43.00 Na hnld with CF I.Id wilh CF Na W. Na W. W. Wmd Wind-Goklevdalc,WA,200 MW,CF:37.1% 15W 2W 2026 30 $ 1,660 5 59.46 $ - $ 43.M Na Inchuled wdh CF i.Wl dwilh CF Na Na Na Na Na Wmd Wind-Offshore,Nmtbem,CA,CF:4]A% 0 200 2028 30 $ 4,636 $ 158.23 $ - $ 103.00 Na ItmhWed wdh CF I.Wl dwdh CF Na da Na Na Na Wind Wmd-Offshore,Northern.CA,IGW,CF:47.0% 0 1,000 2028 30 $ 4,633 S 158.23 S $ 103.00 Na IcehWed wdh CF I.WM wdh CF Na Na Na Na Na Wind+Storege Wmd+Storege-PocateM,1D,200MW,CF:37.1%+BESS:100%pwr,4 home 4500 200 2026 M $ 3290 $ 83.46 E - $ 85.12 1 Included wdh CF ImU&d wpb CF Na da Na Na Na Wind+Sorege Wmd+Storege-Arlhglaq OR,200 MW,CP:37.1%+BESS:100%R.ar,4hwue t,5 2110 2026 30 $ 3,166 S 83.46 $ - $ 85.32 1 imAWed wnh CF IvchWed wJh CF Na da da Na Na Wind+Storage Wmd+Sorege-Manz M,UT,200 MW,CF:29.5%+BESS:100%pwr,4 b. 4500 2W 2026 30 $ 3}32 $ 83.46 S - S 85.32 1 1-b wn CF Iveh wilh CF Na da Na Na Na Wm.Sorege Wmd+:tomge-Medcme B.,WY,2W MW,CF:43.6%+BESS:l00°/p-,4 haul 65sw 2W 2026 30 $ 3,252 $ 83.46 $ - $ 85.32 1 Included wdh CF 1-c dwvh CF Na da da W. W. Wind+Storege Wmd+:forage-GoWerdak,WA,200MW,CF:37.1%+BESS:I00%pwr,4 hours 1500 200 2026 30 $ 3}89 $ 83.46 $ - $ 85.32 1 Included with CF IvchWedwilh CF da da Na Na W. Whd+Sore Wind+Sore -Offshore,NoMem,CA,CF:47.0'/+gBSS:IWI.wr,4 hours 0 2W 2M8 M $ 6,545 $ 182.23 S $ 145.32 85% fmkWu dwkb CF IvchWed weh CF Na v/a da Na Na Soh'+WindEStmage Idalw Falk,ID Sohr+Wmd+BESS:100°/pw',4 hours 41 11 1 25 $ 6,11 S 113.52 $ - $ 148.51 85% lmkWed wdh CF IvcWM wilb CF Na Na Na Na Na Sohr+Wm&storege Lakeview,OR Sohr+Wmd+BESS:100%pwr,4 hours 4,800 200 2026 25 $ 6,052 $ 115.62 S - $ 148.51 85% I.Wed wdh CF I.Wedwdh CF Na da Na Na Na Sohr+WmdFStarege Milford,UT Sohr+Wmd+BESS:100%pwr,4 hours 5,000 200 2026 25 $ 6238 $ 113.22 S - $ 148.51 85% IcekWed wdh CF Inc6Wed wish CF Na da Na Na Na Sohr+Wmd1S Rack Springs,WY Solar+Wind+BESS:100%-,4home 6,400 200 2026 25 $ 5,703 $ 114.42 $ - $ 148.51 85% Imbrded wilh CF IvchWad wilh CP Na da Na Na Na Sohr+Wind+Store Yakima,WA Sohr+Wmd+BESS:]lllp/° r,4 hours t'W* 2W 2M6 25 $ 5,898 S 115.m $ $ 148.51 85% hwh dwn CF hwc dwhh CF da da da Na da Geothermal Geothermal-Dual Flash Ex vaion ofB�deO Plmrc 4500 2011 2026 40 $ 3,835 $ 117.00 $ - $ 115.00 da 2.5 2.5 1,453.4 da Na da Na Geodermal Geodermal-Green0eH B' Phvt 4 W 2W 2026 40 $ 5 68 $ 117.00 S $ 115.g1 Na 2.5 2.5 1453.4 da da da de Nuckar Nuclear-Advanced LWR,b00MWSke N/A RO W32 b0 S 8,416 S 721.53 $ - $ 170.60 N/A 1.0 4.0 76T 0.0000 0.0000 0.0000 0.0000 Nuclear Nuck.-Advaviced LWR,I200MWSde N/A 12W 2032 W $ 72M S M1.53 $ - $ 152.29 N/A 1.0 4.0 767.2 0.00110 0.0000 0.0000 0.0000 Advanced Nuclear Reactor(ARE dual unik wdh Themml Storage(1000 Mwe inlerwnvectbv with Nuclear 1705 MWh Storage,638 MW mftW base genemtim) N/A 638 2032 60 $ 8,772 $ 721.53 $ - $ 472.81 N/A 3.0 5.0 767.2 0.0000 0.ODW ROM 0.0000 Advaviced Nuclear Reactor(AR)with mryroved flml(1000 Mwe interconne-whh 1705 MWh Ahgwd wdh Nuclear Story e,690MW base newtion N/A 690 2038 origm1pbmi$ 8,TR $ 72L53 $ $ 28&Q 1 20 4.0 767.2 1 0.0000 0.0000 00000 0.00m Iron Av bavery presented with most recent costa that have not tbwed mto the PLEXOS model 60 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.3 -2023 IRP Update Supply Side Resources (2022 $) Information Presented is Illustrative Capital Cost$/kW FlxedCost Supply Side Resource Options Mid-Calendar Year 2022 Dollars($) Fixed O&M$/kW-Yr Anal Elevation Total Capital Cast Payment Payment Capitalized O&M Tool Fined Resource D,-Icription Modeled II2P (AFSL) 1/ Demolition Cost Factor l/ ($/kW-Yr) O&Ml/ Premium Capitali.edl/ Cas Transportation l/ Tmal ($/kW-Yr) SCCT"co,x4 No 0 $1,530 $35 7.140%. $111.68 $18.68 0.000% $0.00 $31.59 $50.27 $161.95 SCCT Frame"1"xl No 0 $814 $21 6.456a/o $53.89 $14.09 0.000% $0.00 $31.02 $45.11 $99.00 SCCT Frame"J"xl,30H2-onsite hydrogen production and liquified storage No 0 $3,932 $28 6.456% $255.67 $44.80 0.000% $0.00 $31.42 $76.22 $331.89 SCCT Frame"J"Xl,100H2-o0site hydrogen production and fiquified storage No 0 $6,598 $31 6.456% $427.34 $69.00 0.000% $0.00 $32.44 $101.44 $528.77 SCCT Frame"J"X1,100H2-pipeline Willamette Valley Yes 0 $930 $31 6.456% $62.04 $14.09 0.000% $O.00 $119.30 $133.39 $195.43 SCCT Frame"1"Xl,100H2-pipeline McNary Yes 0 $930 $31 6.456% $62.04 $14.09 0.000% $O.00 $266.68 $280.77 $342.81 SCCT Frame"1"Xl,100H2,BF-onsite hydrogen production and liqu�ed storage No 0 $5,894 $31 6.456% $382.59 $66.37 0.000% $0.00 $32.44 $98.80 5481.39 CCCT Dry"J",1X1 No 0 $1,361 $21 6.609"/ $91.33 $22.72 2.616% $0.59 $21.29 $44.60 $135.93 CCCTD "J",DF,lxl No 0 $0 $0 6.609"/ $0.00 $0.00 2.616% $0.00 $29.83 $29.83 $29.83 SCCT Aero x4 No 1,500 $1,619 S46 7.140% $118.87 $19.77 0.000% $0.00 $31.65 $51.42 $170.29 SCCT Frame"J"xl No 1,500 $853 $28 6.456% $56.89 $14.76 0.000% $0.00 $30.99 $45.75 $102.64 SCCT Frame"J"xl,30H2-onsite hydrogen production and liqu�d storage No 1,500 $4,118 $38 6.456% $268.33 $46.92 0.000% $0.00 $31.39 $78.32 $34&64 SCCT Frame"J"Xl,100H2--fie hydrogen production and liquified storage No 1,500 $6,903 S41 6.456% 5448.32 $73.77 0 $0.00 $32.41 $106.17 $554.49 SCCT Frame"J"Xl,100H2-pipeline Southern OR Yes 1,500 $975 S41 6.456% $65.59 $14.76 0.000%.000% $0.00 $119.19 $133.96 $199.54 SCCT Frame"J"Xl,IOOH2,BF-onsite hydrogen production and liquified storage No 1,500 $6,176 $41 6.456% $401.43 $69.54 0.000% $0.00 $32.41 $101.95 $503.38 CCCT Dry"J",1X1 No 1,500 $1,427 $28 6.609% $96.11 $23.81 2.616% $0.62 $21.29 $45.72 $141.94 CCCT "J",DF,lxl No 1,500 $0 $0 6.609% $0.00 $0.00 2.616o/a $0.00 $29.70 $29.70 $29.70 SCCT Aero x4 No 3,000 $1,712 $46 7.140% $125.56 $20.92 0.000% $0.00 $14.21 $35.12 $160.69 SCCT Frame T'xl No 3,000 $901 $29 6.456% $60.06 $15.61 0.000°/ $0.00 $13.88 $29.48 $89.54 SCCT Frame"J"xl,301-12-onsite hydrogen production and liquified storage No 3,000 $4,355 $38 6.456% $283.62 $49.63 0.0000% $0.00 $14.06 $63.68 $347.31 SCCT Frame"J"Xl,IOOH2-onsite hydrogen production and liquified storage No 3,000 $7,297 $43 6.456% $473.86 $77.98 0.000% $0.00 $14.51 $92.49 $566.35 SCCT Frame"J"Xl,10OH2,BF-onsite hydrogen production and liquified storage No 3,000 $6,529 $43 6.456% $424.29 $73.52 0.000°/ $0.00 $14.51 $88.03 $512.32 CCCT Dry"J",IXl No 3,000 $1,507 $27 6.609% $101.38 $25.15 2.616% $0.66 $9.52 $35.34 $136.71 CCCTD "7",DF,lxl No 3,000 $0 $0 &609% $0.00 $0.00 2.616a/o $0.00 $13.32 $13.32 $13.32 SCCT Aero x4 Yes 5,050 $1,844 $42 T140% $134.64 $22.54 0.000% $0.00 $14.20 $36.74 $171.39 SCCT Frame T'at Yes 5,050 $971 $25 6.456% $64.31 $16.93 0.000% $0.00 $13.83 $30.66 $94.97 SCCT Frame,"J"xl,30H2-onsite hydrogen production and liquified storage No 5,050 $4,699 $34 6.456% $305.37 $53.53 0.000% $0.00 $14.01 $67.53 $372.90 SCCT Frame"J"Xl,100H2-onsite hydrogen production and liquified storage Yes 5,050 $7,86 $37 6.456% $510.43 $84.10 0.000% $0.00 $14.46 $98.56 $608.99 SCCT Fmme"J"X1,100112-pipeline Utah North Yes 5,050 $1,109 $37 6.456% $74.03 $16.83 O.000o/ $0.00 $118.83 $135.66 $209.69 SCCT Frame"J"Xl,]OOH2,BF-onsite hydrogen production and liquified storage No 5,050 $7,041 $37 6.456% $456.98 $79.29 0.00044/ $0.00 $14.46 $93.74 $550.72 SCCT Frame"J"XI,]OOH2,BF-pipeline Dave Johnston Yes 5,050 $1,109 $37 6.456% $74.03 $16.83 0.000% $0.00 $209.67 $226.51 $300.54 SCCT Frame"J"Xl,100H2,BF-pipeline Hunter Yes 5,050 $1,109 $37 6.456% $74.03 $16.83 0.000% SO.00 $39.61 $56.44 $130.47 CCCT Dry' 1X1 Yes 5,050 $1,625 $25 6.609e/ $109.01 $27.13 2.616% 50.71 $9.49 $37.34 $146.35 CCCT Dry"J",DF,]xl Yes 5,050 $0 $0 6.609% $0.00 $0.00 2.616% SO.00 $13.18 $13.18 $13.18 SCCT Aero x4 Yes 6,500 $2,044 $49 7.140% $149.43 $24.98 0.000% SO.00 $24.74 $49.73 $199.16 SCCT Frame"J"xl Yes 6,500 $1,017 $29 6.456% $67.52 $17.63 0.0001/. $0.00 $24.39 $42.02 $109.53 SCCT Frame"J"xl,30H2-onsite hydrogen production and lquifred storage No 6,500 $4,918 $40 6.456% $320.07 $56.05 0.000"/ $0.00 $24.70 $80.76 $400.83 SCCT Fmme"J"Xl,IOOH2-onsite hydrogen production and figndied storage Yes 6,500 $8,241 $44 6.456% $534.94 $88.09 0.000% $0.00 $25.50 $113.59 $648.53 SCCT Frame"J"Xl,100H2,BF-onsite hydrogen production and liquified storage No 6,500 $7,374 $44 6.456% $479 $83.04 0.000% $0.00 $25.50 $108.54 $587.50 SCCT Frame"J"X1,IOOH2,BF-pipeline Naughton Yes 6,500 $1,162 S44 6.456% $77.86 $17.63 0.000% $0.00 $118.77 $136.40 $214.26 SCCT Frame,"J"Xl,IOOH2,BF-pipeline Jim Bridget Yes 6,500 $1,162 S44 6.456% $77.86 $17.63 0.000% $0.00 $175.80 $193.43 $271.30 CCCT Dry"J",1X1 Yes 6,500 $1,704 S43 6.609% $115 $28.46 2.616% $0.74 $16.77 .5.98 $161.46 CCCT Dry"J",DF,lxl Yes 6,500 $0 $0 6.609% $0 $0.00 2.616% $0.00 $23.08 $23.08 $23.08 61 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.3 -2023 IRP Update Supply Side Resources (2022 $) (Continued) Information Presented is Illustrative Capita]Cost$/kW FlxedCwt Supply Side Resource Options Mid-Calendar Year 2022 Dollars($) n.dO&M$/kW-Yr Annual Elevation Total Capital Cast Payment Payment Capitalized O&M Total Fmd Resource DesC' 'On Modeled]RP (AFSL) l/ Demolition Cost Factor l/ ($/kW-Yr) O&Ml/ Premium Capitalized]/ Cas Transportation l/ Total ($/kW-Yr) PC CCU'Oxy-Combustion retrofit @ 100 MW pre-retrofit basis Yes 5,000 $4,673 $37 7.289% $343.30 $54.24 5.541% $3.01 $0.00 $57.25 $400.54 PC CCUS retrofit@ 330 MW pre-retrofn basis Yes 6,500 $2,826 $37 8.887% $254.47 $32.71 5.541% $1.81 $0.00 $34.52 $288.99 PC CC US retrofn 7.MW rc_roadi basis Yes 6,500 $1,9321 $37 8.903%1 $175.28 $18.04 5.541% $1.00 $0.00 $19.04 $194.32 Li-Ion,4-hour,200 MW No N/A $1,827 $24 8.405% $155.59 S42.32 0.000% $0.00 $0.00 S42.32 $197.91 Incremental,double energy capacity(L W)-ion,4hr,200M No N/A $1,495 $24 8.405% $127.65 S42.32 0.000% $0.00 $0.00 $42.32 $169.97 Li-Ion,4-hour,500 MW Yes N/A $1,785 $24 8.405% $152.01 S41.36 0.000% $0.00 $0.00 $41.36 $193.37 Incremental,double energy capacity(L-ion,4hr,500Mw) Yes N/A $1,468 $24 8.405% $125.39 S41.36 0.000% $0.00 $0.00 $41.36 $166.75 Li-ton,4-hour,1000 MW No N/A $1,738 $24 8.405% $148.12 $40.31 0.000% S0.00 $0.00 $40.31 $188.43 lncreruentaL double ener caac' L-ion,4hr,1000 No N/A $1,430 $24 8.405% $122.21 $40.31 0.000% S0.00 $0.00 $40.31 $162.52 Flow Battery,4 hour,200 MW Yes N/A $2,472 $34 8.405% $210.62 $64.27 0.000% $0.00 $0.00 $64.27 $274.89 Incremental,double energy capacity(Flow,41r,200MW) Yes N/A $2,071 $34 8.405% $176.94 $7.00 0.0000/ $0.00 $0.00 $7.00 $183.94 Flow Battery,4 hour,1000 MW No N/A $2,294 $32 8.405% $195.51 $54.86 0.0000/ S0.00 $0.00 $54.86 $250.38 Incremental,double ener ca ad (Flow,41r,1000MW) Yes N/A $1,902 $32 8.405% $162.56 $L66 0.000% $0.00 $0.00 $1.66 $164.22 Gravity Battery,4 hour, Yes N/A $3,493 $0 8.405% $293.64 $80.97 0.000% $0.00 $0.00 $80.97 $374.61 Incremental,double energy capacity(Gravity,4hr,200MW) Yes N/A $1,904 $0 8.405% $160.09 $0.00 0.000% $0.00 $0.00 $0.00 $160.09 Gravity Battery,4 how, Yes N/A $3267 $0 8.405% $274.61 $75.75 0.000% S0.00 $0.00 $75.75 $350.36 Incremental,double energy capacity(Gravity,4hr,500MW) Yes N/A $1,705 $0 8.405% $143.32 $0.00 0.000% S0.00 $0.00 $0.00 $143.32 Gravity Battery,4 how, Yes N/A $2,037 $0 8.405% $171.26 $47.25 0.000% SO.00 $0.00 S47.25 $218.51 Incremental,double ener ca c' Gra ,4hr,]000 No N/A $993 $0 8.405% $83.51 $0.00 0.000% SO.00 $0.00 $0.00 $83.51 Adiabatic CAES,RESC,125 MW,1000 MWh No 6,500 $2322 $49 6.804% $161.34 $16.91 5.480% S0.93 $0.00 $17.84 $179.17 Adiabatic CAES,RESC,125 MW,1250 MWh No 6,500 $2,343 $49 6.804% $162.80 $16.95 5.480% S0.93 $0.00 $17.88 $180.68 Adiabatic CAES,RESC,125 MW,1500 MWh No 6,500 $2,588 $49 6.804% $179.44 $16.99 5.480% $0.93 $0.00 $17.92 $197.36 Adiabatic CAES,RESC,125 MW,2000 MWh No 6,500 $2,673 $49 6.804% $185.25 $17.07 5.480% $0.94 $0.00 $18.01 $203.26 Adiabatic CAES,RESC,125 MW,3000 MWh No 6,500 $2,869 $49 6.804% $198.54 $17.23 5.480% $0.94 S0.00 $18.18 $216.72 Adiabatic CAES,RESC,125 MW,6000 MWh No 6,500 $3,887 $49 6.804% $267.81 $17.71 5.4800/ $0.97 $0.00 $18.68 $286.50 Adiabatic CAES,RESC,250 MW,4000 MWh No 6,500 $2,453 $49 6.804% $170.27 $12.65 5.480% $0.69 SO.00 $13.35 $183.62 Adiabatic CAES,RESC,250 MW,6000 NM No 6,500 $2,748 $49 6.804% $190.34 $12.81 5.480% $0.70 $0.00 $13.52 $203.86 Adiabatic CAES,RESC,250 MW,12000 MWh No 6,500 $3,678 $49 6.804% $253.64 $13,29 5.480% $0.73 $0.00 $14.02 $267.66 Adiabatic CAES,RESC,500MW,4000 MWh Yes 6,500 $2,024 $49 6.804% S141.05 $10.28 5.480% $0.56 $0.00 $10.89 $151.90 Adiabatic CAES,RESC,500 MW,5000 MWh No 6,500 $2,037 S49 6.804/ $141.95 $10.32 5.480% $0.57 $0.00 $]0.89 $152.84 Adiabatic CAES,RESC,500 MW,6000 MWh Yes 6,500 $2,180 S49 6.804% $151.68 $10.36 5.480% $0.57 $0.00 IM93 $162.61 62 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.3 -2023 IRP Update Supply Side Resources (2022 $) (Continued) Information Presented is Illustrative Cep'tel Cast$/kW Fixed Cost Supply Side Resource Options Mid-Calendar Year 2022 Dollars($) P1xedO&M$/kW-Yr Anneal Elevation Told Capital Cost Payment Payment Capitalized O&M Total Fixed Resource Description Modeled IRP (AFSL) 1/ Dernolifioo Cost Factor l/ ($/kW-Yr) 0&M1/ Premium Capitalized]/ Qs Transportation l/ Total (S/kW-Yr) Adiabatic CAES,RESC,500 MW,8000 MWh No 6,500 $2327 S49 6.804% $161.70 $10.44 5.480% $0.57 $0.00 $11.02 $172.71 Adiabatic CAES,RESC,500 MW,12000 MWb No 6.500 $2,645 S49 6.804% $183.31 $10.60 5.480% $0.58 $0.00 $11.19 $194.49 Adiabatic CAES,RESC,500 MW,24000 MWh No 6,500 $3,629 $49 6.804% $250.29 $11.08 5.480% $0.61 $0.00 $11.69 $261.98 Pumped Hydro,Southern OR Yes N/A 14,303 S485 5.567a/ $266.55 $18.00 2.617% $0.47 $0.00 $18.47 $285.02 Pumped Hydro,Portland North Coast Yes N/A $4,303 S485 5.567% $266.55 $18.00 2.617% $0.47 $0.00 $18.47 $285.02 Pumped Hydro,Central WY Yes N/A $4,303 $485 5.567a/ $266.55 $18.00 2.617% S0.47 $0.00 $18.47 $285.02 Pumped Hydro,Eastern WY Yes N/A $4,303 $485 5.567a/ $266.55 $18.00 2.617% S0.47 $0.00 $18.47 $285.02 P edH dro,Central UT Yes N/A $4,303 $485 5.567% $266.55 $18.00 2.617% $0.47 $0.00 $18.47 $285.02 100-how Iron Art Battery,max CF:17% Yes N/A $5367 $160 8.405% $464.51 $20.77 0.000%1 $0.00 $0.00 $20.77 $485.27 Solar-Idaho Falls,ID,20 MW,26.1%CF Yes 4,700 $1,427 $29 7.209% $104.97 $20.87 1.370% $0.29 $0.00 $21.16 $126.12 Solar-Lakeview,OR,20 MW,27.6%CF Yes 4,800 $1,527 $32 7.2090/. $112.33 $20.87 1.370% $0.29 $0.00 $21.16 $133.48 Solar-Mdford,UT,20 MW,30.2%CF Yes 5,000 $1,412 $29 7.209% $103.91 $20.87 1.370% S0.29 $0.00 $21.16 $125.07 Solar-Milford,UT,200 MW,30.2%CF Yes 5,000 $1,140 $29 7.209% $84.31 $20.87 1.370% S0.29 $0.00 $21.16 $105.47 Solar-Rock Springs,WY,200 MW,27.9%CF Yes 6,400 $1,187 $30 7.209% $87.78 $20.87 1.370a/o S0.29 $0.00 $21.16 $108.94 Solar-Yakir.,WA,200 MW,24.2%CF Yes 1,000 $1,211 $31 7.209% $89.51 $20.87 1.370a/o $0.29 $0.00 $21.16 $110.67 Solar+Storage-Idaho Falls,ID,200 MW,26.1%CF+BESS:100%pwr,4 hours No 4,700 $2,879 $54 7.209% $211.42 $63.19 1.370a/ $0.87 S0.00 $64.06 $275.48 Solar+Storage-Lakeview,OR,200 MW,27.60/.CF+BESS:100%pwr,4 hours No 4,800 $2,864 $56 7.209% $210.50 $63.19 1.370a/ $0.87 S0.00 $64.06 $274.55 Solar+Storage-Mdford,UT,200 MW,30.2%CF+BESS:]00°/purr,4 hours No 5,000 $2,881 $54 7.209% $211.55 $63.19 1.370% $0.87 $0.00 $64.06 $275.61 Solar+Storage-Rock Springs,WY,200 MW,27.9%CF+BESS:l00%purr,4 hours No 6,400 $2,902 $55 7.M9% $213.18 $63.19 1.370°/ $0.87 $0.00 $64.06 $277.23 Solar+Store e-Yakima,WA,200 MW,24.2%CF+BESS:100% wr,4 hours No 1,000 $2,977 $56 7.209% $218.63 $63.19 1.370% $0.87 $0.00 $64.06 $282.69 Wind-Pocatello,ID,20 MW,CF:37.1% Yes 4,500 $2,161 $59 6.657% $147.82 $43.00 4.392a/o $1.89 $0.00 S44.89 $192.71 Wind-Pocatello,ID,200 MW,CF:37.1% Yes 4,500 $1,597 $59 6.657% $110.25 $43.00 4.392a/o $1.89 St.00 S44.89 $155.14 Wind-Arlington,OR,20 MW,CF:37.1% Yes 1,500 $2,149 $59 6.657% $147.04 $43.00 4.392% $1.89 St.00 S44.89 $191.92 Wind-Arlington,OR,200 MW,CF:37.1% Yes 1,500 $1,567 $59 6.657% $108.27 $43.00 4.392a/o $1.89 so..00 $44.89 $153.16 Wind-Monticello,UT,20 MW,CF:29.5% Yes 4,500 $2,186 $59 6.657% $149.48 $43.00 4.392% $1.89 $0.00 $44.89 $194.37 Wind-Monticello,UT,200 MW,CF:29.5% Yes 4,500 $1,626 $59 6.657% $112.20 $43.00 4.3920/. $1.89 $0.00 S44.89 $157.09 Wind-Medicine Bow,WY,20 MW,CF:43.6% Yes 6,500 $2,129 $59 6.657% $145.71 $43.00 4.392% $1.89 $0.00 $44.89 $190.60 Wind-Medicine Bow,WY,200 MW,CF:43.6% Yes 6,500 $1,568 $59 6.657% $108.31 $43.00 4.392% $1.89 $0.00 $44.89 $153.20 Wind-Goklendale,WA,20 MW,CF:37.1% Yes 1,5()0 $2.274 $59 6.657% $155.32 $43.00 4.392% $1.89 $0.00 S44.89 $200.21 Wind-Goklendale,WA,200 MW,CF:37.1% Yes 1,500 $1,660 $59 6.657% $114.49 S43.00 4.392% $1.89 $0.00 $44.89 $1'9.38 Wind-Offshore,Northern,CA,CF:47.0% Yes 0 $4,636 $158 6.657% $319'13 $103.00 4.392% $4.52 $0.00 $107.12 $4215. Wind-Offshore,Northern,CA,IGW,CF:470/o Yes 0 $4,633 $158 6.657% $318.98 $103.00 4.392% S4.52 $0.00 $107.52 S426.50 Wind+Storage-Pocatello,ID,200 MW,CF:37.1%+BESS:100%purr,4 hours No 4,500 $3,290 $83 6.6571/. $224.60 $85.32 4.392% $3.75 $0.00 $89.07 $313.66 Wind+Storage-Arlington,OR,200 MW,CF:37.1%+BESS:100%pwr,4 hours No 1,500 $3,166 $83 6.657% $216.30 $85.32 4.392% $3.75 $0.00 $89.07 $305.36 Wind+Storage-Monticello,UT,200 MW,CF:29.5%+BESS:100%pwr,4 hours No 4,500 $3,332 $83 6.657% $227.34 $85.32 4.392% $3.75 $0.00 $89.07 $316.40 Wind+Storage-Medicine Bow,WY,200 MW,CF:43.6%+BESS:100%purr,4 hours No 6,500 $3,252 $83 6.657% $222.05 $85.32 4.392a/o $3.75 $0.00 $89.07 $311.12 Wfihd+Storage-Goklendale,WA,200 MW,CF:37.1%+BESS:100%pwr,4 hours No 1,500 $3,389 $83 6.657% $231.15 $85.32 4.392a/o $3.75 $0.00 $89.07 $320.21 Wind+Store e-Offshore,Northern,CA,CF:47.oa/+BESS:100% r,4hours No 0 $6,545 $182 6.657% $447.82 $145.32 4.392% S6.38 $0.00 S151.70 S599.52 Idaho Falls,ID Solar+Wind+BESS:100%purr,4 hours No 4,700 $6,194 $114 6.657% $419.87 $149.51 4.392% S&52 $0.00 $155.03 $574.90 Lakeview,OR Solar+Wind+BESS:100%pwr,4 hours No 4,800 $6,052 $116 6.657% $410.55 $148.51 4.392% $6.52 S0.00 $155.03 $565.58 Milford,UT Solar+Wind+BESS:100%Pair,4 hours No 5,000 $6,238 $113 6.657% $422.78 $148.51 4.392% $6.52 S0.00 $155.03 $577.81 Rock Springs,WY Solar+Wind+BESS:100%Pair,4 hours No 6,400 $5,703 $114 6.657% $387.27 $148,51 4.392% $6.52 S0.00 $155.03 $542.30 Yakitna,WASolar+Wind+BESS:100%pwr,4 hours No 1,000 $5,898 $115 6.657% S400.27 $148.51 4.392% $6.52 S0.00 $155.03 $555.30 Geothermal-Dual Flash Expaosionof Blundell Plant Yes 4,500 $3,835 $117 6.015% $237.74 $115.00 0.872% $1.00 $0.00 $116.00 $353.74 Geothermal-Greenfickl Bin Plant Yes 4,500 $5,568 $117 6.015% $341.93 $115.00 0.872% $1.00 $0.00 $116.00 $457.93 Nuclear-Advanced LWR,600 MW Site Yes N/A $8,416 $722 5.8461/. $534.16 $170.60 9.4241/. $16.08 $0.00 $186.68 $720.83 Nuclear-Advanced LWR,1200 MW Site Yes N/A $7,272 $722 5.846% $467.32 $152.29 9.424% $14.35 $0.00 $166.64 $633.97 Advanced Nuclear Reactor(AR),dual unit,with Thermal Storage(1000 Mwe intemonncenon with 1705 MWh Storage,638 MW initial base generation) Yes N/A $8,772 $722 5.846% $554.99 S472.81 9.424% S44.56 $0.00 $517.36 $1,072.36 Advanced Nuclear Reactor(AR)with unproved fuel(1000 Mwe mtemoarection with 1705 MWh Storage, 690MWbase gee. Yes N/A $8,772 $722 5.846% $554.99 $286.40 9.424% $26.99 $0.00 $313.39 $868.39 1/Input into IRP 50 and PAR Model Resuhs presented without credits Information Presented is Illustrative CCUS costs are incremental and include envknomental upgrade costs but are missing underlying coal unit costs 63 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.4-2023 IRP Update Supply Side Resources (2022 $) Information Presented is Illustrative C114ertto 3/MWh Supply Side Resource Options Mid-Calendar Year2022 Dollars(S) Lerelaea Dtel cresn 3/Mw4 Frc r..cream/rtc lsdar Frc r..Coa1t:/Irgsw.r Tot.l aesoarre-t Fleaidon Capacity Total Fixed Storage Capitalized O&M csisualued Integration Cwt Only)/OQ T.,Credits(CCUS Only)/45Q T..Coait,(CCUS witM1 RTC/ITC/"Q Re$nnree De.c ion (AFSL) Factor 2/ ($/MWh) mcleney wasoua $/MWh O&Ml/ Ponolus, 1/ 1/ Total Resource Cast 0.1y) Only) Credits SCCT Aero x4 0 33°f4 $56.02 N/A $ 4.46 $ 41.26 $ 0.28 14.14% $ 0.04 $ - $97.60 $ - - $97.60 SCCT Frame"J"xl 0 33% $34.25 N/A $ 4.46 $ 40.51 $ 2.32 14.14% $ 0.33 $ - $77.41 $ - - $77.41 SCCT Frame"J"xl,30H2-onsite hydrogen production and liquif.d storage 0 33% $114.81 N/A $ 5.24 $ 48.14 $ 2.44 14.14/. $ 0.34 $ - $165.73 $ - $165.73 SCCT Fame"I"XI,100H2-onshe hydrogen production and liquified storage 0 33% $182.92 N/A $ 7.04 $ 66.82 $ 2.23 14.14% $ 0.32 $ - $252.28 $ (29.18) ITC $223.11 SCCT Frame"J"X1,100112-pipelne Wig- Valley 0 33% $67.60 N/A $ 7.04 $ 66.82 $ 2.23 14.14% $ 0.32 $ - $136.97 $ (4.12) ITC $132.85 SCCT Frame"J"XI,100H2-pipeline McNary 0 33% $118.59 N/A $ 7.04 $ 66.82 $ 2.23 14.14fo $ 0.32 $ - $187.95 $ (4.12) ITC $183.83 SCCT Frame"J"XI,10011 BF-onsite hydrogen production and liquified storage 0 33% $166.52 N/A $ 7.04 $ 66.82 $ 2.27 14.14% $ 0.32 $ - $235.94 $ (26.11) ITC $209.84 CCCT Dry"1",1Xl 0 78% $19.89 N/A $ 4.46 $ 27.80 $ 1.61 14.39% $ 0.23 $ - 549.53 $ - - 549.53 CCCT D "1",DF,1.1 0 1 12% $28.38 1 N/A $ 4.46 $ 38.96 $ 1.15 14.39% $ 0.16 $ $68.65 $ $68.65 SCCT Aero x4 1,500 33% $58.91 N/A $ 4.46 $ 41.33 $ 0.30 14.14% $ 0.04 $ - $100.58 $ - - $100.58 SCCT Frame"J"at 1,500 33% 535.51 N/A $ 4.46 $ 40.48 $ 2.43 14.14% $ 0.34 $ - $78.76 $ - - $78.76 SCCT Frame"J"xl,30112-onsite hydrogen production and liquif d storage 1,500 33% $119.91 N/A $ 5.24 $ 48.10 $ 2.55 14.14%. $ 0.36 $ - $170.93 $ - - $170.93 SCCT Frame"T Xl,100H2-onsite hydrogen production and liquified storage 1,500 33% $191.81 N/A $ 7.04 $ 66.76 $ 2.38 14.14/. $ 0.34 $ - $261.29 $ (30.57) ITC $230.72 SCCT Frame"J"XI,IOOR2-pipeline southern OR 1,500 33% $69.03 N/A $ 7.04 $ 66.76 $ 2.38 14.14% $ 0.34 $ - $139.51 $ (4.32) ITC $134.19 SCCT Frame"'J Xl,IOOH2,BF-onsite hydrogen production and Bquif d storage 1,500 33% $174.13 N/A $ 7.04 $ 66.76 $ 2.38 14.14%. $ 0.34 $ - $243.61 $ (27.35) ITC $216.26 CCCT Dry"J",1X1 1,500 78% $20.76 N/A $ 4.46 $ 27.80 $ 1.68 14.39% $ 0.24 $ - $50.49 $ - - $50.49 CCCT D "J",DF,lxl 1,500 12% $28.25 N/A $ 4.46 $ 38.79 S 1.15 14.39°/ $ 0.16 $ $68.35 $ $68.35 SCCT Aero x4 31000 33% $55.59 N/A $ 4.57 $ 42.48 $ 0.32 14.14e/ $ 0.04 $ - $98'43 $ - - $98.43 SCCT Frame'T'.1 3,000 33% $30.98 N/A $ 4.57 $ 41.50 $ 2.57 14.14/. $ 0.36 $ - $75.41 $ - $75.41 SCCT Frame TJ xl,30112-onsite hydrogen production and liquified storage 3,000 33% $120.14 N/A $ 5.31 $ 4&94 S 2.70 14.14%. S 0.38 $ - $172.06 $ - - $172.06 SCCT Frame U Xl,IOOH2-onsite hydrogen production and liquified storage 3,000 33% $195.92 N/A $ 7.04 $ 66.80 $ 2.52 14.14% $ 0.36 $ - $265.59 $ (12.32) ITC $233.27 SCCT Frame"J"X1,10OR2,BF-Doane hydrogen production and liquified smmge 3,000 33% $177.22 N/A $ 7.04 $ 66.80 $ 2.52 14.145 $ 0.36 $ - $246.90 $ '28.92) ITC 5217.98 CCCT Dry''",1X1 3,000 78% $20.01 N/A $ 4.57 $ 2&48 S 1.78 14.39% $ 0.26 $ - $50.52 $ - - $50.52 2CCTD "J",DF,lxl 3,000 12% $12.67 N/A $ 4.57 $ 39.92 $ 1.15 14.39% $ 0.16 $ $53.80 $ $53.80 SCCT Aero x4 5,050 33% $59.29 N/A $ 4.42 $ 41.24 $ 0.34 14.14% $ 0.05 $ - $100.92 $ - $100.92 SCCTFrame"J"xl 5,050 33% $32,85 N/A $ 4.42 $ 40,15 $ 2.78 14.14% $ 0.3' $ - $76.17 $ - - $76.17 SCCT Frame"J"xl,30H2-onsite hydrogen production and liqudied storage 5,050 33% $129.00 N/A $ 5.21 $ 47.90 $ 2.91 14.14% $ 0.41 $ - $180.22 $ - - $180.22 SCCT Frame"J"Xt,100H2-cosine hydrogen production and Iquifed storage 5,050 33% 5210.67 N/A $ 7.04 $ 66.85 $ 2.72 14.14% $ 0.38 $ - $280.61 $ (34.85) ITC $245.77 SCCT Frame'J"Xl,]OOH2-pipeline Utah North 5,050 33% $72.54 N/A $ 7.04 $ 66.85 $ 2.72 14.14% $ 0.38 $ - $142.49 $ (491) ITC $137.57 SCCT Frame''"Xl,]OOH2,BF-oneire hydrogen production and liqufif'red storage 5,050 33% $190,51 N/A $ 7.04 $ 66.85 $ 2.72 14.14% $ 0.38 $ - $260.46 $ (31.18) ITC $229.28 SCCT Frame T. Xt,100H2,BF-pipeline Dave Johnston 5,050 33% $103.96 N/A $ 7.04 $ 66.85 $ 2.72 14.14% $ 0.38 $ - $173.91 $ (4.91) ITC $169.00 SCCT Frame'T'Xl,10OH2,BF-pipeline Hooter 5,050 33% 545.13 N/A $ 7.04 $ 66.85 $ 2.72 14.14% $ 0.38 $ - $115.08 $ (4.91) ITC $110.17 CCCT Dry IX 5,050 78% $21.42 N/A $ 4.42 $ 27.57 $ 1.92 14.39% $ 0.28 $ - $51.18 $ - - $51.18 CCCT "J",IX,lx1 5,050 12% $12.53 N/A $ 4.42 $ 38.261$ 1.15 14.39% 1$ 0.16 $ $52.10 $ $52.10 SCCT Aero x4 6,500 33% $68.89 N/A $ 4.33 $ 3'.89 $ 0.38 14.14% $ 0.05 $ - $109.22 $ - - $109.22 SCCT Fmme"1"xl 6,500 33% $37.89 N/A $ 4.33 $ 39.32 $ 2.91 14.14% $ 0.41 $ - $80.53 $ - - $80.53 SCCT Fame 31:xl,30H2-onsite hydrogen production and liquified storage 6,500 33% $138.66 N/A $ 5.15 $ 47.30 $ 3.05 14.14% $ 0.43 $ - $189.44 $ - - $189.44 SCCT Frame''"Xl,10OH2-onsite hydrogen production and liquified storage 6,500 33% $224.34 N/A $ 7.04 $ 66.82 $ 2.84 14.14% $ 0.40 $ - $294.41 $ (36.50) ITC $257.91 SCCT Frame''"Xl,]OOH2,BF-onsite hydrogen production and liqu�ed storage 6,500 33% $203.23 N/A $ 7.04 $ 66.82 S 2.84 14.14% $ 0.40 $ - $273.30 $ (32.66) ITC $240.64 SCCT Fame"1"Xl,]OOH2,BF-pipeline Naughton 6,500 33% $74.12 N/A $ 7.04 $ 66.82 $ 2.84 14.14% $ 0.40 $ - $144.18 $ (5.15) ITC $139.04 SCCT Frame"J"Xl,100H2,BF-pipeinrc Jim Bridger 6,500 33% $93.85 N/A $ 7.04 $ 66.92 $ 2.84 14.14% $ 0.40 $ - $163.91 $ (5.15) ITC $158.77 CCCT Dry"J",IXJ 6100 78% $23.63 N/A $ 4.33 $ 27.04 $ 2.01 14.39% $ 0.29 $ - $52.97 S - - $52.97 CCCT ''",DF,lxl 6,500 12% $21.96 N/A $ 4.33 $ 37.21 $ 1.15 14.39% $ 0.16 $ 1 $60.48 1$ $60.48 64 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.4-2023 IRP Update Supply Side Resources (2022 $) (Continued) Information Presented is Illustrative Comertto$/ h Supply Side Resource Options Mid-Calendar Year 2022 Dollars(S) Lekraea Fuel credis $mlwlt M Tas Credla/ITC(501, ITC Tax Credits/ITC l50,, Total Resource Cost DeSad.. Capacity Tool Fixed Storage CIPle"ized O&M Ogbliaed uwgrarim Cost Only)/0.5QTas Cosaa(CCUS 0n1y)/450Taa Credits(CCUS with M/MI45Q Re$Qalre DeSc- OII (AFSL) Furor 3/ ($/MWh) Fll dauey $/mmBtu $/MWh O&MI/ Premium 1/ II Toted a...eCast Only) Only) Credits Pc CLUB oxy-Conilnstion retrofit @ 100 MW pre-retrued basis 5,000 85% $53.79 N/A $ 4.42 $ 81.01 $ 18.68 0.00% $ - $ - $153.49 $ (54.36) 45Q $99A2 PC CCUS retrofit @ 330 MW pre-retrofit basis 6,500 85% $38.81 N/A $ 4.42 $ 69.13 $ 21.70 0.00% $ - $ - $129.64 $ (43.13) 45Q $86.51 PC CCUS retrofit @ 700 MW -retrord bass 6,500 85% $26.10 N/A $ 4.42 $ 64.81 $ 20.79 0.00% $ $ $111.69 $ 40.44 45Q $71.26 Li-Im 4-hoar,200 MW N/A 17% $135.55 85% $ - $ - Included 0.00% $ - $ - $135.55 $ (35.64) ITC $99.91 Incremental,double energy capacity(L-ion,41a,200MW) N/A 17% $116.42 85% $ - $ - Included 0.00% $ - $ - $116.42 $ (29.16) ITC $87.26 Limbo,4-hour,500 MW N/A 17% $132.45 85% $ - $ - Included 0.00% $ - $ - $132.45 $ (34.81) ITC $97.63 Incremental,double energy capacity(I,iou,41a,500MW) N/A 17% $114.21 8'% Included 0.00% $ - $ - $l14.21 $ (28.63) ITC $85.58 Ltloq 4-hour,l000MW N/A 17% $129.06 85% $ - $ - Included Q00% $ - $ - $129.06 $ (33.91) ITC $95.15 Incremental,doable one (L-ion,4hr,1000 N/A 17% $111.32 85% $ $ Included 0.00% $ $ $111.32 $ 27.90 ITC $83.42 Flow Battery,4 haur,200 Mw c N/A 17% $188.28 85% $ - $ - $ 0.03 0.00% $ - $ - $188.31 $ (59.22) ITC $129.08 Incremental,double energy capacity(Flow,4hr,20OMW) N/A 17% $125.98 85% $ - $ - $ - 0.00% $ - $ - $125.98 $ (49.62) ITC $76.36 Flow Battery,4 how,1000 MW N/A 17% $171.49 70o/o $ - $ - $ 0.13 0.00% $ - $ - $171.62 $ (54.97) TTC $116.65 Incremental,double ener ca c' Flow,4hr,1000 N/A 17% $112.48 85% $ $ $ 0.00% $ $ $112.48 $ 45.5 ITC $66.91 Gravity Battery,4how, N/A 17% $256.58 83% $ - $ - Included 0.00% $ - $ - $256.58 $ (111.55) ITC $145.03 Incremental,double energy capacity(Gravity,41r,20OMW) N/A 17% $109.65 " $ - $ - Included 0.00% $ - $ - $109.65 $ (60.81) ITC $48.84 Gravity Battery,4 hour, N/A 17% $239'97 M% $ - $ - lucluded 0.00% $ - $ - $239.97 $ (104.32) ITC $135.66 Incremental,double energy capacity(Gravity,4hr,500MW) N/A 17% $98.17 83% $ - $ - Included "0% $ - $ - $98.17 $ (54.44) ITC $43.72 Gravity Battery,4 how, N/A 17% $149.66 83% $ - $ - Included 0.00% $ - $ - $149.66 $ (65.06) ITC $84.60 Ivcmmerdal,double ener a c (Grit ,4hr,1000Mw) N/A 17% $57.20 83% $ $ Included 0.00% $ $ $57.20 $ (31.72) ITC $25.48 Adiabatic CAES,RESC,125 MW,1000 MWh 6,500 33% $61.36 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $62.48 $ (18.35) ITC S44.12 Adiabatic CAES,RESC,125 MW,1250 MWh 6,500 38% $55.00 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $56.12 $ (16.46) ITC $39.65 Adiabatic CAES,RESC,125 MW,1500 MWh 6,500 38% $60.08 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $61.20 $ (18.18) ITC $43.01 Adiabatic CAES,RESC,125 MW,2000 MWh 6,500 38% S61.87 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $62.99 $ (18.78) ITC S44.21 Adiabatic CAES,RESC,125 MW,3000 MWh 6,500 38% $65.97 60% $ - S - $ 1.05 6.27% $ 0.07 $ - $67.09 $ (20.16) ITC S46.93 Adiabatic CAES,RESC,125MW,6000 MWh 6,500 38% $87.21 60% $ $ $ 1.05 6.27% $ 0.07 $ $88.33 $ (27.3p ITC $61.02 Adiabatic CAES,RESC,250 MW,4000 MWh 6500 38% $55.90 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - S57.01 $ (17.24) ITC $39.78 Adiabatic CAES,RESC,250 MW,6000 MWh 6,500 38% $62.06 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $63.17 $ (19.31) ITC $43.86 Adiabatic CAES,RESC,250 MW,12000 MWh 6,500 38% $81.48 60% $ $ $ 1.05 6.27% $ 0.07 $ $82.59 $ (25.84) ITC $56.75 Adiabatic CAES,RESC,500 MW,4000 MWh 6,500 33% $52.02 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $53.14 $ (16.00) ITC $37.14 Adiabatic CAES,RESC,500 MW,5000 MWh 6,500 38% $46.53 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $47.64 $ (14.31) ITC $33.33 Adiabatic CAES,RESC,500 MW,6000 MWh 6500 38% $49.50 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - $50.62 $ (15.32) ITC $35.30 Adiabatic CAES,RESC,500 MW,8000 MWh 6,500 38% $52.58 60% $ $ $ 1.05 6.27% $ 0.07 $ $53.69 $ 16.35 ITC $37.34 65 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Table 5.4-2023 IRP Update Supply Side Resources (2022 $) (Continued) Information Presented is Illustrative Supply Side Resource Options $/MWh Mid-Calendar Year 2022 Dollars(S) Lewlized Net CYesn pTt Tax ereda:/ITC Isdar PTC Ta.Credits/ITC(sdar -sax.Cart B-dou Capeity S-,a Capitalized O&M Uphalimd lategradoa Cast oalyl/IQ Tax-sts ICCUS Only)/IQ Tax Credits OXUS wMi M/nC/454 Resource Descriptionto(AFSL) Factor 3/ at Fixed$/M enc diidy $/mnrBN $/MWh O&MI/ Pmadion t/ I/ Taal Resource cast o.1y) Only) bests Adiabatic CAES,RESC,500 MW,12000 MWh 6,500 38% $59.21 60% $ - $ - $ 1.05 6.27% $ 0.07 $ - S60.32 $ (18.58) ITC S41.74 Adiabatic CAES,RESC,500 MW,24000 MWh 6,500 38% $79.75 60% $ $ $ 1.05 6.27% $ 0.07 $ $80.87 $ (25.50 ITC $55.37 Pumped Hydro,Southern OR N/A 42% $78.09 78% $ - $ - $ 0.51 0.00% $ - $ - $78.60 $ (21.69) ITC $56.91 Pumped Hydro,Portland North Coast N/A 42% $78.09 78% $ - $ - $ 0.51 0.00% $ - $ - $78.60 $ (21.69) ITC $56.91 Pumped Hydro,Central WY N/A 42% $78.09 78% $ - $ - $ 0.51 0.00% $ - $ - $78.60 $ (21.69) ITC $56.91 Pumped Hydro,Eastern WY N/A 42% $78.09 78% $ - $ - $ 0.51 0.00% $ - $ - $78.60 $ (21.69) ITC $56.91 P d H dro,Central1 N/A 42% $78.09 78% $ $ $ 0.51 0.00°/a $ $ $78.60 $ 21.69 ITC $56.91 l7hma Iron Art Bahia ,max CF:17% N/A 17% $323.95 40% $ $ Included 0.00% $ $ $323.95 $ (102.03 ITC S221.92 Solar-Idaho Falls,ID,20 MW,26.1%CF 4,700 26% $55.16 N/A $ - $ - $ - 0.00aaa $ - $ 0.74 $55.90 $ (19.00) PTC $36.90 Solar-Lakeview,OR,20 MW,27.6%CF 4,800 28% $55.21 N/A $ - $ - $ - 0.00% $ - $ 0.74 $55.95 $ (1900). PTC $36.95 Solar-Mdford,UT,20 MW,30, CF 5,000 30% $47.28 N/A $ - $ - $ - 0.00% $ - $ 0.74 S48.01 $ (19.00) PTC $29.01 Solar-Milford,UT,200 MW,30,2%CF 51000 30% $39.87 N/A $ - $ - $ - 0.00aaa $ - $ 0.74 $40.60 $ (19.00) PTC $21.60 Solar-Rock Springs,WY,NO MW,27.9%OF 6,400 28% S44.57 N/A $ - $ - $ - 0.00% $ - $ 0.74 $45.31 $ (19.00) PTC $26.31 Solar-Yakima, WA,200 MW,241.2%CF 1,000 24% $52.20 N/A $ $ $ 0.00% $ $ 0.74 $52.94 $ 19.00 PTC $33.94 Solar+Storage-Idaho Falls,ID,1.MW,26.1%CIF+BESS:100%pwr,4 hours 4,700 26% $120.49 85% $ - $ - $ - 0.00% $ - $ 0.74 $121.22 $ (54.64) ITC $66.58 Solar+Storage-Lakeview,OR,200 MW,27.6a/o CF+BESS:100a/o pwr,4 homs 4,800 28% $113.56 85% $ - $ 0.. $ - $ 0.74 $114.29 $ (54.64) ITC $59.65 Solar+Storage-MilFord,UT,200 MW,30.2%CF+BESS:100%pwr,4 hours 5,000 30% 1 .18 85% $ - $ - $ - 0.00% $ - $ 0.74 $104.92 $ (54.64) ITC $50.28 Soler+Storage-Rock Spring,WY,20014W,27.9a/o CF+BESS:100a/o pwr,4 hours 6,400 28% $113.43 85% $ - $ - $ - 0.00% $ - $ 0.74 $114.17 $ (54.64) ITC $59.53 Solar+Bruno a-Yakima,WA,200 MW,24.2%CF+BESS:l00% ,4 hours 1,000 1 24% $133.35 1 85% $ $ $ 0.00% $ $ 0.74 $134.08 $ 54.64 ITC $79.44 Wind-Pocatello,ID,20 MW,CF:37.1% 4,500 37% $59.30 N/A $ - $ - $ - 0.00% $ - $ 0.97 $60.27 $ (19.00) PTC S41.27 Wind-Pus,w1lo,ID,200 MW,CF:37.1% 4,500 37% $47.74 N/A $ - $ - $ - 0.00% $ - $ 0.97 $48.71 $ (19.00) PTC $29.71 Ward-Arlington,OR,20 MW,CF:37.1% 1,500 37% $59.05 N/A $ - $ - $ - 0.00% $ - $ 0.97 $60.03 $ (19.00) PTC S41.03 Wind-Arlington,OR,200 MW,CF:3T 1% 1,500 37% S47.13 N/A $ - $ - $ - 0.00% $ - $ 0.97 $48.10 $ (19.00) PTC $29.10 Wind-MontkeOo,UT,20 MW,CF:29.5% 4,500 30% $75.22 N/A $ - $ - $ - 0.00% $ - $ 0.97 $76.19 $ (19+00) PTC $57.19 Wind-MonticeM,UT,200 MW,CF:29.5% 4,500 30a/o $60.79 N/A $ - $ - $ - 0.00% $ - $ 0.97 $61.76 $ (19.00) PTC $42.76 Wind-Medicine Bow,WY,20 MW,CF:43.6% 6,500 44% $49.90 N/A $ - $ - $ - 0.00% $ - $ 0.97 $50.88 $ (19.00) PTC VIM Wind-Medicine Bow,WY,200 MW,CF:43.6% 6,500 44% S40.11 N/A $ - $ - $ - 0.00% $ - $ 0.97 S41.08 $ (19.00) PTC $22.08 Wind-Ooldendale,WA,20 MW,CF:37.1% 1,500 37% $61.60 N/A $ - $ - $ - 0.00% $ - $ 0.97 $62.58 $ (19.00) PTC $43.58 Wind-Gold-diale,WA,200 MW,CF:37.1% 1,500 37% $49.04 N/A S - $ - $ - 0.009`6 S - $ 0.97 $50.01 $ (19.00) PTC $31.01 Wind-Offshore,Northern,CA,CF:47.0% 0 479/6 $103.63 N/A $ - $ - $ - 0.00% $ - $ 0.97 $104.60 $ (13.36) ITC $91.24 Wind-Offshore,Northam,CA,1GW,CF:47.0% 0 47% $103.59 N/A $ $ $ 0.00% $ $ 0.97 $104.56 $ 13.36 ITC $91.20 Wind+Storage-Pocatello,ID,200 MW,CF:37.1%+BESS:100%pwr,4 hunts 4,500 37% $96.51 85% $ - $ - $ - 0.00% $ - $ 0.97 $97.48 $ (54.64) ITC $42.84 Wind+Storage-Arlington,OR,200 MW,CF:37.1%+BESS:100%pwr,4 hours 1,500 37% $93.96 85% $ - $ - $ - 0.00% $ - $ 0.97 $94.93 $ (54.64) ITC S40.29 Wind+Storage -Monticello,UT,200 MW,CF:29.5%+BESS:100%pwr,4 hours 4,500 30% $122.44 85% $ - $ - $ - 0.00% $ - $ 0.97 $123+41 $ (54+64) ITC $68.77 Wind+Storage-Medicine Bow,WY,200 MW,CF:43.6%+BESS:100%pwr,4 hours 6,500 44% $81.46 85% $ - $ - $ - 0.00% $ - $ 0.97 $92.43 $ (54.64) ITC $27.79 Wind +Storage-Goldendak,WA,200 MW,CF:37.1%+BESS:100%Pwr,4 hours 1,500 37% $98.53 85% $ - $ - $ - 0.00% $ - $ 0.97 $99.50 $ (54.64) ITC $44.86 Wind+Stour -Offshore,Northem,CA,CF:47.0%+BESS:IOD%pwr,4 hours 0 1 47% $145+61 1 85% $ I$ I$ 0.00% 1$ $ 0.97 $146+59 $ 54.64 ITC $91.94 Idaho Falls,ID Solar+Wind+BESS:100%pwr,4 hours 4,700 62% $106.00 85% $ - $ - $ - 0.00% $ - $ 0.85 $106.86 $ (54.64) ITC $52.22 Lakeview,OR Solar+Wind+BESS:100%pwr,4 hours 4,800 62% $103.73 85% $ - $ - $ - 0.00% $ - $ 0.85 $104.59 $ (54.64) ITC $49.95 Mff,d,UT Solar+Wind+BESS:100%pwr,4 hours 51000 58% $113.73 85% $ - $ - $ - 0.00% $ - $ 0.85 $114+58 $ (54+64) ITC $59.94 Rock Springs,WY Solar+Wind+BESS:100%pwr,4 hours 6,400 70% $88.77 85% S - $ - $ - 0.00% $ - $ 0.85 $89.62 $ (54.64) ITC $34.98 Yakima,WA Solar+Wind+BESS:100%pwr,4 hours 1,000 59% $107.35 85% $ $ $ 0.00a/o $ $ 0.85 $108.20 $ 54.64 ITC $53.56 Geothermal-Dual Flash ExpansionofBhurdeOPlant 4,500 90% $44.87 N/A $ - $ - $ - 0.00% $ - $ - $44.87 $ (19.00) PTC $25.17 Geothermal-Greenfield B Plant 4,500 90% $58.08 N/A $ $ $ 0.00% $ $ $58.08 $ (19.00) PTC $39.08 Nuclear-Advanced LWR,600 MW She N/A 86% $95.68 N/A $ - $ - $ - 0.00% $ - $ - $95.68 $ (19.00) PTC $76.68 Nuclear-Advanced LWR,1200 MW She N/A 86% $84.15 N/A $ - $ - $ - 0.00% $ - $ - $84.15 $ (19.00) PTC $65.15 Advanced Nuclear Reactor(AR),dual-a,with The-]Storage(1000 Mwe humor rmech-with 1705 MWh Storage,638 MW initial base generation) N/A 86% $14234 N/A $ - $ - $ - 0.00% $ - $ - $142.34 $ (19.00) PTC $123.34 Advanced Nuckar Reactor(AR)with improved fuel(1000 Mwe interronnection with 1705 MWh &.Im,6.MW base neration) N/A 86% $115.27 N/A $ $ $ 0.00% $ $ $115.27 $ 19.00 PTC $96.27 1/Input into IRP SO and PAR Model 2/Wind and solar shapes are input into IRP Plexos Model NC=Not Calculated Tax credal are before Energy Commntray bonus as a is sae specific Information Presented is Illustrative CCUS costs are incremental and include envanomental upgrade costs but are missing underlying coal and costs 66 PACIFICORP—2023 IRP UPDATE CHAPTER 5—MODELING AND ASSUMPTIONS Modeling Enhancements and Resource Updates Suspension of the 2022 All-Source REP The decision to suspend the 2022 All-Source RFP was made on September 29, 2023, four months after the filing of the 2023 IRP. The decision to suspend was taken for multiple reasons, all with the intent to ensure that our procurement decisions are based on the most up-to-date information and in the best interests of our ratepayers, while also considering the evolving market conditions and other pertinent factors: (1) The stay of EPA's disapproval of Utah's state ozone plan; (2) Ongoing rulemaking by the EPA regarding greenhouse gas emissions,with impacts on our system to be determined; (3) Wildfire risk and associated liability across our six-state service area and throughout the West; and (4) Evolving extreme weather risks that necessitate further decision- making regarding PacifiCorp's operational and resource requirements. In parallel with the modeling updates, the PacifiCorp has engaged in a bilateral effort to procure commercially viable battery technology by June 1, 2026, to ensure that such near-term opportunities remain available. The 2023 IRP Update provides new direction on resource needs spanning the timeframe of the 2022 All-Source RFP and indicates appropriate next steps.6 Transmission Option Updates The 2023 IRP Update has changed the way the majority of transmission projects are modeled. Transmission projects do not have to be selected as one unit or zero units, but can be selected in any size from zero to 100% of a line. In practice, this means that if the model deems it most economic to build .25 units of a local area upgrade can be built in 2033, another .3 units can be built in 2034 and the balance can be left unbuilt. For local area upgrades, this correlates more closely to real world cluster project transmission and funding where (as an example) 30% of the cluster chooses to move forward and the balance withdraws. When considering incremental lines, given the far future timelines for those items, this modeling provides appropriate flexibility considering permitting nuances and the complex nature of transmission approvals. Selection of a portion of an incremental transmission line in the distant future signals that this transmission option has value to the system and warrants further study to determine the best sizing and timing of the line. The exception to this change is that known, incremental, near-term projects such as the Boardman to Hemingway and Energy Gateway South lines must be selected as whole projects. Further engagement with stakeholders regarding transmission modeling methodology will occur in the 2025 IRP public input meetings series. 6 Please refer to Chapter 6—Portfolio Development,and Chapter 7—Action Plan. 67 PACIFICORP-2023 IRP UPDATE CHAPTER 5-MODELING AND ASSUMPTIONS Other Contracts PacifiCorp continually updates and negotiates with contracted facilities. The most current contracted resources,as of January 1,2024,are being used for the 2023 IRP Update. Given timing, this is the last update to contracted resources that will be made for the update. Between the 2023 IRP and the 2023 IRP Draft Update, PacifiCorp has signed an additional 13 megawatts of small Oregon Community Solar Projects that will be reflected in the 2023 IRP Update. As an original purchaser of the output of the Priest Rapids and Wanapum hydro projects, PacifiCorp has an annual option to purchase approximately 100 megawatts of the output from these plants at market-based rates. For this 2023 IRP Update, it has been assumed that PacifiCorp elects to purchase this hydro output in each year of the study horizon. 68 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT CHAPTER ( - PORTFOLIO DEVELOPMENT PacifiCorp used PLEXOS' three optimization models to develop an updated preferred portfolio based on inputs and assumptions that have changed since the 2023 Integrated Resource Plan(IRP). This updated resource portfolio is consistent with PacifiCorp's most recent load-and-resource balance.' This chapter presents the 2023 IRP Update preferred portfolio, a comparison of changes relative to the 2023 IRP preferred portfolio, and an updated assessment of certain portfolio variants. dates Key Updates As discussed in Chapter 5, key changes in this 2023 IRP Update are driven by the U.S. Environmental Protection Agency's (EPA) approval of Wyoming's state Ozone Transport Rule (OTR) plan, the stay of EPA's disapproval of Utah's state OTR plan, extensions to the assumed operational life of new natural gas generating resources, energy storage acquisition strategy, forecast load demand, higher coal prices, and natural gas and wholesale power market price updates. The first of these items,the OTR, is particularly impactful. Since the time the 2023 IRP was filed, the Tenth Circuit Court of Appeals granted PacifiCorp's and other petitioners' motion to stay the EPA's final disapproval of Utah's state implementation plans regarding cross-state ozone transport obligations under the 2015 ozone National Ambient Air Quality Standards (referred to herein as the Ozone Transport Rule or OTR). The stay will remain in place while the case is litigated, or until further order of the court. The court held that the agency may not enforce the federal plan while the stay remains in place. PacifiCorp is thus not subject to the federal ozone transport requirements in Utah, which would have become effective on August 4, 2023. Requirements for the 2024 ozone season and beyond will depend on the outcome of litigation. In granting the stay, the court indicated that PacifiCorp and the other petitioners are likely to succeed on the merits. As discussed later in this chapter, PacifiCorp has produced a variant analysis to understand the potential impacts of litigation outcomes that could reinstate OTR compliance requirements for Utah resources. Additionally, the EPA finalized approval of Wyoming's interstate ozone transport plan on December 19, 2023. The final approval of Wyoming's plan removes federal cross-state ozone transport requirements from electric generating units in the state, including PacifiCorp's generating units. The rule is discussed in Chapter 3. ' See Chapter 4—Load and Resource Balance 69 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Other Updates In addition to the key updates noted above, the 2023 IRP Update includes conventional or traditional planning updates where data has changed following PacifiCorp's filed 2023 IRP. Included are updates to load forecast, market prices, changes in existing resources, and PacifiCorp's contracts with other entities. Certain updates to proxy resource data are responsive stakeholder feedback. These updates result in better alignment with potential for some renewable categories, such as pumped storage and geothermal resources, as well as updates to thermal and nuclear assumptions. Gas resources have been updated to reflect the potential flexibility of fuel types as discussed in Chapter 5. This ability to transition to alternative fuels allows gas resources to operate and provide benefits over a longer useful life. This allows upfront costs to be amortized over a longer useful life, which reduces annual costs and leads to greater probability that these resources will be selected. The change to transmission modeling discussed in Chapter 5 has an impact on portfolio selections as PLEXOS is able to "right-size" transmission to fit needs more precisely. This also means that transmission selections can be built in multiple years, reflecting the reality that resources studied in the PacifiCorp Transmission cluster study process may not all reach operational status in the same year, and transmission investments to enable these projects could potentially be staggered. Within the limits of their useful lives, coal plants are eligible to be retired any time after January 1, 2024, and gas plants are eligible for retirement at any point after January 1, 2026. This serves to standardize assumptions and allows the model to indicate if earlier retirements would be selected if feasible. To the extent that earlier retirements are indicated within the limits of PLEXOS, further study could be made. [Fortfolio Development Process Overview In the 2023 IRP Update process, the company revised the process for developing candidate portfolios. In response to stakeholder feedback requesting greater transparency in the process of making portfolio-level reliability adjustments and model simulation granularity adjustments, the company implemented a new, iterative process to generate candidate portfolios. Each iteration in the portfolio process represents one "phase", and each phase consists of six steps. Figure 6.1 illustrates the six cyclical steps in this new process, followed by an overview and detailed description of these steps. Completion of all six steps of this process constitutes a single phase of a study. 70 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.1 —The Six Steps of One Portfolio Development Phase NIT / ST hourly' portfolio dispatch\. 4% Report LT Expansion 'Y ST Model hourly Plan shortfalls t lan shortfalls by bubble Iterative Optimization 6 F Create X11 I Calculate F Model with I ST wanularitv new selection adjustment drivers Process new sel ecti on drivers (files, scenarios) Overview of Steps Step I For each case, the long-term (LT) capacity expansion model is run according to the parameters and constraints of the particular study. This results in an expansion plan of selected resources, retirement decisions and transmission option selection. Collectively these selections are called a"portfolio". Step 2 The LT model expansion plan is fed into the medium-term (MT) and short-term (ST) models. These two models are run in sync where the NIT model optimizes the timing and allocation of constraints, and the ST model performs an hourly dispatch of the portfolio using the NIT model's determinations. For example, if there is limited fuel available to a thermal unit during a year, the MT will allocate that fuel across the year to give the ST model direction for how much fuel is available in each part of the year. 71 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Step 3 The ST model reports shortfalls that must be covered for each location(or"bubble")in the IRP transmission topology. Step 4 The granularity adjustment is calculated as the difference in resource value between the ST model results and the LT model results. This calculation gives the mathematical magnitude of the ST model's superior granularity. Step 5 The reliability shortfalls and granularity adjustments are formatted into data files that can be used in the next phase of the LT model to improve its outcomes. Step 6 The next phase LT model is built in PLEXOS, where shortfalls are represented as an additional load requirement and the granularity adjustment is represented as a cost adder to every resource option. Granularity Adjustment Detail The capacity expansion/LT and ST models in PLEXOS each run and solve using a different view of the study horizon. The LT model uses 7 blocks per month over the 20-year horizon. This means the LT model groups similar hours into a block, and then concurrently solves the entire 20-year horizon. In contrast, the ST model concurrently solves (or dispatches) each week of each year, or roughly 52 steps of 168 hours each, for a specified portfolio of resources as selected in the LT model. In the 7-block LT view,a resource is seen as having a certain amount of value to the system in the 84 blocks it evaluates during each year(7 blocks per month times 12 months). When the ST model dispatches those same resources at an hourly granularity, the ST model also reports the value it calculates for each resource on an annual basis. The mathematical difference between the ST value and the LT value is the granularity adjustment. This adjustment, determined independently in step 4 of each phase of portfolio development, is used in the subsequent phase of the process so as to bring the ST model's finer granularity analysis into the LT model, improving the consistency of capacity expansion. By contrast, in the 2023 IRP, the ST model resource value results were used to inform additional resource selections that were then applied directly in a final run of the ST model. This new iteratively phased approach means that resource selections occur in the LT model using its capacity expansion logic, but with the benefit of the ST model's resource value determinations. Also responsive to stakeholder feedback, a new granularity adjustment is now calculated for every portfolio developed, rather than using one granularity adjustment calculated for each price-policy scenario. This change, while performance and resource intensive, is responsive to stakeholder concerns regarding the limitations of the prior methodology. Figure 6.2 illustrates the calculation of the granularity adjustment, which is completely derived from ST and LT model outputs.A distinct granularity adjustment is calculated for every individual resource in each year of every phase of every study. 72 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Figure 6.2—Granularity Adjustment Determination IF Energy value of a resource's > Energy value of a resources ♦ Increase Fixed Cost ♦ Less likely to pick resource output in LT Model output in ST Model I F Energy value of a resource's < Energy value of a resource's ♦ Decrease Fixed Cost ♦ More likely to pick output in LT Model I I output in ST Model resource This iterative process was carried out for all price-policy scenarios and variant studies. Since each unique granularity adjustment was then fed back into the LT model for the next run, in practice, this means that no two LT model runs have the same granularity adjustment, and each adjustment is wholly dependent upon the performance of resources within that specific portfolio. Reliability Adjustment Detail Stakeholders in the 2023 IRP also identified concerns related to the methodology for making reliability adjustments. For the 2023 IRP Update, in step 3 of each phase, hourly reliability shortfalls are identified by the ST model to be fed back into the LT model to enhance resource selections.As previously noted,the LT model evaluates average conditions during blocks of hours. While this allows the LT model to solve a long horizon in a reasonable time,the average conditions in a block of hours can result in shortfalls in some hours within a block when viewed with enhanced granularity. The ST model is able to identify these hours in its evaluation, and these deficiencies are reported by the ST model as hourly shortfalls. While granularity adjustments are included as an increase or decrease in fixed costs, reliability adjustments are now included as an increase in the load forecast. As with the granularity adjustments these additions are specific to each study's portfolio. However,unlike the granularity adjustment, the shortfall additions to the load file are cumulatively added to the LT need. ST studies are always run with the base load forecast to verify whether LT additions were sufficient to eliminate shortfalls in all hours. As an example, suppose the phase one portfolio (the very first iteration of the six steps for a particular study)reports a shortfall of 250 megawatts in Utah North on June 8,2032, at 8 PM. This 250 megawatt shortfall is added to the base load file on June 8, 2032, in Utah North, and phase 2 is run with the adjusted load file. If the portfolio selected in phase two reports an additional shortfall of 50 megawatt in Utah North on June 8, 2032, at 8 PM, the 50 megawatt shortfall is added to the adjusted load file, such that the load for that day and time is now 300 megawatts higher than the original phase one load forecast. Once no shortfalls are reported by the ST model (using the base load forecast), the adjusted load file used to select a reliable portfolio continues to be applied so that each later phase includes requirements sufficient to induce the LT model to select a portfolio that is reliable. These adjustments are unique to each price policy scenario/variant. These changes in the application of reliability and granularity adjustments has led to an iterative process where there is a loop from the LT model to the MT and ST models and back to the LT model. This process can be continual, and results evolve over multiple phases. At some point, the process leads to a portfolio that is reliable.Additionally,ongoing granularity adjustments will lead to diminishing returns on cost reductions. The process is considered complete once portfolios are reliable and the present value revenue requirement (PVRR) of reliable portfolios reports changes within a small range. 73 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT referred Portfolio Development As discussed above, the iterative study process was completed for all studies in the 2023 IRP Update. The fully unconstrained Medium Gas, Medium CO2 (MM) study was iterated through eight distinct phases of granularity or reliability adjustments before reaching a point where the results stabilized, and no further significant progress was evident. The portfolios generated in this eight-phase study process were all eligible to be selected as the systemwide best portfolio. Given state policy requirements, however, the systemwide portfolio was not expected to meet all state-specific compliance obligations. To generate an optimal, all-state portfolio, the systemwide portfolio must be integrated with selections optimized under each state's requirements, requiring additional studies. These additional studies were created by layering state compliance constraints into the LT model, and these model runs went through the same iterative process as described above. The preferred portfolio leveraged the resource selections of the least-cost MM system-wide portfolio,the least-cost MM Oregon Policy portfolio and the least-cost Social Cost of Greenhouse Gas (SC-GHG) Washington Policy portfolio. Figure 6.3 illustrates the strategy for the integration of optimal resource selections for all states. Using the figure as a guide,if a given resource is selected as optimal for one state but is not selected in the systemwide portfolio nor for any other individual state, then that resource is assumed to belong to the selecting state to meet its specific requirements. If a resource is selected as optimal for a specific state and systemwide portfolio, it is assumed shared. Figure 6.3 —Integrated Portfolio Strategy PLD(OS Portfolios Preferred Portfolio (unified) Systemwide • Endogenous • All options Selected • Expected case Resources California,Idaho, Utah,Wyoming Washington • All necessary selections included All except All except • Endogenous in preferred • All options portfolio Washington Oregon share share • Washington specific: • Participation All SCGWA CEIP,RPS sharing based on share which portfolio(s) each resource Oregon appears in Oregon Oregon plus • Endogenous Washington Washington • All options share • Oregon specific small-scale,CEP, RP5 \ 74 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Systemwide Portfolio This portfolio was developed through the iterative process without any initial restrictions on resource selection, state needs, transmission availability, or any other inputs. Given the universal benefit of some number of renewables in the iterative approach (phases with higher renewable selections led to an overall lower PVRR),it became clear that the LT model would select additional renewables if the model had the benefit of improved granularity. PacifiCorp began testing strategies that required the model to pick minimum amounts of renewable resources that interconnection study results indicate could be available through 2028. The model was still allowed to select additional renewable resources. The amounts tested ranged from 15% to 100% of the resources modeled as available through 2028 from the serial, transition, cluster one and cluster two interconnection studies. The version requiring 25% of these resources had the lowest PVRR of the tests, therefore the 25% requirement was carried through further systemwide cases. The MM systemwide case requiring the selection of 25%of the cluster study options serves as the starting point for the integrated preferred portfolio. This approach allowed multiple additional iterations to be avoided without risk of overbuilding renewables. Oregon and Washington Policy Portfolios While many resources identified in the unconstrained systemwide portfolio are cost-effective for Washington and Oregon policy requirements, separate portfolios were developed which included the policy requirements specific to each state. These portfolios were developed in tandem with the system-level portfolio using the same iterative process. State policy studies include the entire system but also compliance metrics based on that state's regulations. The LT model thus produces a portfolio in these studies in which the entire system is optimized in a way that complies with the state policies. Per Figure 6.1, above, a state's assumed share of resources is determined according to the overlap observed in the integration process, described in detail for Oregon and Washington respectively,below. The least-cost versions of the Oregon and Washington policy portfolios are used in two ways. First, an allocated portion of the selections identified in the compliance portfolios are integrated with the systemwide portfolio. While the systemwide portfolio is the starting point given the substantial overlap among the portfolios, the modifications associated with the state policy portfolios may increase, accelerate, or replace selections in the systemwide portfolio to produce an integrated preferred portfolio that addresses all requirements. Second, the integrated preferred portfolio resource selections are assumed allocated to California, Idaho,Utah, and Wyoming only to the extent they were identified in the systemwide portfolio. Similarly, resource selections are assumed allocated to Oregon only to the extent identified in the Oregon policy portfolio, and resource selections are allocated to Washington only to the extent identified in the Washington policy portfolio. This approach differs from the approach used in the March 2023 filing of the Oregon Clean Energy Plan(CEP),the March 2023 Washington Clean Energy Implementation Plan(CEIP)re-filing, and the November 2023 Washington Biennial Update portfolio developments. Specifically, the previous approach used in the aforementioned filings locked-in the unconstrained systemwide portfolio and then added only the minimal incremental resource selections needed to meet state policies. This earlier approach in PacifiCorp's first CEP and CEIP reports was viewed by PacifiCorp as entirely valid in an environment where all portfolios were very closely aligned and 75 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT optimal resource additions were minimal. Responsive to stakeholder and commission feedback, the new approach for the 2023 IRP Update integrates resource selections from fully optimized state policy model runs rather than "layering resources on top" of the systemwide solution. This approach is expected to be discussed with regulators and stakeholders and subsequently refined for the 2025 IRP. In the current version of this approach, resource adequacy is achieved for the system but is not examined for each individual jurisdiction. For the 2025 IRP, the use of individual jurisdictional forecasts and individual resource allocations is being contemplated to ensure that each state is independently resource adequate.This prevents resource adequacy impacts of individual state policies from shifting to other states. Oregon Integration The Oregon policy study represents the model's view of the least-cost,least-risk resource portfolio for Oregon, irrespective of the unconstrained systemwide portfolio. The process of integration maintains each other states' optimal resource outcomes without diminishing Oregon's selections. However, Oregon is not beholden to adopt the model's recommendations, and the PacifiCorp intends to continue its dialogue with all states to seek the best solutions for its customers. A comprehensive compliance strategy for Oregon will be influenced by staff and Commission guidance, stakeholder engagement, MSP negotiations, resource acquisition procedures, and a number of possible compliance options beyond capacity expansion. These additional considerations are outside the scope of the 2023 IRP Update, but will be considered in separate engagements and reports according to Oregon requirements. Relative to the systemwide portfolio, the Oregon policy study adds peaking resources with renewable fuel in 2030, additional utility scale wind, as well as small-scale renewable resources mandated by Oregon law. The renewable-fueled peaking unit replaces a hydrogen convertible gas- fueled peaking unit from the systemwide portfolio. This resource is assumed to be fully allocated to Oregon. The Oregon share of the incremental utility-scale wind resource additions is comparable to the small-scale wind requirement, and so Oregon's share of utility scale wind will be acquired as small-scale resources in the integrated portfolio. Utility-scale solar selections decrease in the Oregon run compared to the unconstrained systemwide portfolio, even when required small-scale solar additions are considered. Therefore, utility-scale solar in the preferred portfolio is reduced slightly relative to the systemwide portfolio to represent a reduction in Oregon's share of that resource. The Oregon policy study also results in an acceleration of battery resources relative to the systemwide portfolio. Oregon energy efficiency and demand response measures, already fully allocated to Oregon, are taken directly from the results of the Oregon compliance study for inclusion in the integrated all-state preferred portfolio. Washington Integration Similar to Oregon's policy portfolio integration, Washington's policy study was compared to the unconstrained systemwide portfolio, and Washington's situs selections were integrated based on the differences between resource selections in the two portfolios. As anticipated, when the system is planned and operated on the basis of the SC-GHG CO2 assumption, as in the Washington policy study, total system resource selections are considerably in excess of those needed by Washington to achieve Clean Energy Transformation Act (CETA) clean energy targets. This is because while resources are selected for the entire system, Washington only needs a relatively small share of 76 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT those resources for its own jurisdictional goals. A second study was therefore performed which assumed a larger share of new resources attributed to Washington,based on Washington's roughly 22% share of PacifiCorp's western states (also known as Control Area Generation West or CAGW). This results in fewer total resources and ensures that selected resources are the best of what is available. After accounting for the policy benefits of Washington's system share of the resource selections previously identified in the systemwide study, the CAGW study results indicated that wind resources were the best means of compliance, and over 400 megawatts of additional wind resources in 2030 were incorporated in the preferred portfolio that would be fully allocated to Washington.Washington is also allocated additional wind and solar resources in 2032- 2037, and a small amount of battery resources which were accelerated into 2029. Additionally, demand response and energy efficiency in the preferred portfolio match the selections from the Washington policy run. A comprehensive compliance strategy for Washington will be influenced by staff and Commission guidance, stakeholder engagement, MSP negotiations, resource acquisition procedures, and a number of possible compliance options beyond capacity expansion. These additional considerations are outside the scope of the 2023 IRP Update, but will be considered in separate engagements and reports according to Washington requirements. Preferred Portfolio Integration Outcomes The integrated preferred portfolio resulting from the changes described above is mostly shared among all states, though differences grow in the second half of the study horizon, as shown in Figure 6.4. Figure 6.4-2023 IRP Update System and Situs Resource Allocations 25,000 >� 20,000 v M M 15,000 U 10,000 S,000 - a) 2 0 * Ln o r oo a) O r-q N rn t Ln o r-- oo ai o � N E N N N N N N Cn m rn cn cn rn m Cn M M -t -t -t 7 O O O O O O O O O O O O O O O O O O O U N N N N N N N N N N N N N N N N N N N Shared by all states: ■System Renewable ■System Clean Baseload ■ System Storage Situs or shared by some states: Renewable Natural Gas NonEmitting Peaker Storage 77 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Much of the preferred portfolio closely matches the least cost systemwide MM portfolio. The preferred portfolio moves 134 megawatts of battery early into 2029 from 2031, 2036 and 2037, and adds a total of 101 megawatts of battery storage over the system view. Total peaking is 43 megawatts higher in the preferred portfolio than in the system view, although 224 megawatts of gas peaking units are assumed to be non-emitting to meet state requirements,whereas the system- wide portfolio assumed all gas peaking is fueled by natural gas. The integration of Oregon and Washington energy efficiency and demand response adds 109 total megawatts. Washington's 443 megawatts of situs wind comes online in 2030, and Oregon's small-scale wind and solar are integrated into 2030-2033,reducing Oregon's share of utility-scale solar in 2033,2034, and 2037. No other changes were indicated by state-level requirements, and the situs wind and small-scale renewables are all assumed to be situs to Oregon and Washington. Table 6.1 below shows changes to the systemwide portfolio for state compliance, color coded by which state required the change. Table 6.1 —Preferred Portfolio Resource Integrations (Installed Capacity, M Situs/Partial Share Resources Oregon Washington OR and WA WA and Sys OR and Sys Category 2030 2031 2032 2033 1 2034 2035 2036 2037 2038 2039 2040 2041 2042 Natural Gas - - - - NonEmitting Peaker 224 - - - - - 59 - UtilityScaleWind 443 1580 15 - - - - - - - - - Small Scale Wind - 67 172 - - - - - - - - UtilityScaleSolar - - 449 93 1009 Small Scale Solar 369 5 - 109 - Clean Baseload - - - - - - - 4hr Battery 134 - 8 - 3 - - - 9H Storage(Long Duration) - - - - - - Total 529 1036 16 1655 636 96 0 0 1 555 8360 3139 758 Figure 6.5 below shows allocations through 2032 of all resources in the preferred portfolio using similar Venn diagram imagery to Figure 6.3, above. Figure 6.5—Allocation of the 2023 IRP Update Preferred Portfolio Through 2032 Rest of System F_ Energy Efficiency d Demand ResponseMW Oregon 2030 Non- 01 emitting Peaker 224 MW Solar Wind Storage Clean 1,715 3,944 2,015 Baseload 2030 Small-scale LIVind �� Solar 369 MW MW MW MW 500 MW 2032 Small-scale Wind 67 MW Energy Efficiency and Demand Response Washington 030 utility-scale Energy,Efficiency Wind 443 MW andl •• 78 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT referred Portfolio Results Figure 6.6 reports that PacifiCorp's 2023 IRP Update integrated preferred portfolio continues to include substantial new renewables, facilitated by incremental transmission investments, demand-side management(DSM) resources, significant storage resources,NatriumTM advanced nuclear, and peaking resources. Figure 6.6—2023 IRP Update All-State Preferred Portfolio Cumulative Changes in Installed Capacity 30000 25000 j 20000 m a 15000 10000 5000 0 ^ .................._ _��e�� -5000 -10000 o"' o°` ■Coal ■Gas ■Contracts ■QF ■Hydro vA Nuclear ■Hydro Storage ■Battery ■Solar ■Solar+Storage ■Wind ■Geothermal ■Energy Efficiency ■Demand Response ■Peaking ■Converted Gas *Note: "Coal"includes both minority and majority owned coal resources,including Jim Bridger Units 3 and 4 with CCUS. "Coal"does not include coal resources converted to gas.Coal resources converted to gas are categorized under"Converted Gas"and only show at retirement,as the conversion does not increase the installed capacity of the resource."Gas"includes only existing gas resources.New gas peaking and new hydrogen peaking resources are grouped under"Peaking"."Nuclear"includes only the NatriumTM advanced nuclear project. Figure 6.7 summarizes the annual nameplate capacity in the 2023 IRP Update relative to the 2023 IRP preferred portfolio for the 19-year period 2024 through 2042. Consistent with the updates to the OTR and changes in gas peaking unit assumptions, significant differences can be seen between the 2023 IRP and the 2023 IRP update. 79 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Figure 6.7—Cumulative Increase/(Decrease) in 2023 IRP Update less 2023 IRP Preferred Portfolio 6000 4000 2000 0 ------ ------ ---- ------ -2000 -4000 �r -6000 -8000 -10000 -12000 �o IN�o �o �o �o IN ■ Coal ■Gas ■Contracts ■QF Hydro 4,1 Nuclear ■Hydro Storage ■Battery ■ Solar ■ Solar+Storage ■Wind ■Geothermal ■Energy Efficiency ■Demand Response ■Peaking ■Converted Gas As a result of EPA's approval of Wyoming's OTR plan and the stay of EPA's disapproval of Utah's OTR plan, certain coal units' end-of-life assumptions vary from the 2023 IRP. There is a reduction in early solar and wind resources given the existing thermal fleet's ability to operate with fewer restrictions. The adjustment to include gas peaking resources as convertible to a non- emitting fuel in the future led to an increased selection of peaking units. This selection offsets some renewables due to the peaking units' ability to generate as needed. Present Value Revenue Requirement The 2023 IRP Update Preferred Portfolio represents the least cost study over the 20-year study horizon, with a PVRR of$32.807b under the MM price policy scenario. While the overall PVRR of the preferred portfolio is lowest during the study horizon, the final years of the portfolio represent a cost when compared to the unconstrained, systemwide study. From 2040 to 2042, the preferred portfolio is, on average, $72m more costly each year than the unconstrained system portfolio. This indicates that the resources necessary for individual state compliance added relative to the unconstrained system portfolio would not be cost-effective over their economic lives. In addition to evaluating portfolios under the MM price policy scenario, select variant studies were also modeled under each of the other price curves. Under the Medium Gas, No CO2 price curve, and the Low Gas, No CO2 price curve, the systemwide portfolio is least-cost. In other words, the preferred portfolio proves to be the most robust when different future price environments are considered. Tables showing the preferred portfolio and select variants run under the different price policy assumptions appear at the end of the chapter. 80 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Transmission Upgrades To facilitate the delivery of new resources to PacifiCorp customers across the West, the 2023 IRP Update preferred portfolio includes additional transmission investment. As supported by needs established in previous IRPs, PacifiCorp is finalizing construction of the Energy Gateway South and Energy Gateway West Sub-Segment D1 transmission projects and partnering with Idaho Power to build the B2H transmission project, which is expected to come online in the 2026-2027 timeframe. B2H is a 290-mile high-voltage 500 kilovolt transmission line that connects the Longhorn substation near the town of Boardman in Oregon to the Hemingway substation in Idaho. By exchanging certain transmission assets with Idaho Power Company, PacifiCorp will receive additional transmission rights between Hemingway and the Populus substation in Idaho, which is closely tied to existing and future PacifiCorp transmission connecting to Utah and Wyoming. At the Oregon end of the B2H line, additional transmission upgrades are planned to connect B2H to growing loads. In the 2023 IRP Update, many transmission upgrades and the accompanying resources reflect the results of PacifiCorp's generator interconnection "cluster study" process for evaluating proposed resource additions. By evaluating all newly proposed resource additions in an area at the same time, the cluster study process identifies collective solutions that can allow projects that are ready to move forward to do so in a timely fashion. As a result, transmission upgrades and resource additions in the 2023 IRP Update preferred portfolio consider cluster study requests submitted in the past several years.Additional transmission expansion projects can include development of new segments and exploration of new routes that have connections to other areas. Figure 6.8 summarizes the new interconnection capacity selected to facilitate new generation resources identified as part of the 2023 IRP Update preferred portfolio. In addition to providing increased interconnection capacity, transmission upgrades are also expected to allow for increased transfer capability between different areas of PacifiCorp's system. The 2023 IRP Update preferred portfolio includes portions of the following transmission upgrades between the following areas within the IRP topology. Note that modeling for the 2023 IRP Update allowed for partial selection of lines, though that does not indicate that these lines would be uneconomic if built in their entirety. Given the timing identified primarily in the second half of the IRP study horizon, these opportunities will continue to be explored in the future. - Walla Walla to Yakima. - Gateway Sub-Segment D3: provides direct transfers between Jim Bridger and Borah (Populus), but with supporting projects, also facilitates transfers between Wyoming East and Jim Bridger and between Borah and Utah North. - Incremental Gateway Segments: Segments D2.2,D1.2, and Gateway South 2 would be the second iteration of existing or soon to be in service segments from the original Gateway plan and would provide additional transfer capability between Wyoming East and Bridger and between Wyoming East and Clover. - Oregon 500 kilovolt upgrades: several 500 kilovolt upgrades and supporting projects would connect Portland-North Coast, Willamette Valley, Southern Oregon, and Central Oregon. - East-West transfers: together, B2H 2 and Gateway Segment E would further increase transfer capability between PacifiCorp's east and west balancing authority areas. 81 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Figure 6.8—New Interconnection Capacity by Location, 2023 IRP Update Preferred Portfolio 8,000 o C: 6,000 o 0 0 1 1 1 1 i J 4,000 N � U 2,000 U 0 Ln QD I- 00 M O r-I N m ::I- Ln lD I- 00 M O r-I N N N N N N rn M rn M rn m M m M mZt O O O O O O O O O O O O O O O O O O N N cV N N N N N N N N N N N N N N N ■ Wyoming Idaho Utah Oregon Washington New Solar Resources The 2023 IRP Update preferred portfolio includes 2,084 megawatts of solar by the end of 2030, and 3,749 megawatts of new solar is online by 2037, as shown in Figure 6.9. While not shown in Figure 6.9, the company has also previously contracted for one gigawatt of solar resources with commercial operation dates between 2024 and 2026 for customer-directed voluntary renewable procurement programs. Figure 6.9—2023 IRP Update Preferred Portfolio New Solar Capacity* 10,000 8,000 j 6,000 ns � 4,000 U _mJ1JM9&2,000 ' LLJ 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 I RP Update ■2023 I RP * 2023 IRP Update solar capacity shown in the figure includes committed solar resources shown in 2025 and 2026. Resources are shown in the first full year of operation(the year after the year-online dates). This total includes 374 megawatts of small scale solar to meet Oregon requirements. New Wind Resources 82 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT As shown in Figure 6.10, by 2032, PacifiCorp's 2023 IRP Update preferred portfolio includes 6,034 megawatts of new wind resources, and more than 9,800 megawatts of new wind resources by 2037. Figure 6.10—2023 IRP Update Preferred Portfolio New Wind Capacity 12,000 10,000 v 8,000 6,000 4,000 U 2,000 LLULLi rr.i �. 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 I RP Update ■2023 I RP *Note: Wind additions shown are incremental to Energy Vision 2020 and other projects that have come online over the past few years.Resources are shown in the first full year of operation(the year after year-end online dates). This figure includes 254 megawatts of small-scale wind to meet Oregon requirements,and an additional 443 megawatts of utility scale wind to meet Washington requirements. New Storage Resources As shown in Figure 6.11, the 2023 IRP Update preferred portfolio includes 1,626 megawatts of new storage capacity by the end of year 2029 and more than 4,000 megawatts by 2037. Figure 6.11 —2023 IRP Update Preferred Portfolio New Storage Capacity* 10,000 8,000 > 6,000 � 4,000 E U 2,000 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 I RP Update ■2023 I RP *Note: Resources are shown in the first full year of operation(the year after the year-end online dates). This figure includes a total of 101 megawatts of storage resources required by Oregon and Washington for compliance Peaking Capacity The 2023 IRP Update continues to indicate the need for flexible peaking capacity to achieve reliability and minimize risk. A key change since the filing of the 2023 IRP is the addition of peaking capacity in the form of natural gas resources capable of operating with 100% hydrogen fuel.The inclusion of this technology also guards against the future risk of increasingly constrained emissions and future policy requirements. 83 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.12—2023 IRP Update Preferred Portfolio Peaking Resources Capacity* 6,000 — 5,000 � 4,000 3,000 = 2,000 1 1 U 1,000 - ■■�� ■ ■ ■ 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 1 RP Update 2023 1 RP *Note: Resources are shown in the first full year of operation (the year after the year-end online dates). This figure includes 224 megawatts of peaking units for Oregon compliance that can only run on clean fuel. Nuclear Capacity The 2023 IRP Update continues to show the value associated with the NatriumTM Demonstration Project which provides a significant non-emitting resource. A key change since the filing of the 2023 IRP is the stay of the EPA's disapproval of Utah's OTR plan and subsequent ability of the existing thermal fleet to operate with fewer restrictions as a dispatchable resource. Although additional advanced nuclear resources beyond the NatriumTM Demonstration Project are not selected in this update, PacifiCorp is continually updating advanced nuclear resource cost estimates as they become available. Figure 6.13 —2023 IRP Update Preferred Portfolio New Nuclear Capacity 1,600 1,400 1,200 1,000 nz 800 7 600 j 00 2 .. U 00 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 ■2023 1 RP Update 2023 1 RP Demand-Side Management PacifiCorp evaluates new DSM opportunities, which includes both energy efficiency and demand response programs, as a resource that competes with traditional new generation and wholesale power market purchases when developing resource portfolios for the IRP. The optimal determination of DSM resources results in selecting all cost-effective DSM as a core function of IRP modeling. Consequently, the load forecast used as an input to the IRP does not reflect any incremental investment in new energy efficiency programs; rather,the load forecast is reduced by the selected additions of energy efficiency resources in the IRP Update. DSM resources continue to play a key role in PacifiCorp's resource mix. The chart to the left in Figure 6.14 compares total energy efficiency capacity savings in the 2023 IRP Update preferred 84 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT portfolio relative to the 2023 IRP preferred portfolio and includes 4,326 megawatts by the end of the planning period. In addition to continued investment in energy efficiency programs, the preferred portfolio shows a need for incremental demand response programs. The chart to the right in Figure 6.14 compares cumulative demand response program capacity in the 2023 IRP Update preferred portfolio relative to the 2023 IRP preferred portfolio and does not include capacity from existing programs. The 2023 IRP Update has a cumulative capacity of incremental demand response programs reaching 1,123 megawatts by 2042 which represents a 21% increase relative to the 2023 IRP. Figure 6.14—2023 IRP Update Preferred Portfolio Energy Efficiency and Demand Response Capacity Energy Efficiency Demand Response 6,000 1,500 5,000 4,000 1 F 1,000 3,000 a ,000 500 -��1 ,000 ■ 1 1,r11` 0 Vl �0 l- 00 M O N M Vl �0 l- 00 O, O N � h b r, 00 01 O M Vl �0 1, 00 01 O N N N N N N N H1 M M M M M M M M M V V V N N N N N N M M M M M M M M M Ma a 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N ■2023 IRP Update 2023 IRP ■2023 IRP Update ■2023 IRP Market Activity Subsequent to the filing of the 2023 IRP, the EPA's approval of Wyoming's state OTR plan and the stay of EPA's disapproval of Utah's state OTR plan removed the restrictions that limited energy production in the summer from natural gas and coal-fueled resources in Wyoming and Utah. In the absence of the OTR, market purchases can cost-effectively replace some of the incremental renewable resources that were indicated in the 2023 IRP preferred portfolio, leading to higher relative market activity, as shown in Figure 6.15 below. In addition, a 500 megawatt capacity Wyoming market has been added in the 2023 IRP update,representing the ongoing ability to access diverse (and potentially new)regional markets as discussed in Chapter 3. 85 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.15—2023 IRP Update Preferred Portfolio Market Purchases Summer Market Purchases 1400 — 1200 1000 — 800 tko v 600 Q 400 200 0 O1, O�10 011 01� O1� OHO O�y O�� O�� O�� O�� OHO 11 O�� OHO OHO ONy O�� ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti 020231RPUpdate 020231RP Winter Market Purchases 1400 1200 — 1000 800 v en Iv 600 400 200 0 — — — — — — — — — — — — — — — — — — — O�D Otis OI6 001 O�'b OHO Ob0 O'1", O1", O'i Ogk O 1 11, O11 O'b 11 ONO Opt Op , ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ■2023IRPUpdate ■20231RP *Note: "Summer Market Purchases" includes purchases from June through September while "Winter Market Purchases"includes purchases from December and January.While most data for tables and figures in this document comes from LT capacity expansion model results,this figure uses ST model results.For market data,it is appropriate 86 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT to use ST model results because the ST model is run with an hourly granularity which more accurately represents the energy needed to meet load obligations compared to the less granular LT capacity expansion model. Coal and Gas Retirements/Gas Conversions Coal resources have been an important resource in PacifiCorp's resource portfolio for many years. The operating capabilities of these facilities have been able to adapt to changes in the planning environment. For example, PacifiCorp has been able to lower operating minimums and optimize coal dispatch through the Energy Imbalance Market(EIM). This in turn has enabled the company to both reduce fuel consumption and associated costs and emissions by increasingly buying low- cost,zero-emissions renewable energy from market participants across the West,which is accessed by our expansive transmission grid.PacifiCorp's coal resources will continue to play a pivotal role in following fluctuations in renewable energy as the remaining coal units approach retirement dates. EPA's approval of Wyoming's ozone plan and the stay of EPA's disapproval of Utah's ozone plan results in fewer restrictions on coal-fired operation than were assumed in the 2023 IRP. With these updates, Utah coal resources are no longer planned to retire early, as shown in Table 6.2. Hunter and Huntington coal unit retirements, specifically, have returned to the schedule that had been previously indicated by PacifiCorp's 2021 IRP. 87 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.2 —Coal Unit Retirements in the 2023 IRP and 2023 IRP Update Coal 2023 IRP 2023 IRP Update Retirement Retirement Delta to 2023 Unit Year (12/31/_) Year (12/31/_) IRP (Years) As Selected As Selected Colstrip 3 2025 2025 - Colstrip 4 2029 2029 - Craig 1 2025 2025 - Craig 2 2028 2028 - DaveJohnston 1 2028 2028 - DaveJohnston 2 2028 2028 - DaveJohnston 3 2027 2027 - DaveJohnston 4 2039 2039 - Haydenl 2028 2028 - Hayden 2 2027 2027 - Hunter 1 2031 2042 11 Hunter 2 2032 2042 10 Hunter 3 2032 2042 10 Huntington 1 2032 2036 4 Huntington 2 2032 2036 4 JimBridger 1 2037 2037 - JimBridger 2 2037 2037 - JimBridger 3 2037 2039 2 JimBridger 4 2037 2039 2 Naughton 1 2036 2036 - Naughton 2 2036 2036 - Wyodak 2039 2039 - Coal unit exits,retirements, gas conversions, and retrofits scheduled under the preferred portfolio include: • 2023 = Jim Bridger Units 1-2, converted to natural gas in 2024 (same as in the 2023 IRP) • 2025 = Craig Unit 1 retirement (same as in the 2023 IRP) • 2026=Naughton Units 1-2, converted to natural gas in 2026, operates through 2036 (same as in the 2023 IRP) • 2027 = Dave Johnston Unit 3 retirement (same as in the 2023 IRP) • 2027 = Hayden Unit 2 retirement(same as in the 2023 IRP) 88 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT • 2028=Jim Bridger Units 3-4,retrofitted with carbon capture technology in 2028,operates through 2039 (converted to gas conversion in 2030 and retired in 2037 in the 2023 IRP; unit life is extended by 2 years to capture 12 full years of investment tax credits) • 2028 =Dave Johnston Units 1-2 retirement(same as in the 2023 IRP) • 2028 =Craig Unit 2 retirement(same as in the 2023 IRP) • 2028 =Hayden Unit I retirement (same as in the 2023 IRP) • 2029 = Colstrip Unit 4 exit, Colstrip Unit 3 share is consolidated into Colstrip Unit 4 in 2025 (same as in the 2023 IRP) • 2036=Huntington Units 1-2 retirement,no emissions controls(SNCR installation in 2026, operating through 2032 in the 2023 IRP) • 2039 =Dave Johnston Unit 4 retirement(same as in 2023 IRP) • 2039 = Wyodak retirement, no emissions controls (SNCR installation in 2026, operating through 2039 in the 2023 IRP) • 2042 = Hunter Units 1-3 retirement, no emissions controls (SNCR installation in 2026, operating through 2031 and 2032 in the 2023 IRP) 89 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT [This page is intentionally left blank] 90 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Table 6.3 —Comparison of 2023 IRP Update with 2023 IRP Preferred Portfolio (Megawatts) 2023 IRP L" dare Summary Portfolio Capacity by Resource Type and Year,Installed F4W Resource 2024 2025 F:20:2S:::jj 2027 1 2028 1 2029 1 2030 1 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 Expansion Options Gas-CCCT Peaking 395 224 59 836 3.122 749 5,385 OSM-Energy Efficiency 151 211 160 175 192 219 224 250 196 224 230 25P228 292 187 178 218 231 314 4.161 OSM-Demand Response 38 98 110 35 133 61 11 56 112 9 42 1 43 We 71 95 3 1.051 Renewable-Wind 194 1.361 79 443 5 3.952 2.354 1.202 9.818 Renewable-Utility Solar 300 398 654 363 369 5 449 93 1.116 14 3.763 Renewable-Geothermal _ _ _ _ _ _ _ _ _ _Renewable-Battery 400 565 297 337 521 21 3 1.694 17 9 4.016 Renewable-Battery(Long Duration) Storage-CAES Storage-Pumped Hydro -271 i i i8 35 Nuclear 500 500 Existing Unit Changes Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386) Coal Plant Retirements (220] (205) (909) (598) (1,932) Coal-CCUS (699) (699) Coal-SCR Coal-SNCR Coal-Gas Conversions (357) (713) 1,070] Gas Plant Retirements (358) (484) (842) Retire-Hydra (47) (7) (54) Retire-Non-Thermal (32) (32) Retire-Wind (519) (519) Retire-Solar (18) (18) Expire-Wind PPA [41) (64) (99] (200) (405) Expire-Solar PPA (2) (7) (73) (4) (86) Expire-OF 150 0 (1) 3 0 1 1 1 (57] Expire-Other (161) 0 (161) Total 84 1 1.970 1 948 1 1.507 1 730 1 6821 1.524 637 4,2741 2.678 1 368 1 271 1 644 1 2.5581 3861 1781 2.1391 559 330 2023 IRP Update less 2023 IRP Preferred Portfolio SuninaluT Portfolio Capacity lb�Resource Type and Year,InstaHed NfW Resource 1 2024 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 1031 1 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 20427(670) Expansion Options Gas-CCC I - - - - - - - - - - - - - - - - - -Peakmg 395 (382) (345) (230) 836 3,122 749 DStsl-Enerz Effrciencv (69) (48) (37) (40) (27) (17) (37) (415) 84 49 46 96 (25) (301) 36 7 49 91 (112) DSi\•1-Demand Response (1) (54) (98) 52 34 (4) 34 112 9 42 7 12 43 (125) (19) 51 95 3 193 Reservable-Wind (576) (22) (300) (1,900) 443 5 1,169 994 228 662 703 Reservable-Utility Solar (1,169) (2,126) 171 (1,544) (200) 369 5 (972) 449 (207) 17118 14 (4,092) Renerc-able-Geothermal Renewable-Batters (954) (2,529) (63) (1,603) (812) 521 21 (150) 3 152 1.494 17 9 (3,894) Renewable-Batters(Lone Duration) (150) (200) - (350) Storage-C-U.S - - - - - - - - - - - - - - - - - - - - St—ge-Pumped Hydro (8) 8 - - - - - - - - - - - - - - - - - Nul=ar - - - (500) (500) - - (1.000) Existing Unit Changes Coal Plant Retirements (909) )B34 Gas Convert vs CCUS 1 17699 1 1 (699) (0) Coat-SNCR 418 1 1.649 2-067 Total 1 (70) (2,901) (4,700) (52) (3,422) (2,4001 389 1 150 1 332 1 2.350 1 (1101 103 1 22 1 1,677 1 1,446 1 (12)1 2,548 1 944 1 (95) •For the compare,existing unit changes were consolidated for clarify 91 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT [This page is intentionally left blank] 92 PACIFICORP-2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.4-2023 IRP Update Summer Capacity Load and Resource Balance (Megawatts) 2024 2026 2029 Thermal 6,805 6,852 6,769 6,769 6,546 6,234 6,234 6,234 6,234 6,234 Peaker 352 352 352 352 352 352 352 352 352 0 Hydroelectric 60 60 60 60 60 60 60 60 60 60 Wind 504 716 701 701 701 701 681 649 649 649 Solar 279 356 600 595 591 586 582 578 574 570 Other Renewable 41 41 41 41 41 41 41 41 41 41 Storage 1 1 496 496 496 496 496 496 496 496 Purchase 120 120 120 120 120 120 120 120 120 120 Qualifying Facilities 359 358 356 354 352 350 348 346 343 334 Sale 0 0 0 0 0 0 0 0 0 0 Fast Existing Resources 8,521 8,855 9,495 9,489 9,260 8,941 8,914 8,877 8,869 8,505 Market Purchases Peaker 0 0 0 0 0 372 584 584 584 584 Wind 14 14 14 28 28 28 118 118 648 757 Solar 0 0 0 81 162 162 262 264 264 386 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 0 245 428 608 608 684 694 694 Nuclear 0 0 0 0 0 0 485 485 485 485 Fast Planned Resources 14 14 14 353 618 1,170 2,057 2,134 2,675 2,906 Fast Total Resources 8,534 8,869 9,509 9,842 9,877 10,111 10,971 11,011 11,544 11,411 Load 7,679 7,947 7,877 8,137 8,556 8,727 8,906 9,181 8,972 9,105 Private Generation (102) (143) (111) (141) (174) (213) (256) (304) (151) (175) misting-Demand Response (494) (494) (494) (494) (494) (494) (494) (494) (494) (494) New Demand Response (5) (33) (55) (63) (112) (122) (122) (142) (161) (161) New Energy Efficiency (132) (217) (269) (343) (450) (534) (614) (743) (814) (932) Fast Total obligation 6,946 7,060 6,948 7,097 7,326 7,365 7,420 7,498 7,351 7,343 East Reserve Margin 23% 26% 37% 39% 35% 37% 48% 47% 57% 55% Thermal 878 878 872 872 872 872 736 736 736 736 Peaker 0 0 0 0 0 0 0 0 0 0 Hydroelectric 691 695 692 700 700 699 699 699 699 699 Wind 56 56 56 56 56 56 56 56 56 56 Solar 54 54 54 53 53 53 53 52 52 52 Other Renewable 0 0 0 0 0 0 0 0 0 0 Purchase 0 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 0 Qualifying Facilities 146 193 192 192 191 190 190 190 183 183 Sale (7) (7) (7) (7) (7) (7) (7) (7) (7) (7) West Existing Resources 1,818 1,868 1,860 1,866 1,866 1,864 1,727 1,726 1,720 1,719 Market Purchases 1,413 1,235 508 256 478 348 0 0 0 0 Peaker 0 0 0 0 0 0 0 0 0 0 Wind 0 0 0 0 0 0 12 13 277 706 Solar 0 0 0 54 65 65 65 65 65 65 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 27 218 280 376 376 680 688 688 Nuclear 0 0 0 0 0 0 0 0 0 0 West Planned Resources 1,413 1,235 535 528 823 789 453 759 1,030 1,459 West Total Resources 3,231 3,103 2,395 2,394 2,688 2,653 2,180 2,485 2,750 3,178 Load 3,667 3,842 3,931 4,111 4,257 4,466 4,593 4,817 4,813 4,870 Private Generation (45) (69) (68) (89) (111) (137) (166) (201) (111) (130) Existing-Demand Response (21) (21) (21) (21) (21) (21) (21) (21) (21) (21) New Demand Response (71) (94) (122) (128) (155) (173) (173) (187) (192) (193) New Energy Efficiency (64) (123) (134) (142) (176) (205) (211) (263) (252) (269) West Total obligation 3,466 3,535 3,586 3,731 3,794 3,931 4,022 4,144 4,237 4,257 West Reserve Margin -7% -12% -33% -36% -29% -33% -46% -40% -35% -25% Total Resources 11,766 11,972 11,904 12,236 12,566 12,764 13,152 13,496 14,293 14,589 Obligation 10,412 10,595 10,534 10,828 11,120 11,295 11,442 11,642 11,588 11,600 Planning Reverve Margin(13%) 1,354 1,377 1,369 1,408 1,446 1,468 1,487 1,513 1,506 1,508 Obligation+Reserves 11,766 11,972 11,904 12,236 12,566 12,764 12,930 13,155 13,094 13,108 System Position 0 0 0 0 0 0 222 340 1,199 1,480 Reserve Margin 13% 13% 13% 13% 13% 13% 15% 16% 23% 26% 93 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.4 (Cont.)-2023 IRP Update Summer Capacity Load and Resource Balance (Megawatts) 2034 L 2037 2038 JWL 2040 2041 2042 Thermal 6,234 6,234 6,234 4,802 4,104 4,104 2,890 2,890 2,890 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 60 60 60 60 60 59 60 60 60 Wind 649 649 649 649 649 649 649 547 547 Solar 567 563 559 525 521 518 515 511 508 Other Renewable 41 41 41 41 13 13 13 13 13 Storage 495 495 495 495 495 495 495 495 495 Purchase 120 120 120 120 120 120 120 120 120 Qualifying Facilities 330 328 323 272 270 263 262 261 259 Sale 0 0 0 0 0 0 0 0 0 East Existing Resources 8,496 8,490 8,481 6,965 6,233 6,221 5,003 4,897 4,892 Market Purchases 0 0 0 0 0 0 0 0 0 Peaker 584 584 584 640 1,429 1,429 4,377 5,084 5,084 Wind 757 757 757 814 814 814 814 814 814 Solar 411 411 411 715 715 715 715 715 718 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 695 695 705 1,484 1,484 1,484 1,484 1,484 1,484 Nuclear 485 485 485 485 485 485 485 485 485 Past Planned Resources 2,933 2,933 2,943 4,138 4,928 4,928 7,876 8,583 8,586 Fast Total Resources 11,429 11,423 11,424 11,103 11,161 11,149 12,879 13,479 13,477 Load 9,223 9,361 9,564 9,726 9,867 9,980 10,112 10,248 10,428 Private Generation (197) (220) (242) (265) (287) (309) (330) (352) (374) Fisting-Demand Response (494) (494) (494) (494) (494) (494) (494) (494) (494) New Demand Response (178) (186) (194) (224) (261) (261) (283) (349) (349) New Energy Efficiency (1,037) (1,124) (1,209) (1,317) (1,400) (1,498) (1,589) (1,653) (1,752) Fast Total obligation 7,317 7,338 7,424 7,425 7,425 7,418 7,416 7,400 7,459 East Reserve Margin 56% 56% 54% 50% 50% 50% 749/o 82% 81% Thermal 736 736 736 500 500 500 500 500 500 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 699 699 699 699 699 699 699 699 707 Other Renewable 0 0 0 0 0 0 0 0 0 Purchase 0 0 0 0 0 0 0 0 0 Storage 0 0 0 0 0 0 0 0 0 Qualifying Facilities 182 182 181 162 160 159 159 158 159 Sale (7) (7) (7) (7) (7) (7) (7) (7) (7) West Existing Resources 1,611 1,610 1,610 1,354 1,352 1,351 1,351 1,350 1,360 Market Purchases 0 0 0 0 0 0 0 0 0 Peaker 0 0 0 0 0 0 0 0 0 Wind 706 706 743 952 952 952 952 952 952 Solar 65 65 65 65 65 65 65 65 65 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 688 688 787 1,345 1,345 1,345 1,365 1,372 1,372 Nuclear 0 0 0 0 0 0 0 0 0 West Planned Resources 1,459 1,459 1,595 2,362 2,362 2,362 2,383 2,389 2,389 West Total Resources 3,070 3,070 3,205 3,716 3,714 3,713 3,733 3,739 3,749 Load 4,929 4,995 5,068 5,176 5,246 5,318 5,384 5,461 5,647 Private Generation (148) (163) (178) (193) (208) (222) (236) (250) (264) Dasting-Demand Response (21) (21) (21) (21) (21) (21) (21) (21) (21) New Demand Response (200) (201) (202) (206) (229) (229) (257) (264) (265) New Energy Efficiency (299) (322) (314) (357) (355) (366) (396) (391) (429) West Total obligation 4,261 4,288 4,353 4,399 4,433 4,481 4,474 4,535 4,668 West Reserw Margin -289/o -289,o -26916 -16% -16% -17% -17% -18% -20% Total Resources 14,499 14,492 14,629 14,819 14,875 14,862 16,612 17,219 17,226 Obligation 11,578 11,626 11,778 11,825 11,858 11,899 11,889 11,935 12,127 Planning Reserw Margin(13%) 1,505 1,511 1,531 1,537 1,541 1,547 1,546 1,552 1,577 Obligation+Res ernes 13,083 13,137 13,309 13,362 13,399 13,446 13,435 13,487 13,704 System Position 1,416 1,356 1,320 1,458 1,476 1,416 3,177 3,732 3,522 Reserve Margin 25% 25% 24% 25% 25% 25% 40% 44% 42% 94 PACIFICORP-2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.5-2023 IRP Update Winter Capacity Load and Resource Balance (Megawatts) Thermal 6,828 6,875 6,795 6,795 6,578 6,264 6,264 6,264 6,264 6,264 Peaker 323 323 323 323 323 323 323 323 323 0 Hydroelectric 36 36 36 36 36 36 36 36 36 36 Wind 442 602 594 594 594 594 579 552 552 552 Solar 197 288 408 405 402 399 396 393 391 388 Other Renewable 34 34 34 34 34 34 34 34 34 34 Storage 1 1 468 468 468 468 468 468 468 468 Purchase 172 172 172 172 172 172 172 172 172 172 Qualifying Facilities 284 283 281 279 278 276 275 273 271 263 Sale 0 0 0 0 0 0 0 0 0 0 Fast Existing Resources 8,317 8,613 9,111 9,107 8,884 8,566 8,547 8,515 8,510 8,177 Market Purchases 0 0 0 0 0 0 0 0 0 0 Peaker 0 0 0 0 0 372 584 594 584 584 Wind 50 51 51 66 66 66 141 141 640 737 Solar 0 0 0 50 109 109 187 188 188 284 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 0 259 432 602 602 686 696 696 Nuclear 0 0 0 0 0 0 475 475 475 475 Fast Planned Resources 50 51 51 376 608 1,150 1,990 2,075 2,583 2,776 Fast Total Res ources 8,367 8,664 9,163 9,482 9,492 9,717 10,537 10,590 11,093 10,953 Load 5,724 6,097 6,171 6,444 6,754 6,700 6,872 7,145 7,214 7,387 Private Generation (2) 0 0 0 0 (8) (10) 0 0 0 Ebsting-Demand Response (462) (462) (462) (462) (462) (462) (462) (462) (462) (462) New Demand Response (5) (20) (35) (39) (66) (72) (72) (84) (97) (97) New Energy Efficiency (102) (111) (172) (232) (299) (470) (569) (529) (615) (693) Fast Total obligation 5,154 5,504 5,502 5,711 5,927 5,688 5,759 6,070 6,040 6,135 East Reserve Margin 62% 57% 67% 669,6 60% 71% 83% 74% 849,6 79% Thermal 878 878 874 874 874 874 736 736 736 736 Peaker 0 0 0 0 0 0 0 0 0 0 Hydroelectric 538 544 542 555 556 555 555 553 554 554 Wind 74 74 74 74 74 74 74 74 74 74 Solar 44 43 43 43 42 42 42 41 40 40 Other Renewable 0 0 0 0 0 0 0 0 0 0 Renewable 0 0 0 0 0 0 0 0 0 0 Purchase 1 1 1 1 1 1 1 1 1 1 Qualifying Facilities 116 127 127 127 127 126 126 126 120 120 Sale (12) (12) (12) (12) (12) (12) (12) (12) (12) (12) West Existing Resources 1,639 1,657 1,650 1,662 1,662 1,660 1,522 1,520 1,514 1,513 Market Purchases 0 0 0 0 0 0 0 0 0 0 Peaker 0 0 0 0 0 0 0 0 0 0 Wind 0 0 0 0 0 0 11 12 256 617 Solar 0 0 0 41 48 48 48 48 48 48 Other Renewable 0 0 0 0 0 0 0 0 0 0 Storage 0 0 27 250 324 441 441 837 846 846 Nuclear 0 0 0 0 0 0 0 0 0 0 West Planned Resources 0 0 27 291 372 489 500 897 1,151 1,511 West Total Resources 1,639 1,657 1,676 1,953 2,034 2,149 2,022 2,417 2,665 3,024 Load 3,711 3,577 3,676 3,858 4,024 4,476 4,539 4,419 4,475 4,524 Private Generation (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) &fisting-Demand Response (11) (11) (1 1) (11) (1 1) (11) (11) (1 1) (11) (1 1) New Demand Response (60) (78) (98) (101) (131) (165) (165) (180) (182) (184) New Energy Efficiency (89) (96) (126) (167) (221) (324) (378) (341) (368) (415) West Total obligation 3,551 3,392 3,442 3,580 3,661 3,977 3,986 3,888 3,913 3,914 West Reserve Margin -54% -51% -51% -45% -44% -46% -49% -38% -32% -23% Total Resources 10,006 10,321 10,839 11,436 11,527 11,866 12,559 13,006 13,758 13,977 Obligation 8,705 8,896 8,944 9,291 9,589 9,665 9,745 9,957 9,953 10,049 Planning Reverve Margin(13%) 1,132 1,157 1,163 1,208 1,247 1,256 1,267 1,294 1,294 1,306 Obligation+Reserves 9,837 10,053 10,107 10,499 10,835 10,922 11,012 11,252 11,247 11,355 System Position 170 268 732 936 691 945 1,547 1,755 2,511 2,622 Reserve Margin 15% 16% 21% 23% 20% 23% 29% 31% 38% 39% 95 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.5 (Cont.) - 2023 IRP Update Winter Capacity Load and Resource Balance (Megawatts) end Thermal 6,264 6,264 6,264 4,815 4,117 4,117 2,854 2,854 2,854 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 36 36 36 36 36 36 36 36 36 Wind 552 552 552 552 552 552 552 470 470 Solar 385 383 380 357 354 352 350 347 345 Other Renewable 34 34 34 34 8 8 8 8 8 Storage 467 467 467 467 467 467 467 467 467 Purchase 172 172 172 172 172 172 172 172 172 Qualifying Facilities 259 257 254 213 212 207 206 205 204 Sale 0 0 0 0 0 0 0 0 0 Fast Existing Resources 8,169 8,165 8,159 6,645 5,918 5,911 4,645 4,560 4,556 Market Purchases 0 0 0 0 0 0 0 0 0 Peaker 584 584 584 640 1,429 1,429 4,385 5,092 5,092 Wind 737 737 737 782 782 782 782 782 738 Solar 303 303 303 540 540 540 540 540 554 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 698 698 709 1,556 1,556 1,556 1,556 1,556 1,556 Nuclear 475 475 475 475 475 475 475 475 475 Fast Planned Resources 2,797 2,797 2,808 3,993 4,782 4,782 7,738 8,445 8,414 Fast Total Resources 10,966 10,962 10,967 10,638 10,700 10,693 12,383 13,005 12,971 Load 7,329 7,518 7,607 7,745 7,870 8,007 8,186 8,326 8,472 Private Generation (19) (21) (23) (25) (28) (30) (32) (0) (36) Existing-Demand Response (462) (462) (462) (462) (462) (462) (462) (462) (462) New Demand Response (109) (114) (120) (143) (210) (210) (231) (270) (270) New Energy Efficiency (1,024) (1,147) (1,263) (1,464) (1,573) (1,658) (1,743) (1,868) (2,048) Fast Total obligation 5,715 5,774 5,738 5,651 5,598 5,648 5,719 5,726 5,655 Fast Reserve Margin 92% 90% 91516 88% 91% 89% 1179/o 127% 129% Thermal 736 736 736 499 499 499 499 499 499 Peaker 0 0 0 0 0 0 0 0 0 Hydroelectric 554 554 554 554 554 554 554 554 565 Storage 0 0 0 0 0 0 0 0 0 Renewable 0 0 0 0 0 0 0 0 0 Purchase 1 1 1 1 1 1 1 1 1 Qualifying Facilities 120 120 119 105 104 103 103 103 103 Sale (12) (12) (12) (12) (12) (12) (12) (12) (12) West Existing Resources 1,399 1,399 1,399 1,147 1,147 1,146 1,146 1,145 1,157 Market Purchases 0 0 0 0 0 0 0 0 0 Peaker 0 0 0 0 0 0 0 0 0 Wind 617 617 653 808 808 808 808 808 789 Solar 48 48 48 48 48 48 48 48 48 Other Renewable 0 0 0 0 0 0 0 0 0 Storage 847 847 975 1,701 1,701 1,701 1,724 1,732 1,732 Nuclear 0 0 0 0 0 0 0 0 0 West Planned Resources 1,512 1,512 1,677 2,557 2,557 2,557 2,581 2,588 2,570 West Total Resources 2,911 2,911 3,076 3,705 3,704 3,703 3,726 3,734 3,726 Load 4,770 4,917 4,986 4,938 5,058 5,133 5,273 5,285 5,394 Private Generation (0) (0) (0) (0) (0) (0) (0) (0) (0) Existing-Demand Response (11) (1 1) (1 1) (11) (11) (11) (11) (11) (11) New Demand Response (197) (198) (199) (208) (225) (225) (244) (249) (250) New Energy Efficiency (588) (634) (678) (720) (755) (801) (844) (838) (943) West Total obligation 3,975 4,074 4,098 4,000 4,068 4,096 4,174 4,187 4,190 West Reserve Margin -27% -29% -25% -7% -9% -10% -11% -11% -11% Total Resources 13,877 13,873 14,043 14,342 14,404 14,396 16,110 16,739 16,697 Obligation 9,690 9,847 9,836 9,651 9,666 9,744 9,893 9,913 9,846 Planning Reverve Margin(13%) 1,260 1,280 1,279 1,255 1,257 1,267 1,286 1,289 1,280 Obligation+Res erves 10,950 11,128 11,115 10,905 10,922 11,010 11,179 11,202 11,126 System Position 2,928 2,745 2,928 3,437 3,482 3,386 4,931 5,537 5,572 Reserve Margin 43% 41% 43% 49% 49% 48% 0% 69% 70% 96 PACIFICORP-2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Carbon Dioxide Emissions The 2023 IRP Update preferred portfolio reflects PacifiCorp's on-going efforts to provide valuable energy solutions for our customers that reflects a continued trajectory of declining carbon dioxide (CO2) and other carbon dioxide equivalent (CO2e) emissions resulting in a measure of total emissions. PacifiCorp's emissions have been declining and continue to decline related to several factors including PacifiCorp's participation in the EIM and commitment to CAISO's Extended Day- Ahead Market (EDAM), which reduces customer costs and maximizes use of non-emitting renewable resources that have no fuel cost and that generate tax credits. The chart below in Figure 6.16 compares projected annual CO2e emissions between the 2023 IRP Update and 2023 IRP preferred portfolios. In this graph, emissions are assigned to market purchases at a rate of 0.428 metric tons CO2 equivalent per megawatt-hour. In the 2023 IRP Update, emissions are higher than projected in the 2023 IRP starting in 2026. Removal of the OTR, which limited summer generation from gas and coal-fueled resources, is a significant driver. Further, over the longer-term the load forecast in the 2023 IRP Update is higher than in the 2023 IRP. Importantly, the 2023 IRP Update preferred portfolio continues to show a continued downward trajectory in emissions over time. By 2030, average annual CO2e emissions in the 2023 IRP Update preferred portfolio are reduced by 63% against the year 2005 baseline versus a reduction of 78% against the baseline in the 2023 IRP preferred portfolio. By the end of the planning horizon, system CO2e emissions are projected to fall from 35.1 million metric tons in 2023 to 9.3 million tons in 2042—a reduction of 73.5%. 97 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.16—Preferred Portfolio CO2e Emissions Comparison* 45 40 35 0 30 L 25 20 c °_ 15 10 5 0 M 1:T Ln lD I- W M O rl f V M R4- In lD I- W M O c-I N O O O O O O O O O O O O O O O O O N N N N N N N N N N N . N N N N N N N N ■ 2023 Update IRP CO2e ■ 2023 CO2e IRP * PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2022 from owned facilities, specified sources and unspecified sources. From 2023 through the end of the twenty-year planning period in 2042, emissions reflect those from the 2023 IRP Update preferred portfolio with emissions from specified sources reported in CO2 equivalent.Market purchases are assigned a default emission factor(0.428 metric tons CO2e/megawatt-hour). Emissions from sales are not removed.Beyond 2042,emissions reflect the rolling average emissions of each resource from the 2023 IRP update preferred portfolio through the life of the resource. Figure 6.17 includes historical data,assigns emissions at a rate of 0.428 metric tons CO2 equivalent per megawatt-hour to market purchases (with no credit to market sales), includes emissions associated with specified purchases, and extrapolates projections out through 2050. This graph demonstrates that relative to a 2005 baseline, of 54.6 million metric tons, system CO2e emissions are down 47% in 2025, 63%in 2030, 80% in 2035, 84% in 2040, 84% in 2045, and 100%in 2050 (assuming that by 2050, new gas-fired resources added in the preferred portfolio are fueled with a non-emitting fuel alternative. 98 PACIFICORP-2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Figure 6.17—2023 IRP Update Preferred Portfolio CO2e Emissions Trajectory* 60 100% v 50 rV ...... . ..•' • .. ,, ... 80% v N 40 � m 60% `r' U 30 0 .7 fV 41 w 40% 0 20 0 10 20% 0 0% �1 RT r_ 0 m flo rn ry Ln m r_1 TT r- 0 T-1 r__1 r__1 N fV rV r*l rn ro m �T TT TT M 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N fV fV fV fV fV fV r4 fV fV fV fV (V (V PacifiCorp Emissions (Million MT) —2005 Base Emission •••••• % Reduction from 2005 Base *The emissions trajectory does not incorporate clean energy targets set forth in Oregon House Bill 2021 or any other state-specific emissions trajectories. Oregon and Washington Emissions Compliance The 2023 IRP Update addresses modeled policy outcomes for Oregon's Clean Energy Plan and the Washington Clean Energy Implementation Plan. Circumstances contributing to emissions with these two legislative actions have changed since the 2023 IRP. To the extent systemwide planning drivers have reduced the overall pressure toward renewables procurement and emissions reductions, this places upward pressure on the magnitude and cost of activity that will be required for both Oregon and Washington compliance. For example, EPA's approval of Wyoming's OTR plan and the stay of EPA's disapproval of Utah's OTR plan means that federally mandated compliance obligations which drove renewable resource procurement via restrictions on NOx emissions from coal and gas-fired units that were included in the 2023 IRP are now lessened. Consequently, additional renewables are indicated for Oregon and Washington portfolios compared to what has been most recently presented in PacifiCorp's CEP and CEIP biennial reports,respectively. Where federal law dictates compliance action that is aligned with Oregon and Washington legislative goals, the costs and benefits are shared among all customers. However, where state legislation specifically drives alternative procurements, the costs and benefits of those procurements will fall to the individual states and their customers. The process of integrating state level requirements into the preferred portfolio is discussed at length in preceding sections. 99 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT At this time,PacifiCorp continues to anticipate that allocations and the multistate process will play a significant role in achieving final compliance with Oregon HB 2021 and Washington CETA requirements. Renewable Portfolio Standards JE Figure 6.18 shows PacifiCorp's renewable portfolio standard (RPS) compliance forecast for California,Oregon,and Washington after accounting for new renewable resources in the 2023 IRP Update preferred portfolio. While these resources are included in the preferred portfolio as cost- effective system resources and are not included to specifically meet RPS targets, they nonetheless contribute to meeting RPS targets in PacifiCorp's western states. The California RPS compliance position will be met through year 2030 with owned and contracted renewable resources, as well as REC purchases. Beyond 2030,the company may need to purchase approximately—175,000 RECs per year to meet the RPS target of 60% in years where a shortfall is projected. Oregon RPS compliance is achieved through 2042 with the addition of new renewable resources in the 2023 IRP Update preferred portfolio. Under PacifiCorp's 2020 Protocol and the Washington Interjurisdictional Allocation Methodology, Washington's RPS position is improved by receiving a system share of renewable resources across PacifiCorp's system, and there are no anticipated shortfalls. While not shown in Figure 6.18, PacifiCorp meets the Utah 2025 state target to supply 20% of adjusted retail sales with eligible renewable resources with existing owned and contracted resources and new renewable resources. 100 PACIFICORP—2021 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.18—Annual State RPS Compliance Forecast California RPS 3,000 b 0 2,000 0 H v U 1,000 -iFi11F 0 ------------ o'�°` o'��' o"��O o'�^ o'�� o'��' cP° c4~ cP�" ti ti ti ti ti ti ti ti ti ti ti ti - ti ti ti ti ti ti ®Unbundled4 Surrendered Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance t Shortfall Requirement 80,000 Oregon RPS 60,000 - 0 H 40,000 v m W 20,000 L F-I a 0 1 oti°` oti�' oti�0 oti^ oti� otiq o�° o"�� o'a, o��' ot. o'�4) 0'�(0 0"^ o'�� o'�C) o°° eP� cQ�' ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ®Unbundled Surrendered t Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance �Shortfall Requirement 10,000 Washington RPS a 8,000 e 6,000 F 4,000 U W 2,000 a4 0 oti°` ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ®Unbundled Surrendered Bundled Surrendered ®Unbundled Bank Surrendered Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance �Shortfall Requirement 101 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT rojected Energy Mix Figure 6.19 reports projected changes to PacifiCorp's system energy mix over time, based upon preferred portfolio outcomes in the short-term (ST) model.2 On an energy basis, coal generation drops to 22%by 2028, falls to 12%by 2032, and declines to less than 1%by year 2040. Reduced energy from coal is offset primarily by increased energy from renewable resources, nuclear resources, DSM, and to a smaller extent later in the plan,peaking resources. Figure 6.19—Projected Energy Mix with Preferred Portfolio Resources* 1 oo°i° 90% ' 80% 4% '' 4% 4% 3% 3% 4% 4% 3% 3% 3% 0 3% o 0 70/0 60% 50% 40% 30% 20% 10% 0% O�� O�� ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ■Coal ■Existing Gas/Gas Conversion ■Hydro ■wind ■Solar Other(Renewable) Other(Non-Emitting) ■Other(Non-Renewable) Energy Efficiency ■Demand Response ■Market * Storage resources are excluded as they do not provide net energy. Figure 6.20 shows how PacifiCorp's capacity mix is expected to change over time. Coal capacity drops to 18% of the system in 2028,then further to 11% of the system starting in 2033, and finally to 3% of capacity in 2040. Coal capacity is primarily replaced by renewables that increase in contribution over time. Towards the end of the study period, "other(Non-Renewable)" (mostly new peaking) capacity begins to contribute a larger percentage of system capacity. 2The projected PacifiCorp 2023 IRP update preferred portfolio"energy mix"is based on energy production and not resource capability,capacity or delivered energy.All or some of the renewable energy attributes associated with solar,wind,biomass,biogas,geothermal and qualifying hydro facilities in PacifiCorp's energy mix may be:(a)used in future years to comply with renewable portfolio standards or other regulatory requirements;(b)sold to third parties in the form of renewable energy credits or other environmental commodities;or(c)excluded from energy purchased.PacifiCorp's 2023 IRP update preferred portfolio energy mix includes owned resources and purchases from third parties. 102 PACIFICORP—2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Figure 6.20-Projected Capacity Mix with 2023 IRP Update Preferred Portfolio Resources* 100% 90% ' 80% 70% , 60% 50% 40% 30% 20% ' 10% 0% ■Coal ■Existing Gas/Gas Conversion ■Hydro ■Wind ■Solar ■Other(Renewable) Other(Non-Emitting) ■Other(Non-Renewable) ■Energy Efficiency ■Demand Response * Storage resources are excluded as they do not provide net capacity. Additional Studie In addition to the 2023 IRP Update preferred portfolio, PacifiCorp developed key variants of the updated preferred portfolio, focusing on critical decision variables addressing significant areas of interest and change. The economics of these studies further supports their value in the 2023 IRP Update preferred portfolio as the least-cost,least-risk portfolio.In addition,PacifiCorp is including the Oregon and Washington standalone Compliance studies within this section to provide clarity about the decisions made for the whole system in order to comply with Oregon or Washington. The variant portfolios are summarized in Table 6.6. Like the preferred portfolio, all variant studies were taken through the iterative modeling process described earlier in this chapter. Each variant was subject to granularity adjustments and reliability load additions files specific to the portfolio selected by the model for the variant conditions. For the No-Nuclear and all Jim Bridger 3 & 4 variants,the same process was undertaken to incorporate changes to the preferred portfolio as was completed to integrate Oregon and Washington compliance. Because the overall change in these portfolios is not a wholesale baseline change of assumptions, but merely an"in vs. out" (nuclear) or"configuration vs. configuration" study this process was deemed appropriate. For the Offshore Wind and Utah participation in OTR starting in 2027 studies, the base of the model is very different, resulting in changes to the portfolio that were not incorporated into the preferred portfolio, but left to stand alone. 103 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Table 6.6—Variant Portfolios Case Description No CCUS Counterfactual to Preferred Portfolio where Jim Bridger 3 and 4 run as coal Bridger 3&4 Gas Convert Counterfactual to Preferred Portfolio where Jim Bridger 3 and 4 convert to gas in 2030 No Nuclear Counterfactual to Preferred Portfolio where Natrium project is not allowed Utah OTR Participation Study to evaluate portfolio selections if Utah OTR Stay order is overturned Offshore Wind Study to evaluate portfolio if 1 gigawatt of offshore wind is required in Oregon Oregon HB 2021 Study to evaluate impact to the entire system if Oregon policy needs were shared Washington CETA Study to evaluate impact to the entire system if Washington policy needs were shared CCUS Variant (No CCUS) The preferred portfolio selected Jim Bridger 3 and 4 to be converted to CCUS in 2028. Using the methodology described earlier in the chapter, the replacement for the CCUS was selected based on iterative model runs which remove the selection of CCUS. No other resources changes were selected in the absence of CCUS at Jim Bridger units 3 and 4. However,without CCUS these units retire two years earlier, as their operational life is not extended to capture additional ITC benefits. Figure 6.21 below shows the change in system cost when CCUS at Jim Bridger is not installed, and Jim Bridger 3 and 4 operate as coal through 2037, resulting in a PVRR increase of$746m. This increase is almost entirely driven by the loss of tax credits associated with the CCUS unit. The increase in emissions cost is partially offset by lower fixed and variable costs on the gas converted units,but the loss of the tax credits far outweighs these savings. Figure 6.21 —Increase/(Decrease) in System Costs when CCUS is Removed from the Preferred Portfolio Annual Change in Cost by Line Item Net Difference In Total System Cost $746 $1,000 $800 $800 -.------- $600 $600 00 $400 $200 $ 00 $ $4400 0 ($200) 'JillIOU $ 00 $2200 � ($400) �. ($600) $100 ($800) $0 _— N N N N N N M M M M M M M M 7 7 ($100) N N N N N N N N N N N N N N N N N N N OR' Ory Ory OR' Ory Oti O� O� O� O� O� O� O� O� O� O� V lT lY ■Coal&Gas Fixed ■Coal&Gas Variable ti ry ry ry ■Proxy Resource Costs ■Emissions ■Net Market Transactions ■Transmission —Net Cost/03ene8t) ---Curnalative PVRR(d) Jim Bridger 3 and 4 Gas Conversion Variant The preferred portfolio selected Jim Bridger 3 and 4 to be converted to CCUS in 2028. Using the methodology described earlier in the chapter, evaluating Jim Bridger 3 and 4 as gas converted in 2030 was based on the iterative Jim Bridger 3&4 Gas Convert runs. Because no change to other resources at the Jim Bridger area were indicated by that run,the only change to this model was the 104 PACIFICORP—2021 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT switch of Jim Bridger from CCUS to gas convert in 2030 and run through 2037, while the CCUS unit retires at year end 2039. Figure 6.22 below shows the change in system cost when CCUS at Jim Bridger is replaced with a gas conversion of the unit in 2030,resulting in a PVRR increase of$700m. This increase is almost entirely driven by the loss of tax credits associated with the CCUS unit. The increase in emissions cost is partially offset by lower fixed and variable costs on the gas converted units,but the loss of the tax credits far outweighs these savings. Figure 6.22—Increase/(Decrease) in System Cost Assuming Jim Bridger 3 and 4 Gas Conversion Annual Change in Cost by Line Item Net Difference In Total System Cost $700 $1,000 $800 $800 $600 $goo �,.------ ' $500 $400 $zoo $soo $400 $0 '11 un ($200) $300 i ($400) $200 � ($600) $100 , ($800) $0 --- V ($100) N N N N N N M M M M M M M M M M V V V 0 0 0 0 0 0 0 0 0 N N N N N N N N N 0 0 0 0 0 0 0 0 N N N N N N N N N ■Coal&Gas Fixed ■Coal&Gas Variable ti ry ry ry ti ti ti ■Proxy Resource Costs ■Emissions ■Net Market Transactions■Transmission —Net Cost/(Benefit) ---Cumulative PVRWd) Nuclear Variant (No Nuclear) The preferred portfolio included the Natrium demonstration project at Naughton. Using the methodology described earlier in the chapter, evaluating replacement options for the Natrium Demonstration project was completed using the iterative No Nuclear runs. In those views, gas peaking units replaced the nuclear capacity at Naughton. As a result,this change was incorporated as the replacement for the Natrium demonstration project. Figure 6.23 — Increase/(Decrease) in Proxy Resources when the NatriumTM Demonstration Project is Removed Cumulative Changes hicremental Portfolio Changes 300 300 200 200 100 100 0 0 (100) .0(100) (200) (200) "(300) AMON (300) — .5(400) (400) (500) (500) (600) ,g (600) ,g ryb ^Ny 11 N ry� 1 'ham 1 Mry ^'h 'ya ^h 'h0O 'ham M� 1 F o cry 1 p`1 e p"+ p`�q' 011 p�y0 1 f f p'.�'' p`1 01 01 p�1 `1 I c c ry� ry� ry� N N� ry� ry� ry� ry� N N� ry� ry� ry� ry� N N ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ry ■Coal ■Gas ■Contracts ■Coal ■Gas ■Contracts ■QF ■Hydra r Nuclear ■QF ■Hydro ra Nuclear ■Hydro Storage ■Battery ■Solar ■Hydro Storage ■Battery ■Solar ■Solar+Storage ■Wind ■Wind+Storage ■Solar+Storage ■Wind ■Wind+Storage ■Geothermal ■Energy Efficiency■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response ■Converted Gas ■Peaking ■Peaking ■Converted Gas 105 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.24 below shows the change in system cost when the Natrium project is removed and replaced with a peaking unit in 2037, resulting in a $657m dollar increase in the PVRR of the portfolio. In 2030 when the Natrium plant is removed from the portfolio, proxy resource costs begin to increase as new resources added to the portfolio before 2030 begin to operate differently. Coal and gas variable costs and corresponding emissions costs also increase as the system relies more heavily on those resources for reliability. Figure 6.24—Increase/(Decrease) in System Costs when Nuclear is Removed from the Preferred Portfolio Annual Change in Cost by Line Item Net Difference In Total System Cost $657 $500 $700 $300 - $600 $200 $500 i $100 $400 $0 $300 '1 1 1 1 1 1 1 1•.. �. ($100) $200 — ($200) $100 � ($300) $0 V V1 D r 00 01 O '+ N M V V1 D r 00 01 O .--i N ($100) N N N N N N M M M M M M M M M M V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N Ory Ory O� Orl, Ory � Ong O� On, Ong Ong O� O� Ong O� O� _h _t. _h ■Coal&Gas Fixed ■Coal&Gas Variable R 1 R R 1 ti ti ti ^ ti ti ti ti ti ti ti 117 tiV ■Proxy Resource Costs ■Emissions ■Net Market Transactions■Transmission —Net Costf(Benefit) ---Cumulative PVRR(d) Utah Stay OTR Variant This variant allowed the model to select any portfolio of resources with the assumption that Utah would be subject to an OTR constraint starting in 2027. The significant reduction in the ability for coal units to operate led to a much larger selection of battery storage resources. Additionally, the portfolio relies more heavily on gas production than the preferred portfolio. Figure 6.25 — Increase/(Decrease) in Proxy Resources when Utah OTR starting in 2027 is assumed Cumulative Changes Incremental Portfolio Changes 6,000 5,000 4,000 4,000 3,000 2,000 2,000 1,000 4(2,000) A 0 (4,000) (1,000) (6,000) (2,000) ONb Ory O�W ,11 O1c, 01 1" 1" O11" O1y 0,5b O,y^ O,�W O,yQ CYo CY~ CY'y O^b p^y pryb pry OryW OH O,So Off~ O1" 11 11' ply O1b O1^ 1*1 O1" CYO �~ P N N N N '� N N N N '� '� N N N '� N ti N ry ti N N N N N N N N '� N N N N N N ■Coal ■Gas ■Contracts ■Coal ■Gas ■Contracts ■QF ■Hydro a Nuclear ■QF ■Hydro Nuclear ■Hydro Storage ■Battery ■Solar ■Hydro Storage ■Battery Solar ■Solar+Storage ■Wind ■Wind+Storage ■Solar+Storage ■Wind ■Wind+Storage ■Geothermal ■Energy Efficiency ■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response ■Converted Gas ■Peaking ■Peaking ■Converted Gas As seen below in Figure 6.26,the addition of the Utah OTR starting in 2027 assumption increases costs to the system by $4.lb. This higher cost is attributed mostly to higher emission costs in the years 2027 through 2032, and proxy resource costs in 2041 and 2042. 106 PACIFICORP—2021 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.26—Increase/(Decrease) in System Costs Assuming Utah OTR Starting 2027 Annual Change in Cost by Line Item Net Difference In Total System Cost $4,065 $2,000 $4,500 $4,000 $1,500 $3,500 $3,000 $1,000 $2,500 $500 , $2,000$1,000 — $1,500 $0 --- — $500 $0 ($500) ($500) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o O O O O O O O O O O O O O O O O Off` Off` Off` ■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs ■Emissions ■Net Market Transactions ■Ttansnussion —Net Cost/(Benefit) ---Cuni lative PVRR(d) Oregon Offshore Wind Variant As seen below in Figure 6.27,the requirement for the model to build offshore wind in 2032 off the coast of southern Oregon results in large changes to the portfolio. Additional battery is selected early while Oregon and Washington situs resources and the early cluster resources are not selected. Because of the differing capacity factor of offshore wind, less overall onshore wind and solar are selected. Figure 6.27—Increase/(Decrease) in Proxy Resources Assuming Oregon Offshore Wind is Selected Cumulative Changes Incremental Portfolio Changes 2,000 1,500 1,000 1,000 500 0 NMI, (1,0 oil (3,000)4 ' 0) C (4,000) c7(1,000) (5,000) (1,500) (6,000) (2,000) otia011o1o'y f01" f eoMtio oa0101o,,^ f 01414 S, otiaf", eoti oy oy e1� ;101o� 014 1 b4 ^114 ,.w01 1"4 cY^ ■Coal ■Gas ■Contracts ■Coal ■Gas ■Contracts ■QF ■Hydro ®Nuclear ■QF ■Hydro ■Nuclear ■Hydro Storage ■Battery in Solar ■Hydro Storage ■Battery ■Solar ■Solar+Storage ■Wind ■Wind+Storage ■Solar+Storage ■Wind ■Wind+Storage ■Geothermal ■Energy Efficiency■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response ■Converted Gas ■Peaking ■Peaking ■Converted Gas Figure 6.28 below shows the change in system cost with the Oregon offshore wind, resulting in a $2.67b dollar increase in the PVRR of the portfolio. Overall, the change is negligible until 2031, where the system relies more on coal and gas, and has an increase in emissions costs and market transaction costs. Additionally higher proxy resource costs play a role in the higher overall cost of the portfolio. 107 PACIFICORP—2023 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.28—Increase/(Decrease in System Cost Oregon Offshore Wind is Selected Annual Change in Cost by Line Item Net Difference In Total System Cost $2,673 $1,500 $3,000 V 300 $1,100 $2,500 $900 $2,000 ' $00 $1,500 $5500 $100 ��__��___ _ $500 ($100) $0 ih ($300) ($500) ($500) N o N o 0 0 0 0 0 0 0 0 e 0 0 0 a N ■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs ■Emissions ■Net Market Transactions■Transmission —Net Costf(Benefit) ---Cumulative PVRR(d) Oregon HB 2021 Variant (Oregon Policy Study) Modeling the Oregon small scale renewable resource requirement and a target to meet Oregon emissions requirements results in large changes to the selected resource mixture. The below portfolio assumes the entire system shares in incremental resources required to meet Oregon compliance (with the exception of small scale renewables). Note that the preferred portfolio (against which the Oregon view is being compared) incorporates Oregon selections, so this comparison shows what would incrementally be added for the other five states within PacifiCorp's footprint under the Oregon view. In 2029, the portfolio incorporating these requirements adds additional battery. Total wind selections are lower through 2033 but increase starting in 2034. Overall solar selections are lower through the entirety of the period.Total peaking selections are lower overall,with the largest single year difference in 2040. Figure 6.29—Increase/(Decrease) in Proxy Resources Assuming Oregon HB 2021 Requirements (Oregon Policy Study) Cumulative Changes hicremental Portfolio Changes 3,000 3,000 2,000 , �Hillb2,000 1,000o1,000 (10�) o (2,000) _ y lows (3,000) (1,000) ('6') ..(2,000) (5,000) (6,000) ,g (3,000) ,g If 01 111 o`�' 1 1 oho o 1 o�ti f o,.1 01 01 off^ o�'� 01 cY cy~ cyN o�'a o`vh 4 `1 o* 1 4 oho e e f 0, 01 o„b o„n 1 01 cY' 1b1 S, ■Coal ■Gas ■Contracts ■Coal ■Gas ■Contracts ■QF ■Hydro ?m Nuclear ■QF ■Hydro Nuclear ■Hydro Storage ■Battery ■Solar ■Hydro Storage ■Battery Solar ■Solar+Storage ■Wind ■Wmd+Storage ■Solari-Storage ■Wind ■Wind+Storage ■Geothermal ■Energy Efficiency■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response ■Converted Gas ■Peaking ■Peaking ■Converted Gas Figure 6.30 below shows the change in system cost when Oregon's requirements are embedded into the system run. The $1.5b PVRR difference is driven by higher proxy resource costs, as well as costs related to the operation of units that Oregon no longer participates in. Overall system level emissions are also higher due to a reliance on coal units in which Oregon no longer participates. 108 PACIFICORP—2021 IRP UPDATE CHAPTER 6—PORTFOLIO DEVELOPMENT Figure 6.30—Increase/(Decrease) in System Cost Assuming Oregon HB 2021 Requirements (Oregon Policy Stud Annual Change in Cost by Line Item Net Difference In Total System Cost $1,502 $1,500 $1,600 $1,000 $1$1$600,,400 200 $50 _ _ $ 000 $800 $ �� $400 ($500) ' $200 , $0 ($1,000) ($200) o .-. N - v - e - - - o N N N N N N N N N N N N N N N N N N N ti ry ry � ry ry ry ry ry ti ry � ry ti ti ti ti ti ti ■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs ■Emissions ■Net Market Transactions mTransmission —Net Cost/(Benefit) ---CmnulativePVRR(d) Washington SC CETA Variant (Washington Policy Study) Modeling the Washington CETA requirements results in large changes to the selected resource mixture. The below portfolio assumes the entire system shares in incremental resources required to meet Washington compliance under SC-GHG. Note that the preferred portfolio (against which the Washington view is being compared) incorporates Washington situs selections, so this comparison shows what would incrementally be added for the other five states within PacifiCorp's footprint under the Washington view. If the system were to take a larger share of Washington resources, additional wind and battery storage would make up the bulk of the change. The CETA run adds less peaking capacity starting in 2029, and more solar and battery in 2032. Incrementally more battery is added in 2036 and 2037, coupled with less peaking in the last five years of the study. Overall solar selections are approximately flat. Figure 6.31 —Increase/(Decrease) in Proxy Resources Assuming Washington SC CETA Requirements (Washington Policy Study) Cumulative Changes Incremental Portfolio Changes 4,000 4,000 3,000 3,000 2'000 7 �� 2,000 ' 1,000 b 0 —fill, .0 1,000 V(2,000) s~'(1,000) .(3:000) (4,000) ..(2,000) — x (5,000) 9 (3,000) Orb 0 Orb Ory ONE ONE OHO Off~ O1N 101 r 4p, Orb Off^4 1"101 CY 9� S, O�lb 01 e p* If f e O„N O`yM f, 01 01 p„n 41 01 .9 4 �,fN ■Coal ■Gas ■Contracts ■Coal ■Gas ■Contracts ■QF ■Hydro ®Nuclear ■QF ■Hydro ®Nuclear ■Hydro Storage ■Battery ■Solar ■Hydra Storage ■Battery ■Solar ■Solar+Storage ■Wind ■Wind+Storage ■Solar+Storage ■Wind ■Wmd+Storage ■Geothermal ■Energy Efficiency■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response ■Converted Gas ■Peaking ■Peaking ■Converted Gas Figure 6.32 shows the change in system cost when the system as a whole is operated under the Washington CETA conditions. The$14.4b PVRR increase in cost is driven primarily by increased 109 PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT emissions costs due to the SC-GHG emissions cost adder, as well as a significant overall net increase in market costs. Small reductions in coal and gas variable costs offset some of these expenses. Proxy resource costs are higher starting in 2029 and remain higher through the 20 year study period. Figure 6.32-Increase/(Decrease) in System Cost Assuming Washington SC CETA Requirements (Washington Policy Study) Annual Change in Cost by Line Item Net Difference In Total System Cost $14,402 $3,500 $16,000 $3,000 -- $2,500 $1 ----------- $2,000 $12,000,000 -- ------ $1,500 $1Q,000 $1,000 $8,000 $500ENEENE ,,," $6,000NEEMEME i $0 $4,000 ($500) $2,000 ($1,000) $0 a h b r N a O 0 2 N. o N o N o ■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs ■Emissions ■Net Market Transactions■Transmission -Net Cost/(Benefit) ---Cumulative PVMd) PVRR Tables by Price-Policy Scenario Table 6.7- Cases Under MN Period Case Under MIN PVRR($000) Delta($000) OR 80% WA RPS CCUS Dispatch 2030 Price 20-YEAR MN Base $ 29,519 $ 748 N N Y MN 20-YEAR Preferred Portfolio $ 28,823 $ 52 Y Y Y MN 20-YEAR Systemwide $ 28,771 $ - N N Y MN 20-YEAR No CCUS $ 29,245 $ 474 Y Y N MN 20-YEAR I No Nuclear $ 29,252 $ 480 Y Y Y MN 20-YEAR I Bridger 3&4GC $ 29,321 $ 550 Y N Y MN Table 6.8-Cases Under MM Period 90111W Case Under MM PVRR($000) Delta($000) OR 80% WA RPS CCUS Dispatch 2030 Price 20-YEAR MM Base $ 33,510 $ 703 N N Y MM 20-YEAR Preferred Portfolio $ 32,807 $ - Y Y Y MM 20-YEAR Systemwide $ 32,912 $ 105 N N Y MM 20-YEAR No CCUS $ 33,553 $ 746 Y Y N MM 20-YEAR No Nuclear $ 33,464 $ 657 Y Y Y MM 20-YEAR Bridger3&4GC $ 33,506 $ 700 Y N Y MM Table 6.9-Cases Under SC-GHG Period Case Under SC-GHG PVRR($000) Delta($000) OR 80% WA RPS CCUS Dispatch 2030 Price 20-YEAR SC Base $ 47,504 $ 350 N N Y SC 20-YEAR Preferred Portfolio $ 47,153 $ - Y Y Y SC 20-YEAR Systemwide $ 47,730 $ 576 N N Y SC 20-YEAR No CCUS $ 48,031 $ 877 Y Y N SC 20-YEAR No Nuclear $ 48,493 $ 1,340 Y Y Y SC 20-YEAR Bridger3&4GC $ 47,965 $ 812 Y N Y SC 110 PACIFICORP-2021 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT Table 6.10—Cases Under LN Period Case Under LN PVRR($000) Delta($000) OR 80% WA RPS CCUS Dispatch 2030 Price 20-YEAR LN Base $ 29,241 $ 1,447 N N Y LN 20-YEAR Preferred Portfolio $ 28,042 $ 249 Y Y Y LN 20-YEAR Systemwide $ 27,794 $ - N N Y LN 20-YEAR No CCUS $ 28,441 $ 647 Y Y N LN 20-YEAR No Nuclear $ 28,212 $ 418 Y Y Y LN 20-YEAR Bridger 3&4 GC $ 28,357 $ 563 Y N Y LN Table 6.11 —Cases Under HH Period Case Under IM PVRR($000) Delta($000) OR 80% WA RPS CCUS Dispatch 2030 Price 20-YEAR HH Base $ 41,622 $ - N N Y HH 20-YEAR Preferred Portfolio $ 41,658 $ 36 Y Y Y HH 20-YEAR Systemwide $ 42,252 $ 630 N N Y HH 20-YEAR No CCUS $ 43,005 $ 1,384 Y Y N HH 20-YEAR No Nuclear $ 43,047 $ 11425 Y Y Y HH 20-YEAR Bridger3&4GC $ 43,013 $ 1,392 Y N Y HH III PACIFICORP-2023 IRP UPDATE CHAPTER 6-PORTFOLIO DEVELOPMENT [This page is intentionally left blank] 112 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE CHAPTER 7 - ACTION PLAN STATUS UPDATE This chapter provides an update on the action items listed in the Action Plan of PacifiCorp's 2023 Integrated Resource Plan(IRP). The status for all action items is provided in Table 7.1 below. 113 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE [This page is intentionally left blank] 114 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE Table 7.1 —2023 IRP Action Plan Status Update Action 1. Existing Resource Actions tatus Item Colstrip Units 3 and 4: • PacifiCorp continues to work with co-owners to la • PacifiCorp pursues a beneficial change in ownership develop the most cost-effective path toward an exit agreements that will enable an exit from the Colstrip from the project. project in Montana by 2030. Crain Unit 1: • PacifiCorp continues to work with co-owners to • PacifiCorp will continue to work closely with co- develop the most cost-effective path toward an exit lb owners to seek the most cost-effective path forward from the project. toward the 2023 IRP Update preferred portfolio target exit date of December 31, 2025. Naughton Units 1 and 2 Gas Conversion: . PacifiCorp is on track to complete required • PacifiCorp will initiate the process of converting regulatory notices and filings to process the Naughton Units 1 and 2 to natural gas beginning Q2 conversion of Naughton Units 1 and 2 from coal to 2023, including obtaining all required regulatory natural gas. notices and filings. Natural gas operations are • Coal supply agreements for Naughton Units 1 and 2 lc anticipated to commence spring of 2026. will not be extended beyond the end of December • PacifiCorp will initiate the closure of the Naughton 2025. South Ash Pond no later than the end of December 2025 when coal operations cease, and will complete closure by October 17, 2028, as required under its and closure extension submission. Jim Brid2er Units I and 2 Gas Conversion: . PacifiCorp received an approval order on December • PacifiCorp has initiated the process of ending coal- 7, 2023 from the Wyoming Public Service ld fueled operations. The Wyoming Air Quality Commission for the conversion of Jim Bridger Units Division issued an air permit on December 28, 2022, 1 and 2 from coal to natural gas. for the natural gas conversion. All required regulatory . PacifiCorp ceased coal-fueled operations at Jim notices and filings will be completed by end of 2023. 1 Brid er Units 1 and 2 on December 31, 2023. 115 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE • By the end of Q4 2023, PacifiCorp will administer • Removal of coal handling equipment and termination, amendment, or close-out of existing installation of natural gas components began on permits, contracts, and other agreements. January 1, 2024. Conversions are on track for completion in Q2 2024. Carbon Capture, Utilization, and Storage/Wyoming • PacifiCorp completed its evaluation of information House Bill 200 Compliance: received as part of the CCUS RFP and RFI process • PacifiCorp will complete an evaluation of the in August of 2023. information received as part of the CCUS RFP and • PacifiCorp filed its final plan with the Wyoming le RFI processes by the end of Q3 2023. Public Service Commission on March 29, 2024, as • PacifiCorp will submit, for Wyoming Public Service required under Wyoming House Bill 200. Commission approval, a final plan in compliance with the low-carbon energy portfolio standard no later than March 31, 2024. Regional Haze Compliance: • Utah's first planning period disputes have been • Following the resolution of first planning period resolved. regional haze compliance disputes, and the EPA's • Naughton and Wyodak's first planning period determination of the states' second planning period disputes have been resolved. The Tenth Circuit regional haze state implementation plans, PacifiCorp found EPA's disapproval of Wyoming's plan for will evaluate and model any emission control Wyodak unlawful and remanded the plan to EPA for retrofits, emission limitations, or utilization further review in accordance with the requirements reductions that are required for coal units. of the Clean Air Act.No proposed rule has been • PacifiCorp will continue to engage with the EPA, issued to date. if state agencies, and stakeholders to achieve second • Wyoming submitted its state-approved revised planning period regional haze compliance outcomes regional haze plan requiring the natural gas that improve Class I visibility,provide environmental conversion of Jim Bridger Units 1 and 2 to EPA for benefits, and are cost effective. approval. EPA is reviewing the state plan. PacifiCorp continues to comply with the state-approved plan and operating permits. • PacifiCorp continues to engage with the EPA, state agencies, and stakeholders relating to second planning period regional haze compliance. No 116 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE second planning period requirements have been finalized by EPA to date. NatriumTM Demonstration Proiect: • PacifiCorp will continue to monitor and report key Unchanged TerraPower milestones for development and will make regulatory filings, as applicable. • By the end of 2023, PacifiCorp expects to finalize commercial agreements for the NatriumTM project. • By Q2 2024, PacifiCorp expects to develop a community action plan in coordination with lg community leaders. PacifiCorp will continue to monitor key TerraPower milestones for development and will make regulatory filings, as applicable, including,but not limited to, a request for the Oregon Public Utility Commission to explicitly acknowledge an alternative acquisition method consistent with OAR 860-089-0100(3)(c), and a request for a waiver of a solicitation for a significant energy resource decision consistent with Utah statute 54-17-501. Ozone Transport Rule Compliance: • EPA finalized its approval of Wyoming's cross-state • PacifiCorp will assess the impact of EPA's finalized ozone state plan on December 19,2023. This approval Ozone Transport Rule from March 2023, relative to means PacifiCorp facilities in Wyoming are not the assumptions contained in the 2023 IRP. subject to the federal ozone plan requirements. • PacifiCorp will continue to engage with the EPA, • The Tenth Circuit granted a motion to stay EPA's 1h state agencies, and stakeholders to achieve Ozone disapproval of Utah's state ozone plan. Utah is not Transport Rule compliance outcomes that provide subject to federal ozone requirements while the stay is environmental benefits, support reliable energy in place. The Utah ozone case was transferred to the delivery and are cost effective. D.C. Circuit in February of 2024, for adjudication of • Based on the Ozone Transport Rule trading program the merits, leaving the stay in place. and the associated benefits for reducing NOx emissions, PacifiCorp will install selective non- 117 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE catalytic reduction retrofit equipment at the following units by 2026: Huntington Units 1 and 2, Hunter Units 1-3, and Wyodak. The Company will initiate procurement and permitting activities beginning Q2 2023. Action Item 2• New Resource Actions Customer Preference Request for Proposals: • PacifiCorp and the eligible communities are meeting • PacifiCorp is continuously receiving and evaluating monthly to discuss program design. Subject to the requests for voluntary customer programs in Utah and finalization of the program details, PacifiCorp Oregon. PacifiCorp may use the marginal resources anticipates applying for approval of the program with from ongoing 2022AS RFP and future request for the Utah Public Service Commission in 2024 or 2025. proposals to fulfill customer need. In some cases, customer preference may necessitate issuance of a request for proposals to procure resources within the action plan window. 2a • Consistent with Utah Community Renewable Energy Act, PacifiCorp continues to work with eligible communities to develop program to achieve goal of being net 100% renewable by 2030; PacifiCorp anticipates filing an application for approval of the program with the Utah Public Service Commission in 2024 or 2025, which may necessitate issuance of a request for proposals to procure resources within the action plan window. 2024 All-Source Request for Proposals: • PacifiCorp does not have plans to issue an all-source 2b • PacifiCorp will issue an all-source Request for Request for Proposals at this time but is continuously Proposals (RFP) to procure resources aligned with the receiving and evaluating offers for resources to meet its requirements. 118 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE 2023 IRP preferred portfolio that can achieve • Based on the resource procurement need identified in commercial operations by the end of December 2028. this IRP Update, it is likely that the 2025 IRP will • In Q4 2023, PacifiCorp will notify the Public Utility include an action item to procure incremental Commission of Oregon, the Public Service resources to serve customers over the long term. Commission of Utah,and the Washington Utilities and Nonetheless, a new resource procurement action item Transportation Commission, of PacifiCorp's need for will be established after development of the 2025 IRP. an independent evaluator. • In Q12024,PacifiCorp will file a draft all-source RFP with applicable state utility commissions. • In Q3 2024, PacifiCorp expects to receive approval of the all-source REP from applicable state utility commissions and issue the RFP to the market. • In Q4 2024, PacifiCorp will identify a final shortlist from the all-source RFP, and file for approval of the final shortlist in Oregon. Similarly, PacifiCorp will make a filing in Utah for significant energy resources on final shortlist. PacifiCorp will file a certificate of public convenience and necessity (CPCN) applications, as applicable. • By Q1 2025 PacifiCorp will execute definitive agreements with winning bids from the all-source RFP. • Winning bids from the all-source RFP are expected to achieve commercial operation by December 31, 2028, or earlier. 2022 All-Source Request for Proposals: • PacifiCorp suspended the 2022 All-Source RFP in 2c • In April 2022 PacifiCorp issued an all-source Request September 2023 to further evaluate how key changes for Proposals to procure resources that can achieve in the planning environment might influence long- commercial operations by the end of December 2027. term resource procurement activities. 119 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE • In Q2 2023, PacifiCorp will identify a final shortlist • EPA's approval of Wyoming's cross-state ozone from the all-source RFP, and file for approval of the transport rule plan and the Tenth Circuit Court's stay final shortlist in Oregon. Similarly, PacifiCorp will of Utah's ozone plan have materially impacted the make a filing in Utah for any applicable significant need for the type and volume of resources identified energy resources on final shortlist. PacifiCorp will file in the 2023 IRP preferred portfolio,which considered certificate of public convenience and necessity resource procurement needs coming out of the 2022 (CPCN) applications, as applicable, and All-Source Request for Proposals. • By Q4 2023 PacifiCorp will execute definitive • Consequently, PacifiCorp is executing on a near-term agreements with winning bids from the all-source resource procurement strategy that is consistent with RFP. the preferred portfolio in this IRP Update and will • Winning bids from the 2022 all-source RFP are terminate the 2022 All Source Request for Proposals. expected to achieve commercial operation by December 31, 2027, or earlier. Action Item 3. Transmission Action Items Status Energy Gateway South Segment F (Aeolus-Clover 500 • Regulatory approval processes for certificates of kV transmission line): public convenience and necessity in Utah and • In Q4 2024, construction of Energy Gateway South is Wyoming are on track. In Utah an unopposedstipulation for the CPCN was filed February 22, expected to be completed and placed in service. 2022, and a commission order is pending. In 3a Wyoming, hearings were completed March 2, 2022, and briefs due April 1, 2022; a decision is expected in early Q2 2022. Wyoming approval will be conditioned on obtaining all right-of-way,which is on track to be completed by the end of Q2 2022. 120 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE Energy Gateway West,Segment D.1 (Windstar-Shirley • PacifiCorp is finalizing construction of the Energy Basin 230 kV transmission line): Gateway South and Energy Gateway West Sub- 3b • In Q4 2024, construction of Energy Gateway West Segment D1 transmission projects. segment D.1 to be completed and placed in service. Boardman-to-Hemingway (500 kV transmission line): PacifiCorp has continued to participate in the support, • Continue to support the project under the conditions negotiations, planning and permitting of the Boardman- of the Boardman-to-Hemingway Transmission to-Hemingway 500 kilovolt transmission line, which Project(132H) Joint Permit Funding Agreement. remains targeted for a 2026-2027 in-service date. 3c • Continue to participate in the development and negotiations of the construction agreement. • Continue to participate in"pre-construction" activities in support of the 2026-2027 in-service date. • Continue negotiations for plan of service post B2H for parties to the permitting agreement. Initiate Local Reinforcement Projects as identified with Reinforcements have been identified. A final assessment 3d the addition of new resources per the preferred portfolio, of upgrades is pending signed agreements. and follow-on requests for proposal successful bids Continue permitting support for Gateway West segments PacifiCorp continues permitting efforts on both segments D.3 and E. Initiate preliminary permitting and D.3 and E, maintaining the record of decision on each development activities for future transmission investments segment. not currently included in the preferred portfolio. These 3e future transmission projects can include development of additional Energy Gateway segments and exploration of new routes that have connections to other regions (i.e., connecting southern Oregon to the east with connections to the desert southwest). These activities will enable 121 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE PacifiCorp to prepare for potential growth in new large loads seeking new service over the next decade. 122 PACIFICORP—2023 IRP UPDATE CHAPTER 7—ACTION PLAN STATUS UPDATE Action Item 4. Demand-Side Management (DSM) Actions Sta Energy Efficiency Targets: • PacifiCorp achieved the Action Plan target of 543 • PacifiCorp will acquire cost-effective energy GWh in 2023 and is on track to achieve its 2024 Class efficiency resources targeting annual system energy 2 DSM target. and capacity selections from the preferred portfolio as • PacifiCorp has launched a number of new demand summarized below. PacifiCorp's state-specific response programs in 2022 and 2023. Additionally, processes for planning for DSM acquisitions is the company is currently expanding its existing provided in Appendix D in Volume I1 of the 2023 programs. PacifiCorp continues to pursue the IRP. incremental capacity additions but did not achieve the • PacifiCorp will pursue cost-effective energy 2023 incremental capacity , due to the later than efficiency resources as summarized in the table anticipated timing of program effective dates for below: newly launched demand response programs. However, the company anticipates achieving its Year 1st Year Energy Efficiency(GR'h) Annual Capacity(MW) 2023 543 123 cumulative capacity for 2024. 4a 2024 559 220 2025 568 259 2026 628 197 • PacifiCorp will pursue cost-effective demand response resources targeting annual system capacity' selections from the preferred portfolio2 as summarized in the table below: ear Annual Incremental Capacity(NW) 2023 72 2024 39 2025 152 2026 1 109 1 Capacity impacts for demand response include both summer and winter impacts within a year. 123 PACIFICORP—2023 IRP UPDATE CHAPTER 7—ACTION PLAN STATUS UPDATE Z A portion of cost-effective demand response resources identified in the 2023 preferred portfolio in 2023 for Oregon and Washington represent planned volumes expected are expected to be acquired through a previously issued demand response RFP soliciting resources identified in the 2019 IRP.PacifiCorp will pursue all cost-effective demand response resources identified as incremental to existing resources or as an expansion of existing resources offered through approved programs. Action Item . Market Purchases Status Market Purchases: • Since the publication of the 2023 IRP action plan, • Acquire short-term firm market purchases for on- PacifiCorp has continued to transact consistent with peak delivery from 2023-2025 consistent with the its risk management and energy supply procedures to Risk Management Policy and Energy Supply reliably cost-effectively serve customer requirements. Management Front Office Procedures and Practices. Such transactions include seeking competitive pricing These short-term firm market purchases will be to acquire short-term firm purchases, execute balance acquired through multiple means: Balance of month of month, day-ahead and hour-ahead transactions 5a and day-ahead brokered transactions in which the through exchanges, and engage in prompt-month, broker provides a competitive price. balance-of-month, day-ahead and hour-ahead non- • Balance of month, day-ahead, and hour-ahead brokered bi-lateral transactions. transactions executed through an exchange, such as the Intercontinental Exchange, in which the exchange provides a competitive price. • Prompt-month, balance-of-month, day-ahead, and hour-ahead non-brokered bi-lateral transactions. 124 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE Action Item 6. Renewable Energy Credit (REC)Actions Status Renewable Portfolio Standards (RPS): • PacifiCorp will continue to evaluate the need for • PacifiCorp will pursue unbundled REC RFPs and unbundled RECs and issue RFPs to meet its state RPS purchases to meet its state RPS compliance compliance requirements as needed. requirements. 6a • As needed, issue RFPs seeking unbundled RECs that will qualify in meeting California RPS targets through 2024 and future compliance periods as needed. Renewable Energy Credit Sales: • PacifiCorp will continue to issue reverse RFPs to 6b • Maximize the sale of RECs that are not required to maximize the sale of RECs that are not required to meet state RPS compliance obligations. meet state RPS compliance obligations 125 PACIFICORP-2023 IRP UPDATE CHAPTER 7-ACTION PLAN STATUS UPDATE [This page is intentionally left blank] 126 PACIFICORP—2023 IRP UPDATE APPENDIX A—ADDITIONAL LOAD FORECAST DETAILS APPENDIX A - ADDITIONAL LOAD FORECAST DETAILS The load forecast presented in Chapter 4 represents the data used for capacity expansion modeling and excludes load reductions from incremental energy efficiency resources (Class 2 DSM). The load forecast used in the 2023 IRP Update was produced in May 2023. The average annual energy growth rate for the 2024 through 2042 timeframe is 2.13 percent. Relative to the load forecast prepared for the 2023 IRP, PacifiCorp's 2041 forecasted energy requirement decreased in all jurisdictions other than Utah. Table A.I and Table A.2 illustrate the annual load and coincident peak load forecast when not reducing load projections to account for new energy efficiency measures (Class 2 DSM),I Table A.1 —Forecasted Annual Load Growth, 2024 through 2042 (Megawatt-hours), at Generation, re-DSM Year Total OR WA CA UT WY ID 2024 64,968,110 16,245,780 4,585,770 843,490 29,595,760 9,737,710 3,959,600 2025 67,342,930 17,306,840 4,594,200 838,350 30,789,780 9,840,730 3,973,030 2026 68,341,610 18,158,130 4,613,400 837,260 30,853,380 9,882,670 3,996,770 2027 71,581,930 19,426,800 4,629,410 836,940 32,713,240 9,955,510 4,020,030 2028 76,717,850 21,035,020 4,664,190 839,860 36,091,430 10,038,900 4,048,450 2029 78,931,210 22,407,980 4,681,190 838,600 36,875,730 10,065,380 4,062,330 2030 81,000,340 23,159,280 4,710,570 840,340 38,109,540 10,100,330 4,080,280 2031 83,090,030 24,287,060 4,737,420 841,830 38,958,030 10,168,810 4,096,880 2032 84,020,840 24,745,390 4,775,560 844,880 39,308,670 1 10,229,110 4,117,230 2033 84,868,040 24,957,970 4,792,040 843,400 39,868,630 10,280,680 4,125,320 2034 85,779,130 25,202,840 4,825,440 844,690 40,424,050 10,342,060 4,140,050 2035 86,764,370 25,492,360 4,863,490 846,560 40,999,620 10,406,500 4,155,840 2036 87,968,040 25,852,880 4,918,760 850,950 41,669,790 10,496,540 4,179,120 2037 88,920,970 26,150,610 4,952,290 850,940 42,234,980 10,541,160 4,190,990 2038 90,083,150 26,508,200 5,002,820 853,330 42,896,560 10,611,960 4,210,280 2039 91,291,270 26,881,290 5,055,910 855,790 43,580,400 10,686,960 4,230,920 2040 92,669,760 27,298,340 5,123,440 860,460 44,346,910 10,783,1501 4,257,460 2041 93,733,980 27,630,780 5,163,010 860,290 44,980,320 10,829,300 4,270,280 2042 94,980,880 28,011,130 5,218,220 862,720 45,695,500 10,902,990 4,290,320 Compound Annual Growth Rate 2024-33 3.01% 4.89% 0.49% 0.00% 3.37% 0.60% 0.46% 2024-42 2.13% 3.07% 0.72% 0.13% 2.44% 0.63% 0.45% 1 Class 2 DSM load reductions are included as resources in the System Optimizer model. 127 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.2 -Forecasted Annual Coincident Peak Load (Megawatts) at Generation, pre- DSM Year Total OR WA CA UT 1XIV ID 2024 11,200 2,645 832 146 5,578 1,240 759 2025 11,576 2,786 840 146 5,736 1,276 792 2026 11,629 2,868 846 148 5,742 1,233 791 2027 12,019 3,020 853 149 5,943 1,263 790 2028 12,528 3,137 860 149 6,362 1,245 774 2029 12,844 3,313 867 150 6,461 1,277 776 2030 13,077 3,403 873 150 6,612 1,260 778 2031 13,491 3,580 883 152 6,766 1 1,295 815 2032 13,522 3,647 899 156 6,742 1,254 824 2033 13,670 3,675 908 156 6,836 1,287 806 2034 13,807 3,707 918 157 6,924 1,294 807 2035 13,973 3,745 929 158 7,026 1,305 810 2036 14,212 3,791 940 159 7,128 1,315 879 2037 14,444 3,865 957 160 7,287 1,324 849 2038 14,618 3,910 968 161 7,399 1,330 851 2039 14,767 3,956 979 161 7,500 1,338 833 2040 14,930 3,998 989 162 7,598 1,351 833 2041 15,106 4,050 998 162 7,700 1,360 836 2042 15,437 4,202 1,017 165 7,814 1,371 870 Compound Annual Growth Rate 2024-33 2.24% 3.72% 0.98% 0.79% 2.29% 0.42% 0.68% 2024-42 1.80% 2.60% 1.12% 0.69% 1.89% 0.56% 0.76% Table A.3 and Table A.4 show the forecast changes relative to the 2023 IRP load forecast for loads and coincident system peak, respectively. 128 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.3 -Annual Load Growth Change: 2023 IRP Update Forecast less 2023 IRP Forecast (Me awatt-hours) at Generation, re-DSM Year Total OR WA CA UT 2024 (2,531,160) (2,128,670) (106,340) (18,070) (144,270) (25,850) (107,960) 2025 (2,462,130) (2,423,480) (106,560) (16,870) 428,560 (234,130) (109,650) 2026 (1,596,810) (2,299,520) (108,360) (15,710) 1,165,900 (230,570) (108,550) 2027 (1,067,840) (2,334,490) (127,420) (16,240) 1,678,820 (161,430) (107,080) 2028 36,730 (2,410,940) (147,010) (16,620) 2,907,690 (190,210) (106,180) 2029 1,011,930 (1,544,800) (160,120) (16,560) 3,014,370 (174,590) (106,370) 2030 2,188,500 (906,780) (174,780) (15,450) 3,625,640 (232,220) (107,910) 2031 2,709,340 (534,630) (193,280) (14,770) 3,758,140 (195,310) (110,810) 2032 2,699,060 (415,490) (214,840) (15,080) 3,708,320 (247,620) (116,230) 2033 2,645,810 (461,810) (234,210) (15,300) 3,706,680 (227,590) (121,960) 2034 2,427,590 (538,750) (251,540) (15,430) 3,578,720 (217,420) (127,990) 2035 2,214,410 (592,800) (265,300) (15,330)1 3,424,820 (203,540) (133,440) 2036 1,983,190 (645,890) (278,160) (13,920) 3,251,390 (189,950) (140,280) 2037 1,741,220 (697,660) (289,600) (12,540) 3,066,420 (177,980) (147,420) 2038 1,497,900 (749,210) (300,050) (11,340) 2,877,410 (163,610) (155,300) 2039 1,264,110 (796,550) (309,440) (10,240) 2,690,480 (146,310) (163,830) 2040 1,025,650 (846,980) (316,480) (9,310) 2,501,260 1 (130,110) (172,730) 2041 737,420 (918,850) (321,730) (8,500) 2,283,370 1 (115,200) (181,670) 2042 389,750 (1,007,770) (326,570) (7,830) 2,019,850 1 (97,090) (190,840) 129 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.4—Annual Coincident Peak Growth Change: 2023 IRP Update Forecast less 2023 IRP Forecast(Megawatts) at Generation, re-DSM Year Total OR WA CA 41 UT WY 2024 (228) (188) (14) (1) 41 (55) (11) 2025 (171) (225) (16) (1) 108 (25) (11) 2026 (129) (186) (24) 0 170 (72) (17) 2027 (32) (168) (34) (1) 237 (43) (23) 2028 43 (186) (45) (2) 369 (73) (20) 2029 161 (174) (60) (7) 438 (15) (22) 2030 261 (104) (72) (8) 511 (42) (24) 2031 369 (50) (83) (8)1 552 (16) (26) 2032 313 15 (86) (5) 473 (61) (23) 2033 323 5 (98) (6) 480 (35) (24) 2034 295 (4) (109) (6) 476 (36) (27) 2035 281 (9) (115) (6) 476 (34) (30) 2036 258 (10) (125) (7)1 474 (33) (42) 2037 326 10 (127) (6) 519 (31) (39) 2038 318 4 (131) (6) 523 (31) (41) 2039 304 (2) (134) (7) 515 (30) (38) 2040 259 (22) (141) (8) 498 (28) (40) 2041 225 (28) (151) (9)1 482 (27) (43) 2042 250 16 (150) (8)1 465 (25) (49) 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 2023 IRP Update preferred portfolio. The average annual retail sales growth rate for the 2024 through 2042 time period is 1.23 percent. 130 PACIFICORP—2023 IRP UPDATE APPENDIX A—ADDITIONAL LOAD FORECAST DETAILS Table A.5—System Annual Retail Sales Forecast 2024 through 2042 (Megawatt-hours), ost-DSM System Retail Sales —Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 17,835,359 22,022,137 18,129,854 1,464,602 101,588 59,553,539 2025 17,942,494 23,278,978 18,467,591 1,459,535 98,916 61,247,513 2026 18,069,292 24,757,523 17,208,712 1,457,137 97,095 61,589,760 2027 18,206,269 27,097,919 17,256,311 1,455,278 95,610 64,111,386 2028 18,404,095 31,140,919 17,280,459 1,454,743 94,532 68,374,747 2029 18,477,357 32,446,403 17,226,100 1,454,103 92,916 69,696,878 2030 18,606,777 33,539,212 17,210,097 1,453,570 91,552 70,901,208 2031 18,675,809 34,617,478 17,240,040 1,452,530 90,221 72,076,078 2032 18,820,591 34,586,724 17,254,846 1,450,538 89,285 72,201,984 2033 18,835,115 34,621,087 17,256,601 1,447,587 88,046 72,248,436 2034 18,996,580 34,605,852 17,235,396 1,445,981 87,309 72,371,118 2035 19,150,780 34,635,808 17,258,048 1,446,071 86,790 72,577,498 2036 19,538,961 34,643,086 17,290,488 1,445,336 86,694 73,004,564 2037 19,799,830 34,611,441 17,243,053 1,441,270 86,217 73,181,811 2038 20,105,118 34,651,180 17,352,250 1,440,699 86,074 73,635,320 2039 20,614,193 34,653,725 17,378,585 1,441,351 85,984 74,173,839 2040 21,076,584 34,765,209 17,459,911 1,440,498 86,178 74,828,378 2041 21,548,567 34,680,463 17,469,255 1,437,205 85,894 75,221,384 2042 22,232,471 34,699,960 17,363,944 1,435,197 85,872 75,817,444 Compound Annual Growth Rate 2024-33 0.61% 5.16% -0.55% -0.13% -1.58% 2.17% 2024-42 1.23% 2.56% -0.24% -0.11% +--0.93% 1.35% 131 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.6-Forecasted Retail Sales Growth in Oregon, post-DSM Oregon Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 6,009,691 6,770,640 1,423,019 254,060 30,978 14,488,387 2025 6,001,793 7,550,785 1,453,780 254,046 30,286 15,290,690 2026 5,995,405 8,177,475 1,460,958 254,434 29,787 15,918,058 2027 6,003,026 9,161,375 11473,922 254,806 29,402 16,922,531 2028 6,040,301 10,444,341 1,471,106 255,295 29,196 18,240,240 2029 6,049,448 11,550,309 1,457,111 255,521 28,897 19,341,286 2030 6,090,809 12,048,507 1,458,396 255,858 28,741 19,882,311 2031 6,127,520 12,883,018 1,465,861 256,183 28,628 20,761,210 2032 6,199,100 13,093,944 1,479,500 256,629 28,630 21,057,804 2033 6,237,207 13,137,551 11466,220 256,811 28,489 21,126,278 2034 6,338,859 13,139,320 1,468,115 257,125 28,448 21,231,867 2035 6,468,636 13,149,739 1,479,593 257,436 28,419 21,383,824 2036 6,669,733 13,154,447 1,502,446 257,906 28,481 21,613,013 2037 6,811,623 13,159,336 1,512,959 258,098 28,384 21,770,399 2038 7,025,020 13,161,006 1,537,519 258,427 28,373 22,010,346 2039 7,234,260 13,182,394 1,561,310 258,757 28,366 22,265,087 2040 7,472,789 13,213,778 1,582,701 259,234 28,443 22,556,946 2041 7,673,642 13,233,651 1,581,848 259,423 28,357 22,776,921 2042 7,903,205 13,247,462 1,596,956 259,761 28,355 23,035,739 Compound Annual Growth Rate 2024-33 0.41% 7.64% 0.33% 0.12% -0.93% 4.28% 2024-42 1.53% 3.80% 0.64% 0.12% -0.49% 2.61% 132 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.7- Forecasted Retail Sales Growth in Washington, post-DSM Washington Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 1,601,673 1,506,545 804,037 157,390 3,954 4,073,599 2025 1,596,063 1,487,833 790,828 156,906 3,946 4,035,576 2026 1,606,514 1,478,251 779,113 155,415 3,946 4,023,239 2027 1,599,312 1,472,524 772,203 155,946 3,946 4,003,931 2028 1,597,287 1,471,963 767,628 156,535 3,958 3,997,372 2029 1,583,980 1,461,843 763,578 157,015 3,946 3,970,362 2030 1,574,662 1,455,718 760,964 157,382 3,946 3,952,672 2031 1,560,284 1,449,623 758,497 157,457 3,946 3,929,807 2032 1,549,350 1,448,952 758,110 157,384 3,958 3,917,753 2033 1,531,635 1,441,254 753,176 157,196 3,946 3,887,207 2034 1,523,973 1,441,061 749,436 157,086 3,946 3,875,501 2035 1,520,091 1,442,724 748,469 157,033 3,946 3,872,264 2036 1,528,896 1,447,477 749,604 157,047 3,958 3,886,982 2037 1,529,356 1,447,673 746,146 156,771 3,946 3,883,892 2038 1,537,274 1,455,963 747,027 156,579 3,946 3,900,789 2039 1,551,443 1,464,098 746,962 157,040 3,946 3,923,488 2040 1,569,387 1,481,238 749,544 157,329 3,958 3,961,454 2041 1,581,1561 1,481,8081 748,5561 157,4391 3,9461 3,972,906 2042 1,606,537 1,491,6521 742,1561 157,315 3,9461 4,001,605 Compound Annual Growth Rate 2024-33 -0.50% -0.49% -0.72% -0.01% -0.02% -0.52% 202442 0.02% -0.06% -0.44% 0.00% -0.01% -0.10% 133 PACIFICORP-2023 IRP UPDATF APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.8-Forecasted Retail Sales Growth in California, post-DSM California Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 376,345 232,906 54,770 95,410 1,658 761,090 2025 374,646 228,918 53,970 94,253 1,631 753,419 2026 373,722 226,296 53,643 93,333 1,615 748,609 2027 372,691 224,347 53,351 92,412 1,602 744,404 2028 372,904 223,476 53,080 91,544 1,598 742,601 2029 370,484 221,334 52,568 90,463 1,587 736,436 2030 369,901 220,209 52,241 89,368 1,582 733,302 2031 368,511 218,594 51,858 87,885 1,578 728,426 2032 368,024 218,000 51,707 86,030 1,580 725,341 2033 365,118 216,085 51,301 84,033 1,574 718,111 2034 363,645 214,991 51,113 82,425 1,573 713,747 2035 362,994 214,268 50,975 81,232 1,572 711,041 2036 363,704 213,426 51,090 80,048 1,576 709,843 2037 361,226 211,507 50,815 78,668 1,571 703,787 2038 360,660 211,315 50,682 77,270 1,570 701,498 2039 361,102 210,364 50,669 76,011 1,570 699,715 2040 362,086 211,499 50,618 74,631 1,575 700,409 2041 360,656 210,852 50,306 73,201 1,570 696,584 2042 362,167 210,457 50,226 71,747 1,570 696,167 Compound Annual Growth Rate 2024-33 -0.34% -0.83% -0.72% -1.40% -0.57% -0.64% 2024-42 -0.21% -0.56% -0.48% -1.57% -0.30% -0.49% 134 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.9-Forecasted Retail Sales Growth in Utah, post-DSM Utah Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 8,044,158 11,601,120 71584,303 241,504 50,329 27,521,414 2025 8,184,798 12,108,572 7,824,271 239,686 48,642 28,405,969 2026 8,322,690 12,993,901 6,552,088 238,852 47,672 28,155,204 2027 8,475,372 14,374,976 61557,172 237,330 47,081 29,691,932 2028 8,648,984 17,143,145 6,562,389 235,938 46,862 32,637,319 2029 8,760,307 17,382,865 6,528,435 234,780 46,522 32,952,910 2030 8,884,515 18,004,112 6,522,459 233,524 46,402 33,691,012 2031 8,968,745 18,277,853 6,517,340 232,059 46,332 34,042,329 2032 9,078,372 18,046,433 6,517,560 230,470 46,423 33,919,259 2033 9,119,563 18,080,729 6,511,359 228,901 46,268 33,986,820 2034 9,212,741 18,071,133 6,494,788 227,711 46,254 34,052,628 2035 9,267,597 18,100,907 6,494,316 226,988 46,246 34,136,055 2036 9,450,409 18,101,571 6,484,776 225,810 46,373 34,308,939 2037 9,590,337 18,070,692 6,443,531 223,793 46,239 34,374,592 2038 9,685,086 18,113,815 6,504,625 222,814 46,238 34,572,578 2039 9,966,370 18,095,113 6,492,886 222,240 46,237 34,822,845 2040 10,170,049 18,158,012 6,515,025 221,329 46,368 35,110,783 2041 10,426,605 1 18,074,355 1 6,525,459 219,823 1 46,236 35,292,478 2042 10,787,650 1 18,042,629 1 6,487,029 218,242 46,236 35,581,787 Compound Annual Growth Rate 2024-33 1.40% 5.05% -1.68% -0.59% -0.93% 2.370/., 2024-42 1.64% 2.48% -0.86% -0.56% -0.47% 1.44'%, 135 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.10-Forecasted Retail Sales Growth in Idaho, post-DSM Idaho Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 784,413 545,807 1,689,601 685,232 2,691 3,707,744 2025 784,366 544,739 1,688,371 683,719 2,647 3,703,842 2026 784,715 544,373 1,688,312 684,273 2,593 3,704,265 2027 783,715 543,797 1,687,767 684,004 2,511 3,701,794 2028 782,571 545,468 1,686,184 684,592 2,403 3,701,218 2029 771,773 541,994 1,683,225 685,465 2,246 3,684,702 2030 762,271 538,681 1,682,323 686,442 2,068 3,671,784 2031 749,873 536,634 1,679,416 687,886 1,880 3,655,688 2032 738,061 535,740 1,678,499 688,862 1,709 3,642,871 2033 720,199 531,401 1,676,103 689,461 1,557 3,618,721 2034 706,735 530,090 1,673,407 690,352 1,445 3,602,029 2035 692,578 529,337 1,671,811 692,055 1,366 3,587,147 2036 685,158 529,991 1,670,468 693,131 1,317 3,580,066 2037 672,116 530,845 1,666,797 692,626 1,279 3,563,662 2038 657,883 534,191 1,668,270 694,303 1,257 3,555,904 2039 653,451 534,107 1,667,508 695,752 1,244 3,552,061 2040 648,666 539,676 1,667,303 697,053 15239 3,553,937 2041 643,490 535,618 1 666,7751 696,478 1,231 1 3,543,592 2042 646,050 537,030 11661,863 1 696,749 1,228 3,542,917 Compound Annual Growth Rate 2024-33 -0.94% -0.30% -0.09% 0.07% -5.90% -0.27% 2024-42 -1.07% -0.09% -0.09% 0.09% 4.27% 136 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS Table A.11 -Forecasted Retail Sales Growth in Wyoming,post-DSM Wyoming Retail Sales -Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Lighting Total 2024 1,019,079 1,365,118 6,574,122 31,006 11,978 9,001,304 2025 1,000,829 1,358,131 6,656,371 30,925 11,762 9,058,017 2026 986,246 1,337,228 6,674,597 30,831 11,483 9,040,385 2027 972,153 1,320,899 6,711,894 30,780 11,067 9,046,794 2028 962,048 1,312,525 6,740,071 30,839 10,514 9,055,997 2029 941,364 1,288,059 6,741,183 30,858 9,718 9,011,183 2030 924,619 1,271,986 6,733,713 30,996 8,813 8,970,127 2031 900,877 1,251,755 6,767,067 31,060 7,857 8,958,617 2032 887,682 1,243,655 6,769,470 31,164 6,985 8,938,956 2033 861,392 1,214,067 6,798,442 31,185 6,213 8,911,299 2034 850,627 1,209,257 6,798,538 31,282 5,643 8,895,346 2035 838,884 1,198,832 6,812,883 31,326 5,241 8,887,167 2036 841,061 1,196,174 6,832,104 31,394 4,989 8,905,721 2037 835,172 1,191,388 6,822,804 31,315 4,799 8,885,478 2038 839,195 1,174,889 6,844,128 31,305 4,689 8,894,206 2039 847,568 1,167,650 6,859,250 31,552 4,621 8,910,642 2040 853,608 1,161,005 6,894,719 30,922 4,595 8,944,848 2041 863,018 1,144,179 6,896,311 30,841 4,554 8,938,903 2042 926,862 1,170,731 6,825,714 31,383 4,538 8,959,228 Compound Annual Growth Rate 2024-33 -1.85% -1.29% 0.37% 0.06% -7.03% -0.11% 202442 -0.53% -0.85% 0.21% 0.07% -5.25% -0.03% 137 PACIFICORP-2023 IRP UPDATE APPENDIX A-ADDITIONAL LOAD FORECAST DETAILS [This page is intentionally left blank] 138