20241231CL_2025 IRP Vol 1_Vol 2.pdf

RECEIVED
December 31, 2024
IDAHO PUBLIC
IWZ
ROCKY MOUNTAIN UTILITIES COMMISSION
POWER:: 1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
A DIVISION OF PACIFICORP
December 31, 2024
VIA ELECTRONIC FILING
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd
Building 8 Suite 201A
Boise, Idaho, 83714
RE: CASE NO. PAC-E-24-13 -PacifiCorp's DRAFT 2025 Integrated Resource Plan
Attention: Commission Secretary
Please find enclosed PacifiCorp's (the "Company") DRAFT 2025 Integrated Resource Plan
("Draft 2025 IRP"). The Company is providing the Draft 2025 IRP as a courtesy to its state public
service commissions to provide transparency prior to filing the final 2025 IRP. PacifiCorp will
make the Draft 2025 IRP publicly available on December 31, 2024 and will be publishing
supporting workpapers on January 8, 2025 at the following website
https://www.pacificop2.com/energy/integrated-resource-plan.html.
The Draft 2025 IRP contains the following draft sections that are available as of the date of this
letter:
• Volume I
o Chapter 1 —(Executive Summary)
o Chapter 2—(Introduction)
o Chapter 3 —(Planning Environment)
o Chapter 4—(Transmission)
o Chapter 6 (Load and Resource Balance)
o Chapter 7 (Resource Options)
o Chapter 8 (Modeling and Portfolio Evaluation)
o Chapter 9 (Modeling and Portfolio Selection Results)
o Chapter 10 (Action Plan)
• Volume II
o Appendix A—(Load Forecast)
o Appendix B—(Regulatory Compliance)
o Appendix C—(Public Input Process)
o Appendix D—(Demand-Side Management)
o Appendix E—(Grid Enhancement)
o Appendix F—(Flexible Reserve Study)
o Appendix G—(Plant Water Consumption Study)
o Appendix I—(Capacity Expansion Results)

Idaho Public Utilities Commission
December 31, 2024
Page 2
o Appendix L—(Distributed Generation Study)
o Appendix M—(Stakeholder Feedback Forms)
o Appendix P—(Acronyms)
PacifiCorp began development of its 2025 IRP in January 2024 with a series of public-input
meetings, which addressed a range of topics describing PacifiCorp's modeling methodology and
inputs and assumptions for the 2025 IRP. Agenda items covered topics including, but not limited
to,resource cost-and-performance assumptions,load forecast,price-policy scenarios,market price
assumptions, and transmission options that will be considered as part of the 2025 IRP. All public-
input meeting materials along with responses to stakeholder feedback forms are included in
Appendix C.
Because the Draft 2025 IRP is in draft form and the Company is still working to finalize the 2025
IRP results,PacifiCorp requests the Idaho Public Utilities Commission("Commission")postpone
issuing a public notice and setting scheduled deadlines until the final 2025 IRP is filed on March
31, 2025.
PacifiCorp also requests that all Commission Staff information requests regarding the Draft 2025
IRP be provided through the Company's public stakeholder feedback form process to ensure
transparency to the public input process. The public stakeholder feedback form can be found at the
following website: https:Hcsapps.pacificpower.net/public/stakeholder-feedback-form
PacifiCorp will continue the IRP process with the following public input meetings where the
Company anticipates discussing the draft IRP along with feedback received:
• January 22-23, 2025 —General Public Input Meeting 8; and
• February 26-27, 2025 —General Public Input Meeting 9.
The Company will be filing the final 2025 IRP that includes a preferred portfolio with an action
plan by March 31, 2025.
Please direct informal questions related to this Draft 2025 IRP to Mark Alder, Idaho Regulatory
Affairs Manager, at(801) 220-2313.
Sincerely,
t 4-
Jana L. Saba
Director, Regulation
Enclosures

Idaho Public Utilities Commission
December 31, 2024
Page 3
cc: Jamie Neill, Idaho Governor's Office
Richard Stover, Idaho Governor's Office
Brad Heusinkveld, Idaho Conservation League
Mitch Colburn, Idaho Power Company
Chris McEwan, Idaho Public Utilities Commission staff
Thomas J. Budge, Bayer
Nancy Kelly, Western Resource Advocates
Eric Olsen, Idaho Irrigation Pumpers Association

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2025
Integrated Resource Plan
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Volume I - December 31 , 2024
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• PACIFICORP
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This 2025 Draft Integrated Resource Plan is based upon the best available information at the
time of preparation. The 2025 Integrated Resource Plan is anticipated to be distributed March
31, 2025.
For more information, contact:
PacifiCorp Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
[e-mail]
www.pacificorp.com

PACIFICORP—2025 IRP TABLE OF CONTENTS
TABLE OF CONTENTS - VOLUME I
TABLE OF CONTENTS...............................................................................i
TABLEOF TABLES................................................................................viii
TABLE OF FIGURES ............................................................................... xi
CHAPTER 1 - EXECUTIVE SUMMARY
MAINTAINING CUSTOMER FOCUS....................................................................................................................1
ROADMAP..................................................................................................................................................................1
CHANGES TO OUR PORTFOLIO...................................................................................................................................2
PACIFICORP'S INTEGRATED RESOURCE PLAN APPROACH.....................................................................2
PREFERRED PORTFOLIO HIGHLIGHTS...........................................................................................................4
NEWSOLAR RESOURCES...........................................................................................................................................6
NEWWIND RESOURCES.............................................................................................................................................7
NEWSTORAGE RESOURCES.......................................................................................................................................7
NEWNUCLEAR RESOURCES......................................................................................................................................7
DEMAND-SIDE MANAGEMENT..................................................................................................................................8
COAL AND GAS EXITS,RETIREMENTS,AND GAS CONVERSIONS...............................................................................8
ACTIONPLAN.........................................................................................................................................................11
CHAPTER 2 - INTRODUCTION
2025 INTEGRATED RESOURCE PLAN COMPONENTS.................................................................................18
THE ROLE OF PACIFICORP'S INTEGRATED RESOURCE PLANNING....................................................19
PUBLICINPUT PROCESS.....................................................................................................................................19
CHAPTER 3 - PLANNING ENVIRONMENT
INTRODUCTION.....................................................................................................................................................22
WHOLESALE ELECTRICITY MARKETS.........................................................................................................22
POWERMARKET PRICES..........................................................................................................................................25
POWER MARKET DYNAMICS...................................................................................................................................27
Non-CAISO WECC Generation and Capacity Mix............................................................................................27
Emissions and Environment...............................................................................................................................31
Non-CAISO WECC Demand Forecast...............................................................................................................31
ForwardInfluence of the IRA............................................................................................................................32
NATURALGAS PRICES.............................................................................................................................................32
2022 Summary...................................................................................................................................................32
2023 Summary...................................................................................................................................................34
2024 Summary...................................................................................................................................................35
2025-2032 Forward View..................................................................................................................................36
Conclusion.........................................................................................................................................................37
PACIFICORP'S MULTI-STATE PROCESS....................................................................................................................37
1

PACIFICORP—2025 IRP TABLE OF CONTENTS
ENVIRONMENTAL REGULATION.....................................................................................................................38
FEDERALPOLICY UPDATE................................................................................................................................39
NATIONAL ELECTRIC VEHICLE INFRASTRUCTURE FORMULA PROGRAM.................................................................39
NEW CREDITS AND CONSIDERATIONS FOR NON-EMITTING RESOURCES—INFLATION REDUCTION ACT..................39
NEW CREDITS AND CONSIDERATIONS FOR CUSTOMER RESOURCES—INFLATION REDUCTION ACT..........................40
NEW SOURCE PERFORMANCE STANDARDS FOR CARBON EMISSIONS FROM NEW AND EXISTING SOURCES—CLEAN
AIRACT§ 111(B)AND(D).......................................................................................................................................41
CREDIT FOR CARBON OXIDE SEQUESTRATION—INTERNAL REVENUE SERVICE§45Q............................................42
CLEAN AIR ACT CRITERIA POLLUTANTS—NATIONAL AMBIENT AIR QUALITY STANDARDS..................................42
OzoneNAAQS....................................................................................................................................................42
ParticulateMatter NAAQS................................................................................................................................44
REGIONALHAZE......................................................................................................................................................44
UtahRegional Haze...........................................................................................................................................45
WyomingRegional Haze....................................................................................................................................46
ColoradoRegional Haze....................................................................................................................................48
MERCURY AND HAZARDOUS AIR POLLUTANTS.......................................................................................................49
COALCOMBUSTION RESIDUALS..............................................................................................................................50
WATER QUALITY STANDARDS................................................................................................................................51
Cooling Water Intake Structures........................................................................................................................51
EffluentLimit Guidelines...................................................................................................................................52
RENEWABLE GENERATION REGULATORY FRAMEWORK..........................................................................................53
TAX EXTENDER LEGISLATION.................................................................................................................................54
STATEPOLICY UPDATE......................................................................................................................................54
CALIFORNIA............................................................................................................................................................54
ID A H O......................................................................................................................................................................55
OREGON..................................................................................................................................................................55
WASHINGTON..........................................................................................................................................................56
UTAH.......................................................................................................................................................................57
WYOMING...............................................................................................................................................................58
GREENHOUSE GAS EMISSION PERFORMANCE STANDARDS .....................................................................................59
RENEWABLE PORTFOLIO STANDARDS.........................................................................................................60
CALIFORNIA............................................................................................................................................................60
OREGON..................................................................................................................................................................62
UTAH.......................................................................................................................................................................64
WASHINGTON..........................................................................................................................................................65
REC MANAGEMENT PRACTICES..............................................................................................................................65
CLEANENERGY STANDARDS............................................................................................................................66
WASHINGTON..........................................................................................................................................................66
OREGON..................................................................................................................................................................66
CALIFORNIA............................................................................................................................................................66
WYOMING...............................................................................................................................................................67
TRANSPORTATION ELECTRIFICATION.........................................................................................................67
HYDROELECTRIC RELICENSING.....................................................................................................................68
POTENTIALIMPACT.................................................................................................................................................69
TREATMENTIN THE IRP..........................................................................................................................................70
PACIFICORP'S APPROACH TO HYDROELECTRIC RELICENSING................................................................................70
RATEDESIGN..........................................................................................................................................................70
RESIDENTIAL RATE DESIGN....................................................................................................................................70
COMMERCIAL AND INDUSTRIAL RATE DESIGN........................................................................................................71
11

PACIFICORP—2025 IRP TABLE OF CONTENTS
IRRIGATION RATE DESIGN.......................................................................................................................................71
ELECTRICITY MARKET DEVELOPMENT UPDATE.....................................................................................71
RECENT RESOURCE PROCUREMENT ACTIVITIES....................................................................................73
2022 ALL-SOURCE RFP...........................................................................................................................................74
2024 UTAH RENEWABLES COMMUNITY RFP..........................................................................................................74
2025 ALL-SOURCE RFP...........................................................................................................................................75
CHAPTER 4 - TRANSMISSION
INTRODUCTION.....................................................................................................................................................77
REGULATORY REQUIREMENTS.......................................................................................................................78
OPEN ACCESS TRANSMISSION TARIFF.....................................................................................................................78
RELIABILITYSTANDARDS........................................................................................................................................79
GENERATION INTERCONNECTION STUDY METHODOLOGY CHANGES......................................................................80
AEOLUS TO MONA/CLOVER(GATEWAY SOUTH—SEGMENT F)...............................................................................80
WINDSTAR-POPULUS(GATEWAY WEST—SEGMENT D)..........................................................................................80
POPULUS-HEMINGWAY(GATEWAY WEST-SEGMENT E)........................................................................................81
PLAN TO CONTINUE PERMITTING—GATEWAY WEST..............................................................................................81
BOARDMAN-HEMINGWAY(SEGMENT H)................................................................................................................81
SPANISH FORK—MERCER 345-KV LINE..................................................................................................................82
OTHER TRANSMISSION SYSTEM IMPROVEMENTS....................................................................................................83
ENERGY GATEWAY TRANSMISSION EXPANSION PLAN..........................................................................83
INTRODUCTION........................................................................................................................................................83
BACKGROUND.........................................................................................................................................................83
PLANNINGINITIATIVES............................................................................................................................................83
- Rocky Mountain Area Transmission Study...............................................................................................84
ENERGY GATEWAY CONFIGURATION......................................................................................................................85
ENERGY GATEWAY'S CONTINUED EVOLUTION.......................................................................................................86
EFFORTS TO MAXIMIZE EXISTING SYSTEM CAPABILITY......................................................................90
TRANSMISSION SYSTEM IMPROVEMENTS PLACED IN-SERVICE SINCE THE 2023 IRP..............................................91
PLANNED TRANSMISSION SYSTEM IMPROVEMENTS................................................................................................92
CHAPTER 5 - RELIABILITY AND RESILIENCY
INTRODUCTION.....................................................................................................................................................97
SUPPLY-BASED RELIABILITY............................................................................................................................97
REGIONAL RESOURCE ADEQUACY..........................................................................................................................97
WECC WESTERN ASSESSMENT OF RESOURCE ADEQUACY REPORT.......................................................................98
NERC LONG-TERM RELIABILITY ASSESSMENT(LTRA)........................................................................................99
Resources...........................................................................................................................................................99
WECCSubregions............................................................................................................................................100
LTRAWECCAssessment.................................................................................................................................100
PACIFIC NORTHWEST POWER SUPPLY ADEQUACY ASSESSMENT..........................................................................101
WESTERN RESOURCE ADEQUACY PROGRAM(WRAP)..........................................................................................102
RELIABLE SERVICE THROUGH UNPREDICTABLE WEATHER AND CHALLENGING MARKET LIQUIDITY...................103
PLANNING FOR LOAD CHANGES AS A RESULT OF CLIMATE CHANGE....................................................................104
WEATHER-RELATED IMPACTS TO VARIABLE GENERATION...................................................................................104
WildfireImpacts...............................................................................................................................................105
ExtremeWeather Impacts................................................................................................................................105
111

PACIFICORP—2025 IRP TABLE OF CONTENTS
Impacts on wind and solar energy...................................................................................................................106
WILDFIRE RISK MITIGATION.........................................................................................................................107
TRANSMISSION-BASED RELIABILITY..........................................................................................................108
FEDERAL RELIABILITY STANDARDS......................................................................................................................109
POWER FLOW ANALYSES AND PLANNING FOR GENERATOR RETIREMENTS...........................................................110
CHAPTER 6 - LOAD AND RESOURCE BALANCE
INTRODUCTION...................................................................................................................................................111
SYSTEM COINCIDENT PEAK LOAD FORECAST.........................................................................................112
EXISTING RESOURCES......................................................................................................................................112
THERMALPLANTS.................................................................................................................................................112
RENEWABLERESOURCES......................................................................................................................................114
Wind.................................................................................................................................................................114
Solar.................................................................................................................................................................116
Geothermal......................................................................................................................................................119
Biomass/Biogas................................................................................................................................................120
Distributed Generation Resources...................................................................................................................120
ENERGYSTORAGE.................................................................................................................................................120
HYDROELECTRIC GENERATION.............................................................................................................................120
DEMAND-SIDE MANAGEMENT/DISTRIBUTED GENERATION..................................................................................122
DISTRIBUTED GENERATION FORECAST..................................................................................................................124
POWER-PURCHASE AGREEMENTS..........................................................................................................................125
CAPACITY LOAD AND RESOURCE BALANCE.............................................................................................126
CAPACITY BALANCE OVERVIEW...........................................................................................................................126
LOAD AND RESOURCE BALANCE COMPONENTS....................................................................................................127
Obligation........................................................................................................................................................128
Position............................................................................................................................................................128
CAPACITY BALANCE DETERMINATION..................................................................................................................129
Methodology....................................................................................................................................................129
CapacityBalance Results.................................................................................................................................129
CHAPTER 7 - RESOURCE OPTIONS
INTRODUCTION...................................................................................................................................................139
SUPPLY-SIDE RESOURCES(SSR).....................................................................................................................139
DERIVATION OF RESOURCE ATTRIBUTES...............................................................................................................141
WIND AND SOLAR GENERATION PROFILES............................................................................................................143
RESOURCE OPTIONS AND ATTRIBUTES..................................................................................................................144
RESOURCE OPTION DESCRIPTIONS........................................................................................................................158
LOCATIONAL MODIFIERS AND SELECTED COST FORECASTS.................................................................................163
PVCost Forecast History................................................................................................................................163
WindCost Forecast History.............................................................................................................................164
EnergyStorage.................................................................................................................................................165
DEMAND-SIDE RESOURCES.............................................................................................................................167
RESOURCE OPTIONS AND ATTRIBUTES..................................................................................................................167
Source of Demand-Side Management Resource Data.....................................................................................167
TRANSMISSION RESOURCES...........................................................................................................................173
1V

PACIFICORP—2025 IRP TABLE OF CONTENTS
MARKETPURCHASES........................................................................................................................................173
CHAPTER 8 - MODELING AND PORTFOLIO EVALUATION
INTRODUCTION...................................................................................................................................................176
MODELING AND EVALUATION STEPS..........................................................................................................176
OVERVIEW OF STEPS IN AN ITERATIVE PHASE.......................................................................................................177
Step1................................................................................................................................................................177
Step2................................................................................................................................................................177
Step3................................................................................................................................................................178
Step4................................................................................................................................................................178
Step5................................................................................................................................................................178
Step6................................................................................................................................................................178
GRANULARITY ADJUSTMENT DETAIL....................................................................................................................178
RELIABILITY ADJUSTMENT DETAIL.......................................................................................................................179
RESOURCE PORTFOLIO DEVELOPMENT....................................................................................................180
LONG-TERM(LT)CAPACITY EXPANSION MODEL.................................................................................................181
TransmissionSystem........................................................................................................................................182
TransmissionOptions......................................................................................................................................183
TransmissionCosts..........................................................................................................................................185
ResourceAdequacy..........................................................................................................................................185
Granularity and Reliability Adjustments..........................................................................................................185
ThermalResource Options...............................................................................................................................186
NewResource Options.....................................................................................................................................187
CapitalCosts....................................................................................................................................................189
GeneralAssumptions.......................................................................................................................................189
COSTAND RISK ANALYSIS...............................................................................................................................192
SHORT-TERM(ST)SCHEDULE MODEL..................................................................................................................192
Reliability Assessment and System Cost...........................................................................................................193
STOCHASTIC MODELING........................................................................................................................................194
Stochastic Portfolio Performance Measures....................................................................................................195
Forward Price Curve Scenarios......................................................................................................................197
Other PLEXOS Modeling Methods and Assumptions......................................................................................197
OTHER COST AND RISK CONSIDERATIONS.............................................................................................................197
FuelSource Diversity.......................................................................................................................................197
CustomerRate Impacts....................................................................................................................................198
MarketReliance...............................................................................................................................................198
PORTFOLIOSELECTION...................................................................................................................................198
FINAL EVALUATION AND PREFERRED PORTFOLIO SELECTION.......................................................198
CASEDEFINITIONS.............................................................................................................................................199
INITIALPORTFOLIOS..............................................................................................................................................199
INTEGRATED PORTFOLIOS.....................................................................................................................................202
WASHINGTON PORTFOLIOS ...................................................................................................................................203
SENSITIVITY CASE DEFINITIONS............................................................................................................................204
BusinessPlan Sensitivity..................................................................................................................................207
V

PACIFICORP—2025 IRP TABLE OF CONTENTS
CHAPTER 9 - MODELING AND PORTFOLIO SELECTION
RESULTS
INTRODUCTION...................................................................................................................................................210
INITIAL PORTFOLIO DEVELOPMENT..........................................................................................................210
JURISDICTIONAL PORTFOLIOS......................................................................................................................211
JURISDICTIONAL SHARES PRIOR TO INTEGRATION.................................................................................................213
FULL JURISDICTIONAL PORTFOLIOS ......................................................................................................................214
THE 2025 IRP PREFERRED PORTFOLIO........................................................................................................219
NEWSOLAR RESOURCES.......................................................................................................................................220
NEWWIND RESOURCES.........................................................................................................................................220
NEW STORAGE RESOURCES...................................................................................................................................221
NEWNUCLEAR RESOURCES..................................................................................................................................221
DEMAND-SIDE MANAGEMENT..............................................................................................................................222
WHOLESALE POWER MARKET PRICES AND PURCHASES........................................................................................223
COAL AND GAS RETIREMENTS/GAS CONVERSIONS...............................................................................................224
CARBON DIOXIDE EQUIVALENT EMISSIONS..........................................................................................................225
RENEWABLE PORTFOLIO STANDARDS...................................................................................................................228
OREGON HB2021 COMPLIANCE............................................................................................................................231
Greenhouse gas emissions methodology..........................................................................................................231
CAPACITYAND ENERGY........................................................................................................................................232
DETAILED PREFERRED PORTFOLIO........................................................................................................................234
INTEGRATED PORTFOLIO RESOURCE COMPARISONS BY TECHNOLOGY AND YEAR...............................................241
PREFERRED PORTFOLIO VARIANTS............................................................................................................247
VARIANT STUDY ANALYSIS..................................................................................................................................249
ADDITIONAL SENSITIVITY ANALYSIS..........................................................................................................254
WASHINGTON SCENARIOS...............................................................................................................................255
CHAPTER 10 - ACTION PLAN
INTRODUCTION...................................................................................................................................................257
THE 2025 IRP ACTION PLAN.............................................................................................................................258
PROGRESS ON 2023 ACTION PLAN.................................................................................................................263
ACQUISITION PATH ANALYSIS.......................................................................................................................273
RESOURCE AND COMPLIANCE STRATEGIES...........................................................................................................273
ACQUISITION PATH DECISION MECHANISM...........................................................................................................273
PROCUREMENTDELAYS..................................................................................................................................274
IRP ACTION PLAN LINKAGE TO BUSINESS PLANNING...........................................................................274
RESOURCE PROCUREMENT STRATEGY......................................................................................................275
RENEWABLE RESOURCES,STORAGE RESOURCES,AND DISPATCHABLE RESOURCES............................................275
RENEWABLE ENERGY CREDITS.............................................................................................................................275
DEMAND-SIDE MANAGEMENT..............................................................................................................................275
SMALL SCALE RENEWABLE ENERGY SUPPLY........................................................................................................276
ASSESSMENT OF OWNING ASSETS VERSUS PURCHASING POWER....................................................276
Vi

PACIFICORP-2025 IRP TABLE OF CONTENTS
MANAGING CARBON RISK FOR EXISTING PLANTS.................................................................................276
PURPOSEOF HEDGING......................................................................................................................................277
TREATMENT OF CUSTOMER AND INVESTOR RISKS...............................................................................279
STOCHASTIC RISK ASSESSMENT............................................................................................................................279
CAPITALCOST RISKS............................................................................................................................................279
SCENARIORISK ASSESSMENT................................................................................................................................279
VII

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF TABLES - VOLUME I
CHAPTER 1 -EXECUTIVE SUMMARY
TABLE 1.1-TRANSMISSION PROJECTS INCLUDED IN THE 2025 IRP PREFERRED PORTFOLIO 1,2.....................................6
TABLE 1.2-2025 IRP COAL RESOURCE RESULTS SUMMARY.....................................................................................10
TABLE1.3-2025 IRP ACTION PLAN...........................................................................................................................11
CHAPTER 2 -INTRODUCTION
CHAPTER 3 -PLANNING ENVIRONMENT
TABLE 3.1-2023 AND 2024 MONTHLY AVERAGE ON-PEAK SPOT PRICES($/MWH)..................................................25
TABLE 3.2-2025-2027 FORWARD PRICE SPREAD($/MWH)........................................................................................27
TABLE 3.3-STATE RPS REQUIREMENTS.....................................................................................................................60
TABLE 3.4-CALIFORNIA COMPLIANCE PERIOD REQUIREMENTS.................................................................................61
TABLE 3.5-CALIFORNIA BALANCED PORTFOLIO REQUIREMENTS..............................................................................62
TABLE 3.6-PACIFICORP'S REQUESTS FOR PROPOSAL ACTIVITY................................................................................74
CHAPTER 4 - TRANSMISSION
TABLE 4.1-ENERGY GATEWAY TRANSMISSION EXPANSION PLAN.............................................................................90
CHAPTER 5 -RELIABILITY AND RESILIENCY
TABLE 5.1-WARA DEMAND-AT-RISK SUMMARY.....................................................................................................98
TABLE 5.2-WECC SUBREGION DESCRIPTIONS........................................................................................................100
TABLE 5.3-NERC LTRA FOR SELECTED WECC SUBREGIONS................................................................................101
TABLE 5.4-NORTHWEST POWER AND CONSERVATION COUNCIL 2029 ADEQUACY ASSESSMENT............................102
CHAPTER 6 -LOAD AND RESOURCE BALANCE
TABLE 6.1-FORECASTED SYSTEM SUMMER COINCIDENT PEAK LOAD IN MEGAWATTS,BEFORE ENERGY EFFICIENCY
(MW)................................................................................................................................................................112
TABLE6.2-COAL-FIRED PLANTS..............................................................................................................................113
TABLE 6.3-NATURAL GAS-FIRED PLANTS...............................................................................................................114
TABLE 6.4-OWNED WIND RESOURCES.....................................................................................................................115
TABLE 6.5-NON-OWNED WIND RESOURCES............................................................................................................115
TABLE 6.6-SOLAR POWER PURCHASE AGREEMENTS...............................................................................................117
TABLE 6.7-SOLAR QUALIFYING FACILITIES,OREGON.............................................................................................118
TABLE 6.8-SOLAR QUALIFYING FACILITIES,UTAH..................................................................................................119
TABLE 6.9-SOLAR QUALIFYING FACILITIES,WYOMING..........................................................................................119
TABLE 6.10-DISTRIBUTED GENERATION CUSTOMERS AND CAPACITY.....................................................................120
TABLE 6.11-STORAGE RESOURCES..........................................................................................................................120
TABLE 6.12-PACIFICORP HYDROELECTRIC GENERATION FACILITIES......................................................................121
TABLE 6.13-ExISTING DSM RESOURCE SUMMARY.................................................................................................124
TABLE 6.14--SUMMER PEAK-SYSTEM CAPACITY LOADS AND RESOURCES WITHOUT RESOURCE ADDITIONS .......130
TABLE 6.15-WINTER PEAK SYSTEM CAPACITY LOADS AND RESOURCES WITHOUT.................................................132
VIII

PACIFICORP-2025 IRP TABLE OF CONTENTS
CHAPTER 7-RESOURCE OPTIONS
TABLE 7.1-SUPPLY-SIDE RESOURCE OPTION TABLES..............................................................................................145
TABLE 7.2-2025 THERMAL SUPPLY-SIDE RESOURCES,CHARACTERISTICS AND COSTS(2024$).............................146
TABLE 7.3-2025 NON-THERMAL SUPPLY-SIDE RESOURCES,CHARACTERISTICS AND COSTS(2024$).....................147
TABLE 7.4-2025 THERMAL SUPPLY-SIDE RESOURCES,OPERATING CHARACTERISTICS AND ENVIRONMENTAL DATA
(2024$).............................................................................................................................................................148
TABLE 7.5-2025 NON-THERMAL SUPPLY-SIDE RESOURCES,OPERATING CHARACTERISTICS AND ENVIRONMENTAL
DATA(2024$)...................................................................................................................................................149
TABLE 7.6-2025 IRP THERMAL SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M..............150
TABLE 7.7-2025 IRP NON-THERMAL SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M......151
TABLE 7.8-2025 IRP STORAGE SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M...............152
TABLE 7.9-2025 IRP THERMAL SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS.............153
TABLE 7.10-2025 IRP NON-THERMAL SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS..154
TABLE 7.11-2025 IRP STORAGE SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS............155
TABLE 7.12-GLOSSARY OF TERMS USED IN THE SUPPLY-SIDE RESOURCE TABLES..................................................156
TABLE 7.13-GLOSSARY OF ACRONYMS USED IN THE SUPPLY-SIDE RESOURCE TABLES..........................................157
TABLE 7.14-DEMAND RESPONSE EXISTING AND PLANNED PROGRAMS...................................................................168
TABLE 7.15-DEMAND RESPONSE PROGRAM ATTRIBUTES WEST CONTROL AREA,*................................................168
TABLE 7.16-DEMAND RESPONSE PROGRAM ATTRIBUTES EAST CONTROL AREA,*.................................................169
TABLE 7.17- 2045 TOTAL CUMULATIVE ENERGY EFFICIENCY POTENTIAL BY.........................................................172
TABLE 7.18-STATE-SPECIFIC TRANSMISSION AND DISTRIBUTION CREDITS(2024$)................................................172
CHAPTER 8 -MODELING AND PORTFOLIO EVALUATION
TABLE 8.1-MAJORITY-OWNED COAL GENERATOR RESOURCE OPTIONS..................................................................186
TABLE 8.2-MINORITY-OWNED COAL GENERATOR RESOURCE OPTIONS..................................................................187
TABLE 8.3-NATURAL GAS GENERATOR RESOURCE OPTIONS...................................................................................187
TABLE 8.4-PRICE-POLICY CASE DEFINITIONS..........................................................................................................200
TABLE8.5-PORTFOLIO VARIANTS............................................................................................................................200
TABLE 8.6-PORTFOLIO INTEGRATION RESOURCE EXAMPLE....................................................................................203
TABLE 8.7-SENSITIVITY CASE DEFINITIONS.............................................................................................................205
CHAPTER 9 -MODELING AND PORTFOLIO SELECTION RESULTS
TABLE 9.1-ITERATIVE PHASES OF UTAH,IDAHO,WYOMING AND CALIFORNIA MN PORTFOLIO..............................211
TABLE 9.2-OREGON INITIAL SHARE.........................................................................................................................213
TABLE 9.3-WASHINGTON INITIAL SHARE................................................................................................................213
TABLE 9.4-UTAH,IDAHO,WYOMING AND CALIFORNIA INITIAL SHARE..................................................................214
TABLE 9.5-OREGON FULL JURISDICTIONAL PORTFOLIO..........................................................................................215
TABLE 9.6-WASHINGTON FULL JURISDICTIONAL PORTFOLIO .................................................................................216
TABLE 9.7-UTAH,IDAHO,WYOMING,CALIFORNIA(UIWC)FULL JURISDICTIONAL PORTFOLIO............................217
TABLE 9.8-TRANSMISSION PROJECTS INCLUDED IN THE 2025 IRP PREFERRED PORTFOLIO 1,2.................................220
TABLE 9.9-2025 IRP COAL RESOURCE RESULTS.....................................................................................................225
TABLE 9.10-PACIFICORP'S 2025 IRP PREFERRED PORTFOLIO.................................................................................235
TABLE 9.11-PREFERRED PORTFOLIO SUMMER CAPACITY LOAD AND RESOURCE BALANCE(2025-2034)...............237
TABLE 9.12-PREFERRED PORTFOLIO SUMMER CAPACITY LOAD AND RESOURCE BALANCE(2036-2045)...............238
TABLE 9.13-PREFERRED PORTFOLIO WINTER CAPACITY LOAD AND RESOURCE BALANCE(2025-2034)................239
TABLE 9.14-PREFERRED PORTFOLIO WINTER CAPACITY LOAD AND RESOURCE BALANCE(2035-2045)................240
TABLE9.15-NEW GAS ............................................................................................................................................241
TABLE9.16-NUCLEAR'.............................................................................................................................................241
TABLE 9.17-RENEWABLE PEAKING' ........................................................................................................................242
TABLE 9.18-DSM-ENERGY EFFICIENCY................................................................................................................242
TABLE 9.19-DSM-DEMAND RESPONSE.................................................................................................................242
1X

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE 9.20-UTILITY SCALE WIND..........................................................................................................................243
TABLE 9.21-SMALL SCALE WIND'...........................................................................................................................243
TABLE9.22-UTILITY SOLAR....................................................................................................................................243
TABLE 9.23-SMALL SCALE SOLAR' .........................................................................................................................244
TABLE 9.24-BATTERY STORAGE.............................................................................................................................244
TABLE 9.25-LONG DURATION STORAGE.................................................................................................................244
TABLE 9.26-MAJORITY OWNED COAL RETIREMENTS1.............................................................................................245
TABLE 9.27-CARBON CAPTURE AND SEQUESTRATION SELECTIONS........................................................................245
TABLE 9.28-COAL TO GAS CONVERSION SELECTIONS.............................................................................................245
TABLE 9.29-PREFERRED PORTFOLIO VARIANT STUDIES..........................................................................................247
TABLE 9.30-INITIAL AND VARIANT CASES UNDER MEDIUM GAS/ZERO CO2..........................................................247
TABLE 9.31-INITIAL AND VARIANT CASES UNDER LOW GAS/ZERO CO2................................................................248
TABLE 9.32-INITIAL AND VARIANT CASES UNDER HIGH GAS/HIGH CO2...............................................................248
TABLE 9.33 INITIAL AND VARIANT CASES UNDER MEDIUM GAS/SOCIAL COST OF CO2........................................249
CHAPTER 10 -ACTION PLAN
TABLE 10.1-2025 IRP ACTION PLAN.......................................................................................................................259
TABLE 10.2-2023 IRP ACTION PLAN STATUS UPDATE............................................................................................263
X

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF FIGURES - VOLUME I
CHAPTER 1 -EXECUTIVE SUMMARY
FIGURE 1.1-KEY ELEMENTS OF PACIFICORP'S 2025 IRP APPROACH...........................................................................4
FIGURE 1.2-2025 IRP PREFERRED PORTFOLIO(EXISTING AND PLANNED RESOURCES)*.............................................5
FIGURE 1.3-2025 IRP PREFERRED PORTFOLIO NEW SOLAR CAPACITY.......................................................................6
FIGURE 1.4-2025 IRP PREFERRED PORTFOLIO NEW WIND CAPACITY.........................................................................7
FIGURE 1.5-2025 IRP PREFERRED PORTFOLIO NEW STORAGE CAPACITYI°2................................................................7
FIGURE1.6-2025 IRP NEW NUCLEAR..........................................................................................................................8
FIGURE 1.7-2025 IRP PREFERRED PORTFOLIO THERMAL RESOURCES.........................................................................9
CHAPTER 2 -INTRODUCTION
CHAPTER 3 -PLANNING ENVIRONMENT
FIGURE 3.1 -FORWARD PRICES AT WECC MAJOR TRADING HUBS.............................................................................26
FIGURE 3.2-NATIONAL RPS TARGETS........................................................................................................................28
FIGURE 3.3-STATES WITH CO2 REDUCTION TARGETS................................................................................................28
FIGURE 3.4-NON-CAISO WECC GENERATED ENERGY(TWH).................................................................................29
FIGURE 3.5-NoN-CAISO WECC CAPACITY ADDITION(GW)...................................................................................30
FIGURE 3.6-NON-CAISO WECC CAPACITY RETIREMENT(GW)...............................................................................31
FIGURE 3.7-NON-CAISO WECC CAPACITY RETIREMENT(GW)...............................................................................32
FIGURE 3.8-DAILY 2022 HENRY HUB SPOT PRICES(USD/MMBTu).........................................................................33
FIGURE 3.9-ANNUAL 2022-2023 CHANGE IN US NATURAL GAS PRODUCTION BY REGION(BCF/D)..........................34
FIGURE 3.10-LOWER 48 WEEKLY WORKING GAS IN UNDERGROUND STORAGE(BCF/D)..........................................35
FIGURE 3.11-HENRY HUB FUTURES...........................................................................................................................37
FIGURE 3.12-WESTERN ENERGY IMBALANCE MARKET EXPANSION..........................................................................72
CHAPTER 4 - TRANSMISSION
FIGURE4.1 -SEGMENT D.............................................................................................................................................80
FIGURE4.2-SEGMENT E..............................................................................................................................................81
FIGURE 4.3-ENERGY GATEWAY TRANSMISSION EXPANSION PLAN...........................................................................89
CHAPTER 5 -RELIABILITY AND RESILIENCY
CHAPTER 6 - LOAD AND RESOURCE BALANCE
FIGURE 6.1-CUMULATIVE HISTORICAL AND NEW CAPACITY INSTALLED BY...........................................................125
FIGURE 6.2-CONTRACT CAPACITY IN THE 2025 IRP SUMMER LOAD AND RESOURCE BALANCE.............................126
FIGURE 6.3-ENERGY EFFICIENCY PEAK CONTRIBUTION IN SUMMER CAPACITY LOAD AND RESOURCE BALANCE
(REDUCTION TO LOAD,IN MW) .......................................................................................................................128
FIGURE 6.4-SUMMER SYSTEM CAPACITY POSITION TREND ....................................................................................134
FIGURE 6.5-WINTER SYSTEM CAPACITY POSITION TREND......................................................................................135
FIGURE 6.6-EAST SUMMER CAPACITY POSITION TREND..........................................................................................136
FIGURE 6.7 -WEST SUMMER CAPACITY POSITION TREND........................................................................................137
XI

PACIFICORP-2025 IRP TABLE OF CONTENTS
CHAPTER 7-RESOURCE OPTIONS
FIGURE 7.1-HISTORY OF SSR PV COST&FORECAST..............................................................................................164
FIGURE 7.2-HISTORY OF SSR WIND COSTS&FORECAST........................................................................................165
FIGURE 7.3-HISTORY OF SSR BATTERY ENERGY STORAGE SYSTEM COSTS&FORECAST......................................166
CHAPTER 8 -MODELING AND PORTFOLIO EVALUATION
FIGURE 8.1-PORTFOLIO EVALUATION STEPS WITHIN THE IRP PROCESS..................................................................177
FIGURE 8.2-GRANULARITY ADJUSTMENT DETERMINATION....................................................................................179
FIGURE 8.3-TRANSMISSION SYSTEM MODEL TOPOLOGY WITH MAJOR OPTIONS.....................................................183
FIGURE 8.4-CO2 PRICES MODELED BY PRICE-POLICY SCENARIO............................................................................191
FIGURE 8.5-NOMINAL WHOLESALE ELECTRICITY AND NATURAL GAS PRICE SCENARIOS......................................192
CHAPTER 9 -MODELING AND PORTFOLIO SELECTION RESULTS
FIGURE 9.1-2025 IRP PREFERRED PORTFOLIO(ALL RESOURCES)...........................................................................219
FIGURE 9.2-2025 IRP PREFERRED PORTFOLIO NEW SOLAR CAPACITY...................................................................220
FIGURE 9.3-2025 IRP PREFERRED PORTFOLIO NEW WIND CAPACITY.....................................................................221
FIGURE 9.4-2025 IRP PREFERRED PORTFOLIO NEW STORAGE CAPACITY1..............................................................221
FIGURE 9.5-2025 IRP NEW NUCLEAR......................................................................................................................222
FIGURE 9.6-LOAD FORECAST COMPARISON BETWEEN RECENT IRPS(BEFORE INCREMENTAL ENERGY EFFICIENCY
SAVINGS)..........................................................................................................................................................222
FIGURE 9.7-2025 IRP PREFERRED PORTFOLIO ENERGY EFFICIENCY AND DEMAND RESPONSE CAPACITY..............223
FIGURE 9.8-COMPARISON OF POWER PRICES AND NATURAL GAS PRICES IN RECENT IRPS.....................................224
FIGURE 9.9-2025 IRP PREFERRED PORTFOLIO THERMAL RESOURCES.....................................................................224
FIGURE 9.10-2025 IRP PREFERRED PORTFOLIO CO2 EMISSIONS AND PACIFICORP CO2 EQUIVALENT EMISSIONS
TRAJECTORY1 ...................................................................................................................................................227
FIGURE 9.11-ANNUAL STATE RPS COMPLIANCE FORECAST...................................................................................230
FIGURE 9.12-OREGON ALLOCATED EMISSION REDUCTION RELATIVE TO HB 2021 TARGET...................................232
FIGURE 9.13-PROJECTED ENERGY MIX WITH PREFERRED PORTFOLIO RESOURCES.................................................233
FIGURE 9.14-PROJECTED CAPACITY MIX WITH PREFERRED PORTFOLIO RESOURCES..............................................233
FIGURE 9.15-INCREASE/(DECREASE IN PROXY RESOURCES WITH NO CCS.............................................................250
FIGURE 9.16-INCREASE/(DECREASE IN SYSTEM COSTS WITH NO CCS ...................................................................250
FIGURE 9.17-INCREASE/(DECREASE IN PROXY RESOURCES WITH NO NUCLEAR.....................................................251
FIGURE 9.18-INCREASE/(DECREASE IN SYSTEM COSTS WITH NO NUCLEAR...........................................................251
FIGURE 9.19-INCREASE/(DECREASE IN PROXY RESOURCES WITH NO COAL POST 2032.........................................252
FIGURE 9.20-INCREASE/(DECREASE IN SYSTEM COSTS WITH NO COAL POST 2032................................................252
FIGURE 9.21 -INCREASE/(DECREASE IN PROXY RESOURCES WITH OFFSHORE WIND...............................................253
FIGURE 9.22-INCREASE/(DECREASE IN SYSTEM COSTS WITH OFFSHORE WIND......................................................254
CHAPTER 10 -ACTION PLAN
xii

PACIFICORP-2025 IU CHAPTER I-EXECUTIVE SUMMARY
CHAPTER I - EXECUTIVE SUMMARY
Maintaining customer focus
Our draft 2025 Integrated Resource Plan (IRP) is a roadmap for continual progress in safely,
reliably and affordably serving over 2 million customers across six states. This roadmap continues
to deliver on PacifiCorp's commitments to the diverse communities in which it operates.
Roadmap
Two significant transmission projects have been placed in-service since the 2023 IRP, and are
therefore included in the 2025 IRP as given accomplishments:
• The Energy Gateway South transmission line—a new 416-mile,high-voltage 500-kilovolt
(kV) transmission line and associated infrastructure running from the Aeolus substation
near Medicine Bow, Wyoming, to the Clover substation near Mona, Utah. This
transmission line was placed in service in the fourth quarter of 2024.
• The Energy Gateway West Subsegment D1 project—a new high-voltage 230-kV
transmission line and a rebuild of an existing 230 kV transmission line from the Shirley
Basin substation in southeastern Wyoming to the Windstar substation near Glenrock,
Wyoming. These lines were placed in service in fourth quarter of 2024.
These projects laid the groundwork for long-term affordability and reliability and helping build a
more resilient grid.
• The following resources are added in the draft 2025 IRP:
0 6,379 megawatts of new wind resources
0 7,668 megawatts of storage resources, including four-hour, eight-hour, and 100-hour
durations
0 5,492 megawatts of new solar resources
0 500 megawatts of advanced nuclear(NatriumTM reactor demonstration project)
Customer Programs
• 5,149 megawatts of capacity saved through energy efficiency programs
• 1,052 megawatts of capacity saved through direct load control programs
Transmission
• Various upgrades to increase the transfer capability from southern Utah to the major load
center in the Wasatch Front
• New transmission from the Walla Walla substation near Walla Walla, Washington to the
Wine Country substation near Sunnyside, Washington
1

PACIFICORP-2025 IRP CHAPTER I-EXECUTIVE SUMMARY
• 120 miles of new transmission from the Fry substation near Albany, Oregon to a new
substation in Deschutes County, Oregon
• New transmission, including lines from the Fry substation near Albany, Oregon and from
the Dixonville substation near Roseburg, Oregon, each connecting to a substation near
Lebanon, Oregon
• A second 416-mile transmission line from the Aeolus substation near Medicine Bow,
Wyoming, to the Clover substation near Mona, Utah (Energy Gateway South 2)
• Additional local transmission upgrades to connect clean resources to the transmission
system in southern Utah, southern and central Oregon, the Willamette Valley in Oregon,
and in Yakima and Walla Walla, Washington
Changes to our Portfolio
• Continue to work with co-owners to develop the most cost-effective path toward an exit
from the Colstrip project in Montana by 2030
• Continue to evaluate carbon capture and sequestration options for Jim Bridger Units 3 and
4 in Rock Springs, Wyoming, for completion by 2030
• Continue the process of coal-to-gas conversion of Naughton Units 1 and 2 in Kemmerer,
Wyoming, for completion by 2026
• Continue to evaluate coal-to-gas conversion of Dave Johnston Units 1 and 2 in Glenrock,
Wyoming, for completion by 2029
• Retire Dave Johnston Unit 3 in Glenrock, Wyoming, in 2027
rce Plan Approach
In the 2025 IRP,PacifiCorp presents a preferred portfolio that builds on its vision to deliver energy
affordably, reliably and responsibly through near-term investments in transmission infrastructure
that will facilitate continued growth in new renewable resource capacity while maintaining
substantial investment in energy efficiency and demand response programs.
At the same time, the preferred portfolio is responsive to the rapidly expanding arena of new state
and federal regulatory requirements.
The 2025 IRP preferred portfolio demonstrates that reliable service will require investment in
transmission infrastructure, new wind and solar resources, the conversion of four coal units to
natural gas peaking units, significant demand response and energy efficiency programs, the
addition of carbon capture technology on identified coal resources, the addition of an advanced
nuclear resource,and the addition of energy storage resources.As discussed in Chapter 8,the 2025
IRP preferred portfolio includes resources necessary for individual state policy compliance and
assumes those resources are allocated to the state whose policy necessitated the addition.
2

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
The primary objective of the IRP is to identify the best mix of proxy resources to serve customers
in the future.' Building upon developments initiated in the 2023 IRP Update, PacifiCorp
recognizes that the basis for identifying a least-cost, least-risk portfolio varies across its
jurisdictions, so the 2025 IRP assesses the cost-effectiveness of individual resources in light of the
requirements specific to each jurisdiction. For the 2025 IRP, three distinct sets of jurisdictional
requirements were represented:
• Utah, Idaho, Wyoming, and California
o Cost-effective resources
o Compliance with Western Resource Adequacy Program (WRAP) capacity requirements
for Utah, Idaho, Wyoming, and California load
• Oregon
o Compliance with energy and emissions requirements from House Bill 2021 (HB2021)
o Compliance with WRAP capacity requirements for Oregon load
o Compliance with small-scale renewable capacity standard
• Washington
o Compliance with clean energy requirements from the Clean Energy Transformation Act
(CETA)
o Compliance with WRAP capacity requirements for Washington load
Resources identified under each jurisdictional view are brought together into an "integrated"
portfolio and only allocated to those jurisdictions in which they were identified as cost effective.
For each jurisdiction, the best combination of resources is determined through analysis that
measures cost and risk. Beyond the costs and risks quantified through modeling, the least-cost,
least-risk resource portfolio is the portfolio that can be delivered through specific action items at a
reasonable cost and with manageable risks while considering customer demand for clean energy
and ensuring compliance with state and federal regulatory obligations.
The full planning process is completed every two years, with a review and update completed in
the off years. Consequently, these plans, particularly their longer-range elements, can and do
change over time.
PacifiCorp's 2025 IRP was developed through an open and extensive public process, with input
from an active and diverse group of stakeholders, including customer advocacy groups,
community members,regulatory staff,and other interested parties. The public-input process began
with the first public input meeting in January 2024,representing the earliest IRP cycle kick-off for
PacifiCorp.
For the first time, in the 2025 IRP process PacifiCorp developed a full draft document and
distributed it to stakeholders on December 31, 2024. The timing and requirements of this draft
necessitated coverage of IRP topics in the public input meeting series occur three months earlier
than in past planning cycles,reducing the number of public meetings, but also increasing meeting
1 Proxy resources are not actual projects but indicative projects,with estimated costs,technology,timing and location.
Actual project data is evaluated in downstream processes.One key example of such a downstream process is a request
for proposals,in which bids are solicited on real-world projects where the costs,technology,timing and location can
be known and are subject to negotiation.
2 While California has a number of policy requirements,PacifiCorp is currently required to demonstrate compliance
using system-wide portfolio results.
3

PACIFICORP—2025 IRP CHAPTER I—EXECUTIVE SUMMARY
length and accelerating the timing of the coverage of all topics. Following the kick-off,PacifiCorp
hosted stakeholders in seven online public input meetings, with an additional two meetings
scheduled to take place after the distribution of the draft. Throughout this effort, PacifiCorp
received valuable input from stakeholders and presented findings from a broad range of studies
and technical analyses that shaped and informed the 2025 IRP. In the 2025 IRP, PacifiCorp also
enhanced the connections between stakeholder input and IRP development by providing footnotes
which reference stakeholder feedback the company received over the course of this IRP cycle.
Links to each publicly available stakeholder feedback form and PacifiCorp response are provided
in these footnotes and are provided in Appendix M (Stakeholder Feedback Forms).
As depicted in Figure 1.1, PacifiCorp's 2025 IRP was developed by working through five
fundamental planning steps that began with development of key inputs and assumptions to inform
the modeling and portfolio development process. The portfolio development process is where
PacifiCorp produced a range of different resource portfolios that meet projected gaps in the load
and resource balance, each uniquely characterized by the size, type, timing and location of new
resources in PacifiCorp's system. The resource portfolios produced for the 2025 IRP were created
considering a wide range of potential coal and natural gas retirement dates, options for certain coal
units to convert to gas or to retrofit for carbon capture sequestration, and other planning
uncertainties.
PacifiCorp then developed variants of the top performing resource portfolio to further analyze
impacts of specific resource actions relative to the top performing portfolio. In the resource
portfolio analysis step, PacifiCorp conducted targeted reliability analysis to ensure portfolios had
sufficient flexible capacity resources to meet reliability requirements. PacifiCorp then analyzed
these different resource portfolios to measure comparative cost, risk, reliability and emissions
levels. This resource portfolio analysis informed selection of the least-cost and least-risk portfolio,
the 2025 IRP preferred portfolio, and development of the associated near-term resource action
plan. Throughout this process, PacifiCorp considered a wide range of factors to develop key
planning assumptions and to identify key planning uncertainties, with input from its stakeholder
group. Supplemental studies were also analyzed to produce specific modeling assumptions.
Figure 1.1 —Key Elements of PacifiCorp's 2025 IRP Approach
Inputsand Action
Assumptions - I H Plan
Preferred Portfolio Highlights
PacifiCorp's selection of the 2025 IRP preferred portfolio is supported by comprehensive data
analysis and an extensive public input process, described in the chapters that follow. Figure 1.2
shows that PacifiCorp's 2025 preferred portfolio continues to include substantial new renewables,
demand-side management (DSM) resources, storage resources, advanced nuclear, and non-
emitting peaking resources facilitated by incremental transmission investments.
The 2025 IRP preferred portfolio is in addition to previously contracted resources, some of which
have not yet achieved commercial operation, including: 1,564 megawatts (MW) of wind, 1,736
4

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
MW of solar additions, and 1,072 MW of battery storage capacity. These resources will come
online in the 2025 to 2026 timeframe.
The 2025 IRP preferred portfolio includes the advanced nuclear Natrium'demonstration project,
anticipated to achieve online status by the end of 2030. By the end of 2032,the preferred portfolio
includes 2,801 MW of energy storage resources, including 844 MW of iron-air batteries with 100-
hour storage capability. Advancement of these technologies will be critical to meeting growing
loads and achieving environmental compliance requirements. Over the 20-year planning horizon,
the 2025 IRP preferred portfolio includes 6,379 MW of new wind and 5,492 MW of new solar.
Figure 1.2—2025 IRP Preferred Portfolio (Existing and Planned Resources)*
45000 Cumulative Portfolio
40000 ■
35000
30000
b 25000 ,
20000 —
15000 � .��--.■■■■�
10000 I111111 IIII Noll
5000
No No �o �o No No No �o No No No No �o No No No No No ryo No No
■Coal ■Converted Gas ■Gas ■Hydrogen Storage Peaker
■Renewable Peaking ■QF ■Hydro z Nuclear
■Hydro Storage ■Battery ■Solar ■Wind
■Geothermal ■Energy Efficiency ■Demand Response L 0 MW selected
* Technologies highlighted in gray were available for selection in IRP modeling but are not part of PacifiCorp's
existing resource mix and were not selected for the preferred portfolio.
The 2025 IRP preferred portfolio includes a second 416-mile transmission line from the new
Aeolus substation near Medicine Bow, Wyoming, to the Clover substation near Mona, Utah,
known as Energy Gateway South 2, planned to come online in 2036. Smaller upgrades increase
transfer capability between southern Utah and the Wasatch Front, between Walla Walla and
Yakima in Washington, and between the Willamette Valley and Deschutes County in Oregon.
Many of the transmission upgrades and interconnection options modeled for the 2025 IRP reflect
the results of PacifiCorp's "cluster study" process for evaluating proposed resource additions.
Since 2020,PacifiCorp has been evaluating all newly proposed resource additions in an area at the
same time, using a cluster study process that identifies collective solutions that can allow projects
that are ready to move forward to do so in a timely fashion. Table 1.1 summarizes the incremental
transmission projects in the 2025 IRP preferred portfolio. Note, at this time, the Boardman-to-
Hemingway transmission line (B2H) is not included in the preferred portfolio. PacifiCorp is
reevaluating the timing and needs analysis underlying B2H because of factors such as changed
native load growth and a lack of capacity available on neighboring transmission systems to deliver
to load pockets.
5

PACIFICORP—2025 IRP CHAPTER I—EXECUTIVE SUMMARY
Table 1.1 —Transmission Projects Included in the 2025 IRP Preferred Portfolio I,z
Build
Export Import Interconnect Investment Build
(MW) (MW) (MW) N From To
2026 Rebuild existing Cameron-Sigurd 138 kV 250 250 250 30 100% Utah South Wasatch Front
2027 Cluster 1 Area 11-Willamette Valley 0 0 199 13 100% n/a n/a
Serial queue-Central Oregon 0 0 152 3 100% n/a n/a
2028 Cluster 2 Area 23-Willamette Valley 0 0 393 2 100% n/a n/a
2030 Cluster 1/2/3-Walla Walla 0 0 628 66 100% n/a n/a
2031 Cluster 1/2/3-Walla Walla 0 0 393 348 100% n/a n/a
Walla Walla-Wine Country 230 kV 400 400 400 145 100% n/a n/a
2032 Cluster 1 Area 14-Summer Lake 400 400 400 120 100% Summer Lake Hemingway
Cluster 2/3-Willamette Valley-Fry-Full Circle 230 kV 450 450 450 413 100% Willamette Valley Central OR
2036 Gateway South 2:Aeolus Clover#2 500 kV 1,500 1,500 1,990 1,810 100% Wyoming East Clover
Huntington—Clover 345 kV 800 800 800 264 100% Utah South Wasatch Front
Spanish Fork-Mercer 345 kV 300 300 300 153 100% Utah South Wasatch Front
West Cedar-Three Peaks 138 kV 200 200 200 14 100%1 Utah South Wasatch Front
S.Lebanon-Dixonville 500 kV,Dbl-Ckt Fry-S.Lebanon 230 kV 1,500 1,500 665 1,117 100%1 Willamette Valley Southern OR
2041 Serial through Cluster 1 Area 13-Southern Oregon 0 0 231 52 100% n/a n/a
Grand Total I 5,800 1 5,800 7A51 4,551
'Export and import values represent total transfer capability.The scope and cost of transmission upgrades are
planning estimates.Actual scope and costs will vary depending upon the interconnection queue,the transmission
service queue,the specific location of any given generating resource and the type of equipment proposed for any
given generating resource.
2 Transmission upgrades frequently include primarily all-or-nothing components, though the cluster study process
allows for project-specific timing and some costs are project-specific.
In Volume I,Chapter 9—Modeling and Portfolio Selection Results,a sensitivity analysis evaluates
the impacts of significant new loads coming online in the 2033 timeframe and supports continuing
with permitting Energy Gateway segments, as well as initiating preliminary permitting and
development activities for future transmission investments not currently included in the preferred
portfolio. These future transmission projects can include development of additional transmission
expansion 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).
New Solar Resources
The 2025 IRP draft preferred portfolio includes 245 MW of new solar by the end of 2027, 1,275
MW by the end of 2030, and 5,492 MW by the end of 2045, as shown in Figure 1.3.
Figure 1.3—2025 IRP Preferred Portfolio New Solar Capacity
9,000
8,000 _7,000
N 6,000
' 5,000 T
4,000
E 3,000
D 2,000 ------
�� ---
U 1,000 ���
0 �P�f�m
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP =251RPOR =251RPWA =251RPUIWC ---2023 1 RP Update ---23IRP
6

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
New Wind Resources
As shown in Figure 1.4,PacifiCorp's 2025 IRP draft preferred portfolio includes 486 MW of new
wind generation by the end of 2028, 2,175 MW by the end of 2030, and 6,379MW of cumulative
new wind by the end of 2045.
Figure 1.4—2025 IRP Preferred Portfolio New Wind Capacity
10,000 --------------
8,000 -saa.....�•
j 6,000
4,000
E -�♦
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
�251RP =25 IRP OR =25 IRP WA =- 25 IRP UIWC ---2023 IRP Update ---23IRP
New Storage Resources
New storage resources in the 2025 IRP draft preferred portfolio are summarized in Figure 1.5. The
2025 IRP draft preferred portfolio includes 1,818 MW of new storage resources by the end of
20272 including both 4- and 8-hour lithium-ion storage. By year-end 2030, the 2025 draft IRP
includes 2,716 MW of storage which includes nearly 656 MW of 100-hour iron air storage, and
by year-end 2045, the 2025 IRP draft preferred portfolio includes 7,668 MW of new storage.
Figure 1.5—2025 IRP Preferred Portfolio New Storage Capacity1,2
10,000
8,000 --------- --------- --------------
j 6,000
nz '
4,000 -
E _
� 2,000
0 -
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP =251RPOR =251RPWA =251RPUIWC ---2023 1 RP Update ---231RP
'The 2023 IRP Update includes 400 MW of PVS battery (Green River solar+storage) in 2026 that has since been
signed and thus is not included as new storage capacity in the 2025 IRP.
2 The 1,818 MW of new storage resources by the end of 2027 includes 520 MW of signed battery storage contracts
that have been committed since the filing of the 2023 IRP Update.
New Nuclear Resources
The 2025 IRP draft includes advanced nuclear as part of its least-cost,least-risk preferred portfolio.
As shown in Figure 1.6, the 500 MW advanced nuclear Natrium' demonstration project is
currently scheduled to come online by the end of 2030.
7

PACIFICORP—2025 IRP CHAPTER I—EXECUTIVE SUMMARY
Figure 1.6—2025 I" New Nuclear
1,600
--------------------------
1,400
1,200
1,000 - �♦
800 -
7 600 ♦♦
U 200 �Pap
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
�251RP =251RPOR =251RPWA 325 IRP UIWC ---2023 IRP Update ---23IRP
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 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.
PacifiCorp's load forecast before incremental energy efficiency savings has decreased relative to
projected loads used in the 2023 IRP. On average, forecasted system load is down 3.9 percent and
forecasted coincident system peak is down 0.6 percent when compared to the 2023 IRP. Over the
planning horizon, the average annual growth rate, before accounting for incremental energy
efficiency improvements, is 2.03 percent for load and 1.91 percent for peak. Changes to
PacifiCorp's load forecast are driven by lower projected demand from new large customers, who
are expected to provide or pay for their necessary resources and transmission.
Energy efficiency and demand response programs are important tools for meeting customers'
future energy needs. Our innovative approach moves beyond management based on peak loads
and focuses on turning demand-response resources into dynamic operating reserves. That's why
we're expanding existing demand-response programs and introducing new solutions for
customers,particularly as more interconnected technologies enter the market. These programs will
reduce our need to buy reserve power on the market and create greater customer benefits.
• In the near-term years of 2025 through 2028, our ongoing conservation and cost-effective
demand-response initiatives will seek to deliver:
0 678 megawatts of energy efficiency between 2025 and 2028
0 213 megawatts of demand response between 2025 and 2028
Coal and Gas Exits, Retirements, and Gas Conversions
Coal resources have been an important resource in PacifiCorp's resource portfolio for many years.
However,there have been material changes in how PacifiCorp has been operating these assets(i.e.,
by lowering operating minimums and optimizing dispatch through the WEIM) that has enabled
8

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
the company to reduce fuel consumption and associated costs and emissions, and instead buy
increasingly 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. New for the 2025 IRP, coal-
fired units that do not have an enforceable environmental compliance requirement have the option
to continue coal-fired operation through the end of the study horizon. Where natural gas supply is
expected to be available, an option to convert to natural gas was modeled, and is required for
continued operations at units that are required to cease coal-fired operation. As shown in Figure
1.7, the 2025 IRP converts 562 MW of coal fueled generation to natural gas fueled, and exits
PacifiCorp's share in 386 MW of minority-owned coal, and also retires 220 MW of majority-
owned coal at Dave Johnston by the end of the study horizon. The balance of the coal units
continue to operate through the end of the study horizon, with 700 MW at Jim Bridger 3 and 4
converting to carbon capture in 2030.
Figure 1.7—2025 IRP Preferred Portfolio Thermal Resources
9,000
8,000 ———— 7�..■ ---
7,000
al 6,000
5,000
4,000
3,000
7 2,000
U
1,000
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
Coal �Coal-CCUS �Gas-Steam �Gas-CT/CCCT ---2023 1 RP Update ---23 IRP
A summary of the coal unit exits,retirements, and conversions in the 2025 IRP preferred portfolio
and the 2023 IRP Update preferred portfolio is shown in Table 1.2. In addition to these coal unit
exits,retirements, and conversions,the preferred portfolio continues to operate all existing natural
gas units through the end of the study horizon.
9

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
Table 1.2 —2025 IRP Coal Resource Results Summary
Majority-Owned Coal
2023 IRP Update Retirement Year 2025 IRP Retirement Year
Unit As Selected As Selected
Dave Johnston 1 &2 2028(Coal ash compliance) Not retired(Gas conversion 2029)
Dave Johnston 3 2027(Clean air compliance) 2027(Clean air compliance)
Dave Johnston 4 2039(Assumed end of life) Not retired
Hunter 1-3 2042(Assumed end of life) Not retired
Huntington 1 &2 2036(Assumed end of life) Not retired
Jim Bridger 1 &2 2037(Gas conversion 2024/Assumed end of life) Not retired(Gas conversion 2024)
Jun Bridger 3 &4 2039(CCS/Assumed end of life) Not retired(CCS)
Naughton 1 &2 2036(Gas conversion 2026/Assumed end of life) Not retired(Gas conversion 2026)
)A odak 2039 (.Assumed end of life) Not retired(Coal)
Minorite-Owned oa
2023 IRP Update Retirement Year 2025 IRP Retirement Year
L"tilt
As Input As Input
Colstrip 2025 (Transfer capacity to wilt 4) 2025 (Transfer capacity to unit 4)
Colstrip 4 2029(PacifiCorp exit) 2029(PacifiCorp exit)
Craig 1 2025 (Assumed end of life) 2025 (Assumed end of life)
Craig 2 2028(Assumed end of life) 2028(Assumed end of life)
Hayden 1 2028(Assumed end of life) 2028(Assumed end of life)
Hayden 2 2027(Assumed end of life) 2027(Assumed end of life)
10

PACIFICORP-2025 IRP CHAPTER I-EXECUTIVE SUMMARY
Action Plan
The 2025 IRP action plan identifies specific actions PacifiCorp will take primarily over the next 2-4 years to deliver its preferred portfolio.
Action items are based on the size, type and timing of resources in the preferred portfolio, findings from analysis completed over the
course of portfolio modeling, and feedback received by stakeholders in the 2025 IRP public-input process. Table 1.3 details specific 2025
IRP action items by resource category.
Table 1.3 —2025 IRP Action Plan
Action
1. Existing Resource Actions
Item M M
Colstrip Units 3 and 4:
la • PacifiCorp will continue to work with co-owners to develop the most cost-effective path toward an exit from the Colstrip
project in Montana by 2030.
Craig Unit 1:
lb • PacifiCorp will continue to work closely with co-owners to seek the most cost-effective path forward toward the 2025 IRP
preferred portfolio target exit date of December 31, 2025.
Naughton Units 1 and 2:
• PacifiCorp will continue the process of converting Naughton Units 1 and 2 to natural gas as initiated in Q2 2023, including
lc obtaining all required regulatory notices and filings. Natural gas operations are anticipated to commence spring of 2026.
• PacifiCorp will initiate the closure of the Naughton 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 pond closure extension submission.
Carbon Capture and Storage/Low Carbon Portfolio Standard:
ld • PacifiCorp will continue to evaluate the economic and technical feasibility of carbon capture technology on Jim Bridger
Units 3 and 4 to comply with Wyoming's low carbon portfolio standard.
Regional Haze Compliance:
• Following the resolution of first planning period regional haze compliance disputes, and the EPA's determination of the states'
le second planning period regional haze state implementation plans, PacifiCorp will evaluate and model any emission control
retrofits, emission limitations, or utilization reductions that are required for coal units.
• PacifiCorp will continue to engage with the EPA, state agencies, and stakeholders to achieve second planning period regional
haze compliance outcomes that improve Class I visibility, provide environmental benefits, and are cost effective.
11

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
Action
Item 1. Existing ctions (continued)
NatriumTM Demonstration Proiect:
• By the end of 2025, PacifiCorp expects to finalize a commercial off-take agreement for the NatriumTM project. PacifiCorp
if will continue to monitor key TerraPower development milestones 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 ozone state plan on December 19, 2023. This approval means
PacifiCorp facilities in Wyoming are not subject to the federal ozone plan requirements.
1g • The Tenth Circuit granted a motion to stay EPA's disapproval of Utah's state ozone plan. Utah is not subject to federal
ozone requirements while the stay is in place. The Utah ozone case was transferred to the D.C. Circuit in February of 2024,
for adjudication of the merits, leaving the stay in place. PacifiCorp will continue to monitor developments in the Utah ozone
case and adjust its plans accordingly in response to developments.
Natural Gas Emissions Compliance Strateeies
• The 2025 IRP indicates that changes in accounting and/or dispatch of existing natural gas resources may be a beneficial element
1h of Oregon's HB 2021 compliance strategy and to align with evolving state policies.A range of implementation strategies exist,
with intertwined implications on resource allocation,market participation, and compliance requirements. PacifiCorp will meet
with impacted parties, program administrators, and regulators to enable a refined analysis of the available options to prepare
for implementation no later than the start of 2030.
12

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
Action
t2. New Resource Actions
Item
Customer Preference Request for Proposals:
• PacifiCorp is continuously receiving and evaluating requests for voluntary customer programs in Utah and Oregon.
PacifiCorp may use the marginal resources from future request for proposals to fulfill customer need. In some cases,
2a customer preference may necessitate issuance of a request for proposals to procure resources within the action plan window.
• Consistent with Utah Community Renewable Energy Act, PacifiCorp will continue to work with eligible communities to
develop program to achieve goal of being net 100 percent renewable by 2030; PacifiCorp filed an application for approval of
a resource solicitation process for the program with the Utah Public Service Commission in November 2024. PacifiCorp
plans to file an application for the remainder of the program during Q 12025.
2025 All-Source Request for Proposals:
• PacifiCorp will issue as appropriate by jurisdiction need, one or more all-source Request for Proposals (RFP) to procure
2b resources aligned with the 2025 IRP preferred portfolio that can achieve commercial operations by the end of December 2029.3
• In light of the differentiated resource needs by jurisdiction identified in the 2025 IRP, scope and targeted resource needs may
vary by jurisdiction.
Action
Item 3. Transmission Action Items
4M 1
Local Reinforcement Proiects
3a Initiate local reinforcement projects as identified with the addition of new resources per the preferred portfolio, and follow-on
requests for proposal successful bids.
Gateway West Support
Continue permitting support for Gateway West segments D.3 and E. Initiate preliminary permitting and development activities
3b for future transmission investments not currently included in the preferred portfolio. These 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
PacifiCorp to prepare for potential growth in new large loads seeking new service over the next decade.
3 Procurement strategy was a frequent topic during the 2025 IRP public input meeting process and stakeholder feedback. See Appendix M, stakeholder feedback
form#17(Oregon Public Utilities Commission)
13

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
Action
Item 4. Demand-Side Management (DSM) Actions
Enemy Efficiency Targets:
• PacifiCorp will acquire cost-effective energy efficiency resources targeting annual system energy and capacity selections
from the preferred portfolio. PacifiCorp's state-specific processes for planning for DSM acquisitions is provided in
4a Appendix D in Volume II of the 2025 IRP.
• PacifiCorp will pursue cost-effective energy efficiency resources.
• PacifiCorp will pursue cost-effective demand response resources targeting annual system capacity selections from the
preferred portfolio. Capacity impacts for demand response include both summer and winter impacts within a year.
Action
Item 5. Market Purchases
Market Purchases:
• PacifiCorp will acquire short-term firm market purchases for on-peak delivery from 2025-2027 consistent with the Risk
Management Policy and Energy Supply Management Front Office Procedures and Practices. These short-term firm market
5a purchases will be acquired through multiple means:
o Balance of month and day-ahead brokered transactions in which the broker provides a competitive price.
o Balance of month, day-ahead, and hour-ahead transactions executed through an exchange, such as the
Intercontinental Exchange, in which the exchange provides a competitive price.
o Prompt-month,balance-of-month, day-ahead, and hour-ahead non-brokered bi-lateral transactions.
Action
Item 6. Renewable Energy Credit (REC)Actions
Renewable Portfolio Standards (RPS):
• PacifiCorp will pursue unbundled REC RFPs and purchases to meet its state RPS compliance requirements.
6a 0 PacifiCorp will issue RFPs seeking unbundled RECs that will qualify in meeting California RPS targets through 2026 and
future compliance periods, as needed.
14

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
6b Renewable Energy Credit Sales:
• Maximize the sale of RECs that are not required to meet state RPS compliance obligations.
15

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
16

PACIFICORP—2025 IRP CHAPTER 2—INTRODUCTION
CHAPTER 2 - INTRODUCTION
PacifiCorp files an Integrated Resource Plan (IRP) on a biennial basis with the state utility
commissions of Utah, Oregon,Washington,Wyoming, Idaho, and California. This IRP fulfills the
company's commitment to develop a long-term resource plan that considers cost,risk,uncertainty,
and the long-run public interest. Regulatory staff, advocacy groups, and other interested parties
influence the development of the IRP through a collaborative public input process. As the owner
of the IRP and its action plan, all policy judgments and decisions concerning the IRP are made by
PacifiCorp considering its obligations to its customers, regulators, and shareholders.
In recent integrated resource planning cycles, there has been increased focus on individual state
jurisdictional outcomes aligned with both stakeholder and regulatory interest, and state legislation
and rulemaking. In an effort to recognize and respect this trend, PacifiCorp's 2025 IRP enhances
jurisdictional portfolio development and reporting leading to the integration of results into the
preferred portfolio. Chapter 8 (Modeling and Portfolio Evaluation) describes the fundamental
methodologies used to arrive at state-level initial portfolios and how they are subsequently
integrated to form a single coherent plan.
PacifiCorp's selection of the 2025 IRP preferred portfolio is supported by comprehensive data
analysis and an extensive public input process, described in the chapters that follow. Chapter 9
(Modeling and Portfolio Selection Results), shows that PacifiCorp's 2025 preferred portfolio
continues to include substantial new renewables, facilitated by incremental transmission
investments, demand-side management(DSM)resources, significant storage resources (including
iron-air technology with 100- hour storage duration), and advanced nuclear.'
The 2025 IRP preferred portfolio is in addition to contracted resources,many of which are located
in Utah. The 100 MW Hornshadow I Solar and 200 MW Hornshadow Solar II facilities are set to
come online in 2025, while two facilities combining solar and storage are set to come online in
2025 and 2026: Faraday with 525 MW solar and 150 MW storage and Green River with 400 MW
solar and 400 MW storage. Finally, Oregon's Community Solar Program has ten small-scale solar
facilities scheduled to come online in 2025 and 2026, totaling approximately 18 MW.
The 2025 IRP preferred portfolio includes the 500 MW advanced nuclear NatriumTM
demonstration project, anticipated to achieve online status by summer 2030. Over the 21-year
planning horizon, the 2025 IRP preferred portfolio includes 6,379 MW of new wind, 5,492 MW
of new solar and 7,668 MW of new storage resources.
New storage includes five battery facilities totaling 520 MW are projected to come online ahead
of the peak summer season in 2026: Dominguez BESS (200 MW), Enterprise BESS (80 MW),
Escalante BESS (80 MW), Granite Mountain BESS (80 MW) and Iron Springs BESS (80 MW).
These signed battery storage contracts were committed since the filing of the 2023 IRP update.
To facilitate the delivery of new renewable energy resources to PacifiCorp customers across the
West, the preferred portfolio includes additional transmission projects which are described in
' See Chapter 7(Resource Options)
17

PACIFICORP-2025 IRP CHAPTER 2-INTRODUCTION
Volume I, Chapter 1 (Executive Summary), Chapter 4 (Transmission), and Chapter 9 (Modeling
and Portfolio Selection Results).
Other significant analysis to support the 2025 IRP includes:
• An updated demand-side management resource conservation potential assessment
• A distributed generation study for PacifiCorp's service territory
• A flexible reserve study
• An updated plant water consumption study
• An energy storage potential evaluation
• An assessment of grid enhancement technologies
• Historic weather years
• An updated load and resource balance
This chapter outlines the components of the 2025 IRP, summarizes the role of the IRP, and
provides an overview of the public input process.
025 Integrated Resource Plan Components
The basic components of PacifiCorp's 2025 IRP include:
• Assessment of the planning environment, market trends and fundamentals, legislative and
regulatory developments, and current procurement activities; Volume I, Chapter 3
(Planning Environment)
• Description of PacifiCorp's transmission planning efforts and activities;Volume I,Chapter
4 (Transmission)
• Regional resource adequacy assessments, wildfire mitigation planning and the role of
transmission in system reliability and incident recovery; Volume I, Chapter 5 (Reliability
and Resiliency)
• Load and resource balance on a capacity and energy basis and determination of the load
and energy positions for the front ten years of the twenty-year planning horizon; Volume
I, Chapter 6 (Load and Resource Balance)
• Profile of resource options considered for addressing future capacity and energy needs;
Volume I, Chapter 7 (Resource Options)
• Description of IRP modeling,including a description of the portfolio development process,
cost and risk analysis, and preferred portfolio selection process; Chapter 8 (Modeling and
Portfolio Evaluation)
• Presentation of IRP modeling results and selection of PacifiCorp's preferred portfolio;
Volume I, Chapter 9 (Modeling and Portfolio Selection Results)
• Presentation of PacifiCorp's 2025 IRP action plan linking the company's preferred
portfolio with specific implementation actions, including an accompanying resource
acquisition path analysis and discussion of resource procurement risks; Volume I, Chapter
10 (Action Plan)
The IRP appendices, included as Volume II, contain the items listed below:
• Load Forecast (Volume II, Appendix A)
• Regulatory Compliance (Volume II, Appendix B)
18

PACIFICORP—2025 IRP CHAPTER 2—INTRODUCTION
• Public Input(Volume II, Appendix C)
• Demand-Side Management(Volume II, Appendix D)
• Grid Enhancement(Volume II, Appendix E)
• Flexible Reserve Study (Volume II,Appendix F)
• Plant Water Consumption Study (Volume II, Appendix G)
• Capacity Expansion Results (Volume II, Appendix I)
• Distributed Generation Study (Volume II, Appendix L)
• Stakeholder Feedback Forms (Volume II, Appendix M)
• Washington Clean Energy Action Plan(Volume II, Appendix O)
• Acronyms (Volume II, Appendix P)
PacifiCorp is also providing data disks for the 2025 IRP. These electronically provided materials
support and provide additional details for the analysis described within the document. Data disks
are generated for public, confidential, and highly confidential data to be provided as appropriate
to each recipient.' Confidential and highly confidential data access are provided separately under
non-disclosure agreements, or specific protective orders in docketed proceedings. The "Highly
Confidential" data disk category, adopted in the prior 2023 IRP planning cycle, allows the
company to provide the maximum amount of access to parties who are not participants in
commercial developments or those who have direct conflicts of interest regarding commercially
sensitive information.
The Role of PacifiCorp's Integrated Resource Plan
PacifiCorp's IRP establishes a proxy resource plan capable delivering adequate and reliable
electricity supply at a reasonable cost and in a manner "consistent with the long-run public
interest."3 In this way,the IRP serves as a roadmap for determining and implementing PacifiCorp's
long-term resource strategy. In doing so, it accounts for state commission IRP requirements, the
current view of the planning environment,corporate business goals, and uncertainty.As a business
planning tool, it supports informed decision-making on resource procurement by providing an
analytical framework for assessing resource investment tradeoffs,including supporting request for
proposal bid evaluation efforts.As an external communications tool,the IRP engages stakeholders
in the planning process and guides them through the key decision points leading to PacifiCorp's
preferred portfolio of generation, demand-side, and transmission resources.
Public input Process
The IRP standards and guidelines for certain states require PacifiCorp to have a public input
process allowing stakeholder involvement in all phases of plan development. PacifiCorp organized
held seven public input meetings, spanning one or two days each,to facilitate information sharing,
collaboration, and expectations for the 2025 IRP. The topics covered all facets of the IRP process,
ranging from specific input assumptions to the portfolio modeling and risk analysis strategies
employed.
2 The Draft 2025 IRP is supported by a public data disk only.
s The Public Utility Commission of Oregon and Public Service Commission of Utah cite"long-run public interest"as
part of their definition of integrated resource planning.Public interest pertains to adequately quantifying and capturing
for resource evaluation any resource costs external to the utility and its ratepayers. For example, the Public Service
Commission of Utah cites the risk of future internalization of environmental costs as a public interest issue that should
be factored into the resource portfolio decision-making process.
19

PACIFICORP-2025 IRP CHAPTER 2-INTRODUCTION
In addition to the public input meetings, PacifiCorp used other channels to facilitate resource
planning-related information sharing and stakeholder input throughout the IRP process. The IRP
webpage is accessible using the following link:
www.pacificop2.com/energy/integrated-resource-plan.html
Messages relevant to PacifiCorp's IRP can sent to the following email address:
irpnpacificorp.com
Additionally, a stakeholder feedback form provides opportunities for stakeholders to submit
additional input and ask questions throughout the 2025 IRP public input process. The submitted
forms, as well as PacifiCorp's responses to these feedback forms are located on the PacifiCorp's
IRP website:
www.pacificorp.c om/energy/inte grated-resource-plan/comments.html
Summaries of stakeholder feedback forms received, and company responses were provided
throughout the public input meeting series and are also available in Appendix M (Stakeholder
Feedback Forms). In the 2025 IRP, links to stakeholder feedback forms are provided in footnotes
to further tie together stakeholder feedback with the development of the filed IRP. Appendix C
(Public Input Process) reports additional details regarding engagement for the 2025 IRP.
20

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
CHAPTER 3 - PLANNING ENVIRONMENT
CHAPTER HIGHLIGHTS
• Federal and state tax credits continue to encourage the procurement of wind and solar
resources, which will likely dominate U.S. capacity additions for the next decade. Flexible
generation,transmission,new storage technologies,and market design changes will be need
to better integrate these resources into the grid.
• The Federal Inflation Reduction Act (IRA) was enacted on August 16, 2022, creating
technology specific tax credits for projects placed in service after December 31, 2021, and
technology neutral tax credits for projects placed in service after December 31, 2024.
Eligible resources include any technology that generates electricity and does not emit
greenhouse gases. The IRA is modeled in all 2025 IRP studies. As of December 2024, the
future of some provisions of the IRA remains unknown under the new administration.
• 2024 saw significant new environmental regulation with potential impacts to PacifiCorp's
generation resources. These included Greenhouse Gas (GHG) emission standards for
existing coal-fired and new gas-fired plants, Mercury and Air Toxics Standards (MATS)
revisions, Effluent Limitations Guidelines revisions, Coal Combustion Residuals legacy
rule, and the NEPA Phase 2 rule.
• In 2019, the Washington Legislature approved the Clean Energy Transformation Act
(CETA), which requires that 100% of electricity sales in Washington be 100% renewable
and non-emitting by 2045.PacifiCorp filed its inaugural Clean Energy Implementation Plan
(CEIP) in December 2021, and expects to file its second CEIP in October 2025, detailing
the company's action plan for the next four-year period.
• In 2021, Washington passed the Climate Commitment Act, which establishes a cap-and-
invest program that was implemented through the regulatory rulemaking process in 2022
and came into effect January 1, 2023. The Climate Commitment Act does not modify any
of PacifiCorp's obligations under CETA,and utilities that are subject to CETA are allocated
allowances commensurate with emissions associated with Washington retail load at no cost.
The legislation allows — but does not require — linkage with cap-and-trade programs in
jurisdictions outside of Washington State.
• In 2021, Oregon passed House Bill 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. The 2025
IRP includes modeling to support House Bill 2021 which will be expanded upon in
PacifiCorp's Oregon Clean Energy Plan submission to be filed within 180 days of the 2025
IRP.
PacifiCorp and the California Independent System Operator Corporation(CAISO)launched
the voluntary western energy imbalance market (WEIM) November 1, 2014, the first
western energy market outside of California. Since inception, The WEIM's footprint has
grown significantly, generating $3.4 billion in monetary benefits to customers of
participating entities. ($1.42 billion total footprint-wide benefits as of August 2, 2021).
A significant contributor to EIM benefits is transfers across balancing authority areas,
providing access to lower-cost supply, while factoring in the cost of compliance with
21

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
greenhouse gas emissions regulations when energy is transferred into the CAISO balancing
authority area. Building on the success of WEIM, in 2022 PacifiCorp, along with CAISO
and other stakeholders, collaborated to develop a market design for an extended day ahead
market(EDAM) that CAISO plans to launch in 2025.
Introduction
This chapter profiles the major external influences that affect PacifiCorp's long-term resource
planning and recent procurement activities. External influences include events and trends affecting
the economy, wholesale power and natural gas prices, and public policy and regulatory initiatives
that influence the environment in which PacifiCorp operates.
Major issues in the power industry include resource adequacy and associated standards for the
Western Electricity Coordinating Council(WECC).Future natural gas prices,the role of gas-fired
generation, the role of emerging technologies, and the net costs of renewables and battery
technologies also factor into the selection of the portfolio that best achieves least-cost, least-risk
planning objectives.
On the government policy and regulatory front, a further significant issue in the power industry
and facing PacifiCorp continues to be planning for eventual, but highly uncertain, climate change
policies. This chapter provides discussion on climate change policies as well as a review of
significant policy developments for currently regulated pollutants. This chapter also provides
updates on the status of renewable portfolio standards and resource procurement activities.
sale Electricity
PacifiCorp's system operates in conjunction with a multifaceted market. Operations and costs are
tied to a larger electric system known as the Western Interconnection which functions, on a day-
to-day basis, as a geographically dispersed marketplace. Each month, millions of megawatt-hours
of energy are traded in the wholesale electricity market. These transactions yield economic
efficiency by ensuring that resources with the lowest operating cost are serving demand throughout
the region and by providing reliability benefits that arise from a larger portfolio of resources.
PacifiCorp actively participates in the wholesale market by making purchases and sales to
minimize costs and to keep its supply portfolio in balance with customers' expectations. This
interaction with the market takes place on time scales ranging from sub-hourly to years in advance.
Without the wholesale market, PacifiCorp — or any other load serving entity — would need to
construct or own an unnecessarily large margin of supplies that would go unused in all but the
most unusual circumstances and would substantially diminish its capability to cost effectively
match delivery patterns to the profile of customer demand.
The benefits of access to an integrated wholesale market have grown with the increased penetration
of intermittent generation such as solar and wind. Intermittent generation can come online and go
offline abruptly in congruence with changing weather conditions. Federal and state (where
applicable) tax credits and improved technology performance have continued to place wind and
solar energy generators"in the money"in areas of high resource potential.As such,wind and solar
will continue to play a dominant role in power supply options over the next decade. To better
22

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
integrate these resources into the larger grid requires more flexible generation, transmission,
evolving storage technologies, and market design changes.
Regarding transmission, there are long-haul, renewable-driven transmission projects in advanced
development in the U.S. WECC. These transmission lines ultimately connect areas of high
renewable energy potential and low population density to areas of high population density with
less renewable potential. This includes PacifiCorp's 416-mile high-voltage 500-kilovolt (kV)
Gateway South project and the 59-mile high-voltage 230-kV Gateway West Segment D.1 project,
brought in-service in late 2024. These transmission projects will provide greater system-wide
flexibility transferring energy from Wyoming to load centers located in Utah.
The intermittency of renewable generation has also given rise to a greater need for fast-responding
and long-duration storage, which is essential for grid stability and resiliency. Pumped storage has
been the traditional storage option and there are multiple projects being developed throughout the
West. Of remaining mechanical, thermal, and chemical storage options, lithium-ion (Li-ion)
batteries have shown the most promise in terms of cost and performance. In 2013, the California
Public Utility Commission (CPUC) required investor-owned utilities to procure 1,325 MW of
storage by 2020; that requirement has been satisfied. As of 2022, nine states had implemented
energy storage targets or mandates, with action being considered in at least one other.' In
California, the Elkhorn Battery project became fully operational for Pacific Gas & Electric
(PG&E) in April of 2022. The Moss Landing project in Monterey County includes 182.5 MW of
Tesla Megapack energy storage.2 Hybrid co-located solar photovoltaic (SPV) and battery systems
are now in Utah, Hawaii, Arizona,Nevada, California, and Texas.
In 2018, the Federal Energy Regulatory Commission (FERC) directed regional transmission
organizations (RTO) and independent system operators (ISO) to develop market rules for the
participation of energy storage in wholesale energy, capacity,and ancillary services markets'. The
FERC gave operators nine months to file tariffs and another year to implement — essentially
opening wholesale markets to energy storage. Operators' proposed tariffs have varied substantially
among regions with PJM requiring a 10-hour continuous discharge capability while New England
requires a continuous 2-hour capability. Later, in May 2019, the FERC issued an order generally
affirming the earlier order to establish reforms to remove barriers to the participation of electric
storage resources in certain organized wholesale markets.PacifiCorp continues to evaluate the cost
effectiveness of several energy storage systems, including pumped storage, stand-alone Li-ion
batteries, flow batteries, iron-air storage and other long-duration storage, as well as energy storage
co-located with generating resources.
Increased renewable generation has also 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 Energy Imbalance
1 California,New Jersey,New York,Massachusetts,Oregon,Nevada,Virginia,Connecticut,and Maine have either
mandated or set energy storage targets,while Arizona is considering the implementation of targets.
2 In addition to Elkhorn,PG&E has contracts for more than 3,330 MW of battery storage being deployed statewide
through 2024,more than 900 MW of which has been connected to California's electric grid.The Mercury News,
March 8,2023;PG&E ushers in landmark Tesla battery energy storage system at Moss Landing(mercurynews.com)
3162 FERC¶61,127 United States of American Federal Energy Regulatory Commission, 18 CFR Part 35 [Docket
Nos.RM16-23-000;AD16-20-000;Order No. 841]Electric Storage Participation in Markets Operated by Regional
Transmission;Organizations and Independent System Operator(Issued February 15,2018)
23

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Market (EIM). The EIM became operational November 1, 2014, and since that time has seen NV
Energy, Puget Sound Energy, Arizona Public Service, Portland General Electric, Powerex, Idaho
Power, Balancing Authority of Northern California, Salt River Project, Seattle City Light, Los
Angeles Department of Water and Power, Northwestern Energy, and Public Service Company of
New Mexico, Avista Utilities, Tucson Electric Power, Turlock Irrigation District, Tacoma Power,
Bonneville Power Administration, Avangrid Renewables, El Paso Electric, and Western Area
Power Administration join the EIM. Black Hills Power plans to join the EIM in 2026. The multi-
service area footprint brings greater resource and geographical diversity allowing for increased
reliability and cost savings in balancing generation with demand using 15-minute interchange
scheduling and five-minute dispatch. CAISO's role is limited to the sub-hourly scheduling and
dispatching of participating EIM generators. CAISO does not have any other grid operator
responsibilities for PacifiCorp's service areas. As part of other EIM participating entities,
PacifiCorp is also participating in the CAISO stakeholder process to establish an Extended Day-
Ahead Market(EDAM),which is currently in the phase of implementation activities and expected
to onboard participants in 2026.
As with all markets,electricity markets face a wide range of uncertainties.In February 2021,winter
storm Uri caused an unprecedented 24.1% decline in marketed natural gas production in Texas, a
drop of 186.7 billion cubic feet(Bcf) compared to the previous month. This decline contributed to
the largest monthly decline in natural gas production on record in the Lower 48 states.This weather
event caused widespread disruptions in energy supply and demand, including extended electric
power blackouts in Texas.
The Western United States experienced an excessive heat event during the first week of September
2022. As a result, record temperatures were recorded on September 4th through September 7t',
reaching as high as 1140 F in Sacramento, California, 1100 F in Burbank, California, and 1070 F in
Salt Lake City, Utah. With these record setting temperatures, the West saw a widespread surge in
electricity demand and correspondingly tight supply conditions. Maintaining reliability across the
region during this period was a testament to the benefits of energy markets, geographic diversity
across the West, and conservation efforts during extreme heat events.
Market participants routinely study demand uncertainties driven by weather and overall economic
conditions. The North American Electric Reliability Corporation (NERC) publishes an annual
assessment of regional power reliability, and any number of data services are available that track
the status of new resource additions4. In NERC's latest release, the WECC region was classified
as "elevated risk", in which shortfalls may occur in extreme conditions.
The Western Resource Adequacy Program(WRAP)5 will also provide market participants insight
into potential supply constraints and give participants some assurance that sufficient resources
have been procured for the program to maintain a 1-in-10-year loss of load expectancy standard.
In addition to binding load and resource showings for the upcoming season, the WRAP will
conduct advisory two- and five-year resource adequacy assessments for the footprint that will
allow participants to better plan for the future needs of their systems. The Forward Showing
program will ensure participants procure sufficient resources to meet a footprint wide reliability
4 2020 Long-term Reliability Assessment,December 2020,North American Electric Reliability Assessment
5 https://www.westernpowerpool.org/about/programs/western-resource-adequacy-program
24

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
standard, and the Ops Program will facilitate transfers between entities in a resource deficit and
those with excess resources.
In addition to reliability planning,there are externalities that can heavily influence the direction of
future prices. One such uncertainty is the evolution of natural gas prices over the course of the IRP
planning horizon. Natural gas-fired generation and gas prices have been a critical determinant of
western electricity prices, and this is expected to continue over the term of this plan's decision
horizon. While the share of natural gas in the resource western resource mix is expected to fall by
the end of the horizon because of increasing renewable resource buildout, natural gas will remain
on the margin in many hours,particularly critical hours when renewable resource output is limited.
Another critical uncertainty that weighs heavily on the 2025 IRP,as in past IRPs,is the uncertainty
surrounding future greenhouse gas policies,both federal and/or state.PacifiCorp's official forward
price curve (OFPC) does not assume a federal carbon dioxide (CO2) policy, but other price
scenarios developed for the IRP consider impacts of potential future federal and state policies
which drive additional costs and restrictions of emissions. However, PacifiCorp's OFPC does
include enforceable state climate programs that have been signed into law'.
Power Market Prices
Mild weather, strong production, and limited exports caused high storage levels in the fossil gas
market, resulting in low gas prices throughout 2024. Low fuel prices coupled with mild demand
led to an annually averaged 34% decrease in on-peak spot prices across the Non-CAISO WECC
trading hubs in 2024, as seen in Table 3.1.
Table 3.1 - 2023 and 2024 Monthly Average On-Peak Spot Prices ($/MWh)
Jan 135.23 137.27 2.05 2%
Feb 84.41 41.95 -42.46 -50%
Mar 76.51 25.05 -51.46 -67%
Apr 79.53 18.57 -60.97 -77%
May 21.60 20.48 -1.13 -5%
Jun 38.87 31.13 -7.74 -20%
Ju 1 93.02 67.88 -25.13 -27%
Aug 88.59 48.50 -40.09 -45%
Sep 51.76 52.55 0.78 2%
Oct 78.57 46.24 -32.33 -41%
Nov 70.90 35.19 -35.71 -50%
Dec 52.12 47.50 -4.62 -9%
Annual 72.59 47.69 -24.90 -34%
*As of December 16, 2024
6 California and Washington carbon allowance price forecasts are applied when appropriate. Washington allowance
prices assumed the forecast published by Vivid Economics,commissioned by Washington Department of Ecology
as part of its CCA Regulatory Impact Analysis for WAC 173-446,which was the best available information at the
time of modeling. Available at hitps:Hgpps.ecology.wa.gov/publications/documents/2202047,gdf,
25

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Source: SNL
Barring major geo-political disruptions or other sustained economic drivers, forecasted wholesale
power prices are expected to increase slightly relative to 2024 peaks and will follow seasonal
weather trends with higher prices over the summer months. Broker price spreads indicate August
2025 On-Peak power prices at Palo Verde,Mead,Four Corners, and Mid-Columbia are all trading
around$1054120 per MWh.
Fi ure 3.1 -Forward Prices at WECC Major Trading Hubs
$160.00
$140.00
$120.00 —
/�
$100.00
$80.00 �♦
♦ -
$60.00 ARM
. -
i
r / v
$20.00 / aw
♦♦ /
N w Ln N N w Ln N N w U1 N
\ \ \ \ \ N \ \ \ \ \ N \ \ \ \ \
N N N N N \ N N N N N \ N N N N N \
O O O O O N O O O O O N O O O O O N
N N N N N O N N N N N O N N N N N O
Ln Ln Ln Ln Ln N M M Q1 Ol a) V �I N
Ui 61 V
PV On-Peak ——— PV Off-Peak —Mead On-Peak ——— Mead Off-Peak
4C On-Peak ——— 4C Off-Peak —MidC On-Peak ——— MidC Off-Peak
Source: OTC, Siemens PTI
26

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
Table 3.2 reports the quarterly on-peak and off-peak price spread across the major WECC hubs,
driving the peaks and valleys observed in Figure 3.1 above.
Table 3.2 - 2025-2027 Forward Price Spread ($/MWh)
Date On-Peak_ Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak
IJ112025 $ 44.57 $ 44.53 $ 49.32 $ 49.35 $ 55.87 $ 60.23 $ 72.60 $ 57.25
----- ----- -- ---------------- ---------------•_-------------- ---------------•-------------- ---------•---------------
5/1/2025 $ 18.04 $ 27.62 $ 21.12 ? $ 30.62 $ 17.05 1 $ 34.20 $ 26.81 $ 17.02
--------------- ------------------------------- ---------------7--------------- ---------------T-------------- --------------T--------------
8/1/2025 $104.89 ; $ 60.81 $120.14 $ 67.85 $111.56 $ 77.93 $103.20 $ 53.99
........
11/1/2025 $ 42.14 i $ 47.94 $ 46.28 ; $ 51.86 $ 43.55 : $ 54.89 $ 59.08 ; $ 47.28
--------------- --------------- --------------- --------------I-- --- - -- ---------- --- ------ ---- - --t---------------
1/1/2026 $ 63.81 i $ 73.32 $ 68.41 i $ 85.12 $ 79.99 i $ 99.17 $100.52 i $ 92.19
------------ - ------ -- _-------------------------
5/1/2026 $ 17.98 $ 37.62 $ 16.18 $ 39.84 $ 17.00 1 $ 46.59 $ 27.99 i $ 23.71
--- -------- -------------------------------- --------------------------------------------------------------
8/1/2026 $107.13 $ 71.57 $125.96 ? $ 59.86 $113.94 $ 91.72 $113.74 $ 56.61
---------------- ---------------•-------------- ---------------•--------------- ---------------•--------- --------------•---------------
11/1/2026 $ 45.38 $ 57.92 $ 46.83 ? $ 68.32 $ 46.89 $ 66.32 $ 75.27 $ 67.37
_______________7--------------- ___---_-__--_-_ --------------- -----------------____--------_ -----_-..-.-_ --------------
1/1/2027 $ 71.36 $ 83.56 $ 70.01 $ 88.44 $ 89.44 $113.02 $102.48 $ 91.87
----------------- --------------- ------
5/1/2027 $ 19.80 : $ 35.40 $ 9.73 : $ 35.70 $ 18.71 i $ 43.83 $ 34.07 i $ 34.10
--------------- ---------------i--- - ---------------e--------------- --------------a--------------- --------------a---------------
8/1/2027 $114.63 : $ 80.80 $134.58_: $ 81.71 $121.91 : $103.55 $125.72 i $ 55.51
-- -- - - - - -- - - - -
11/1/2027 $ 41.95 i $ 57.62 $ 54.19 $ 70.41 $ 43.35 i $ 65.97 1 $ 82.83 $ 78.10
Source: OTC
Power Market Dynamics
Non-CAISO WECC Generation and Capacity Mix
The generation mix in the non-CAISO WECC region reflects the influence of individual
state RPS and emissions policies. In 2023,natural gas resources provided about 3 1% of generated
energy followed by hydro at 22%, coal at 18%, and wind at 12%. Natural gas and coal share is
expected to decrease slightly, with non-hydro renewables expected to replace this energy
throughout 2030.
27

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.2 - National RPS Targets
NH-
24.8%by
2025
� VT:75% ME:100%by
by 2032 2050
1
2030
2035
1
1 CT:40%by
1 NJ:50%by
2030
:I, 1
�1 1'1, • 1 DE:25%by
1 1 ' 2025
SC:2%by MD:50%by
2021 2030
DC:100%
HI:100%by by 2032
2045
■State RPS ■State Goal
Figure 3.3 - States with CO2 Reduction Targets
MN.March 2019 WI:Aug 2019
Governor calls Executive Order NY:June 2019 ME:June 2019
WA:May 2019 for 80 for new agency IL:Legislation passed net zero 100 RPS by
zero carbon reduction by to ensure zero requiring zero carbon by 2040. 2050 enacted.generation by 2050 carbon carbon also RGGI also RGGI
2045 enacted generation by generation by participant artici ant
2050. 2030 in P
OR:2021 Zero development I
carbon generation
Northeast and
by 2o4o enacted
Mid Atlantic
state carbon
trading under
NV:Zero RGGI
carbon by G (NJ joins RGGI
e
Jan.2020.VA
has advanced
efforts to join)
DC:100%
RPS by
CA:Active 2032
carbon trading
AB32,and zero
carbon by 2045
NM.Zero
carbon by 2045
for IOUS.2050
Hr 100`b for coops
RPS by
2045
®Active Carbon Trading ■Zero Carbon Generation Requirement
LJCarbon Trading Developing Zero Carbon Generation Requirements Developing
Source: Siemens PTI
28

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.4 -Non-CAISO WECC Generated Energy(TWh)
600
500
400
300
200
100
0
2022 2023 2024 2025 2026 2027 2028 2029 2030
■ "oal Natural Gas ■Nuclear ■Hydro ■ Solar ■Wind ■Other
Source: IHS Markit, SNL, Siemens PTI
29

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
In 2023, 3.5 GW of solar resources and 600 MW of wind were added in the non-CAISO WECC,
with similar quantities coming online through October 2024. Into 2025, Siemens expects
approximately 3.6 GW of wind and 2.1 GW of solar to come online based on activity in regional
interconnection queues. Storage capacity additions have also been significant, with 1.4 GW of
storage capacity brought online in 2022 and 1.9 GW online through October 2024. Minimal fossil
fuel capacity came online in 2023 and that trend may continue through 2030 if carbon reduction
goals continue to drive renewable additions.
Figure 3.5-Non-CAISO WECC Capacity Addition(GW)
14
12
10
8 ■
6
4
2
0
202S 2026 2027 2028 2029 2030
■Storage ■ Natural Gas ■Other ■Solar ■Wind
Source:IHS Markit, SNL, Siemens PTI
30

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.6 -Non-CAISO WECC Capacity Retirement (GW)
2.5
2
1.5
1
0.5
0
2025 2026 2027 2028 2029 2030
■Coal ■Hydro ■Gas ■Oil
Source:IHS Markit, SNL, Siemens PTI
Emissions and Environment
Cool weather and low natural gas prices in 2023 led to decreased emissions and low demand for
allowances. In addition, the finalization of the Good Neighbor Plan in March 2023 contributed to
an 18%NOx emission reduction within the 10 implemented states. On April 25, 2024, the U.S.
Environmental Protection Agency(EPA)unveiled its final rule to regulate greenhouse gas
(GHG) emissions from power plants under Section 111 of the Clean Air Act. The updated rule
mandates that coal-fired baseload units achieve 90% carbon capture and storage (CCS)by 2032.
It also provides an option for plants scheduled for retirement by 2039 to co-fire up to 40%
natural gas as a transitional measure to reduce emissions.
Non-CAISO WECC Demand Forecast
After years of relatively stagnant demand nationwide, recent additions of loads—such as data
centers, manufacturing facilities, and electrification initiatives—have caused load forecast
projections to surge. According to regional outlooks, the non-CAISO WECC region is
anticipated to experience a compound annual growth rate (CAGR) of 1.8% from 2024 to 2030.
Recent Integrated Resource Plans (IRPs) from utilities across the region, including Nevada
Energy, Arizona Public Service, show higher-than-usual load growth expectations, largely due to
significant new load additions expected to come online in the coming years.
31

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.7 -Non-CAISO WECC Capacity Retirement (GW)
70,000
60,000
50,000
40,000
30,000
20,000
10,000
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Source: Siemens PTI
Forward Influence of the IRA
In August 2022, the US Congress Passed the Inflation Reduction Act ("IRA"). The notable near-
term impacts of the IRA are to allow all non-carbon emitting resources and energy storage
resources to select either production tax credits and investment tax credits. Production tax credits
are expected to provide greater benefits for wind, solar, and many other generation technologies
and may contribute to suppressed market prices during periods of renewable resource oversupply
as generators may be willing to accept negative attempt to avoid losing production tax credits.
As of November 2024, the future of some provisions of the IRA remains uncertain under the new
administration.While a repeal of the IRA is unlikely as that would require congressional approval,
the Trump administration could slow the payment of grants and loans or rescind or modify
regulations and guidance issued to date on how to implement provisions of the IRA. This action
would make it difficult for companies and individuals to plan with certainty with respect to
claiming tax credits for investments in new renewable and non-emitting technologies including
EVs and offshore wind. A US policy movement away from federal climate initiatives could also
enhance China's global dominance in clean energy industries such as solar panels and EVs,while
potential new import tariffs could hinder the deployment of energy generation and other
technologies supported by the IRA.
32

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Natural Gas Prices
2022 Summary
In the first quarter of 2022, demand for natural gas surpassed production in the US due to well
freeze-offs in January and February.High withdrawals of natural gas from storage during this time
caused prices to increase. Continued demand for U.S. liquified natural gas (LNG) exports into
Europe due to Russia's war on Ukraine, as well as increasing weather-driven demand, caused
upward price pressure.
In the second quarter, starting in May, weather-related demand for natural gas for electric
generation as well as uncertainty around storage injections led to an increase in natural gas
prices. The Henry Hub spot prices, as you can see in Figure 3.7, rose to over$9/MMBtu.
However, in late June, the second largest LNG export terminal in the US, accounting for 17% of
total LNG export capacity, suffered a tragic explosion which took it offline. As such prices fell to
below $6/MMBtu. For the first half of 2022, the U.S. was the largest exporter of LNG in the
world, and over two-thirds of the cargoes headed to Europe.
Figure 3.8 -Daily 2022 Henry Hub Spot Prices (USD/MMBtu)
10.00
Weather related
demand and LNG -�—�
&00 exports outpaces
production \4
1
6.00 / Above normal
summer temperature
Freeport LNG drives record demand }}}
4.00 R export terminal for power generation /
\ explosion /
Well freezeoffs reduces demand
Z pp Below normal winter
reduces temperature drives record
production demand for heating
0.00
Jan-22 Feb22 Mar-22 Apr-22 May-22 Jun-22 Jd-22 Aug-22 Aug-22 Oct-22 Oct-22 Nov-22 Dec-n
Source:S&P Global, Siemens PTI
The price of natural gas quickly rebounded in July and August, because of a heat wave in many
parts of The U.S.,which resulted in record high demand for power generation. The Western
States of the U.S. were particularly affected by this not only due to higher demand for power but
also from reduced supply of hydro resources due to continuing drought.
Despite these challenges, US Lower 48 supply surpassed pre-pandemic levels in the first half of
2022, led by gas production growth as higher prices spurred increased rig activity. Rig activity
was more pronounced in low-cost basins such as Permian (Texas/New Mexico) and Haynesville
(Louisiana) as they have better infrastructure to access demand areas.
Production growth slowed over the second half of 2022 as inflation, labor, and materials
shortages, and service sector constraints continued to impact producers, keeping overall domestic
production hovering around 100 Bcf/d. Natural gas delivery in the US is complex due to the
number of supply sources and pipelines that transport gas to various hubs around the country. As
such prices at Henry Hub do impact prices in the West as the same source that supplies the gulf
coast region can also supply the Western states.
33

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
However, there may be regional differences in price due to pipeline constraints. For instance, in
December 2022 and January 2023, while most of the country had above-normal temperatures,
California experienced wet and below-normal cold temperatures that significantly increased
demand for natural gas. This higher demand, the constraint on pipelines, and reduce storage
levels contributed to significantly higher prices that the west is currently experiencing.
2023 Summary
In 2023, U.S. natural gas prices saw a significant drop compared to the previous year, with the
benchmark Henry Hub price averaging $2.57 per million British thermal units (MMBtu), a steep
62% decline from 2022. This price decline was largely driven by record-high production levels,
which reached an average of 104 billion cubic feet per day (Bcf/d), 4% higher than the previous
year. This production increase was particularly notable in key regions like the Permian,
Haynesville, and Appalachia, where technological advancements and strong oil prices supported
higher outputs.
Figure 3.9—Annual 2022-2023 Change in US Natural Gas Production by Region (bcf/d)
Permian
1 Haynesville
Appalachia
Eagle Ford
0. Bakken
Anadarkteulf of Mexico
0
Niobrara
-0.5
-1
-1.5 Rest of US
Source: EIA, Siemens PTI
Weather played a critical role in shaping the market. Warmer-than-average winter temperatures in
January and February significantly reduced demand for natural gas in residential and commercial
heating, particularly in the Midwest and Northeast, where natural gas is a primary heating source
for most households. These mild conditions led to the lowest winter consumption levels in seven
years and kept storage inventories above the five-year average for much of the year, further
pressuring prices downward.
34

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.10—Lower 48 Weekly Working Gas in Underground Storage (Bcf/d)
4,500
4,000
3,500
3,000
2,500
1�
2,000
1,500
1,000
500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
-2021 2022 -2023 2024
Source: EIA, Siemens PTI
On the West Coast, natural gas prices were influenced by unique regional factors. Severe winter
storms early in the year disrupted supply chains and increased demand for heating in California
and surrounding areas, creating temporary price spikes in localized markets. However, as weather
conditions stabilized and milder temperatures returned, these pressures eased, and West Coast
prices aligned more closely with the broader national trend of declining natural gas costs.
While domestic demand for natural gas remained relatively flat overall, there were notable
increases in liquefied natural gas (LNG) exports,which rose by 12%, and pipeline exports, which
increased by 9%. These exports helped offset some of the impact of reduced residential and
commercial consumption. Despite this,the overall supply-demand balance remained tilted toward
oversupply, with storage levels high and production continuing at record rates.
Adding to the dynamics was the gradual recovery of the Freeport LNG facility, which had been
offline due to an outage in 2022 and returned to full operation in 2023.While this increased export
capacity, it did not significantly alter the broader market trajectory, as domestic production
remained the dominant factor. Prices remained under $3.00/MMBtu for most of the year, with
May marking the lowest monthly average at $2.19/MMBtu, illustrating how robust supply and
subdued demand combined to create one of the least volatile years for natural gas in recent history.
35

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
2024 Summary
In 2024, U.S. natural gas prices remained relatively low, with the Henry Hub averaging under $3.00
per MMBtu through November. Production levels, while slightly reduced compared to the previous
year, remained robust at an average of 103.3 Bcf/d according to EIA. This marked the first annual
production decline since 2020, driven by lower drilling activity as a result of subdued spot prices.
Despite this,overall supply continued to outpace domestic demand,keeping inventories above the five-
year average.
In the Permian Basin of western Texas and southeastern New Mexico,natural gas production,primarily
as associated gas from oil wells,increased this year alongside rising oil production driven by oil prices,
with expanding pipeline takeaway capacity, such as the Matterhorn pipeline, continuing to support
higher production levels despite some volatility caused by periodic pipeline maintenance affecting
Permian supply
On the demand side, residential and commercial consumption increased due to a colder winter
compared to 2023, reversing the trend of reduced heating needs observed in the prior year. LNG
exports reached a record 12.1 Bcf/d as global demand for U.S.natural gas grew,particularly in Europe,
where efforts to diversify energy sources remained a priority. However, higher exports were offset by
stable industrial demand and moderate consumption for power generation, resulting in a balanced
domestic market. Regional pricing saw temporary variations,particularly in the West,where localized
weather events, including early-season storms, increased heating demand briefly. Despite these
regional factors,the national market reflected a stable supply-demand balance with minimal volatility.
This relative stability was further supported by the continued high storage levels, maintaining
downward pressure on prices throughout the year.
2025-2032 Forward View
As we consider the 2025 to 2030 timeframe, our fundamental forecast for natural gas spot prices
at Henry Hub indicates a steady upward trend, with prices expected to average in the mid-
$4/MMBtu range in real terms by 2027. Total natural gas demand is projected to reach 122 Bcf/d
by 2029, a 13% increase from 2023 levels, driven primarily by rising LNG exports and pipeline
deliveries to Mexico. LNG exports are anticipated to double by 2027, as several terminals reach
final investment decisions and expand capacity. Similarly,pipeline exports to Mexico are expected
to grow significantly, fueled by increased demand for power generation and industrial use.
To meet this growing demand, U.S. natural gas production is expected to expand significantly,
particularly from low-cost basins such as the Permian,Eagle Ford,and Haynesville. These regions
are well-positioned to serve both domestic and export markets, benefiting from their proximity to
demand centers and the development of new takeaway capacity through ongoing pipeline
expansion projects. While the market may experience tightness through the middle of the decade
due to accelerating LNG export growth, the combination of increased production and strategic
infrastructure investments is expected to stabilize supply and support a balanced market by 2032.
36

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
Figure 3.11 —Henry Hub Futures
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
V C.C) CD r- 00 M O N CO � Cn CD h 00 O O N M � LO (D n CO M O
N N N N N N CO M CO CO M M M M M M 1 � � � � � � � � LO
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
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
Q4 2024
Source: Siemens PTl, GPCM
Conclusion
In summary, the natural gas market is poised for significant growth through the 2025-2030
timeframe, driven by surging export demand and supported by robust production from key basins
and expanding infrastructure. While domestic demand shifts modestly, the market's stability will
hinge on the alignment of production growth with expanding export capacity. Despite periods of
tightness mid-decade, strategic investments and rising supply will position the market for long-
term equilibrium, with Henry Hub prices reflecting this balance.
PacifiCorp's Multi-State Process
PacifiCorp is a multi-state utility that provides retail electric service to over 2 million customers
across six states. The costs of providing this retail electric service to customers is recovered
through retail rates established in regulatory proceedings in each state. To ensure states receive the
appropriate allocation of costs and benefits from PacifiCorp's integrated system,the collaborative
multi-state process(MSP)has been used to develop an allocation methodology. This collaborative
process has led to the development and adoption of PacifiCorp's current inter jurisdictional cost-
allocation method.
The underlying principle of each of the historical inter jurisdictional cost-allocation methods has
been the use of PacifiCorp's system as a single whole. Except for distribution, all states are served
from a common portfolio of generation and transmission assets, which enables the company to
leverage economies of scale and take advantage of load diversity to plan and operate in a way that
results in cost savings for all customers. Recently, state energy policies across the states served by
the company have challenged this principle. For example, requirements to remove coal-fired
generation from rates in certain states will necessarily result in some states being allocated the
37

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
costs and benefits of coal-fired generation while other states are not. Similarly, diverging state
polices related to implementation of the Public Utilities Regulatory Policy Act of 1978, retail
choice, private generation, and incorporation of societal externalities in resource planning
challenge the long-standing practice of planning for a single, integrated system.
In December 2019, PacifiCorp filed the most recent inter jurisdictional cost-allocation
methodology, known as the 2020 PacifiCorp Inter jurisdictional Allocation Protocol (2020
Protocol). Under the 2020 Protocol, five of PacifiCorp's six retail states would continue sharing
all system resources, while Washington, which had previously only recognized resources in
PacifiCorp's west Balancing Authority Area, would share in all system transmission and non-
emitting resources. Signatories to the 2020 Protocol had been discussing the development of a
future allocation methodology that would address all states' energy policy, while maintaining the
benefits of PacifiCorp's system. In 2024, PacifiCorp determined that a negotiated agreement was
unlikely given the differences in state energy policies and data limitations for parties to compare
alternatives. PacifiCorp will file a new allocation methodology for approval by all six state
commissions and implementation in 2026. PacifiCorp's guiding principles in the development of
the new allocation methodology will continue to be:
1. Provide a long-term, durable solution;
2. Follow cost-causation principles;
3. Minimize rate impacts at implementation;
4. Allow for state autonomy for new resource portfolio selection;
5. Maintain and optimize system-wide benefits and joint dispatch to the extent possible;
6. Enable compliance with state policies;
7. Ensure credit-supportive financial outcome; and
8. Provide the company with a reasonable opportunity to recover its costs.
Environmental Regulatio
The upcoming administration change featuring Republican control of the House, Senate, and
presidency, sets the stage for significant shifts in federal energy policy that could influence
PacifiCorp's portfolio selection process used in the development of future IRPs. PacifiCorp
recognizes the potential for new legislative and regulatory priorities to impact the energy sector
and resource planning. The company actively monitors federal legislative and regulatory
developments and participates in rulemaking processes by submitting comments, engaging in
hearings, and providing policy assessments to ensure alignment with evolving requirements.
Suggested upcoming legislative priorities under the new administration include changes to the
Inflation Reduction Act and a reconciliation bill with energy as a focal point that could directly
impact PacifiCorp's existing and potential generation portfolio.
38

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
Federal Policy Update
National Electric Vehicle Infrastructure Formula Program
- $5 billion FY 2022-2026
The U.S.Department of Transportation's(DOT)Federal Highway Administration(FHWA)NEVI
Formula Program will provide funding to states to strategically deploy electric vehicle (EV)
charging stations and to establish an interconnected network to facilitate data collection, access,
and reliability. Funding is available for up to 80% of eligible project costs, including:
• The acquisition, installation, and network connection of EV charging stations to facilitate
data collection, access, and reliability;
• Proper operation and maintenance of EV charging stations; and,
• Long-term EV charging station data sharing.
Section 11401 Grants for Charging and Fueling Infrastructure
- $2.5 billion for FY 2022—2026.
Competitive grant program to strategically deploy publicly accessible electric vehicle charging
infrastructure and other alternative fueling infrastructure along designated alternative fuel
corridors. At least 50 percent of this funding must be used for a community grant program where
priority is given to projects that expand access to EV charging and alternative fueling infrastructure
within rural areas, low- and moderate-income neighborhoods, and communities with a low ratio
of private parking spaces
New Credits and Considerations for Non-emitting Resources — Inflation
Reduction Act
The Inflation Reduction Act of 2022 (IRA) is a comprehensive set of clean energy legislation
signed into law in August 2022 by President Biden. Substantive details of how the legislation will
be implemented 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:
• 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 and production tax credits 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 production tax credits at full
value through December 31, 2024. Solar projects are newly eligible to apply the
production tax credit to energy generated. Additional 10% bonus credits each are
available for both locating projects in communities with retired coal operations and
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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 2025 IRP,resources in designated areas 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)
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 EVs and FCEVs, and require a traction
battery that has at least seven kilowatt-hours (kWh). An available tax credit under the CVC may
be limited by the vehicle's MSRP 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$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 the federal Investment Tax Credit (ITC) for small scale solar systems
through 2034 and expands the credit to include standalone energy storage systems as well. Since
the passage of the IRA,the ITC has been extended beyond its original expiration date for ten years.
For facilities beginning construction before January 1, 2025, the bill will extend the ITC for up to
30 percent of the cost of installed equipment for ten years and will then step down to 26 percent in
2033 and 22 percent in 2034. For projects beginning construction after 2019 that are placed in
service before January 1, 2022, the ITC is set at 26 percent. In addition to the new federal ITC
schedule for generating facilities, the updated ITC includes credits for standalone energy storage
with a capacity of at least 3 kWh for residential customers and 5 kWh for non-residential
customers.
The 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, IRA increases the credit to 30% of cost,with an annual cap of$1,200 along with
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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).
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 April 2024, the EPA finalized new rules
addressing greenhouse gas emissions from new and reconstructed natural gas-fueled combustion
turbines (Clean Air Act Section I I I(b) rule) and existing coal- and gas- or oil-fueled steam units
(Clean Air Act Section I I I(d) rule).
For new combustion turbines, the final rule establishes three subcategories based on operating
intensity as measured by capacity factor.
I. Base load turbines (operating above 40% of maximum annual capacity factor) must
initially meet a standard reflective of an efficient combined cycle design and also achieve
90% carbon capture by January 1, 2032.
2. Intermediate load turbines (operating between 20%and 40% of capacity factor)must meet
a standard reflective of an efficient simple cycle design.
3. Low load turbines (operating below 20% capacity factor) must meet a standard based on
using low-emitting fuels.
For existing coal-fired electric generating units (EGUs), the final rule subcategorizes plants based
on the units intended operational timeline.
1. Long-term units (operating beyond January 1, 2039) must meet emission limits based on
90% carbon capture and storage (CCS)by January 1, 2032.
2. Medium-term units (retiring by January 1, 2039) must meet limits by January 1, 2030,
using 40%natural gas co-firing.
3. Near-term units (closing before January 1, 2032)have no emission reduction obligations.
For existing gas- or oil-fueled steam units, the final rule subcategories units based on capacity
factor.
I. Base load units(annual capacity factor greater than or equal to 45%)must maintain routine
operations and maintenance, with no increase in emission rate (1,400 lb/MWh)
2. Intermediate load units (annual capacity factor between 8% and 45%) must maintain
routine operations and maintenance, with no increase in emission rate (1,600 lb/MWh)
3. Low load units (annual capacity factor less than 8%) must meet a standard based on using
low-emitting fuels.
States are required to submit implementation plans within two years of the rule's publication.
These plans must show meaningful engagement with stakeholders, including affected
communities and reliability authorities. States also have flexibility to consider factors like
Remaining Useful Life, allow for emissions trading and averaging, and provide one-year
compliance extensions for delays beyond an operator's control.
The rule has been challenged by multiple parties and is currently awaiting a decision from the D.C.
Circuit Court of Appeals.
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Credit for Carbon Oxide Sequestration — Internal Revenue Service § 45Q
In 2008, the Internal Revenue Service issued a tax credit for carbon oxide sequestration under
section 45Q to incentivize carbon capture and sequestration (CCS) investments. The tax credit is
computed per metric ton (tonne) of qualified carbon oxide captured and sequestered.' Carbon
oxide can either be permanently disposed of in secure geological storage or the carbon oxide can
be utilized—typically as a tertiary injectant in enhanced oil recovery(EOR).
The Bipartisan Budget Act of 2018 reformed 45Q for carbon capture equipment that is placed in
service on or after February 9,2018, increasing the credit amount from$10/tonne to $35/tonne for
utilization and from $20/tonne to $50/tonne for storage.' This Act also removed the limit on the
amount of tax credits that could be awarded for CCS, and, instead,requires a minimum amount of
carbon oxide to be capture annually (500,000 tonnes per year for an electric generating facility)
and is available for 12 years from the date the carbon capture equipment is originally placed into
service. The Consolidated Appropriations Act of 2021 extended the date construction must begin
to receive the tax credits by two years, from January 1, 2024 to January 1, 2026.
The Inflation Reduction Act made considerable changes to the 45Q tax credit in 2022. The tax
credit amount increased to $60/tonne (use) and $85/tonne (storage), the construction window was
extended to January 1, 2033, the minimum capture thresholds were lowered (18,750 tonnes per
year for electric generating facilities) and the Act now requires 75% of a generating units CO2
production to be captured, among other requirements.
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
NAAQS are rigorously vetted by the scientific community, industry, public interest groups, and
the general public, and establish the maximum allowable concentration allowed for each"criteria"
pollutant in outdoor air. 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. If an area is determinedto
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
7 Before February 9,2018,the tax credit was strictly for CO2.
8 The tax credit reaches$35/tonne and$50/tonne in 2026.
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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
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
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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
on the same day. The U.S. Supreme Court heard oral arguments on the emergency stay requests
February 21, 2024, and granted a stay on the federal implementation plan on June 27, 2024.
Particulate Matter NAAQS
In April 2017, the EPA Administrator signed a final action to reclassify the Salt Lake City and
Provo PM2.5 nonattainment areas from moderate to serious. PacifiCorp's Lake Side and Gadsby
facilities were identified as major sources subject to Utah's serious nonattainment area SIP for
PM2.5 and PM2.5 precursors. On April 27, 2017, PacifiCorp submitted a Best Available Control
Technology (BACT) analysis for Lake Side and Gadsby to the Utah Division of Air Quality for
review. On January 2, 2019, the Utah Air Quality Board adopted source specific emission limits
and operating practices in the SIP which incorporated the current emission and operating limits for
the Lake Side and Gadsby facilities.
In November of 2020, the EPA proposed to redesignate the Salt Lake City and Provo PM2.5
nonattainment areas to attainment. EPA received adverse comments on the proposed re-
designation. EPA and the Utah Division of Air Quality working to address the comments. Re-
designation to attainment would have no effect on current emissions and operating limits for the
Lake Side and Gadsby facilities.
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). The states are required to update their regional
haze rule plans approximately every ten years, with second planning period revisions due in
August of 2023. Litigation over the first planning period requirements for both Utah and Wyoming
are mostly concluded.
On June 15, 2005, EPA issued final amendments to its regional haze rule to require emission
controls known as BART for industrial facilities meeting certain regulatory criteria with emissions
that have the potential to affect visibility. The regulated pollutants include fine PM, NOx, S02,
certain VOCs, and ammonia. The 2005 amendments included final guidelines, known as BART
guidelines, for states to use in determining which facilities must install controls and the type of
controls the facilities must use. States were given until December 2007 to develop their
implementation plans, in which states were responsible for identifying the facilities that would
have to reduce emissions under BART guidelines, as well as establishing BART emissions limits
for those facilities.
On August 20,2019,EPA issued a final guidance document on the technical aspects of developing
regional haze SIPS for the second implementation period of the regional haze program. EPA issued
additional guidance through a memorandum on July 8, 2021, that emphasizes the 4-factor
reasonable progress analysis for the second planning period and the reduced weight of visibility as
a factor in the second planning period.
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Utah Regional Haze
In May 2011, the state of Utah issued a regional haze SIP requiring the installation of S02, NOx
and PM controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the
EPA approved the S02 portion of the Utah regional haze SIP and disapproved the NOx and PM
portions. EPA's approval of the S02 SIP was appealed by environmental advocacy groups to the
Tenth Circuit. In addition, PacifiCorp and the state of Utah appealed EPA's disapproval of the
NOx and PM SIP. PacifiCorp and the state's appeals were dismissed, and the S02 appeal was
denied by the Tenth Circuit. In June 2015, the state of Utah submitted a revised SIP to EPA for
approval with an alternative BART NOx analysis incorporating a requirement for PacifiCorp to
retire Carbon Units 1 and 2, crediting NOx controls previously installed on Hunter Unit 3, and
concluding that no incremental controls (beyond those included in the May 2011 SIP and already
installed) were required at the Hunter and Huntington units. On June 1, 2016, EPA issued a final
rule to partially approve and partially disapprove Utah's regional haze SIP and propose a FIP. The
FIP required the installation of SCR controls by August 4, 2021, at four of PacifiCorp's units in
Utah, including Hunter Units 1 and 2 and Huntington Units 1 and 2. On September 2, 2016, the
state of Utah and PacifiCorp filed petitions for administrative and judicial review of EPA's final
rule, followed by a motion to stay the effective date of the final rule.
On June 30, 2017, Utah and PacifiCorp provided new information to EPA, again requesting
reconsideration. EPA responded on July 14, 2017, indicating its intent to reconsider its FIP. EPA
also filed a motion with the Tenth Circuit to stay EPA's FIP and hold the litigation in abeyance
pending the rule's reconsideration. On September 11, 2017, the Tenth Circuit granted the petition
for stay and the request for abatement. The compliance deadline of the FIP and the litigation were
stayed pending EPA's reconsideration, and EPA was required to file periodic status reports with
the court.
Utah and PacifiCorp worked with EPA to develop a revised Utah regional haze SIP,based on new
CAMx modeling. The Utah Air Quality Board approved the revised SIP on June 24,2019, and the
SIP revision was submitted to EPA for review on July 3, 2019. On December 3, 2019, Utah
submitted a supplement to EPA with a minor SIP revision relating to PM2.5.
On January 10, 2020, the EPA published its proposed approval of the Utah SIP revision and
withdrawal of the FIP requirements for the Hunter and Huntington plants to install SCR on Hunter
Units 1 and 2 and Huntington Units 1 and 2. After receiving public comments and holding a public
hearing in the Price area on February 12,2020,EPA issued final approval of the Utah SIP revision
and FIP withdrawal on November 27, 2020. The final rule credits existing NOx emission controls
at the Hunter and Huntington plants as well as NOx and PM emission reductions provided by the
closure of the Carbon plant in 2015. Based on the newly approved plan, EPA also withdrew the
2016 FIP requirements to install SCR control technology on Hunter Units 1 and 2 and Huntington
Units 1 and 2. On January 11, 2021,the Tenth Circuit granted Utah,PacifiCorp and EPA's motion
to dismiss the Utah regional haze petitions.
Environmental advocacy groups filed a petition for review in the Tenth Circuit on January 19,
2021,objecting to the revised Utah regional haze SIP.After holding the case in abeyance at EPA's
request, the Tenth Circuit lifted the abeyance and granted PacifiCorp and Hunter co-owners and
Utah's pending motions to intervene. 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. PacifiCorp is
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coordinating oral argument with EPA and the state of Utah.
Utah Regional Haze Second Planning Period — On April 21, 2020, PacifiCorp submitted a
Regional Haze Reasonable Progress Analysis for the second planning period to the Utah
Department of Environmental Quality for PacifiCorp's Huntington and Hunter plants.The analysis
was requested by the state as part of its second planning period SIP development process.
PacifiCorp's analysis included a proposal to implement reasonable progress emission limits for
NOx and S02 at the Hunter and Huntington units to meet second planning period requirements.
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 S02 rate-
based limit for the Hunter and Huntington plants. EPA notified Utah on August 22, 2022, that its
SIP submittal was complete.
On December 2, 2024, EPA issued a final partial approval and disapproval for Utah's regional
haze state implementation plan for the second planning period without simultaneously issuing a
federal implementation plan. Specifically,the EPA disapproved the long-term strategy,reasonable
further progress goals, and federal land management consultation components of the state plan.
EPA's disapproval of Utah's long-term strategy is based in part on the rejection of SCR for Hunter
and Huntington. In addition to disapproving the State's long-term strategy, the EPA disapproved
Utah's reasonable progress goals and its consultation with Federal Land Managers, as compliance
with these requirements is dependent on compliance with the long-term strategy provisions. There
are no new compliance obligations for PacifiCorp at this time, as the disapprovals did not include
a simultaneously proposed federal plan.
Wyoming Regional Haze
On January 10, 2014, EPA issued a final rule partially approving and partially disapproving the
Wyoming regional haze SIP. The 2014 final rule required installation of the following NOx and
PM controls at PacifiCorp facilities for regional haze first planning period:
• Naughton Units 1 and 2: BART is LNB/over-fired air(OFA)
• Naughton Unit 3 by December 31, 2014: SCR equipment and a baghouse
• Jim Bridger Unit 3 by December 31, 2015: SCR equipment
• Jim Bridger Unit 4 by December 31, 2016: SCR equipment
• Jim Bridger Unit 2 by December 31, 2021: SCR equipment
• Jim Bridger Unit 1 by December 31, 2022: SCR equipment
• Dave Johnston Unit 3: SCR within five years or a commitment to shut down in 2027
• Wyodak: SCR equipment within five years
Naughton—In its 2014 rule, EPA approved Wyoming's determination that BART for Units 1 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,
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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 1 and 2 in the Tenth Circuit. On
August 15, 2023, the court determined EPA properly approved Wyoming's Naughton
determination and denied environmental groups'petition.
Jim Bridger— In its 2014 rule, EPA approved Wyoming's SIP determination that BART for Jim
Bridger Units 1 through 4 was LNB/OFA, with SCR required over staggered years under long-
term strategy requirements. SCR was installed on Jim Bridger Units 3 and 4 by the dates required
by the Wyoming SIP. On February 5, 2019, PacifiCorp submitted to Wyoming an application and
proposed SIP revision instituting plant-wide variable average monthly-block pound per hour NOx
and SO2 emission limits, in addition to an annual combined NOx and SO2 limit, on all four Jim
Bridger boilers in lieu of the requirement to install SCR on Units 1 and 2. The proposed SIP
revision demonstrated that the proposed limits were more cost effective while leading to better
modeled visibility than the SCR installation on Units 1 and 2.Wyoming submitted a regional haze
SIP revision to the EPA on May 14, 2020,that incorporated PacifiCorp's proposed emission limits
in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. While EPA
communicated that it would issue a proposed approval of Wyoming's Jim Bridger SIP, the
proposal was not issued before the administration change in 2021.
When EPA failed to issue a determination by the statutory deadline in November 2021, the
Governor of Wyoming issued a temporary emergency order on December 27, 2021, using
authority granted by the Clean Air Act, suspending the existing SIP requirement for Jim Bridger
Unit 2 to install SCR by December 31, 2021. The suspension was issued for four months due to
the EPA's failure to act on the SIP revision submitted by Wyoming in 2020. EPA published a
proposed disapproval of the Jim Bridger SIP revision in the Federal Register on January 18, 2022.
However, PacifiCorp negotiated a consent decree with Wyoming and an administrative consent
order with EPA and the disapproval was not finalized. Under the Wyoming consent decree and
EPA administrative consent order, PacifiCorp is required to comply with a compliance plan that
allows continued operation of Jim Bridger Units 1 and 2 under the emission limits established by
Wyoming in 2020 until they are converted to natural gas in 2024. The consent decree committed
Wyoming to processing a SIP revision requiring the conversion and imposing post-conversion
emission limits.
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
submission and is expected to conduct a separate federal public comment process on the plan
during the summer of 2023. 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 complete.
Dave Johnston—Under regional haze, the Dave Johnston plant was required to either install SCR
on Dave Johnston Unit 3 or retire the unit by the end of 2027. PacifiCorp has committed to close
Unit 3 by the end of 2027.
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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 analyses 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. PacifiCorp supports the state
plan as it meets regional haze requirements.
The EPA issued a final partial approval and disapproval for Wyoming's regional haze state
implementation plan for the second planning period. Specifically, the EPA disapproved the long-
term strategy, reasonable further progress goals, and federal land management consultation
components of the state plan. EPA's disapproval of Wyoming's long-term strategy is based in part
on the state's decision to forego a full four-factor analysis for units at Jim Bridger,Naughton,Dave
Johnston, and Wyodak. In addition to disapproving the State's long-term strategy, the EPA
disapproved Wyoming's reasonable progress goals and its consultation with Federal Land
Managers, as compliance with these requirements is dependent on compliance with the long-term
strategy provisions. There are no new compliance obligations for PacifiCorp at this time, as the
disapprovals did not include a simultaneously proposed federal plan.
Colorado Regional Haze
The Colorado regional haze SIP required SCR controls at Craig Unit 2 and Hayden Units 1 and 2.
In addition, the SIP required the installation of selective non-catalytic reduction (SNCR)
technology at Craig Unit 1 by 2018. Environmental groups appealed EPA's action, and PacifiCorp
intervened in support of EPA. In July 2014, parties to the litigation other than PacifiCorp entered
into a settlement agreement that requires installation of SCR equipment at Craig Unit 1 in 2021.
In February 2015, Colorado submitted a revised SIP to EPA for approval. As part of a further
agreement between the owners of Craig Unit 1, state and federal agencies, and parties to previous
settlements, the owners of Craig agreed to retire Unit 1 by December 31, 2025, or, to convert the
unit to natural gas by August 31, 2023. The Colorado Air Quality Board approved the agreement
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on December 15, 2016. Colorado submitted the corresponding SIP amendment to EPA Region 8
on May 17, 2017. EPA approved the SIP on July 5,2018.
Colorado Regional Haze 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 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
The Mercury and Air Toxics Standards(MATS)became effective April 16,2012. The MATS rule
required that new and existing coal-fueled facilities achieve emission standards for mercury, acid
gases and other non-mercury hazardous air pollutants. Existing sources were required to comply
with the new standards by April 16, 2015. However, individual sources may have been granted up
to one additional year, at the discretion of the Title V permitting authority,to complete installation
of controls or for transmission system reliability reasons. By April 2015, PacifiCorp had taken the
required actions to comply with MATS across its generation facilities. On April 25,2016,the EPA
published a Supplemental Finding that determined that it is appropriate and necessary to regulate
under the MATS rule which addressed a Supreme Court decision requiring consideration of costs.
On February 7, 2019, the EPA published a reconsideration of the Supplemental Finding in which
it proposed to find that it is not appropriate and necessary to regulate hazardous air pollutants,
reversing the Agency's prior determination. In May 2020,the EPA published its decision to repeal
the appropriate and necessary findings in the MATS rule regarding regulation of electric utility
steam generating units, and to retain the rule's current emission standards. The rule took effect in
July 2020. Several petitions for review were filed in the D.C. Circuit by parties challenging and
supporting the EPA's decision to rescind the appropriate and necessary finding. The court granted
EPA's motion to hold the cases in abeyance while the agency reviewed the 2020 repeal. On
February 9,2022,EPA published a rule proposing to rescind the 2020 revocation of the appropriate
and necessary finding and to reinstate the finding. EPA also solicited information on the
performance and cost of new or improved technologies to control hazardous air pollutants (HAP)
emissions, improved methods of operation, and risk-related information for the required review of
the MATS rule and the risk and technology review. EPA published its decision on March 6, 2023,
to revoke the May 2020 finding, concluding that it is appropriate and necessary to regulate coal
and oil-fired electric generation units under section 112 of the Clean Air Act. PacifiCorp plants
are in compliance with the MATS standards, so the reinstatement of the finding has no immediate
practical effect. However, PacifiCorp is monitoring potential legal proceedings that may be
restarted based on this decision.
On April 25, 2024, EPA finalized revisions to the MATS rule following the agency's review of
the 2020 Residual Risk and Technology Review. The final rule, effective July 8, 2024, tightens
the standard for emissions of mercury from lignite-fired units and sets a more stringent standard
for emissions of filterable particulate matter from all existing units. The rule also requires that
continuous emissions monitoring be used to demonstrate compliance with the filterable particulate
matter standard.
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Coal Combustion Residuals
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal
combustion byproducts under the Resource Conservation and Recovery Act (RCRA). The final
rule became effective October 19, 2015. The final rule regulates coal combustion byproducts as
non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for
the disposal of coal combustion residuals (CCR). Under the final rule, surface impoundments and
landfills utilized for coal combustion byproducts may need to be closed unless they can meet the
more stringent regulatory requirements. The final rule requires regulated entities to post annual
groundwater monitoring and corrective action reports. The first of these reports was posted to
PacifiCorp's CCR compliance data and information websites in March 2018. Based on the results
in those reports, additional action was required under the rule. At the time the rule was published
in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained
CCR. Before the effective date in October 2015, nine surface impoundments and three landfills
were either closed or repurposed to no longer receive CCR, and hence are not subject to the final
rule.
Multiple parties filed challenges over various aspects of the final rule in 2015, resulting in
settlement of some of the issues and subsequent regulatory action by the EPA,including subjecting
inactive surface impoundments to regulation. In response to legal challenges and court actions,
EPA, in March 2018, issued a proposal to address provisions of the final CCR rule that were
remanded back to the agency. The proposal included provisions that establish alternative
performance standards for owners and operators of CCR units located in states that have approved
permit programs or are otherwise subject to oversight through a permit program administered by
the EPA. The first phase of the CCR rule amendments was made effective in August 2018 (the
"Phase 1, Part I rule"). In addition to adopting alternative performance standards and revising
groundwater performance standards for certain constituents, the EPA extended the deadline by
which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection
standard and impoundments that do not meet the rule's aquifer location restrictions to October
2020.
Following the March 2019 submittal of competing motions from environmental groups, EPA
finalized its Holistic Approach to Closure: Part A rule("Part A rule") in September 2020. The rule
reclassified compacted-soil lined surface impoundments from "lined" to "unlined," established a
deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure, and
revised the alternative closure provisions to grant facilities additional time to initiate closure in
order to manage CCR and non-CCR waste streams either due to a lack of alternative capacity or
due to a commitment to close the coal-fueled operating unit and complete closure of unlined
impoundments by a date certain.The Part A rule also revised certain requirements regarding annual
groundwater monitoring and corrective action reports and publicly accessible CCR internet sites.
A provision in Part A allows demonstrations to be submitted to the EPA allowing for operation of
unlined 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 was placed into service. EPA was
notified on October 12, 2023, of PacifiCorp's withdrawal of its pending Part A alternative storage
capacity demonstration request.
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On October 16, 2020,the EPA released the pre-publication version of the final Holistic Approach
to Closure: Part B rule ("Part B rule"). The Part B rule finalizes a two-step process, as set forth in
the March 2020 proposal, allowing facilities to request approval to continue operating an existing
unlined CCR surface impoundment with an alternate liner system. The other provisions that were
contained in the Part B proposal, including (1) options to use CCR during closure of a CCR unit,
(2) an additional closure-by-removal option and(3) new requirements for annual closure progress
reports, were not finalized with the Part B rule. These options will be addressed by the EPA in a
subsequent rulemaking action. In addition to the Part A and Part B rules, the EPA has proposed
the Phase II rule, the federal CCR permit program rule, and the advanced notice of proposed
rulemaking for legacy impoundments. Until the proposals are finalized and fully litigated,
PacifiCorp cannot determine whether additional action may be required.
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. EPA rejected Wyoming's application due to concerns about the
state's ability to meet federal standards for the safe management of coal ash. The state of Utah
adopted the federal final rule in September 2016, and issued the final permit for Huntington Power
Plant CCR Landfill on March 21, 2023, and for Hunter Power Plant CCR Landfill on May 15,
2024. It is anticipated that the state of Utah will submit an application to EPA for approval of its
CCR permit program but the timing of the submission remains uncertain.
The EPA finalized the legacy surface impoundments rule to extend federal CCR regulatory
requirements to (1) inactive CCR surface impoundments at inactive utilities and (2) CCR
management units (CCRMU) at active facilities, including CCR impoundments and landfills that
closed prior to the effective date of the 2015 CCR Rule, inactive CCR landfills, and other areas
where CCR is managed directly on the land. The final rule was published in the Federal Register
on May 8, 2024, and became effective on November 8, 2024. The final rule includes exemptions
and establishes new categories where regulation is deferred for applicable units, including
CCRMU containing less than 1,000 tons of CCR, CCRMU located beneath critical infrastructure
or large buildings or structures vital to the continuation of current site activities, and CCRMU that
were closed prior to the effective date of the new rule. Affected facilities must conduct a facility
evaluation and report to determine the presence of CCRMUs and/or legacy surface impoundments.
Because the facility evaluation and report requirement will determine the magnitude of compliance
obligations, the relevant registrants cannot assess the full impacts of the rule at this time.
Water Quality Standards
Cooling Water Intake Structures
The federal Water Pollution Control Act (Clean Water Act) establishes the framework for
maintaining and improving water quality in the United States through a program that regulates,
among other things,discharges to and withdrawals from waterways. The Clean Water Act requires
that cooling water intake structures reflect the "best technology available for minimizing adverse
environmental impact" to aquatic organisms. In May 2014, EPA issued a final rule, effective
October 2014, under § 316(b) of the Clean Water Act to regulate cooling water intakes at existing
facilities. The final rule established requirements for electric generating facilities that withdraw
more than two million gallons per day,based on total design intake capacity, of water from Waters
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of the United States (WOTUS) and use at least 25 percent of the withdrawn water exclusively for
cooling purposes.PacifiCorp's Dave Johnston generating facility withdraws more than two million
gallons per day of water from WOTUS for once-through cooling applications. Jim Bridger,
Naughton, Gadsby, Hunter, and Huntington generating facilities currently use closed-cycle
cooling towers and withdraw more than two million, but less than 125 million, gallons of water
per day. The rule includes impingement (i.e., when fish and other aquatic organisms are trapped
against screens when water is drawn into a facility's cooling system) mortality standards and
entrainment (i.e., when organisms are drawn into the facility) standards. The standards will be set
on a case-by-case basis to be determined through site-specific studies and will be incorporated into
each facility's discharge permit.
Rule-required permit application requirements (PARs) have been submitted to the appropriate
permitting authorities for the Jim Bridger, Naughton, Gadsby, Hunter and Huntington plants. As
the five facilities utilize closed-cycle recirculating cooling water systems (cooling towers)
exclusively for equipment cooling, it is expected that state agencies will require no further action
from PacifiCorp to comply with the rule-required standards.
Because Dave Johnston utilizes once-through cooling with withdrawal rates greater than 125
million gallons per day,the facility has been required to conduct more rigorous PARs.
Effluent Limit Guidelines
In November 2015,the EPA published final effluent limitation guidelines and standards(ELG)for
the steam electric power generating sector which, among other things, regulate the discharge of
bottom ash transport water,fly ash transport water,combustion residual leachate and non-chemical
metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in
response to the EPA's concerns that the addition of controls for air emissions has changed the
effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally
promulgated guidelines, permitting authorities were required to include the new limits in each
impacted facility's National Pollutant Discharge Elimination System (NPDES) permit upon
renewal with the new limits to be met as soon as possible,beginning November 1, 2018, and fully
implemented by December 31, 2023.
On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed
with the EPA. EPA granted the request for reconsideration and extended certain compliance dates
for FGD wastewater and bottom ash transport water limits until November 1,2020. On November
22, 2019, EPA proposed updates to the 2015 rule, specifically addressing FGD wastewater and
bottom ash transport water. Those proposals were formalized in rule when the EPA administrator
signed the Reconsideration Rule,and it was published in the Federal Register on October 13,2020.
The rule eases selenium limits on FGD wastewater, eases the zero-discharge requirements on
bottom ash transport water associated with blowdown of ash handling systems, allows a two-year
time extension to meet FGD wastewater requirements and includes additional subcategories to both
wastewater categories.
On April 25, 2024, EPA finalized the Supplemental ELG and Standards for the Steam Electric
Generating Point Source Category(2024 ELG Rule or Final Rule),which maintains the 2020 ELG
Rule Cessation of Coal Subcategory and includes a new subcategory for units that will
retire/repower by December 31, 2034. The 2024 ELG Rule also imposes a zero liquid discharge
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requirement at coal-based generating units for bottom ash transport water, flue gas desulfurization
wastewater, and coal combustion residual leachate.
Most of the issues raised by the 2024 ELG Rule are already being addressed at PacifiCorp facilities
through compliance with the CCR rule and will not impose significant additional requirements on
the facilities.The Dave Johnston plant submitted a notice of planned participation in October 2021
for subcategorization for units ceasing coal combustion by December 31, 2028. Participation in
the subcategory allows continued management of bottom ash transport water using impoundments
and discharge of the waste stream.,The plant requested that the option to transfer to the installation
and operation of a bottom ash recycle system be included in the new NPDES permit.
Renewable Generation Regulatory Framework
Regulatory and permitting requirements for renewable energy projects are addressed at federal,
state, and local levels. All wind projects in the United States must comply with federal regulations
for wildlife impacts, aviation safety, clean water, communication systems, and Department of
Defense impacts. Eagle Incidental Take Permits (EITPs), including associated surveys,
monitoring, and compensatory mitigation, are necessary for wind projects that may result in take
of bald or golden eagles. State and county regulations often address localized topics such as road
and traffic concerns, community economic impacts, viewshed requirements, sage-grouse
stipulations, wind turbine location guidelines, and land use and zoning restrictions. Solar projects
must comply with federal and state regulations that restrict disturbance of certain flora and fauna
and are subject to local planning and zoning regulations for land use. Storm water pollution
prevention plans for renewable projects are usually required on a state level to control sediment
runoff during construction and all renewable projects must comply with the Clean Water Act rules
which are controlled at the federal level. Renewable energy projects located on federally managed
lands or that receive federal funding are subject to National Environmental Policy Act (NEPA)
review, which may include cultural and biological resource surveys, assessment of potential
impacts, public comment periods, and avoidance/minimization/mitigation efforts. Power lines
associated with renewable energy projects, including collector lines at the project site and grid-
connecting transmission lines, may also be subject to environmental regulations, review,
stipulations, or permits.
The wind projects (TB Flats, Ekola Flats, and Cedar Springs) constructed as part of PacifiCorp's
Energy Vision 2020 initiative, for example, were required to obtain permits from the State of
Wyoming's Industrial Siting Division, which required extensive studies of the conditions of the
site, coordination with state agencies in the development process, and forecast of impacts from the
project. Renewable energy projects in the State of Wyoming that meet the Industrial Siting
Division's size or capital thresholds must obtain approval before they can begin construction.Most
wind project developers coordinate with federal and/or state authorities to evaluate and mitigate
potential impacts to birds or other wildlife species, particularly eagles, migratory birds, and bats,
during the wind turbine siting process to minimize wildlife impacts and potential operational risks.
Greater sage-grouse are currently managed by the states, and renewable energy projects and
associated transmission lines require state agency review; stipulations or mitigation requirements
vary by state and project impacts.Because the generation capabilities of renewable energy projects
are site specific and can vary greatly between different sites, understanding the specific permit
requirements for each site is critical to developing a successful project.
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Tax Extender Legislation
The 2021 IRP included a description of the Taxpayer Certainty and Disaster Relief Act of 2020.
Among other things, the bill extended and expanded certain alternative energy tax credits.
Extensions to this legislation have been subordinated by the Inflation Reduction Act, described
above.
Late 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, andthe
second auction in February 2013. PacifiCorp is required to sell, through the auction process, its
directly allocated allowances and purchase the required 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 percent below 1990 levels by
2030. CARB has subsequently been directed to update the AB 32 scoping plan to reflect the new
interim 2030 target and previously established 2050 target. CARB's 2022 Scoping Plan was
adopted laying out a path to achieve targets for carbon neutrality and reduce anthropogenic
greenhouse gas emissions by 85 percent below 1990 levels no later than 2045, as directed by
Assembly Bill 1279,passed in 2022.
CARB adopted the Advanced Clean Cars II Rule in August of 2022. The rulemaking establishes
that by 2035 all new passenger cars, trucks and SUVs sold in California will be zero emissions.
The Advanced Clean Cars II regulations take the state's already growing zero-emission vehicle
market and robust motor vehicle emission control rules and augments them to meet more
aggressive tailpipe emissions standards and ramp up to 100%zero-emission vehicles.
In 2002, California established a 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. In September 2018, Governor Jerry Brown
signed into law the 100 Percent Clean Energy Act of 2018, Senate Bill (SB) 100, which requires
utilities to procure 60 percent of their electricity from renewables by 2030 and enabled all the
state's agencies to work toward a longer-term planning target for 100 percent of California's
electricity to come from renewable and zero-carbon resources by December 31, 2045. Interim
targets for the carbon-free target were subsequently adopted by SB 1020 in 2022.
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Idaho
In 2007, Idaho released its State Energy Plan, focusing on developing of a broad range of power
generation options, improving energy efficiency, diversifying the state's energy portfolio, and
reducing dependency on fossil fuels. The plan outlined strategies for energy conservation, the
development of renewable energy sources,and improvements to transmission infrastructure within
the state, aiming to balance growth with environmental stewardship and promote both economic
development and sustainable energy practices.
In 2012, Idaho updated its 2007 plan to address new energy challenges and opportunities,
emphasizing five core objectives: 1) a secure and stable energy system for Idaho's citizens and
businesses, 2) maintaining Idaho's low-cost energy supply, 3) protecting public health and
conserving natural resources, 4) promoting economic growth, job creation, and rural economic
development, and 5) ensuring Idaho's energy policy can adapt to changing circumstances.
In October of 2020, Governor Brad Little issued Executive Order 2020-17, continuing the role of
the Office of Energy and Mineral Resources(OEMR)as the central coordinator for Idaho's energy
policy. The OEMR manages energy production, conservation, and policy alignment, ensuring the
state's energy resources remain stable and cost-effective.
Oregon
In 2007, the Oregon Legislature passed House Bill (HB) 3543 —Global Warming Actions, which
establishes greenhouse gas reduction goals for the state that: (1) end the growth of Oregon
greenhouse gas emissions by 2010; (2) reduce greenhouse gas levels to ten percent below 1990
levels by 2020; and (3) reduce greenhouse gas levels to at least 75 percent below 1990 levels by
2050. In 2009, the legislature passed SB 101, which requires the Public Utility Commission of
Oregon (OPUC) to submit a report to the legislature before November 1 of each even-numbered
year regarding the estimated rate impacts for Oregon's regulated electric and natural gas
companies of meeting the greenhouse gas reduction goals of ten percent below 1990 levels by
2020 and 15 percent below 2005 levels by 2020. The OPUC submitted its most recent report
November 1, 2014.
In 2007, Oregon enacted Senate Bill (SB) 838 establishing an RPS requirement in Oregon. Under
SB 838,utilities are required to deliver 25 percent of their electricity from renewable resources by
2025. On March 8,2016, Governor Kate Brown signed SB 1547-13,the Clean Electricity and Coal
Transition Plan, into law. SB 1547-B extends and expands the Oregon RPS requirement to 50
percent 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 percent by 2025, 35 percent by 2030, 45 percentby
2035, and 50 percent 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.
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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 2021, which directs utilities to reduce emissions levels below
2010-2012 baseline levels by 80% by 2030, 90% by 2035, and 100% by 2040. HB 2021 also
expanded the capacity standard for Small Scale Renewables from 8%to 10%. PacifiCorp filed its
first Clean Energy Plan (CEP) on May 31, 2023, which included possible pathways towards
compliance with HB 2021 emissions reduction goals, inclusive of the Small-Scale Renewable
(SSR) targets and with emphasis on community-based actions. As also directed by HB 2021,
PacifiCorp convened a Community Benefits and Impacts Advisory Group in the fall of 2022. A
Oregon Tribal Nations Clean Energy-specific engagement series was started in March of 2023
after six months of direct outreach. The engagement series was formatted by informed feedback
from outreach to Oregon Tribal Nations members with whom PacifiCorp had an existing
relationship and through new Tribal Nations relationship building
In December 2022, Oregon Department of Environmental Quality adopted the Advanced Clean
Cars II Rulemaking on Low and Zero Emission Vehicles which requires 100% of new light-duty
vehicles (LDVs)be zero-emission vehicles (ZEVs)or PHEVs by 2035,ramping up from an initial
requirement that 35% of new LDVs be ZEVs in 2026 this follows the CARB rulemaking. In Jan
of 2022, HB 2165 passed requiring that all electricity companies (with>25,000 retail customers)
recover the cost of prudent infrastructure investments in transportation electrification.
Furthermore, in November 2021, Oregon adopted California's emission standards for HMDV via
the Advanced Clean Truck Rules 2021, paving the way for Oregon to adopt a target of 100% of
new MHDV sales being ZEVs by 2050.
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
renewable resources on electric utilities. Under I-937, utilities must supply 15 percent 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 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 percent below 1990 levels by 2035;
and (3) by 2050, reduce emissions to 50 percent below 1990 levels or 70 percent 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.
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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 percent of its electricity
from renewable and non-emitting resources by 2045. PacifiCorp submitted its inaugural Clean
Energy Implementation Plan on December 30, 2023, establishing a trajectory towards CETA
compliance both for the current CEIP period, 2022—2025, and across the next two decades.
In 2021, Washington passed the Climate Commitment Act, which establishes a cap-and-invest
program that was implemented through the regulatory rulemaking process and came into effect
January 1, 2023. The Climate Commitment Act does not modify any of PacifiCorp's obligations
under CETA, and utilities that are subject to CETA are allocated allowances within the cap-and-
trade program at no cost, for emissions associated with Washington retail load. The legislation
allows — but does not require — linkage with cap-and-trade programs in jurisdictions outside of
Washington State.
In December 2022, Department of Ecology adopted the Advanced Clean Cars II Rulemaking on
Low and Zero Emission Vehicles which requires 100%of new light-duty vehicles(LDVs)be zero-
emission vehicles (ZEVs) or PHEVs by 2035, ramping up from an initial requirement that 35%of
new LDVs be ZEVs in 2026 this follows the CARB rulemaking. Furthermore, in December 2021,
Washington adopted California's emission standards for HMDV via the Advanced Clean Truck
Rules 2021. In 2022, Department of Ecology passed the Clean Fuel Standard law requires fuel
suppliers to gradually reduce the carbon intensity of transportation fuels to 20%below 2017 levels
by 2034. There are several ways for fuel suppliers to achieve these reductions, including:
• Improving the efficiency of their fuel production processes
• Producing and/or blending low-carbon biofuels into the fuel they sell
• Purchasing credits generated by low-carbon fuel providers, including electric vehicle
charging providers
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 percent
of their 2025 adjusted retail electric sales.
In April 2019,the Utah Legislature passed HB 411, Community Renewable Program,that allowed
cities and municipalities in Utah to elect to participate on behalf of their residents. The Community
Renewable Program is an opt-out program with the goal of being 100% net renewable by 2030.
Customers within a participating community may opt out of the program and maintain existing
9 Significant Utah legislative activity gathered interest in the 2025 IRP public input meeting series and stakeholder
feedback.Regarding Utah SB-224,see Appendix M, stakeholder feedback form#13 (Emma Verhamme).
Portfolio planning is currently not directly impacted by Utah SB-224,however variant and sensitivity studies may
reflect this potential,such as the Low Cost Renewables case and the No Coal 2032 case.Additional discussion of
Utah activity is addressed in Appendix M,stakeholder feedback form#37(Utah Citizens Advocating Renewable
Energy).
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rates. The legislation prohibits cost shifting to non-participating customers. By the end of 2019,
23 Utah communities passed a resolution as required by the legislation to participate in the
program. Program design efforts are underway and ongoing.
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 the Electric Vehicle Infrastructure Program on December 20, 2021 for implementation
on January 1, 2022. The program construct will undergo regulatory review every three years
through 2032.
In March of 2024, the Utah Legislature passed SB 224, Energy Independence Amendments, that
modifies the factors the Public Service Commission must consider when evaluating certain
proposed energy resource decisions, establishes parameters for an affected electrical utility's
recovery of costs associated with proven dispatchable generation resources located within the state,
and encourages the commission to evaluate the purchase of excess proven dispatchable generation
capacity.
In March of 2024, the Utah Legislature passed HB 191, Electrical Energy Amendments, that
requires the Public Service Commission to act in accordance with the state energy policy and make
certain determinations before authorizing the early retirement of an electrical generation facility.
Wyoming
On March 8, 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 percent cost recovery in rates for the cost of the power purchase agreement and the
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agreement is 100 percent 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 required the Wyoming Public Service
Commission to put in place astandard for each public utility specifying a percentage of electricity
to be generated from coal-fired generation utilizing carbon capture technology by 2030. The
requirement applies to generation allocated to Wyoming customers. HB 200 requires 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 Wyoming Public
Service Commission implemented new administrative rules Low-Carbon Energy Portfolio
Standards that went into effect in January 2022 requiring public utilities to file an initial plan to
establish intermediate standards and requirements no later than March 31,2022. A final plan must
be filed by March 31, 2023 and include a low-carbon energy portfolio standard of no less than 20
percent unless it is not economically or technically feasible. During the 2024 legislative session
the Reliable and Dispatchable Low-Carbon Energy Standard statute was amended through SF 42,
which extended the deadline for compliance with the Low-Carbon Energy Standards from July 1,
2030 to July 1, 2033.
In 2024, the Wyoming legislature passed SF 0023 Public Utilities-Energy Resource Procurement
(SF 23) and SF 0024 Public Service Commission-Integrated Resource Plans (SF 24). SF 23
requires public utilities to conduct a solicitation process that is approved by the Wyoming Public
Service Commission in order to acquire or construct a significant energy resource after July 1,
2024. A significant energy resource consists of 100 megawatts or more of new utility-owned
generating capacity or utility-contracted generating capacity that has a dependable life or contract
term of 10 or more years. SF 24 requires the Wyoming Public Service Commission to engage in
long-range planning regarding public utility regulatory policy to facilitate the well-planned
development and conservation of utility resources and requires the Commission to adopt rules
providing a process for the review and acknowledgement of an action plan within an 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 statethat 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 lb CO2/MWh,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 lb CO2/MWh.
The Washington Department of Commerce issued a proposal to lower the emission performance
standard to 863 lb CO2/MWh in October 2024. However, Chehalis was purchased by PacifiCorp
in 2008.The change in ownership is the act that triggered the applicability of the standard. Because
the EPS was 1,100 lb GHG/MWh during the time of triggered applicability, that is the standard
that Chehalis complies with. It isn't until Chehalis undergoes a change in ownership, upgrade, or
new or renewed long-term financial commitment with anyone other than Bonneville Power
Administration that applicability to the lowered standard would be triggered.
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Renewable Portfolio Standards
An RPS requires a retail seller of electricity to include in its resource portfolio a certain amount of
electricity from renewable energy resources, such as wind, geothermal and solar energy. The
retailer can satisfy this obligation by using renewable energy from its own facilities, purchasing
renewable energy from another supplier's facilities, using Renewable Energy Credits (RECs)that
certify renewable energy has been generated, or a combination of all of these.
RPS policies are currently implemented at the state level and vary considerably in their renewable
targets (percentages), target dates, resource/technology eligibility, applicability of existing plants
and contracts, arrangements for enforcement and penalties, and use of RECs.
In PacifiCorp's service territory, California, Oregon, and Washington have each adopted a
mandatory RPS, and Utah has adopted a RPS goal. Each of these states' legislation and
requirements are summarized in Table 3.3, with additional discussion below.
Table 3.3 —State RPS Requirements
California Oregon Washington Utah
Legislation • Senate Bill 1078(2002) • Senate Bill 838 Oregon • Initiative Measure No. • Senate Bill 202(2008)
• Assembly Bill 200(2005) Renewable Energy Act 937(2006)
• Senate Bill 107(2006) (2007) • SB 5400(2013)
• Senate Bill 2 First Extraordinary • House Bill 3039(2009)
Session(2011) • House Bill 1547-B(2016)
• Senate Bill 350(2015)
• Senate Bill 100(2018)
Requirement • 20%by December 31,2013 • 5%by December 31,2011 • 3%by January 1,2012 • Goal of 20%by 2025
or Goal • 25%by December 31,2016 • 15%by December 31,2015 • 9%by January 1,2016 (must be cost
• 33%by December 31,2020 • 20%by December 31,2020 • 15%by January 1, effective)
• 44%by December 31,2024 • 27%by December 31,2025 2020 and beyond • Annual targets are
• 52%by December 31,2027 • 35%by December 31,2030 *Annual targets are based on the
• 60%by December 31,2030 • 45%by December 31,2035 based on the average of adjusted10 retail sales
and beyond • 50%by December 31,2040 the utility's load for the for the calendar year
• Planning target of 100% *Based on the retail load for previous two years 36 months before the
renewable and zero-carbon that year target year
by 2045
La *Based on the retail load for a
three-year compliance period
California
California originally established its RPS program with passage of SB 1078 in 2002. Several bills
have since been passed into law to amend the program. In the 2011 First Extraordinary Special
Session, the California Legislature passed SB 2 (1X) to increase California's RPS to 33 percent
by 2020.II SB 2 (1X) also expanded the RPS requirements to all retail sellers of electricity and
publicly owned utilities.In October 2015, SB 350, the Clean Energy and Pollution Reduction Act,
10 Adjustments for generated or purchased from qualifying zero carbon emissions and carbon capture storage and
DSM.
" www.leginfo.ca.gov/pub/1 1-12/bill/sen/sb 0001-0050/sbxl 2 bill 20110412 chaptered.pdf
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
was signed into law.12 SB 350 established a greenhouse gas reduction target of 40 percent below
1990 levels by 2030 and 80 percent below 1990 levels by 2050 and expanded the state's
renewables portfolio standard to 50 percent by 2030. In September 2018, the signing of SB 100,
the Clean Energy Act of 2018, further expanded and accelerated the California RPS to 60 percent
by 2030 and directed the state's agencies to plan for a longer-term goal of 100 percent of total
retail sales of electricity in California to come from eligible renewable and zero-carbon resources
by December 31, 2045.
SB 2 (1X) created multi-year RPS compliance periods, which were expanded by SB 100. The
California Public Utilities Commission approved compliance periods and corresponding RPS
procurement requirements, which are shown in Table 3.4 below.
Table 3.4—California Compliance Period Requirements
Compliance Period Procurement Quantity Requirement Calculation
(20% *2011 Retail Sales)+(20% * 2012 Retail Sales)
Compliance Period 1 (2011-2013) +(20%*2013 Retail Sales)
(21.7%*2014 Retail Sales)+(23.3%*2015 Retail Sales)
Compliance Period 2(2014-2016) +(25%*2016 Retail Sales)
(27% *2017 Retail Sales)+(29%*2018 Retail Sales)
Compliance Period 3 (2017-2020) +(31%*2019 Retail Sales)+(33%*2020 Retail Sales)
Compliance Period 4(2021-2024) (35.75%0** /0 021 Retail Sales)+(38.5%*2022 Retail Sales)
+(41.25/0 2023 Retail Sales)+(44 2024 Retail Sales)
Compliance Period 5 (2025-2027) *(46.677%*2025 Retail Sales)+(49.33%*2026 Retail Sales)
/0
+(52 2027 Retail Sales)
Compliance Period 6(2028-2030) *(54.677% *2028 Retail Sales)+(57.33%*2029 Retail Sales)
/0
+(60 2030 Retail Sales)
SB 2 (1X) established new"portfolio content categories" for RPS procurement, which delineated
the type of renewable product that may be used for compliance and also set minimum and
maximum limits on certain procurement content categories that can be used for compliance.
Portfolio Content Category 1 includes eligible renewable energy and RECs that meet either of the
following criteria:
Have a first point of interconnection with a California balancing authority,have a first
point of interconnection with distribution facilities used to serve end users within a
California balancing authority area, or are scheduled from the eligible renewable
energy resource into a California balancing authority without substituting electricity
from another source;or
Have an agreement to dynamically transfer electricity to a California balancing
authority.
Portfolio Content Category 2 includes firmed and shaped eligible renewable energy resource
electricity products providing incremental electricity and scheduled into a California balancing
authority.
12leginfo.legislature.ca.gov/faces/bilINavClient.xhtml?bill id=201520160SB350
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Portfolio Content Category 3 includes eligible renewable energy resource electricity products, or
any fraction of the electricity, including unbundled renewable energy credits that do not qualify
under the criteria of Portfolio Content Category 1 or Portfolio Content Category 2.13
Additionally, the CPUC established the balanced portfolio requirements for contracts executed
after June 1, 2010. The balanced portfolio requirements set minimum and maximum levels for the
Procurement Content Category products that may be used in each compliance period as shown in
Table 3.5.
Table 3.5—California Balanced Portfolio Requirements
California RPS Compliance Period E Balanced Portfolio Requirement
Compliance Period 1 (2011-2013) Category 1 —Minimum of 50%of Requirement
Category 3 —Maximum of 25%of Requirement
Compliance Period 2 (2014-2016) Category 1 —Minimum of 65%of Requirement
Category 3 —Maximum of 15%of Requirement
Compliance Period 3 (2017-2020)
Compliance Period 4(2021-2024) Category 1 —Minimum of 75%of Requirement
Compliance Period 5(2025-2027) Category 3 —Maximum of 10%of Requirement
Compliance Period 6(2028-2030)
In December 2011, the CPUC confirmed that multi jurisdictional utilities, such as PacifiCorp, are
not subject to the percentage limits in the three portfolio content categories. PacifiCorp is required
to file annual compliance reports with the CPUC and annual procurement reports with the
California Energy Commission (CEC). Neither SB 350 nor SB 100 changed the portfolio content
categories for eligible renewable energy resources or the portfolio balancing requirements
exemption provided to PacifiCorp. For utilities subject to the portfolio balancing requirements,the
CPUC extended the compliance period 3 requirements through 2030.
The full California RPS statute is listed under Public Utilities Code Section 399.11-399.32.
Additional information on the California RPS can be found on the CPUC and CEC websites.
Qualifying renewable resources include solar thermal electric, photovoltaic, landfill gas, wind,
biomass, geothermal, municipal solid waste, energy storage, anaerobic digestion, small
hydroelectric, tidal energy, wave energy, ocean thermal,biodiesel, and fuel cells using renewable
fuels. Renewable resources must be certified as eligible for the California RPS by the CEC and
tracked in the Western Renewable Energy Generation Information System (WREGIS).
Oregon
In June of 2007, Oregon established a comprehensive renewable energy policy, including RPS,
with the passage of SB 838, the Oregon Renewable Energy Act. 14 Subject to certain exemptions
and cost limitations established in the Oregon Renewable Energy Act, PacifiCorp and other
qualifying electric utilities must meet a target of at least 25 percent renewable energy by 2025. In
March 2016,the Legislature passed SB 1547,15 also referred to as Oregon's Clean Electricity and
13 A REC can be sold either"bundled"with the underlying energy or"unbundled"as a separate commodity from the
energy itself into a separate REC trading market.
14 www.leg.state.or.us/07reg/measpdf/sbO800.dir/sbO838.en.pdf
15 olis.leg.state.or.us/liz/2016R1/Downloads/MeasureDocument/SB1547/Enrolled
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Coal Transition Act. In addition to requiring Oregon to transition off coal by 2030, the new law
doubled Oregon's RPS requirements, which are set at 27 percent by 2025, 35 percent by 2030, 45
percent by 2035, and 50 percent by 2040 and beyond. Other components of SB 1547 include:
- Development of a community solar program with at least 10 percent of the program
capacity reserved for low-income customers.
- A requirement that by 2025, at least eight percent of the aggregate electric capacity of
the state's investor-owned utilities must come from small-scale renewable projects
under 20 megawatts.
- Creates new eligibility for pre-1995 biomass plants and associated thermal co-
generation. Under the previous law,pre-1995 biomass was not eligible until 2026.
- Direction to the state's investor-owned utilities to propose plans encouraging greater
reliance on electricity in all modes of transportation, to reduce carbon emissions.
- Removal of the Oregon Solar Initiative mandate.I6
SB 1547 also modified the Oregon REC banking rules as follows:
- RECs generated before March 8, 2016, have an unlimited life.
- RECs generated during the first five years for long-term projects coming online
between March 8, 2016, and December 31, 2022, have an unlimited life.
- RECs generated on or after March 8, 2016, from resources that came online
before March 8, 2016, expire five years beyond the year the REC was
generated.
- RECs generated beyond the first five years for long-term projects coming online
between March 8, 2016, and December 31, 2022, expire five years beyond the year
the REC is generated.
- RECs generated from projects coming online after December 31, 2022, expire five
years beyond the year the REC is generated.
- Banked RECs can be surrendered in any compliance year regardless ofvintage(eliminates
the "first-in, first-out"provision under SB 838).
To qualify as eligible, the RECs must be from a resource certified as Oregon RPS eligible by the
Oregon Department of Energy and tracked in WREGIS.
Qualifying renewable energy sources can be located anywhere in the United States portion of the
Western Electricity Coordinating Council geographic area, and a limited amount of unbundled
renewable energy credits can be used toward the annual compliance obligation. Eligible renewable
resources include electricity generated from wind, solar photovoltaic, solar thermal, wave, tidal,
ocean thermal, geothermal, certain types of biomass and biogas, municipal solid waste, and
hydrogen power stations using anhydrous ammonia.
Electricity generated by a hydroelectric facility is eligible if the facility is not located in any
federally protected areas designated by the Pacific Northwest Electric Power and Conservation
Planning Council as of July 23, 1999, or any area protected under the federal Wild and Scenic
Rivers Act,P.L. 90-542, or the Oregon Scenic Waterways Act, ORS 390.805 to 390.925; or if the
16 In 2009,Oregon passed House Bill 3039,also called the Oregon Solar Initiative,requiring that on or before
January 1,2020,the total solar photovoltaic generating nameplate capacity must be at least 20 megawatts from all
electric companies in the state. The Public Utility Commission of Oregon determined that PacifiCorp's share of the
Oregon Solar Initiative was 8.7 megawatts.
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
electricity is attributable to efficiency upgrades made to the facility on or after January 1, 1995,
and up to 50 average megawatts of electricity per year generated by a certified low-impact
hydroelectric facility owned by an electric utility and up to 40 average megawatts of electricity per
year generated by certified low-impact hydroelectric facilities not owned by electric utilities.
PacifiCorp files an annual RPS compliance report by June 1 of every year. In addition, ORS
469A.075 now aligns the filing of the Renewable Portfolio Implementation Plan (or RPIP) with
the filing of the IRP. These compliance reports and implementation plans are available on
PacifiCorp's website.17
The full Oregon RPS statute is listed in Oregon Revised Statutes (ORS) Chapter 469A and the
solar capacity standard is listed in ORS Chapter 757. The Public Utility Commission of Oregon
rules are in Oregon Administrative Rules (OAR) Chapter 860 Division 083 for the RPS and OAR
Chapter 860 Division 084 for the solar photovoltaic program. The Oregon Department of Energy
rules are under OAR Chapter 330 Division 160.
Utah
In March 2008, Utah's governor signed Utah SB 202, the Energy Resource and Carbon Emission
Reduction Initiative, later codified in Utah Code Title 54 Chapter 17.18 This law provides that,
beginning in the year 2025, 20 percent of adjusted retail electric sales of all Utah utilities be
supplied by renewable energy if it is cost effective. Retail electric sales will be adjusted by
deducting the amount of generation from sources that produce zero or reduced carbon emissions
and for sales avoided because of energy efficiency and demand side management programs.
Qualifying renewable energy sources can be located anywhere in the Western Electricity
Coordinating Council areas, and unbundled renewable energy credits can be used for up to 20
percent of the annual qualifying electricity target.
Eligible renewable resources include electricity from a facility or upgrade that becomes
operational on or after January 1, 1995,that derives its energy from wind, solar photovoltaic, solar
thermal electric, wave, tidal or ocean thermal, certain types of biomass and biomass products,
landfill gas or municipal solid waste, geothermal, waste gas and waste heat capture or recovery,
and efficiency upgrades to hydroelectric facilities if the upgrade occurred after January 1, 1995.
Up to 50 average megawatts from a certified low-impact hydro facility and in-state geothermal
and hydro generation without regard to operational online date may also be used toward the target.
To assist solar development in Utah, solar facilities located in Utah receive credit for 2.4 kilowatt-
hours of qualifying electricity for each kWh of generation.
Under the Carbon Reduction Initiative,PacifiCorp is required to file a progress report by January 1
of each of the years 2010, 2015, 2020 and 2024.
PacifiCorp filed its most recent progress report on December 29, 2023. This report showed that
the company is positioned to meet its 20 percent target requirement of approximately 5.0 million
megawatt-hours of renewable energy in 2025 from existing company-owned and contracted
renewable energy sources.
17 www.pacificpower.net/ORrps
"le.utah.gov/-2008/bills/sbillenr/sbO2O2.pdf
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
In 2027, the legislation requires a commission report to the Utah Legislature, which may contain
any recommendation for penalties or other action for failure to meet the 2025 target. The legislation
requires that any recommendation for a penalty must provide that the penalty funds be used for
demand side management programs for the customers of the utility paying the penalty.
Washington
In November 2006, Washington voters approved I-937, a ballot measure establishing the Energy
Independence Act, which is an RPS and energy efficiency requirement applied to qualifying
electric utilities, including PacifiCorp.19 The law requires that qualifying utilities procure at least
three percent of retail sales from eligible renewable resources or RECs by January 1,2012 through
2015; nine percent of retail sales by January 1, 2016 through 2019; and 15 percent of retail sales
by January 1, 2020, and every year thereafter.
Eligible renewable resources include electricity produced from water, wind, solar energy,
geothermal energy, landfill gas,wave, ocean, or tidal power, gas from sewage treatment facilities,
biodiesel fuel with limitation, and biomass energy based on organic byproducts of the pulp and
wood manufacturing process, animal waste, solid organic fuels from wood, forest, or field
residues, or dedicated energy crops. Qualifying renewable energy sources must be located in the
Pacific Northwest or delivered into Washington on a real-time basis without shaping, storage, or
integration services. The only hydroelectric resource eligible for compliance is electricity
associated with efficiency upgrades to hydroelectric facilities.Utilities may use eligible renewable
resources, RECs, or a combination of to meet the RPS requirement.
PacifiCorp is required to file an annual RPS compliance report by June 1 of every year with the
Washington Utilities and Transportation Commission (WUTC) demonstrating compliance with
the Energy Independence Act. PacifiCorp's compliance reports are available on PacifiCorp's
website.20
The WUTC adopted final rules to implement the initiative;the rules are listed in the Revised Code
of Washington (RCW) 19.285 and the Washington Administrative Code (WAC)480-109.
REC Management Practices
PacifiCorp provides the following summary of REC management practices in compliance with
Order 20-186 in Oregon.The company intends to maximize the value of RECs for customers either
through retirement for compliance purposes or monetization through sales. As a multi-state utility,
PacifiCorp has Renewable Portfolio Standards in Washington, Oregon, and California, and a
Renewable Portfolio Goal in 2025 in Utah. PacifiCorp generally retains and retires RECs allocated
to Washington,Oregon,and California for compliance purposes,but requests flexibility to manage
its RECs based on opportunities it sees in the market, which may include selling RECs at a
favorable price and acquiring RECs at a lower price. The company maximizes the sale of RECs
allocated to Utah, Idaho, and Wyoming and allocates the revenue from those sales to those states.
One exception to REC sales is a special contract for one industrial customer where the customer
foregoes REC sales revenue in exchange for a REC retirement to maintain renewable claims for
19 www.secstate.wa.gov/elections/initiatives/text/1937.pdf
20 www.pacificpower.net/report
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
corporate sustainability goals. An expansion of this program is currently under development to be
offered under a new tariff in Utah, Idaho and Wyoming.
Clean Energy Standards
Washington
In 2019, Governor Jay Inslee signed into law Senate Bill 5116, the Clean Energy Transformation
Act. Under the law, Washington utilities are required to be carbon neutral by January 1, 2030,and
institute a planning target of 100 percent clean electricity by 2045. The bill establishes four-year
compliance periods beginning January 1, 2030, and requires utilities to use electricity from
renewable resources and non-emitting electric generation in an amount equal to 100 percent of the
retail electric load over each compliance period. Through December 31, 2044, an electric utility
may satisfy up to 20 percent of its compliance obligation with an alternative compliance option
such as the purchase of unbundled RECs.
Oregon
As noted under State Policy Updates, above, in July 2021, Oregon Governor Kate Brown signed
into law House Bill 2021, which set emissions reduction targets for utilities and electricity
providers. Under the law, retail electricity providers shall reduce greenhouse gas emissions by 80
percent below baseline emissions levels by 2030,by 90 percent below baseline emissions level by
2035, and by 100 percent below baseline emissions levels by 2040.
California
In 2018, California passed Senate Bill 100—known as the "100 percent Clean Energy Act of
2018,"which sets a 2045 goal of powering all retail electricity sold in California with renewable
and zero-carbon resources. The law also updates the state's Renewables Portfolio Standard to
ensure that by 2030 at least 60 percent of California's electricity is renewable.
In 2022, California passed Senate Bill 1020, the Clean Energy, Jobs, and Affordability Act of
2022. This bill established interim targets to the previously-established SB 100. It requires that
eligible renewable energy resources and zero-carbon resources supply:
• 90% of all retail sales of electricity to California end-use customers by December 31, 2035
• 95% of all retail sales of electricity to California end-use customers by December 31, 2040
• 100% of all retail sales of electricity to California end-use customers by December 31, 2045
• 100% of electricity procured to serve all state agencies by December 31, 2030
In 2022, California passed Senate Bill 1158. This bill requires the State Energy Resources
Conservation and Development Commission to adopt guidelines for the reporting and disclosure
of electricity sources by the hour. The bill includes hourly power source reporting as a new set of
reporting requirements at the Energy Commission and allows for the commission to modify
those requirements for small entities with under 60,000 customers in California, like Pacific
Power. The Energy Commission issued proposed rules October 1, 2024, that would exempt the
company from the hourly reporting requirement. The Energy Commission will likely adopt a
final rule in early 2025.
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Wyoming
In July 2020,House Bill 200 (HB 200),Reliable and Dispatchable Low-Carbon Energy Standards
went into effect requiring 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 Wyoming Public Service Commission
implemented rules for Low-Carbon Energy Portfolio Standards that went into effect in January
2022 requiring public utilities to file an initial plan to establish intermediate standards and
requirements no later than March 31, 2022. A final plan must be filed by March 31, 2023 and
include a final low-carbon energy portfolio standard of no less than 20 percent unless it is not
economically or technically feasible. The Company requested an extension and filed the final plan
on March 29,2024 that included a proposal to: conduct additional technical and economic analyses
for an Allam Fetvedt Cycle Project at either the Dave Johnston or Wyodak facilities by conducting
a pre-FEED study in conjunction with SK and 8 Rivers;conduct additional technical and economic
analyses by conducting a front-end engineering and design (FEED) study at the Jim Bridger
facility; and no determination of a low-carbon portfolio standard at this time since CCUS continues
to be evaluated for its technical and economic feasibility. The Commission approved the
Company's final plan in public deliberations held on September 19, 2024. The statute also allows
electric utilities to implement a surcharge not to exceed 2% of customer bills to recover costs to
comply with the standard.
Transportation Electrification
The electric transportation market continues to strengthen since 2022. Overall, light duty battery
electric vehicle sales have grown since 2022 resulting in a market share of about 9% in the United
States21. PacifiCorp states, especially west coast states continue to outpace the US market share
percentage, California is number one, with Oregon and Washington close behind 22. By 2030 EVs
(LDV) are expected to reach 7.7 million or 46%of sales 21. EV sales still comprise a small portion
of overall sales,however this will shift as medium-duty/heavy-duty(MD/HD)customers continue
to expand. PacifiCorp also hosts major interstates and traffic corridors that will see continued
electrification through policies discussed above. Furthermore, many businesses are moving to
electrify their fleets from port authorities,transit agencies, etc.which will increase load over time.
This rapidly evolving market represents a potential driver of future load growth and those impacts
managed proactively,provide an opportunity to increase the efficiency of the electrical system and
provide benefits for all PacifiCorp customers. In addition, increased adoption of electric
transportation has the ability to improve air quality, reduce noise pollution,reduce greenhouse gas
emissions,improve public health and safety,and create financial benefits for drivers,which can be
a particular benefit for low- and moderate-income populations.
Current EV adoption numbers indicate that there is still an enormous opportunity for growth in the
EV market. To develop a prospective forecast of EV adoption, PacifiCorp developed a model to
assess trends for light duty vehicles (LDVs) and medium-duty and heavy-duty vehicles
(MD/HDVs). To inform a future vehicle adoption curve,the Company reviewed three national EV
21 October 2024 auto sales volume to hold steady in the US I S&P Global
22 Electric vehicle market and policy developments in U.S. states,2023 -International Council on Clean
Transportation
21 Electric Vehicle Sales and the Charging-Infrastructure-Required Through 2035
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
forecasts, each representing varying degrees of aggressiveness. While these forecasts represent
national trends, the adoption curves themselves are quite different and can be adjusted to reflect
state-specific parameters such as current market conditions, light duty truck saturation, and EV
policies adopted in the state. PacifiCorp monitors vehicle adoption in each state on an annual basis
and adjusts forecasts accordingly as new data is made available.
To help manage and understand the potential future load growth impacts of electric transportation
PacifiCorp is investing to support EV fast chargers along key corridors, develop commercial and
residential charging programs,research new rate designs and implement time-of-use pricing programs
and managed charging pilots, create partnerships for smart mobility programs and develop
opportunities for customers in our rural communities.
In California, Pacific Power's Electric Vehicle Infrastructure Rule 24 will pay for and coordinate
the design and deployment of service extensions from our electrical distribution line facilities to
the service delivery point for separately metered electric vehicle charging stations.24 Pacific Power
continues to provide programs funded by the Oregon Clean Fuels program as well as the recent
HB 2165 legislation passed that created a transportation electrification benefits charge to support
infrastructure development in the state of Oregon. As of November 2022, the Washington Utility
and Transportation Commission approved Pacific Power's Transportation Electrification Plan
which sets out an estimated spend of $3.5 million over the next five years to support TE in
Washington state.
In Utah, PacifiCorp is implementing the $50 million Electric Vehicle Infrastructure Program that
has four core components: Company-owned public fast chargers, customer incentives, innovative
projects, and outreach and education efforts. In June 2024,the first four locations with Company-
owned public direct current fast chargers (DCFC) became operational. It is anticipated that there
will be roughly 20 locations with an estimated 100 DCFC stations throughout Utah by the end of
the program. As of the end of 2023, PacifiCorp had supported installation of over 4,800 EV ports
throughout the territory.
Electric vehicle load is reflected in the Company's load forecast. PacifiCorp continues to actively
engage with local,regional, and national stakeholders and participate in state regulatory processes
that can inform future planning and load forecasting efforts for electric vehicles.
Hydroelectric Relice
The issues involved in relicensing hydroelectric facilities are multifaceted.They involve numerous
federal and state environmental laws and regulations, and the participation of numerous
stakeholders including agencies, Native American tribes, non-governmental organizations, and
local communities and governments.
The value of relicensing hydroelectric facilities is continued availability of energy, capacity, and
ancillary services associated with hydroelectric generation. Hydroelectric projects can often
provide unique operational flexibility because they can be called upon to meet peak customer
demands almost instantaneously and back up intermittent renewable resources such as wind and
solar with carbon-free generation. In addition to operational flexibility, hydroelectric generation
"Califomia Electric Vehicle Infrastructure Line Extensions(uacificuowennetl
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
does not have the emissions concerns of thermal generation. Hydroelectric projects can also often
provide important ancillary services, such as spinning reserve and voltage support,to enhance the
reliability of the transmission system.
As of December 31, 2024, PacifiCorp has 15 FERC licensed hydroelectric projects. Each license
may contain a single or multiple hydro developments (e.g., dams and powerhouses). PacifiCorp is
currently seeking new licenses for the Cutler (30 MW) and Ashton (7.85 MW) hydroelectric
projects. A new license for Cutler is expected in 2025, and a new license for Ashton in 2027. The
next project to undergo the FERC relicensing process is the Bear River hydroelectric project (77
MW). That project's FERC license expires in 2033.
The FERC hydroelectric relicensing process can be extremely political and often controversial.
The process itself requires that the project's impacts on the surrounding environment and natural
resources, such as fish and wildlife, be scientifically evaluated, followed by development of
proposals and alternatives to mitigate those impacts. Tribal and interested party consultation is
conducted throughout the process. If resolution of issues cannot be reached in this process,
litigation often ensues, which can be costly and time-consuming. The usual alternative to
relicensing is decommissioning. Both choices, however, can involve significant costs.
FERC has sole jurisdiction under the Federal Power Act to issue new operating licenses for non-
federal hydroelectric projects on navigable waterways, federal lands, and under other criteria.
FERC must find that the project is in the broad public interest. This requires weighing,with"equal
consideration," the impacts of the project on fish and wildlife, cultural resources, recreation, land
use, and aesthetics against the project's energy production benefits. Because some of the
responsible state and federal agencies have the ability to place mandatory conditions in the license,
FERC is not always in a position to balance the energy and environmental equation. For example,
the National Oceanic and Atmospheric Administration Fisheries agency and the U.S. Fish and
Wildlife Service have the authority in the relicensing process to require installation of fish passage
facilities (fish ladders and screens) and to specify their design. This is often the largest single
capital investment that will be considered in relicensing and can significantly impact project
economics. Also, because a myriad of other state and federal laws come into play in relicensing,
most notably the Endangered Species Act and the Clean Water Act, agencies' interests may
compete or conflict with each other, leading to potentially contrary or additive licensing
requirements. PacifiCorp has generally taken a proactive approach towards achieving the best
possible relicensing outcome for its customers by engaging in negotiations with stakeholders to
resolve complex relicensing issues. In some cases, settlement agreements are achieved which are
submitted to FERC for incorporation into a new license. FERC welcomes license applications that
reflect broad involvement or that incorporate measures agreed upon through multi- party
settlement agreements. History demonstrates that with such support, FERC generally accepts
proposed new license terms and conditions reflected in settlement agreements.
Potential Impact
Relicensing hydroelectric facilities involves significant process costs. The FERC relicensing
process takes a minimum of five years and may take longer, depending on the characteristics of
the project, the number of stakeholders, and issues that arise during the process. As of December
31, 2023, PacifiCorp had incurred approximately $33 million in costs for license implementation
and ongoing hydroelectric relicensing, which are included in construction work-in-progress on
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
PacifiCorp's Consolidated Balance Sheet. As current or upcoming relicensing and settlement
efforts continue for the Cutler, Ashton and other hydroelectric projects, additional process costs
are being or will be incurred that will need to be recovered from customers. Hydroelectric
relicensing costs have and will continue to have a significant impact on overall hydroelectric
generation cost. Such costs include capital investments and related operations and maintenance
costs associated with fish passage facilities,recreational facilities,wildlife protection,water quality,
cultural and flood management measures. Project operational and flow-related changes, such as
increased in-stream flow requirements to protect aquatic resources, can also directly result in lost
generation. Much of these relicensing implementation and settlement costs relate to PacifiCorp's
two largest hydroelectric projects: Lewis River and North Umpqua.
Treatment in the IRP
The known or expected operational impacts related to FERC orders and settlement commitments
are incorporated in the projection of existing hydroelectric resources discussed in Chapter 7.
PacifiCorp's Approach to Hydroelectric Relicensing
PacifiCorp continues to manage the hydroelectric relicensing process by pursuing interest-based
resolutions or negotiated settlements as part of relicensing. PacifiCorp believes this proactive
approach, which involves meeting Tribal, agency and others' interests through creative solutions,
is the best way to achieve environmental and social improvements while balancing customer costs
and risks. PacifiCorp also has reached agreements to decommission projects where that has been
the most cost-effective outcome for customers.
Rate Desi n
Current rate designs in Utah have evolved over time based on orders and direction from the Public
Service Commission of Utah and settlement agreements between parties during general rate cases.
Most recently, current rates and rate design changes were adopted in Docket No 20-035-04 The
goals for rate design are(generally)to reflect the cost to serve customers and to provide price signals to
encourage economically efficient usage. This is consistent with resource planning goals that balance
consideration of costs, risk, and long-run public policy goals. PacifiCorp currently has a number of rate
design elements that take into consideration these objectives, in particular,rate designs that reflect
cost differences for energy or demand during different time periods and that support the goals of
acquiring cost-effective energy efficiency.
Residential Rate Design
Residential rates in Utah are comprised of a customer charge and energy charges. The customer
charge is a monthly charge that provides limited recovery of customer-related costs incurred to
serve customers regardless of usage and is broken into separate charges for residential customers
who live in single family and multi-family dwellings All other remaining costs are recovered
through volumetric- based energy charges. Energy charges for residential customers are designed
with an inclining-tier rate structure so high usage during a billing month is charged a higher rate.
Additionally, energy charges are differentiated by season with higher rates in the summer when the
costs to serve are higher.Residential customers also have an option for time-of-day rates. Time-of-
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
day rates have a surcharge for usage during the on-peak periods and a credit for usage during the
off-peak periods. This rate structure provides an additional price signal to encourage customers to
use less energy during the daily on-peak periods when energy costs are higher. As of December
2023, , less than one percent of customers have opted to participate in the time-of-day rate option.
. As part of the STEP legislation enacted in SB 115, the company developed a pilot time-of-use
program to encourage off-peak charging of electric vehicles for residential customers. The results
of this pilot may inform future rate design offerings. Any changes in standard residential rate
design or institution of optional rate options to support energy efficiency or time-differentiated
usage should be balanced with the recovery of fixed costs to ensure price signals are economically
efficient and do not unduly shift costs to other customers.
Commercial and Industrial Rate Design
Commercial and industrial rates in Utah include customer charges, facilities charges, power
charges (for usage over 15 kW) and energy charges. As with residential rates, customer charges
and facilities charges are generally intended to recover costs that do not vary with energy usage.
Power charges are applied to a customer's monthly demand on a kW basis and are intended to
recover the costs associated with demand or capacity needs. Energy charges are applied to the
customer's metered usage on a kWh basis. All commercial and industrial rates employ seasonal
variations in power and/or energy charges with higher rates in the summer months to reflect the
higher costs to serve during the summer peak period. Additionally, for customers with load 1,000
kW or more, rates are further differentiated by on-peak and off-peak periods for both power and
energy charges. For commercial and industrial customers with load less than 1,000 kW, the
company offers an optional time-of-day rates—one that differentiates energy rates for on- and off-
peak usage,
Irrigation Rate Design
Irrigation rates in Utah are comprised of an annual customer charge, a monthly customer charge,
a seasonal power charge, and energy charges. The annual and monthly customer charges provide
some recovery of customer-related costs incurred to serve customers regardless of usage.All other
remaining costs are recovered through a seasonal power charge and energy charges. The power
charge is for the irrigation season only and is designed to recover demand-related costs and to
encourage irrigation customers to control and reduce power consumption. Energy charges for
irrigation customers are designed with two options. One is a time-of-day program with higher rates
for on-peak consumption than for off-peak consumption. Irrigation customers also have an option
to participate in a third-party operated Irrigation Load Control Program. Customers are offered a
financial incentive to participate in the program and give the company the right to interrupt service
to the participating customers when energy costs are higher.
Electricity Market Development Updat
PacifiCorp and the CAISO launched the Western Energy Imbalance Market (WEIM) on
November 1, 2014. The WEIM is a voluntary market and the first western energy market outside
of California. NV Energy (NVE) began participating in December 2015, Arizona Public Service
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
(APS) and Puget Sound Energy(PSE)began participating in October 2016, and Portland General
Electric(PGE)began participating in October 2017.Idaho Power and Powerex began participating
in April 2018, and the Balancing Authority of Northern California(BANC)i began participating in
April 2019. Seattle City Light (SCL) and Salt River Project (SRP) began participating in April
2020, and 2021 saw the addition of NorthWestern Energy, Los Angeles Department of Water &
Power(LADWP),Public Service Company of New Mexico(PNM),and Turlock Irrigation District
(TID). Avista Utilities, Tucson Electric Power (TEP), Tacoma Power and Bonneville Power
Administration(BPA) officially became a participant in the EIM in 2022. El Paso Electric (EPE),
Western Area Power Administration Desert Southwest (WAPA DSW) and Avangrid (AVR)
entered in April 2023. In 2026, Black Hills Montana and Berkshire Hathaway Energy Montana
(BHE Montana) have planned entry into the WEIM.
The WEIM footprint now includes portions of Arizona, California,Idaho,Nevada, Oregon,Texas,
New Mexico, Utah, Washington, Wyoming, and British Columbia which make up almost eighty
percent of the Western Energy Coordinating Council (WECC) load and will expand to include
Montana in 2026. PacifiCorp continues to work with the CAISO, existing and prospective WEIM
entities, and stakeholders to enhance market functionality and support market growth.
Figure 3.12—Western Energy Imbalance Market Expansion
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
The WEIM has produced approximately $5.8513 in monetary benefits since inception for
participating utilities,quantified in the following categories: (1)more efficient dispatch,both inter-
and intra-regional, by automating dispatch every fifteen and five minutes within and across the
WEIM footprint based on the most economical solution; (2)reduced renewable energy curtailment
by allowing balancing authority areas to export or reduce imports of renewable generation that
would otherwise need to be curtailed; and (3) reduced need for flexible reserves in all WEIM
balancing authority areas which reduces cost by aggregating load, wind, and solar variability and
forecast errors of the WEIM footprint.
A significant contributor to WEIM benefits is transfers across balancing authority areas,providing
access to lower-cost supply, while factoring in the cost of compliance with greenhouse gas
emissions regulations that exist in states with a price on carbon (i.e., California and Washington).
Generally, transfer quantities are based on transmission and interchange rights between
participating balancing authority areas.
After development and expansion of the WEIM in the west, a natural next question was—are there
continued opportunities to increase economic efficiency and renewable integration beyond the
scope of WEIM but short of a full regional transmission organization? PacifiCorp believes the
answer is `yes'.
Over the duration of 2022, the CAISO held a robust stakeholder process to develop the market
design of the Extended Day-Ahead Market(EDAM). With stakeholder feedback,the final EDAM
proposal was released in early December 2022. On December 8th, PacifiCorp announced that it
intends to join EDAM. The final EDAM design was approved by the CAISO Board of Governors
and WEIM Governing Body in early February 2023, and received FERC approval on December
28, 2023. EDAM is scheduled to go live on May 1, 2026, and to date, PacifiCorp and Portland
General Electric have signed their EDAM implementation agreements.
The Southwest Power Pool (SPP) has also been developing a day-ahead market offering, called
Markets+. Markets+ introduces a potential risk to WEIM benefits through a shrinking WEIM
footprint as stakeholders who want to participate in Markets+ would need to exit WEIM. In
addition to a smaller WEIM footprint, day-ahead markets with different design elements and
requirements for participation exacerbate the seams issue which already exist throughout the west.
SPP and stakeholders filed their tariff with FERC on March 29, 2024 and received a deficiency
letter on July 31, 2024 that SPP is currently working through to remedy FERC's clarification and
additional information request due at the end of November 2024. SPP does not believe the SPP
Markets+timeline will be impacted for their projected spring 2027 go-live target and stakeholders
must be vigilant to ensure the markets work as cohesively as possible.
Recent Resource Procurement Activities
PacifiCorp issued and will issue multiple requests for proposals (RFP) to secure resources or
transact on various energy and environmental attribute products.Table 3.6 summarizes recent RFP
activities.
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Table 3.6—PacifiCorp's Requests for Proposal Activity
RFPis RFP Objective ME Status Issued Completed
Renewable energy Excess system RECs Ongoing Based on specific Ongoing
credits(Purchase) need
Renewable energy Oregon compliance needs Ongoing Based on specific Ongoing
credits(Purchase) need
Renewable energy Washington compliance needs Ongoing Based on specific Ongoing
credits(Purchase) need
Renewable energy California compliance needs Ongoing Based on specific Ongoing
credits(Purchase) need
Short-term sMarket System balancing Ongoing Based on specific Ongoing
Seeking resources consistent to Expected
2024 Utah Renewables the Community Clean Energy Expected November
Community RFP Act(Utah Code 54-17-901 to- Ongoing 2024 October
9 2025
09
Seeking resources consistent Expected
2025 All-Source RFP with the 2025 IRP's least cost Ongoing Expected 2025 in Q4
resource portfolio 2025
2022 All-Source RFP
On April 1, 2024, PacifiCorp published the company's 2023 Integrated Resource Plan Update.
The 2023 IRP Update preferred portfolio demonstrated that with limited procurement of battery
resources in the near-term,which can be achieved outside of a request for proposals process,there
is material customer benefit to scaling down and delaying resource acquisition until after 2030. As
such, the 2022 All-Source Request for Proposals was terminated. PacifiCorp's 2025 IRP will
inform the next steps for incremental resource acquisition.
2024 Utah Renewables Community RFP
The 2024 Utah Renewable Communities' Request for Proposals for renewable energy resources
(2024 URC RFP), is administered by the Community Renewable Energy Agency (Agency) on
behalf of customers that participate in the Community Clean Energy Program (Program). The
2024 URC RFP is seeking cost-competitive bids for energy produced by wind, photovoltaic (PV)
solar, geothermal, or hydroelectric resources and interconnecting with PacifiCorp's transmission
system. The Agency is seeking to purchase energy from renewable resources pursuant to the
Community Clean Energy Act(Act(Utah Code 54-17-901 to-909))and in support of the Program
created by the Act and the Utah Public Service Commission(Commission). The 2024 URC RFP
is planned to be released in late November 2024.
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
2025 All-Source RFP
PacifiCorp will seek to file the 2025 All Source RFP ("2025AS RFP")based on results identified
in the 2025 IRP preferred portfolio. Further updates on the status and schedule of the 2025AS RFP
will be provided as they become available.
Recent Resource Procurement/DSM Procurement
In 2023,PacifiCorp issued a Request for Proposals to re-procure program delivery services for the
Home Energy Savings and Wattsmart Business energy efficiency programs in Washington and
California. As a result of the re-procurement, new contracts for Washington and California were
signed in 2024. For Washington specifically, PacifiCorp followed its Competitive Procurement
Framework,25 including seeking Washington DSM Advisory Group input and posting a notice on
the Company website prior to releasing the Request for Proposals. In 2024, PacifiCorp issued a
Request for Proposals to re-procure program delivery services for Wattsmart Business in Utah,
Idaho and Wyoming, and contracting is underway.
In 2024, PacifiCorp also issued an RFP for energy efficiency implementation services for a
commercial new construction program in its Utah service area. The procurement and subsequent
contracting steps are still underway.
25 2022-2023 Biennial Conservation Plan,Appendix 6(Docket UE-201830)
The current Competitive Procurement Framework for Washington Conservation and Efficiency Resources is
available in Appendix 6 to the 2024-2025 Biennial Conservation Plan(Docket UE-230904).
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
CHAPTER 4 - TRANSMISSION
CHAPTER HIGHLIGHTS
• PacifiCorp's planned transmission projects help facilitate a transitioning resource portfolio and
comply with reliability requirements, while providing sufficient flexibility necessary to ensure
existing and future resources can meet customer demand cost effectively and reliably.
• Given the long lead time needed to site, permit, and construct new transmission lines, these
projects need to be planned well in advance of resource additions.
• PacifiCorp's transmission planning and benefits evaluation efforts adhere to regulatory and
compliance requirements and respond to commission and stakeholder requests for a robust
evaluation process and clear criteria for evaluating transmission additions.
• The 2025 IRP preferred portfolio includes the following notable transmission upgrades:'
o A series of upgrades to increase transfer capability between southern Utah and the
Wasatch Front,projected to come online between 2026 and 2036.
o New transmission from the Walla Walla substation near Walla Walla, Washington
to the Wine Country substation near Sunnyside, Washington, projected to come
online in 2031.
0 120 miles of new transmission from the Fry substation near Albany, Oregon to a
new substation in Deschutes County, Oregon, projected to come online in 2032.
o New transmission including lines from the Fry substation near Albany, Oregon and
from the Dixonville substation near Roseburg, Oregon, each connecting to a
substation near Lebanon, Oregon,projected to come online in 2036.
o A second 416-mile transmission line from the Aeolus substation near Medicine
Bow,Wyoming,to the Clover substation near Mona,Utah(Energy Gateway South
2),projected to come online in 2036.
• Further, the 2025 IRP preferred portfolio includes near-term transmission upgrades across
PacifiCorp's transmission system including investment in infrastructure in Oregon, Utah, and
Washington that will facilitate continued and long-term growth in new resources needed to
serve PacifiCorp's customers.
Introduction
PacifiCorp's bulk transmission network is a high-value asset that is designed to reliably transport
electric energy from a broad array of generation resources (owned or contracted generation
including market purchases) to load centers. There are many benefits associated with a robust
transmission network, some of which are set forth below:
1 Two significant transmission projects have been placed in-service since the 2023 IRP,and are therefore included in
the 2025 IRP base modeling:
• The Energy Gateway South transmission line-a new 416-mile,high-voltage 500—kilovolt(kV)transmission
line and associated infrastructure running from the Aeolus substation near Medicine Bow,Wyoming,to the
Clover substation near Mona,Utah.This transmission line was placed in service in Q4-2024.
• The Energy Gateway West Subsegment D1 project-a new high-voltage 230-kilovolt transmission line and
a rebuild of an existing 230 kV transmission line from the Shirley Basin substation in southeastern
Wyoming to the Windstar substation near Glenrock,Wyoming.These lines were placed in service in Q4-
2024.
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
1. Reliable delivery of diverse energy supply to continuously changing customer demands
under a wide variety of system operating conditions.
2. Ability to always meet aggregate electrical demand and customers' energy requirements,
considering scheduled outages and the ability to maintain reliability during unscheduled
outages.
3. Ability to meet changing regulatory requirements as states move towards a carbon free
energy future.
4. Economic dispatch of resources within PacifiCorp's diverse system.
5. Economic transfer of electric power to and from other systems as facilitated by the
company's participation in the market, which reduces net power costs and provides
opportunities to maintain resource adequacy at a reasonable cost.
6. Access to some of the nation's best wind and solar resources,which provides opportunities
to develop geographically diverse low-cost renewable assets.
7. Resiliency to protect against system and market disruptions where limited transmission can
otherwise constrain energy supply.
8. Ability to meet obligations and requirements of PacifiCorp's Open Access Transmission
Tariff(OATT).
PacifiCorp's transmission network is highly integrated with other transmission systems in the west
and provides the critical infrastructure needed to serve our customers cost effectively and reliably.
Consequently, PacifiCorp's transmission network is a critical component of the IRP process.
PacifiCorp has a long history of providing reliable service in meeting the bulk transmission needs
of the region. This valued asset will become even more critical as the regional resource mix
transitions to accommodate increasing levels of variable generation from renewable resources that
will be used to serve the growing energy needs of our customers.
This chapter provides:
• An overview of PacifiCorp's regulatory requirements including recent updates to
PacifiCorp's generation interconnection procedures.
• Support for PacifiCorp's plan to continue permitting the balance of Gateway West;
• Key background information on the evolution of the Energy Gateway Transmission
Expansion Plan; and
• An overview of PacifiCorp's investments in recent short-term system improvements that
have improved reliability, helped to maximize efficient use of the existing system, and
enabled the company to defer the need to invest in larger-scale transmission infrastructure.
Open Access Transmission Tariff
Consistent with the requirements of its GATT, approved by the Federal Energy Regulatory
Commission(FERC),PacifiCorp plans and builds its transmission system based on two customer-
type agreements—network customer or point-to-point transmission service. For network
customers,PacifiCorp uses ten-year load-and-resource (L&R) forecasts supplied by the customer,
as well as network transmission service requests to facilitate development of transmission plans.
Each year, PacifiCorp solicits L&R data from each of its network customers to determine future
L&R requirements for all transmission network customers. The bulk of PacifiCorp's network
customer needs comes from the company's Energy Supply Management (ESM) function, which
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
supplies energy and capacity for PacifiCorp's retail customers. Other network customers include
Utah Associated Municipal Power Systems, Utah Municipal Power Agency, Deseret Power
Electric Cooperative (including Moon Lake Electric Association), Bonneville Power
Administration (BPA), Basin Electric Power Cooperative, Tri-State Generation & Transmission,
the United States Department of the Interior Bureau of Reclamation, and the Western Area Power
Administration.
PacifiCorp uses its customers' L&R forecasts and best available information, including
transmission service and generation interconnection requests, as factors to determine the need and
timing for investments in the transmission system.If customer L&R forecasts change significantly,
PacifiCorp may consider alternative deployment scenarios or schedules for transmission system
investments, as appropriate. In accordance with FERC guidelines, PacifiCorp is able to reserve
transmission network capacity based on this data. PacifiCorp's experience, however, is that the
lengthy planning,permitting and construction timeline required to deliver significant transmission
investments, as well as the typical useful life of these facilities, is well beyond the 10-year
timeframe of L&R forecasts.2 A 20-year planning horizon and ability to reserve transmission
capacity to meet existing and forecasted need over that timeframe is more consistent with the time
required to plan for and build large-scale transmission projects, and PacifiCorp supports clear
regulatory acknowledgement of this reality and corresponding policy guidance.
For point-to-point transmission service,the OATT requires PacifiCorp to grant service on existing
transmission infrastructure using existing capacity or to build transmission system infrastructure
as required to provide the service. The required action is determined with each point-to-point
transmission service request through FERC-approved study processes that identify the
transmission need.
Reliability Standards
PacifiCorp is required to meet mandatory FERC,North American Electric Reliability Corporation
(NERC), and Western Electricity Coordinating Council (WECC) reliability standards and
planning requirements. The operation of PacifiCorp's transmission system also responds to
requests issued by California Independent System Operator (CAISO) RC West as the NERC
reliability coordinator. The company conducts annual system assessments to confirm minimum
levels of system performance during a wide range of operating conditions,from serving loads with
all system elements in service to extreme conditions where portions of the system are out of
service. Factored into these assessments are load growth forecasts, operating history, seasonal
performance, resource additions or removals, new transmission asset additions, and the largest
transmission and generation contingencies. Based on these analyses, PacifiCorp identifies any
potential system deficiencies and determines the infrastructure improvements needed to reliably
meet customer loads. NERC planning standards define reliability of the interconnected bulk
electric system in terms of adequacy and security. Adequacy is the electric system's ability to
always meet aggregate electrical demand for customers. Security is the electric system's ability to
withstand sudden disturbances or unanticipated loss of system elements. Increasing transmission
capacity often requires redundant facilities to meet NERC reliability criteria.
z For example,PacifiCorp's application to begin the Environmental Impact Statement process for the Gateway West
segment of its Energy Gateway Transmission Expansion Project was filed with the Bureau of Land Management in
2007.A partial Record of Decision(ROD)was received in late April 2013,and a supplemental ROD was received in
January 2017.
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PACIFICORP-2025 IU CHAPTER 4-TRANSMISSION
Generation Interconnection Study Methodology Changes
In 2022 PacifiCorp filed a request with FERC to modify its large generator interconnection
procedure to allow PacifiCorp to study new standalone storage resources as not discharging during
high generation of other resources in the region. The request was approved by FERC in March
2022 and the new assumptions were implemented into generation interconnection studies starting
with Cluster 2.The new operating assumptions have allowed PacifiCorp to use more realistic study
assumptions for storage resources which in some circumstances should alleviate the need for
additional network upgrades to interconnect new resources.
In 2023 FERC released Order 2023 which required modifications of all transmission provider's
including PacifiCorp's, generator interconnection procedures. Several notable changes were
included in Order 2023. First, FERC required all transmission providers to move to a first ready,
first serve cluster study process which PacifiCorp had already transitioned to in 2020. Second,
FERC required all transmission providers to use a distribution factor analysis to assign cost
responsibility to specific interconnection customer requests driving the need for network upgrades.
This change to PacifiCorp's procedures will allow for projects sited in locations that have smaller
impacts on the transmission system, avoiding cost responsibility for upgrades in the region that its
project does not cause. Other aspects of the Order 2023 include requiring 100 percent of site
control for proposed generating facilities with the initial application and substantial withdrawal
penalties at the facilities study stage both of which should disincentivize speculative projects.
PacifiCorp will implement a transition process in which existing interconnection requests that have
not yet proceeded far enough in the study process will have the opportunity to be studied in a
transition cluster study or be withdrawn. PacifiCorp's next application window for new generation
interconnection requests will open in 2026.
Aeolus to Mona/Clover (Gateway South — Segment F)
The Energy Gateway South transmission line is a new 416-mile,high-voltage 500-kV transmission
line and associated infrastructure running from the Aeolus substation near Medicine Bow,
Wyoming, to the Clover substation near Mona, Utah. The transmission line is currently under
construction and scheduled to come online by the end of 2024.
Windstar-Populus (Gateway West — Segment D)
The Windstar-to-Populus transmission project consists of three key sub-segments:
• DI- Recently placed in service, a Figure 4.1 - Segment D
single-circuit 230-kV line running �/�/ Y O M I N G
approximately 59 miles between the
existing Windstar and Aeolus
substations while looping in and out of •Windstar
Shirley Basin substation in eastern 0 Shirley Basin
Br - 0.1 Aeolus
Wyoming; _ Anticline o� ,,
• D2—A single-circuit 500-kV line
completed October 2020 and energized November 2020 and
• D3—A single-circuit 500-kV line running approximately 200 miles between the new
Anticline substation and the Populus substation in southeast Idaho.
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
Populus-Hemingway (Gateway West - Segment E)
The Populus-to-Hemingway transmission project consists of two single-circuit 500-kV lines that
run approximately 500 miles between the Populus substation in eastern Idaho to the Hemingway
substation in western Idaho.
While PacifiCorp is not requesting acknowledgement of a plan to construct these segments in this
IRP, the company will continue to permit the projects specifically transmission segment between
Midpoint-to-Hemingway portion of Segment E.
Figure 4.2 - Segment E
N I D A H 0 The Gateway West Segment E project would enable
Hemingway GA ` *A V w PacifiCorp to more efficiently dispatch system resources,
Midpoint improve performance of the transmission system (i.e.,
E sore►, reduce line losses), improve reliability, and enable access
coder Hil Pcpulus to a diverse range of new resource alternatives over the
o long term.
Plan to Continue Permitting — Gateway West
The Gateway West transmission projects continue to offer benefits under multiple,future resource
scenarios. To ensure the company is well positioned to advance the projects, it is prudent for
PacifiCorp to continue to permit the balance of Gateway West transmission projects. The record
of decision(ROD) and right-of-way grants contain many conditions and stipulations that must be
met and accepted before a project can move to construction. PacifiCorp will continue the work
necessary to meet these requirements and will continue to meet regularly with the Bureau of Land
Management (BLM) to review progress.
Boardman-Hemingway (Segment H)
Boardman-to-Hemingway(B2H) is an approximately 290-mile high-voltage 500-kV transmission
line capable of coming online in 2027. PacifiCorp is continuing to coordinate with regional
transmission providers and retail customers to evaluate options for this project.
PacifiCorp continues to participate in the project under the Joint Funding Permitting Agreement
with Idaho Power. In accordance with this agreement,PacifiCorp is responsible for its share of the
costs associated with federal and state permitting activities and other pre-construction activities
agreed to in the updated agreement.
Idaho Power's 2023 IRP identified the B2H as a preferred resource to meet its capacity needs,
reflecting a need for the project in 2026 to avoid a deficit in load-serving capability in peak-load
periods. Given the status of ongoing permitting activities and the construction period,Idaho Power
expects the in-service date for the transmission line to be in 2027 or beyond.
The BLM released its record of decision ROD for B2H on November 17, 2017. The ROD allows
BLM to grant right-of-way to Idaho Power for the construction, operation,and maintenance of the
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
B2H Project on BLM-administered land. The BLM right-of-way grant was executed on January
9, 2018.
The U.S. Forest Service (USFS) issued a separate ROD on November 9, 2018, for lands
administered by the USFS based on the analysis in the final environmental impact statement. The
USFS ROD approves the issuance of a special-use authorization for a portion of the project that
crosses the Wallowa-Whitman National Forest. The U.S. Department of the Navy issued a ROD
on September 25, 2019, in support of construction of a portion of the B2H project on 7.1-miles of
the Naval Weapons Systems Training Facility in Boardman, Oregon.
On September 27, 2022, Oregon's Energy Facility Siting Council approved the Oregon site
certificate completing Oregon's permit actions that provide for the construction of the project
across private lands in Oregon. Following this action an appeal was made to the Oregon
Supreme court challenging the approval. On March 8, 2023, the court affirmed the site
certificate which finalized the site certificate.
In January of 2022 Idaho Power, BPA and PacifiCorp agreed in a non-binding term sheet to
negotiate Bonneville's exit of the project with Idaho Power acquiring Bonneville's share
responsibility of the project. This will provide Idaho Power with a 45 percent share of the
project and retain PacifiCorp's 55 percent share. Additional terms under negotiations include
changes in transmission service between PacifiCorp and BPA; between BPA and Idaho Power,
as well as the purchase and sale of certain assets between Idaho Power and PacifiCorp. The
Boardman to Hemingway amended Permit Funding Agreement removing Bonneville and
updating the agreement to capture additional pre-construction tasks was executed on March 23,
2023. The Joint Purchase and Sale agreement between Idaho Power and PacifiCorp provides
Idaho Power with certain assets allowing service to BPA customers in southeast Idaho via the
B2H line, and capacity from the Four Corners substation in New Mexico to the Populus
substation in southern Idaho. Associated with the term sheet is the Hemingway project
construction agreement, construction agreements for upgrades that provide PacifiCorp additional
capacity across Idaho Power's transmission system and a construction agreement that provides
PacifiCorp additional capacity to serve central Oregon loads. These agreements were all
executed on March 23, 2023.
Idaho Power has applied for Certificates of Public Convenance and Necessity (CPCN) in Oregon
and Idaho. Issuance of both certificates were received in June of 2023. PacifiCorp received a
CPCN in Idaho in June 2023 and in Wyoming in August 2023.
The current project schedule includes projected completion in 2027.
At this time, PacifiCorp is reevaluating the timing and needs analysis underlying B2H because of
factors such as changed native load growth and a lack of capacity available on neighboring
transmission systems to deliver to load pockets.
Spanish Fork—Mercer 345-kV line
The 2025 preferred portfolio includes the construction of a new, approximately 50-mile, 345-kV
transmission line between Spanish Fork Substation and Mercer substation in Utah, with an
identified in-service date of 2036, based on projected interconnection requirements. Load-service
and reliability requirements may bring this date forward, as could accelerated generator
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
interconnection demand. PacifiCorp has begun the permitting process for this new transmission
line and is currently targeting an in-service date of 2027 for the line.
Other Transmission System Improvements
The 2025 IRP preferred portfolio also includes near-term transmission upgrades across its
transmission system. Ongoing investment in transmission infrastructure in Idaho, Oregon, Utah,
Washington, and Wyoming will facilitate continued and long-term growth in new renewable
resources and increased reliability for its customers.
Energy Gateway Transmission Expansion PlanZ
Introduction
Given the long—lead time required to successfully site, permit, and construct major new
transmission lines, these projects need to be planned well in advance. The Energy Gateway
Transmission Expansion Plan is the result of several robust local and regional transmission
planning efforts that are ongoing and have been conducted multiple times over a period of several
years. The purpose of this section is to provide important background information on the
transmission planning efforts that led to PacifiCorp's proposal of the Energy Gateway
Transmission Expansion Plan.
Background
Until PacifiCorp's announcement of Energy Gateway in 2007, its transmission planning efforts
traditionally centered on new resource additions identified in the IRP. With timelines of seven to
ten years or more required to site,permit,and build transmission,this traditional planning approach
was proving to be problematic, leading to a perpetual state of transmission planning and new
transmission capacity not being available in time to be viable for meeting customer needs. The
existing transmission system has been at capacity for several years,and new capability is necessary
to enable new resource development.
The Energy Gateway Transmission Expansion Plan, formally announced in May 2007,has origins
in numerous local and regional transmission planning efforts discussed further below. Energy
Gateway was designed to ensure a reliable, adequate system capable of meeting current and future
customer needs. Importantly, given the changing resource picture, its design supports multiple
future resource scenarios by connecting resource-rich areas and major load centers across
PacifiCorp's multi-state service area. In addition,the ability to use these resource-rich areas helps
position PacifiCorp to meet current state renewable portfolio requirements and other state-specific
policy goals. Energy Gateway has since been included in all relevant local, regional and
interconnection-wide transmission studies.
Planning Initiatives
Energy Gateway is the result of robust local and regional transmission planning efforts. PacifiCorp
has participated in numerous transmission planning initiatives,both leading up to and since Energy
Gateway's announcement. Stakeholder involvement has played an important role in each of these
initiatives, including participation from state and federal regulators, government agencies,private
and public energy providers, independent developers, consumer advocates, renewable energy
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
groups,policy think tanks, environmental groups, and elected officials. These studies have shown
a critical need to alleviate transmission congestion and move constrained energy resources to
regional load centers throughout the west, and include:
• Rocky Mountain Area Transmission Study
Recommended transmission expansions
overlap significantly with Energy Gateway presented
configuration, including: PF Report
o Bridger system expansion is similar i, considered transmission
to Gateway West. upgrades, capable of giving LSEs
o Southeast Idaho to southwest Utah generationgreater ccess to lower cost
• and enhancing fuel
expansion akin to Gateway Central, diversity, are - for
Segment B, Segment C and Sigurd to consumers underof
Red Butte (in service 2015). reasonable assumptions 11 about
o Improved east-west connectivity natural gas prices.
similar to Energy Gateway Segment
H alternatives.
• Western Governors' Association Transmission Task Force Report
Examined the transmission needed to PIV
deliver the largely remote generation - observes
resources contemplated by the Clean anF transmission d
stments
Diversified Energy Advisory Committee. continue network' ' ' '_
value even as This effort built upon the transmission
conditions change. For example,
previously modeled by the Seams Steering transmission originally
Group-Western Interconnection and Li the site of a now obsolete
included transmission necessary to support a IF power plant continues to be
range of resource scenarios, including high used since a newpower plant is
efficiency, high renewables and high often constructed at the same
conventional resource scenarios. Again, for "
PacifiCorp's system, the transmission
expansion that supported these scenarios closely resembled Energy Gateway's
configuration.
• NorthernGrid Regional Transmission Plan Reports
In the 2020-2021 NorthernGrid Regional Transmission Plan, sub segments of Energy r(Aft_ analyzing perf _ _ __•stressed of
Gateway (both Gateway West and cas_
Gateway South) were listed as necessary tos, a rigorous
contingencyconc
provide acceptable system performance. c cirri m enc-.
The study also established that the amount
of new Wyoming wind generation that is
added over time can impact the would be needed to meet the
transmission system reliability west of
Wyoming. Additionally, three interregional L_ - -
projects were included in the study: the Southwest Inter-tie Project(SWIP North), Cross
Tie and TransWest Express, which showed that all three projects relied on Energy
Gateway to attain their full transfer capability rating.
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
The NorthernGrid 2022-2023 Regional Transmission Plan identified the regional
combination consisting of Gateway West (Segment D.3 and Segment E) and B2H as the
most efficient and cost-effective set of projects for the NorthernGrid 10-year planning
horizon. Gateway South was considered as an in-service project in all cases, including the
selected regional combination.
• WECC/Reliability Assessment Committee (RAC)Annual Reports and Western
Interconnection Transmission Path Utilization Studies
These analyses measure the historical use of
transmission paths in the west to provide ••- •
insight into where congestion is occurring and •••-• ' in the
ath is
assess the cost of that congestion. The EnergyUsage of _'_ _'
th
Gateway segments were included in the analysescurrentl numberhigh _ • _ •
that support these studies, alleviating several sts •
transmission service to move
points of significant congestion on the system, renewable power to the West
including Path 19 (Bridger West) and Path 20 from the Wyoming area."
(Path Q.
Energy Gateway Configuration
To address constraints identified on PacifiCorp's transmission system, as well as meeting system
reliability requirements discussed further below, the recommended bulk electric transmission
additions took on a consistent footprint,which is now known as Energy Gateway. This expansion
plan establishes a triangle of reliability that spans Utah, Idaho and Wyoming with paths extending
into Oregon and Washington. This plan contemplates geographically diverse resource locations
based on environmental constraints, economic generation resources, and federal and state energy
policies.
Since Energy Gateway's initial announcement in 2007, this series of projects has continued to be
vetted through multiple public transmission planning forums at the local, regional and Western
Interconnection level. In accordance with the local planning requirements in PacifiCorp's GATT,
Attachment K, PacifiCorp has conducted numerous public meetings on Energy Gateway and
transmission planning in general. Meeting notices and materials are posted publicly on
PacifiCorp's Attachment K Open Access Same-time Information System(OASIS)site.PacifiCorp
is also a member of NorthernGrid regional planning organization and WECC's Reliability
Assessment Committee and was formally a member of Northern Tier Transmission Group(NTTG)
regional planning organization.
These groups continually evaluate PacifiCorp's transmission plan in their efforts to develop and
refine the optimal regional and interconnection-wide plans. Please refer to PacifiCorp's OASIS
site for information and materials related to these public processes.3
Additionally, an extensive 18-month stakeholder process on Gateway West and Gateway South
was conducted. This stakeholder process was conducted in accordance with WECC Regional
Planning Project Review guidelines and FERC OATT planning principles, and was used to
3 http://www.oatioasis.com/ppw/index.html
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
establish need, assess benefits to the region,vet alternatives, and eliminate duplication of projects.
Meeting materials and related reports can be found on PacifiCorp's Energy Gateway OASIS site.
Energy Gateway's Continued Evolution
The Energy Gateway Transmission Expansion Plan is the product of years of ongoing local and
regional transmission planning efforts with significant customer and stakeholder involvement.
Since its announcement in May 2007,Energy Gateway's scope and scale have continued to evolve
to meet the future needs of PacifiCorp customers and the requirements of mandatory transmission
planning standards and criteria. Additionally, PacifiCorp has improved its ability to meet near-
term customer needs through a limited number of smaller-scale investments that maximize
efficient use of the current system and help defer, to some degree, the need for larger capital
investments like Energy Gateway (see the following section titled "Efforts to Maximize Existing
System Capability"). The IRP process, as compared to transmission planning, can result in
frequent changes in the least-cost, least-risk resource plan driven by changes in the planning
environment (i.e., market conditions, cost and performance of new resource technologies, etc.).
Near-term fluctuations in the resource plan do not always support the longer-term development
needs of transmission infrastructure, or the ability to invest in transmission assets in time to meet
customer needs. Together, however, the IRP and transmission planning processes complement
each other by helping PacifiCorp optimize the timing of its transmission and resource investments
to deliver cost-effective and reliable energy to our customers.
While the core tenets for Energy Gateway's design have not changed, the project configuration
and timing continue to be reviewed and modified to coincide with the latest mandatory
transmission system reliability standards and performance requirements, annual system reliability
assessments, input from several years of federal and state permitting processes, and changes in
generation resource planning and our customers' forecasted demand for energy.
As originally announced in May 2007, Energy Gateway consisted of a combination of single- and
double-circuit 230 kV, 345 kV and 500 kV lines connecting Wyoming, Idaho, Utah, Oregon and
Nevada. In response to regulatory and industry input regarding potential regional benefits of
"upsizing" the project capacity (for example, maximized use of energy corridors, reduced
environmental impacts and improved economies of scale), PacifiCorp included in its original plan
the potential for doubling the project's capacity to accommodate third-party and equity partnership
interests.During late 2007 and early 2008,PacifiCorp received in excess of 6,000 MW of requests
for incremental transmission service across the Energy Gateway footprint, which supported the
upsized configuration. PacifiCorp identified the costs required for this upsized system and offered
transmission service contracts to queue customers. These queue customers, however,were unable
to commit due to the upfront costs and lack of firm contracts with end-use customers to take
delivery of future generation and withdrew their requests. In parallel, PacifiCorp pursued several
potential partnerships with other transmission developers and entities with transmission proposals
in the Intermountain Region. Due to the significant upfront costs inherent in transmission
investments,firm partnership commitments also failed to materialize,leading PacifiCorp to pursue
the current configuration with the intent of only developing system capacity sufficient to meet the
long-term needs of its customers.
In 2010, PacifiCorp entered into memorandums of understanding (MOU) to explore potential
joint-development opportunities with Idaho Power Company on its Boardman-to-Hemingway
(132H)project and with Portland General Electric Company(PGE)on its Cascade Crossing project.
One of the key purposes of Energy Gateway is to better integrate PacifiCorp's east and west
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
balancing authority areas, and Gateway Segment H from western Idaho into southern Oregon was
originally proposed to satisfy this need. However, recognizing the potential mutual benefits and
value for customers of jointly developing transmission, PacifiCorp has pursued these potential
partnership opportunities as a potential lower-cost alternative.
In 2011,PacifiCorp announced the indefinite postponement of the Gateway South 500 kV segment
between the Mona substation in central Utah and Crystal substation in Nevada. This extension of
Gateway South, like the double-circuit configuration discussed above, was a component of the
upsized system to address regional needs if supported by queue customers or partnerships.
However, despite significant third-party interest in the Gateway South segment to Nevada, there
was a lack of financial commitment needed to support the upsized configuration.
In 2012, PacifiCorp determined that one new 230 kV line between the Windstar and Aeolus
substations and a rebuild of the existing 230 kV line were feasible, and that the second new
proposed 230 kV line and proposed 500 kV line planned between Windstar and Aeolus would be
eliminated. This decision resulted from PacifiCorp's ongoing focus on meeting customer needs,
taking stakeholder feedback and land-use limitations into consideration, and finding the best
balance between cost and risk for customers. In January 2012, PacifiCorp signed the B2H
Permitting Agreement with Idaho Power Company and BPA that provides for PacifiCorp's
participation through the permitting phase of the project. The B2H project was pursued as an
alternative to PacifiCorp's originally proposed transmission segment from eastern Idaho into
southern Oregon (Hemingway to Captain Jack). Idaho Power leads the permitting efforts on the
B2H project, and PacifiCorp continues to support these activities under the conditions of the B2H
Transmission Project Joint Permit Funding Agreement. The proposed line provides additional
connectivity between PacifiCorp's west and east balancing authority areas and supports the full
projected line rating for the Gateway projects at full build out. PacifiCorp plans to continue to
support the project under the Permit Funding Agreement and will assess next steps post-permitting
based on customer need and possible benefits.
In January 2013, PacifiCorp began discussions with PGE regarding changes to its Cascade
Crossing transmission project and potential opportunities for joint development or firm capacity
rights on PacifiCorp's Oregon system. PacifiCorp further notes that it had a memorandum of
understanding with PGE for the development of Cascade Crossing that was terminated by its own
terms. PacifiCorp had continued to evaluate potential partnership opportunities with PGE once it
announced its intention to pursue Cascade Crossing with BPA. However,because PGE decided to
end discussions with BPA and instead pursue other options, PacifiCorp is not actively pursuing
this opportunity. PacifiCorp continues to look to partner with third parties on transmission
development as opportunities arise.
In May 2013, PacifiCorp completed and placed in service the Mona-to-Oquirrh project. In
November 2013,the BLM issued a partial ROD providing a right-of-way grant for all of Segment
D and most of Segment E of Energy Gateway. The agency chose to defer its decision on the
western-most portion of Segment E of the project located in Idaho in order to perform additional
review of the Morley Nelson Snake River Birds of Prey Conservation Area. Specifically, the
sections of Gateway West that were deferred for a later ROD include the sections of Segment E
from Midpoint to Hemingway and Cedar Hill to Hemingway.
In May 2015, the Sigurd-to-Red Butte project was completed and placed in service.
In December 2016,the BLM issued its ROD and right-of-way grant for the Gateway South project.
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
In January 2017, the BLM issued its ROD and right-of-way grant, previously deferred as part of
the November 2013 partial ROD, for the sections of Segment E from Midpoint to Hemingway and
Cedar Hill to Hemingway.
In October 2020, Segment D2 of Gateway West, from Aeolus to Jim Bridger was placed into
service which included a new 500 kV substation at Aeolus, and a new 345 kV substation at
Anticline.
In October 2020, a portion of Gateway West Segment D1, the 230 kV line between Aeolus and
Shirley Basin was also constructed and completed in 2020. The remaining portion of Gateway
West, Segment DI, consisting of a new 230 kV line between Shirley Basin and Windstar
substations and a rebuild of an existing 230 kV line between Shirley Basin and Dave Johnston
substations is under construction with an expected completion date of both lines in December
2024.
Gateway Segment F, referred to as Gateway South, a 416-mile 500 kV line from Aeolus
substation in Wyoming to Mona/Clover substation in central Utah is under construction with an
expected completion date of December 2024.
Other Gateway segments, including Gateway West Segment D3 from Bridger substation in
Wyoming to Populus substation in Idaho and Gateway West Segment E from Populus to
Hemingway, in Idaho, are in pre-construction activities to address requirements as defined in their
permitting Record of Decision and right-of-way grants issued by the BLM.
PacifiCorp will continue to adjust the timing and configuration of its proposed transmission
investments based on its ongoing assessment of the system's ability to meet customer needs, its
compliance with mandatory reliability standards, and the stipulations in its project permits.
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
Figure 4.3—Energy Gateway Transmission Expansion Plan
Energy Gateway
W A S H I N (7 T O N
M O N TA N A
McNary
Boardman Walk,la
•\`'"y
_ Y
iOGON IDA i0
HelTwngway Tom"'Y w E s T W Y O M I N G
Midpoint
Captain JaMO Borah p, •Windstar
SNtley Basin
cedar Hill Populus mine ice ! Q Aeolus
i 03
A
tt
3 m I Terminal
CALIFORNIA I—z OgWrrh So`�
o u l F py
EJI
NEVADA M `w•t
COLORADO
PacihCorp retail service area
New transmission lines: G U T A H
— 500 kV minimum voltage Red Butte
— 345 kV minimum voltage
230 kV minimum voltage
e Existing substation
O New substation
A R I Z 0 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.
PacifiCorp is reevaluating the timing and needs analysis underlying 1321-1 because of factors such as changed native
load growth and a lack of capacity available on neighboring transmission systems to deliver to load pockets.
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
Table 4.1 —Ener Gateway Transmission Expansion Plan
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 e Placed in-service:May 2013
Oquirrh-Terminal 345 kV double circuit 14 mi • Status:right-of-way acquisition underway
• Scheduled in-service:2024
(DI) New 230 kV single circuit . Status:permitting underway
Windstar-Aeolus Re-built 230 kV single 59 mi •
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 kV single circuit 200 mi . Scheduled in-service:2034 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:permitting underway
Aeolus-Mona • Scheduled in-service:December 2024
(G) 345 kV single circuit 170 mi • Status: completed
Sigurd-Red Butte . Placed in-service:May 2015
(H) • Status:pre-construction activities in progress
Boardman- 500 kV single circuit 290 mi . Scheduled in-service:2027
Hemingway
[Efforts to Maximize Existing System
In addition to investing in the Energy Gateway transmission projects, PacifiCorp continues to
make other system improvements that have helped maximize efficient use of the existing
transmission system and defer the need for larger-scale, longer-term infrastructure investment.
Despite limited new transmission capacity being added to the system over the last 20 to 30 years,
PacifiCorp has maintained system reliability and maximized system efficiency through other
smaller-scale, incremental projects.
System-wide, PacifiCorp has instituted more than 130 grid operating procedures and 20 remedial
action schemes (RAS) to maximize the existing system capability while managing system risk.
In addition, PacifiCorp has been an active participant in the Energy Imbalance Market(EIM)
since November 2014. As of April 2023, 22 participants have joined the EIM. By broadening the
pool of lower-cost resources that can be accessed to balance load system requirements, enhances
reliability and reduces costs across the entire EIM Area. In addition, the automated system can
identify and use available transmission capacity to transfer the dispatched resources, enabling
more efficient use of the available transmission system.
To secure further benefits from market-based resource dispatch, PacifiCorp announced in
December 2022 that it expects to participate in the Extended Day-Ahead Market (EDAM) being
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PACIFICORP—2025 IRP CHAPTER 4—TRANSMISSION
developed by the California Independent System Operator(CAISO).4 While the EIM makes full
use of resource flexibility within the hour and will continue to do so, the EDAM will provide
economic, reliability, and environmental benefits by optimizing the pool of resources that are
made available to EIM in light of forecasted requirements for the entire market footprint over the
following several days, well beyond the end of the current hour. This includes coordination of
generator starts and shutdowns and the charging and discharging of energy storage resources.
Transmission System Improvements Placed In-Service Since the 2023 IRP
PacifiCorp East (PACE) Control Area
1. Central Wyoming Area
• Installs a 345 kV, 200-MVAr switched shunt reactor at Mona substation
o Project driver was to address the high voltage conditions experienced during steady
state operations under light load and light transfer conditions
o Benefits include more effective high voltage control and safe and more reliable
power for the Utah area by reducing lines taken out of service and preservation of
substation equipment life, particularly circuit breakers which are exposed to
frequent switching, reduced probability of mis operation and increased
maintenance costs.
2. Northern Utah/Southeast Idaho Area
• Constructed a new 345 kV yard adjacent to the existing Bridgerland 138 kV substation.
Looped in the existing Populus—Terminal 345 kV line into Bridgerland and Ben Lomond
substations.
o Project driver was to resolve System Operating Limit on Path C.
o Benefits include the ability to maintain the WECC Path C rating to 1600 MW
southbound and 1250 MW northbound.
3. Salt Lake City Utah area
• Install two capacitor banks at Magna Substation and rebuild the Tooele—Pine Canyon 138
kV transmission line
o Project driver was to correct N-1 contingency overload and low voltage issues
at Magna substation and on the Tooele — Pine Canyon 138 kV line from
consistent load growth and new block loads.
o Benefits included mitigating the risk of thermal overloads and low voltage
issues,adding additional capacity to address projected load growth and improve
transmission reliability
4. Southern Utah area
• Reconductor 2.57-miles of the St. George-Purgatory Flat 138 kV transmission line.
o Project driver was to increase the thermal rating of the line which loaded to 95
percent of its continuous summer thermal rating summer 2022.
o Benefits included the increases of the transmission line summer continuous
rating by 63 MVA.
a http://www.caiso.com/Documents/EDAM-Fact-Sheet.pdf
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
PacifiCorp West (PACW) Control Area
1. Klamath Falls Oregon Area
• Constructed a second 230 kV transmission line from Snow Goose to Klamath Falls
substation.
o Project driver was to resolve NERC Standard TPL-001-5 Category P6 (N-1-1) for
a double contingencies on the 230-kV system serving Yreka, Klamath Falls and
La Pine area for the loss of the Klamath Falls-Snow Goose 230 kV line and either
the Lone Pine-Copco 230 kV line or Bonneville Power Administration's (BPA)
Pilot Butte-La Pine 230 kV line can cause a voltage collapse affecting a large region
of the southern Oregon and northern California system.
o Benefits included reinforcing 230 kV system between in Klamath Falls area to
cover TPL-001-5 category P6(N-1-1)contingencies during all operating conditions
on the existing system and minimize risk of a large-scale outage to customers
throughout the Klamath Falls and Yreka areas.
2. Prineville Oregon Area
• Construct a second 115 kV line between Houston Lake and Ponderosa substations.
o Project driver was to eliminates potential N-1 overloads of the Prineville 115 kV
system associated with increased load, changing generation mix, and grid flow
conditions in the area.
o Benefits included the elimination of a NERC Standard TPL-001-5 Category P1
contingency event for a fault on the 115 kV line between Baldwin Road and
Ponderosa substation or a fault on the 115 kV line between Houston Lake and
Stearns Butte.
Planned Transmission System Improvements
PacifiCorp East (PACE) Control Area
1. Central Utah Area
• Upgrade the 345-138 kV 167-MVA transformer at Camp Williams substation to a 345-138
kV 700-MVA transformer
o Project driver is to correct NERC Standard TPL-001-5 Category P6 deficiencies
during peak summer loading conditions for the N-1-1 event of losing both Spanish
Fork substation 345-138 kV transformers that would cause thermal overloads to the
Camp Williams 345-138 kV transformer and the Clover—Nebo 138 kV line.
o Benefits include mitigating the NERC Standard TPL-001-5 Category P6
deficiencies.Provides additional 345 kV source to northern Utah Valley and Jordan
Valley as well as increase system reliability
• Install a second 345-138 kV 700 MVA transformer at Oquirrh substation
o Project driver is to correct N-1 contingency overload issues in the South Jordan
area.
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
o Benefits include increasing capacity on the 138 kV network serving the Salt Lake
Valley.
• Construct a new 345 kV line between Spanish Fork and Mercer 345 kV substations
o Project driver is to eliminate the need for the Lakeside II Remedial Action Scheme
(RAS) and prevent generation shedding during contingencies. Once flows across
the Wasatch Front South boundary exceed 5,562 MW, the Lakeside RAS is no
longer effective and cannot be modified to accommodate more flow.
o Benefits include the increase of path limit to 6,300 MW and allow 1,000 MW
additional generation to be interconnected in southern Utah
2. Utah, Idaho &Wyoming -Upgrade Program—Replace Over-dutied Circuit Breakers
• Replaced breakers identified as over-dutied with higher-capability breakers in various
substations located in Idaho, Utah, and Wyoming
o Project driver was to correct NERC Standard TPL-001-5 Requirement R2.3
deficiencies identified in PacifiCorp's 2015-2018 NERC TPL Assessment resulting
in the identification of 12 substations to be addressed as required per R2.8.
o Benefits include eliminating the risk of over-dutied breakers failing under fault
interruption conditions that pose safety and reliability risks, and the resolution of
the NERC TPL-001-5 Requirement R2.3 deficiencies and as required per R2.8.
3. Salt Lake City,Utah Area
• Convert North Salt Lake Substation to 138-kV
o Project driver is to correct N-1 contingency overload issues in the North Salt Lake
area.
o Converting to 138 kV at North Salt Lake substation increases the capacity in the
area while mitigating the contingency overloads, reduces the burden on the 46 kV
system, and brings better reliability to the customers in the area.
• Loop the 90th South—Terminal 345 kV line into and out of the Midvalley 345 kV yard
o Project Driver is to eliminate identified overloading of the 90th South—Midvalley
345 kV #1 line under heavy transfer conditions across the Wasatch Front South
boundary.
o Benefits include increasing the transfer capability across the Wasatch Front South
boundary by 45-MW, improving operating flexibility, and allowing additional
transfers from Clover/Mona as well as from southern Utah to the Wasatch Front.
• Construct a new 230-46 kV substation near Eden,Utah.
o Project driver is to provide a transmission loop to the area to facilitate aline rebuild
through Ogden Canyon.
o Benefits include improved future reliability and area capacity.
4. Southeast Idaho Area
• Install a 25 MVAR shunt capacitor bank at the Franklin 138 kV substation.
o Project driver is to correct NERC Standard TPL-001-5 Category PI (N-1)
contingency events for the loss of the Treasureton—Franklin 138 kV line.
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PACIFICORP-2025 IRP CHAPTER 4-TRANSMISSION
o Benefits include resolving the NERC Standard TPL-001-5 Category P1 voltage
issues
PacifiCorp West (PACW) Control Area
1. Eastern Oregon Area
• Replace the entire Burns 500 kV reactive station, including the series capacitor bank,
bypass breakers, shunt reactors, and all switches and circuit switchers.
o Project driver is to replace obsolete and degrading assets to prevent equipment
failure which would result in a substantial financial impact and limiting Jim Bridger
and Wyoming wind generation for an extended time.
o Benefits include replacement of obsolete equipment with modern SCADA-
operable equipment (reducing operational labor), reduces the risk of failure, and
improves recovery time.
2. Portland Oregon Area
• Reconfigure and convert the existing Bonneville Power Administration's (BPA) St.
Johns—Columbia and PacifiCorp's(PAC)Columbia—Knott 57 kV lines,and a portion
of the idle 69 kV line north of Albina to 115 kV
o Project driver is to correct NERC Standard TPL-001-5 Category P6 (N-1-1)
deficiencies for load loss of up to 62-MW in the urban northeast Portland core area
and Category P6 (N-1-1) deficiencies for voltage issues on the 57 kV system.
o Benefits include resolution of NERC Standard TPL-001-5 Category P6 (N-1-1)
deficiencies, elimination of the 57 kV system voltage in the North Portland and
creates a third 115 kV path between the St. Johns/Rivergate and the Knott/Albina
area.
3. Roseburg Oregon Area
• Convert the 69 kV transmission Lines 30 and 65 to 115 kV,along with four distribution
substations and construct a new 115 kV tie from Roberts Creek to the converted Green
substation.
o Project driver is to resolve multiple capacity limitations in the area; notably the
Roberts Creek 115-69 kV transformer,the Winchester 115-69 kV transformer,Line
66 between Dixonville and Sutherlin and Line 65 between Dixonville and
Southgate. 12 system problems were identified as being affected by these
limitations.
o Benefits include improvement of operability of the system to increase reliability
during outages and maintenance and gives the system enough excess capacity to
accommodate 20 years of growth at a 1.3 percent per year rate.
• Replace the existing 230-115 kV transformer at Dixonville substation with a new 280
MVA transformer.
o Project driver is to resolve excess voltage on the 115 kV bus. The current
transformer steady state voltage sits at 10.4 percent above nominal in the North
Umpqua Hydroelectric System and is nearly 8.7 percent above nominal at
Dixonville substation.
o Benefit includes bringing the 115 kV bus voltage at Dixonville to operate within an
acceptable range and avoids excessive voltage throughout the Roseburg and North
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Umpqua areas extending the life of the transformers as well as all the downstream
equipment.
4. Medford Oregon Area
• Construct a 230-kV transmission line between Lone Pine and Whetstone substations
o Project driver is to correct NERC Standard TPL-001-5 Category P1 (N-1) and P6
(N-1-1)outage combinations including loss of the two Meridian-Lone Pine 230-kV
lines(N-1),N-1-1 loss of the Meridian-Whetstone and Dixonville-Grants Pass 230-
kV lines, or N-1-1 loss of Sams Valley 500-230 kV source and either the Meridian-
Whetstone 230-kV line or Dixonville-Grants Pass 230-kV line.
o Benefits include resolving the NERC Standard TPL-001-5 Category P1 and P6
issues as well as preventing reverse flow across the Medford 115 kV system to
support the 230 kV system and allows operating the Medford 115 kV system radial.
• Construct one new 500-230 kV substation called Sams Valley
o Project driver is to correct NERC Standard TPL-001-5 deficiencies for the loss of
a single 230 kV line and for N-1-1 and N-2 outages to 230 kV lines that were
initially identified in PacifiCorp's 2010 NERC TPL Assessment and supported
through subsequent NERC TPL Assessments, and to provide a second 500 kV
source to address load growth in the Southern Oregon region.
o Benefits include adding a second source of 500 kV capacity, adding a new 230-kV
line, improving reliability of the 230 kV network, mitigates the risk of thermal
overloads and low voltage,mitigates the risk of shedding load in preparation of the
second contingency for N-1-1 outages, and resolves the NERC TPL-001-5
deficiencies.
These investments help maximize the existing system's capability, improve PacifiCorp's ability
to serve growing customer loads, improve reliability, increase transfer capacity across WECC
Paths, reduce the risk of voltage collapse and maintain compliance with North American Electric
Reliability Corporation and Western Electricity Coordinating Council reliability standards.
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CHAPTER 5 - RELIABILITY AND RESILIENCY
CHAPTER HIGHLIGHTS
• Regional resource adequacy assessments highlight that there are resource adequacy risks
through the mid-2020s. In conditions of increased demand and resource variability, higher
summer temperatures reduce excess energy supply, in turn tightening supply from the market.
• PacifiCorp's wildfire mitigation plans, which outline a risk-based, balanced, and integrated
approach, contain six critical focus areas of planning and execution for a reliable and resilient
energy future: (1) Risk analysis and drivers, (2) Situational awareness, (3) Inspection and
correction, (4)Vegetation management, (5) System hardening, and(6) Operational practices.
• The 2025 IRP preferred portfolio includes the Energy Gateway South (GWS) and Energy
Gateway West segment D.1, which are currently operational. The preferred portfolio also
includes future transmission upgrades that support the transition to renewable energy by
providing access to low-cost, location-specific renewable resources, and additional transfer
capability,which enables greater use of low-cost resource options and relieves stress on current
assets.
Introduction
Serving reliably(i.e.,keeping the lights on for customers),as well as planning for a resilient system
(i.e., operating through and recovering from a major disruption) is a primary focus for PacifiCorp.
With the increasing retirement of thermal baseload resources, the incorporation of increasing
numbers of intermittent renewable resources, and the impacts of climate change, planning for a
reliable and resilient energy future is more crucial, and more complex, than ever. PacifiCorp
continues to build on a strong track record of serving its customers safely,reliably, and affordably.
The focus on reliability and resiliency spans across several areas of the company: PacifiCorp's
resource planning and energy supply teams work closely with regional partners and ensure that
there is sufficient supply to serve customers, while transmission and distribution teams work to
mitigate the destructive impact of wildfire risk throughout the west to ensure that PacifiCorp can
deliver power safely to customers now and in the future.
Supply-Based Reliability
Regional Resource Adequacy
As part of its 2025 IRP, PacifiCorp has conducted a review and evaluation of western resource
adequacy studies and information,.
In December 2024 the Western Electricity Coordinating Council (WECC) published the Western
Assessment of Resource Adequacy(WARA),which serves as an interconnection-wide assessment
of resource adequacy as discussed below. PacifiCorp also reviewed the 2020 North American
Electric Reliability Council(NERC)Long-Term Reliability Assessment and the status of resource
adequacy assessments prepared for the Pacific Northwest by the Pacific Northwest Resource
Adequacy Forum.
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WECC Western Assessment of Resource Adequacy Report
The WECC WARA was published in December 2024 and was developed based on data collected
from balancing authorities describing their own demand and supply projections over the next 10
years.' The analysis is probabilistic and represents an hourly assessment of resource adequacy over
the study period. A key driver of the results is the forecasted growth in load across the west,which
is projected to increase by over 20.4%in the next ten years (on an energy basis),more than double
the 9.6% growth forecast from the 2022 WARA. PacifiCorp's loads are located in the NW-
Northwest and NW-Central regions evaluated as part of the WARA. Peak demand in the NW-
Northwest region is forecasted to grow by 13.5% in the next ten years, while the NW-Central
region is forecasted to grow by 8.5% over the same time period. While significant, these are both
lower than the growth of the Western Interconnection as whole, where growth is projected at
17.2%, driven by increases in California and the Desert Southwest.
Resource plans have identified a vast quantity of resources to meet this demand, 172 GW
of new generation resources, which is more than double the generation capacity added in the last
ten years. Plans include 68 GW of solar capacity additions in the next ten years, while will nearly
triple the 35 GW in operation in 2023,plus 40 GW of wind capacity additions in the next ten years,
relative to 37 GW in operation in 2023. Similarly,battery storage is projected to grow by 37 GW.
The WARA highlights concerns that planned resources will not be brought online in a timely
manner and includes four scenarios evaluating various levels of resource build out.
In the All Additions scenario, which includes all planned resources, the WARA identifies
risks in the NW-Northwest region, primarily in the winter, and primarily in 2029 and later. Risks
increase and appear in other regions if lower levels of planned resources are achieved, as
summarized in Table 5.1.
Table 5.1 —WARA Demand-at-Risk Summary2
Month 55%Resource Additions Scenario
Region 1 2 3 4 5 6 7 8 9 10 11 12
California - - - - - - - - - - - -
Desert Southwest Medium Medium Low
NW-Northwest High High Medium Low Low Medium Medium High High High
NW-Northeast Low Low Medium
NW-Central - Low Medium Medium Medium - - -
Month 85%Resource Additions Scenario
Region 1 2 3 4 5 6 7 8 9 10 11 12
California - - - - - - - - - - - -
Desert Southwest
NW-Northwest f,1edi.mi Medium Low Medium Low Medium
NW-Northeast Low Low
NW-Central Low Low Low Medium
Risk reflects the count of hours in each month that exceed a one-day-in-ten-years threshold by 2034.
High >50 hours Mediurn 10-49 hours Low <10 hours
The NW-Northwest and NW-Central regions which include PacifiCorp's load both have
hours at risk. In the NW-Northwest region, significant risk exists in both the summer and winter
1 WECC.Western Assessment of Resource Adequacy 2024.Available online: https://feature.wecc.or;;/wara/
(accessed 12/18/2024)
2 WECC.WARA 2024 Demand-at-Risk Hours by Subregion.Available online at:https://www.wecc.or;4/wecc-
document/17071 (Accessed 12/18/2024)
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seasons. While PacifiCorp has significant transfer capability into the NW-Northwest and
proportionately lower dependence on hydropower than the NW-Northwest region as a whole,
regional capacity limitations would result in less margin for error. In the NW-Central region,
risks are somewhat lower, and concentrated in the summer, but still indicate that incremental
resources are necessary to serve growing loads. The results shown assume import capability
between sub-regions—in the absence of imports, risks are high in the NW-Northwest and NW-
Central regions even if all planned new resources are built.
The WARA characterizes four risks that impact planned resource additions: supply chain
disruptions, interconnection queue, siting delays, and increased costs. Some of the impacts are
reduced as a result of PacifiCorp's particular circumstances. PacifiCorp's relatively large
portfolio and geographic footprint create a wider range of opportunities than are available to
many other utilities, increasing the likelihood that some new projects will be able to proceed.
This is bolstered by PacifiCorp's implementation of a cluster study interconnection process in
2020, which has enabled large numbers of interconnection requests to be processed more quickly
than was possible in the past, increasing the likelihood that projects will be available in desired
timeframes. After cost-effective projects are identified, PacifiCorp's relatively large demand
allows it to contract with multiple developers for multiple sites, reducing the impact if any single
developer or site falls through or is delayed. That said, substantial risks remain for any resource
additions.
The WARA also characterizes risks associated with several other factors: resource
variability, transmission considerations, energy policy, and extreme weather. The limitations of
wind, solar, and energy-limited resources like energy storage are different from those of baseload
or dispatchable resources, and those limitations become more restrictive as the share of these
resources increases. Given the expected tripling of solar capacity and doubling of wind capacity,
variability is expected to increasing significantly. The variability and operational requirements
of that future resource mix is not fully characterized, and could be impacted further by extreme
weather events. The other risk factors cover a range of planning and policy considerations, and
the process through which resource and transmission build outs are implemented. Utility
planning and procurement takes time, and the build out of resources and transmission is reliant
upon a range of state and federal processes and requirements.
NERC Long-Term Reliability Assessment (LTRA)
Resources
As part of the regional reliability assessment to support the 2025 IRP, PacifiCorp reviewed and
incorporated learnings from the NERC LTRA, published in December 2024.3 The NERC LTRA
s NERC.2024 Long-Term Reliability Assessment.December 2024.Available online at:
https://www.nerc.coM/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC Long%20Term%2OReliability%20
Assessment 2024.pdf(accessed 12/18/2024)
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organizes prospective resources into three broad capacity supply categories in its 10-year WECC
region reliability assessment:
• Tier 1: resources under construction, or with signed contracts.
• Tier 2: resources with completed interconnection studies.
• Tier 3: resources in an interconnection queue that do not meet the Tier 2 requirement.
Planning Reserve Margin
The LTRA defines "planning reserve margin" as the difference between resources and demand,
divided by demand, expressed as a percentile.
Comparing the anticipated resource-based reserve margin to the reference planning margin yields
one of three risk determinations:
• High Risk: shortfalls may occur at normal peak conditions
• Elevated Risk: shortfalls may occur in extreme conditions
• Normal Risk: low likelihood of electricity supply shortfall
WECC Subregions
Table 5.2 presents the WECC subregions used for the NERC LTRA. In the data that follows, the
two subregions in Canada are not considered.
Table 5.2 —WECC Subregion Descriptions
Designation Subregio Country Peak
NW The rest of WECC,beyond the exceptions listed below United States Summer
SW Primarily Arizona and New Mexico United States Summer
CA/MX California/Mexico United States Summer
AB Alberta Canada Winter
BC British Columbia Canada Winter
LTRA WECC Assessment
Table 5.3 presents the WECC LTRA assessments for the three WECC subregions that include the
United States. Anticipated Reserve Margin is based on existing resources, firm transfers, and Tier
1 additions, less confirmed retirements. Prospective Reserve Margin adds existing resources
without firm transmission, or with other potential limitations, likely transfers, and Tier 2 capacity
additions, less unconfirmed retirements. Values that fall below the reference margin level (i.e.
planning target) are highlighted.
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Table 5.3 -NERC LTRA for Selected WECC Subregions
WECC-NW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Anticipated Reserve Margin(%) 38.7% 37.7% 34.1% 29.3% 23.3'! 17.00% 79% L79i 4.6
Prospective Reserve Margin(%) 39.9% 40.6% 37.8% 34.2% 30.051 25.7% 20.4% 18.4% 15.7% 13.95'
Reference Margin Level(%) 16.3% 15.8% 15.9% 15.4% 14.71-b 14.54/0 14.3% 14.2% 14.4% 13.8%
WECC-SW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Anticipated Reserve Margin(%) 36.9% 35.6% 31.8% 24.2% 17.4% 11.3%t 7.7% 0.2% -4.7% -8.7�E
Prospective Reserve Margin(%) 38.6% 40.1% 38.2% 31.1% 26.7% 20.4% 16.80/c 9.2% 4.9% 0.09:
Reference Margin Level(9�) 11.0% 10.8% 12.0% 11.7% 10.2% 10.1% 9.9% 9.7c46 10.8", 9
WECC-CA/MX
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Anticipated Reserve Margin(%) 45.8% 45.2% 38.4% 43.15-- 28.8% 29.6% 23.3% 25.0% 15.2%
Prospective Reserve Margin(%) 51.8% 55.1% 48.2% 62.5% 45.6% 57.9% 51.0% 59.0% 50.2% 47.3%
Reference Margin Level(9�) 17.4% 17.4% 16.4% 17.4% 16.6% 16.4% 16.1% 16.3% 14.9% 15.3%
As shown, the WECC-NW subregion that includes PacifiCorp's load meets the reference
margin with anticipated resources through 2030, and with prospective resources through the ten
year horizon. The WECC-SW subregion also meets the reference margin with anticipated
resources through 2030,but only has sufficient prospective resources through 2031. The WECC-
CA/MX region meets the reference margin with anticipated resources through 2033, and with
prospective resources through the ten year horizon. While this presents a relatively favorable view
of supply and demand, the LTRA definition of Tier 1 resources includes everything with an
interconnection agreement and/or power purchase agreement. Not all such resources will
ultimately be brought online in a timely manner. The factors identified the WECC WARA(supply
chain disruptions, interconnection queue, siting delays, and increased costs) can all derail projects
that are otherwise feasible.
Pacific Northwest Power Supply Adequacy Assessment
The Northwest Power and Conservation Council released its 2029 Adequacy Assessment in
August 2024.4 Starting in 2011, an annual loss-of-load-probability of up to five percent was
deemed adequate. Starting with the 2023 assessment a multi-metric framework of shortfall
frequency, duration, and magnitude was used. These metrics include:
• Loss of load events(LOLEV): limits the expected frequency of shortfall events to protect
against frequent use of emergency measures.
• Duration Value at Risk: limits shortfall duration to protect against tail-end (extreme)
duration use of emergency measures.
• Peak Value at Risk: limits maximum hour capacity shortfall to protect against tail-end
(extreme) magnitude of emergency measures.
• Energy Value at Risk: limits total annual energy shortfall to protect against tail-end
(extreme) annual aggregate use of emergency measures.
An adequate system must meet all of these metrics. The 2029 Adequacy Assessment is based on
the 2021 Northwest Power Plan, discussed below, with updates for expected changes through
4 Northwest Power and Conservation Council.Pacific Northwest Power Supply Adequacy Assessment for 2029.
August 2024.Available online at:https://www.nwcouncil.org/fs/18853/2024-4.pdf(accessed 12/18/2024)
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2029, including load growth, resource development, and transmission. Based on updated results
for adequacy in year 2029,the 2029 Adequacy Assessment concludes that power supply would be
adequate under reference conditions. This conclusion is in part based on coal plants changing to
natural gas, rather than retiring (including Jim Bridger 1 and 2, which were converted in 2024).
The 2029 Adequacy Assessment identifies two scenarios that could lead to reliability shortfalls.
First, if energy efficiency savings only meet the low end of the targeted quantity, shortfall risks
increase in the winter. Second, higher data center loads in the absence of commensurate resource
supply could lead to reliability shortfalls in both the winter and the summer.An additional potential
risk is related to the Boardman-to-Hemingway project which the 2029 Adequacy Assessment
assumes is operational by 2029, increasing transfer capability between Idaho and the Pacific
Northwest, as this upgrade is not part of PacifiCorp's 2025 IRP preferred portfolio. The metric
results from the 2029 Adequacy Assessment are provided in Table 5.4, with shortfalls highlighted
in orange.
Table 5.4—Northwest Power and Conservation Council 2029 Adequacy Assessment
Type Metric Threshold Reference Low End EE Higher Data Center
Frequency Winter LOLEV 0.1 0.022 0.35 1.294
Frequency Summer LOLEV 0.1 0.017 0.033 0.3
Duration Duration VaR 97.5 8 hours 0 1.5 20.6
Magnitude Peak VaR 97.5 1200 MW 0 1,567 3,076
Magnitude Energy Va R 97.5 9600MWh 0 4,196 196,324
Western Resource Adequacy Program (WRAP)
The WRAP is a regional reliability planning and compliance program, intended to help facilitate
region-wide resource adequacy, and initiated on behalf of the utilities that are part of the Western
Power Pool (formerly the Northwest Power Pool). WRAP allows for coordination and visibility
of resource needs and supply among the participants,taking advantage of the diversity and sharing
from pooling resources.
WRAP begins with regional analysis,as the program sets regional reliability metrics for upcoming
seasons, including planning reserve margins that are applied to loads and qualifying capacity
contributions that apply to resources. With those values in hand, utilities must secure resources
and, seven months prior to the start of a winter or summer season,must submit a forward showing
demonstrating they have resources and transmission to cover their load and planning reserve
margin requirements. Some time is provided to cover shortfalls before the season begins. Within
the season,an operational component allows those participants with a day-ahead resource shortfall
to call upon the program and receive incremental resources from participants who have a surplus.
WRAP is based on two seasons: summer(June through September)and winter(November through
March). Planning reserve margins vary by month, and also by region, as WRAP covers two
regions: the Pacific Northwest (primarily Oregon and Washington and British Columbia, with
parts of northern Idaho and Montana) and the Desert Southwest, including the remainder of Idaho,
Utah, Wyoming, Colorado, Nevada, and Arizona. Similarly, monthly qualifying capacity
contributions are calculated for each resource, and capture technology type, regional variations,
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and resource-specific performance. For example, wind and solar contributions incorporate a
resource's output during capacity critical hours(the highest load hours after netting out wind,solar,
and run of river hydro generation).
As of September 2024, the Western Power Pool Board of Directors has approved updates to the
WRAP tariff along with seven business practice manuals detailing of the program will operate.
WRAP is currently operational with non-binding requirements and has plans in place to enable
fully binding operations in Summer 2027 for participants that provide notice of their intent by
January 2026.All participants will be binding for Winter 2027-2028(i.e. starting November 2027).
PacifiCorp is currently participating in WRAP and is working with the Western Power Pool to
address a number of outstanding issues,including the interaction between WRAP and the CAISO's
Enhanced Day-Ahead Market(EDAM)and complexity from PacifiCorp's footprint spanning both
WRAP regions. While some issues remain, PacifiCorp's 2025 IRP includes modeling to capture
WRAP compliance requirements starting in 2028 and continuing through the study horizon. While
proxy resource selections within the 2025 IRP can only begin on January 1st of each year, actual
resource procurement could be targeted to the November 2027 start date to the extent necessary,
or short-term products could be used to address unmet requirements, if any.
Reliable Service through Unpredictable Weather and Challenging Market
Liquidity
PacifiCorp,other utilities, and power marketers who own and operate generation engage in market
purchases and sales of electricity on an ongoing basis to balance the system and maximize the
economic efficiency of power system operations. In addition to reflecting spot market purchase
activity and existing long-term purchase contracts in the IRP portfolio analysis, PacifiCorp
previous IRP modeling has included front office transactions (FOT). FOTs are proxy resources,
assumed to be firm,that represent procurement activity made on an on-going forward basis to help
PacifiCorp cover short positions. However, market transactions that are not based on a specified
source do not provide qualifying capacity for WRAP compliance.While other short-term products
exist, such as slices of hydropower projects on the Mid-Columbia or tolling agreements for
merchant-owned natural gas plants, there are relatively few such opportunities and there may be
significant competition for such products given rising demand and stricter resource adequacy
requirements under WRAP. With that in mind, for the 2025 IRP,PacifiCorp is not including short-
term market products as options for WRAP compliance.
WRAP compliance does not guarantee reliability, in particular a monthly qualifying capacity
contribution value does not ensure resources will be available to meet hourly requirements such as
the hourly balancing test in the EDAM. At the same time, PacifiCorp recognizes that increasing
coordination of spot market transactions through EIM, EDAM, and WRAP is likely to provide
significant economic benefits. To balance the limitations of market transactions for capacity and
reliability requirements and the benefits of market transactions for regional dispatch,the 2025 IRP
does not allow market purchases in certain key periods,but otherwise allows market purchases up
to transmission limits. During the summer WRAP season (June through September), market
purchases are not allowed from 4:00 p.m. to 12:00 a.m. on PacifiCorp's top five load days in each
month. Similarly, in the winter WRAP season (November through March), market purchases are
not allowed from 4:00 a.m. to 8:00 a.m. as well as 4:00 p.m. to 12:00 a.m., again on PacifiCorp's
top five load days in each month. For the 2025 IRP,PacifiCorp is also differentiating market prices
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within each month,to reflect historical patterns on the days used to derive the chaotic normal load
forecast and reflecting the same weather conditions used to develop wind and solar generation
profiles. In general, market prices are higher when load is high and wind and solar output is
relatively low, though market prices reflect region-wide conditions of PacifiCorp's supply and
demand is only a part. Market prices in EIM and EDAM will reflect the balance of supply-and-
demand, and surplus supply from PacifiCorp is likely to result in lower market clearing prices.
While this effect is not captured in PacifiCorp's hourly market price forecast, market sales for the
2025 IRP have been capped at historical average levels, since large surpluses would impact
pricing.
Aligned with review of the regional studies discussed above, and the historical market purchases
and transactions,the company will continue to refine its assessments of market depth and liquidity
for transactions to quantify the risk associated with the level of market reliance. Additional
description is provided in Volume I, Chapter 7 (Resource Options); also, see the sensitivities
discussion in Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling
and Portfolio Selection Results).
Planning for Load Changes as a Result of Climate Change
Recent weather-based reliability events throughout the United States have underscored the need
for utilities to consider the potential for increasingly extreme weather and the underlying reliability
challenges that may be caused as part of its planning process.PacifiCorp has accounted for climate
change within the 2025 IRP to assess the ways in which climate change may impact planning
assumptions.
The Company's load forecast is based on historical actual weather adjusted for expectations and
impacts from climate change. The historical weather is defined by the 20-year period of 2004
through 2023. The climate change weather uses the data from the historical period and adjusts the
percentile of the data to achieve the expected target average annual temperature and calculate the
HDD and CDD impacts and peak producing weather impacts within the energy forecast and peak
forecast, respectively. These temperature changes lead to higher summer peaks and lower winter
peaks, with increasing impacts across the study horizon. See Appendix A for additional detail
regarding how climate change is incorporated into the load forecast.
Weather-Related Impacts to Variable Generation
New for the 2025 IRP, all wind and solar generation profiles are based on historical weather
conditions on the same historical day underlying the load forecast. This captures the relationship
between load, wind, and solar that happened in recent history. Each month of the Company's
chaotic normal load forecast reflects the range of weather conditions experienced in the most
typical month from 2013-2022,while stochastic analysis for the 2025 IRP will reflect the range of
weather conditions experienced in every year from 2006-2023. The effect of extreme weather
events associated with climate change is an evolving area of research that is growing in importance
as renewable, intermittent resources dependent upon wind, solar, and hydrologic conditions
comprise an increasing proportion of utility resource portfolios. For the 2025 IRP, PacifiCorp is
not projecting specific climate impacts on wind and solar generation, but notes that recent history
may be more representative of future conditions than earlier conditions. As a result,reliability and
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system cost risks identified using inputs derived from recent historical years may be of greater
concern as an indicator of future risk.
Wildfire Impacts
Increased wildfire frequency associated with climate change is expected to have a range of impacts
to intermittent generation sources, including wind, solar, and hydro resources.
Wind generation sites in PacifiCorp's system are most likely to be subjected to fast moving range
fires.Impacts at wind generation sites from range fires are likely to be limited and short in duration,
as turbines and collector substations are surrounded by gravel surfaces that are fire resistant.
Sensitive turbine equipment is located far above the ground away from damaging heat sources.
Impacts to transmission lines and aboveground collector lines from range fires at wind generation
sites is also anticipated to be minor due to the limited fuels available to cause ignition to wooden
poles. Outage durations are likely to be short when operations staff is required to evacuate a site
in advance of a fire and to curtail generation as a precautionary measure.
Climate change also poses fire risks at solar generation sites, which are also likely to manifest as
range fires given solar projects are typically sited well away from substantial tree stands that could
block solar panels. Impacts could be significant depending on the amount of vegetation at a site,
as generating equipment is close to the ground close to potential fuel sources. If a range fire creates
sufficient heat to impact equipment, resumption of generation will be dependent on the ability to
obtain and install necessary replacement equipment.
Fire impacts at hydro generation sites will be driven primarily by impacts to transmission lines.
Hydro generation sites are typically in heavily forested terrain and serviced by only one or two
transmission lines. An intense forest fire can damage miles of transmission lines that can take
weeks to months to restore to service. If a fire threatens a hydro generation site, the site will be
proactively evacuated with generation units typically taken offline and the facility put into spill to
avoid potential instream flow impacts that could occur with an unplanned unit shutdown resulting
from impacts to local transmission lines. Generation units would be restarted as soon as possible
when conditions permit safe re-entry to provide generation locally until transmission service, if
interrupted, is restored. Fire damage to dams, water conveyance structures, and generating plants
is expected to be minimal. Some damage to local distribution lines and communication
infrastructure upon which hydro generation sources rely is also possible, which could impact
generation restoration timelines.
PacifiCorp outlines its wildfire mitigation strategies later in this document.
Extreme Weather Impacts
Climate change also has the potential to result in increased frequency and magnitude of extreme
weather events. Such changes can result in more frequent and intense precipitation events and
flooding, which could impact hydropower generation and change historic operating practices to
maintain flood control capabilities at projects where flood control benefits are part of project
operations. Like wildfire events, increased flooding has the potential to impact access to remote
hydro facilities. Increased precipitation and reduced snow water equivalent have the potential to
modify runoff patterns impacting hydro generation but is not expected to impact dam safety at
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PacifiCorp hydro facilities, which are subject to FERC dam safety requirements that ensure they
are able to safely pass probable maximum flood events. Increases in extreme weather that results
in more frequent flood events has the potential to increase debris loading in river systems and
reservoirs, potentially increasing generation downtime to remove debris that may reduce inflows
to hydro units or reduce flows through fish screens.
Changes to wind patterns and wind speeds, and changes in extreme high and low air temperatures
have the potential to impact wind and solar generation. Extreme high temperatures can raise
ground temperatures, which has the potential to impact collector system capacities at wind and
solar projects and reduce collector system carrying capacity, limiting output, similar to high
temperature impacts to high voltage transmission lines. However,these impacts are not anticipated
to be significant on wind energy resources given peak output is typically observed outside of
summer months. Increasing air temperatures result in lower air densities, which could negatively
impact wind energy output even if wind speeds are unchanged. Lower wind speeds in the summer
relative to historic experience because of extreme high temperatures is also possible.Wind turbines
in PacifiCorp's fleet generally are protected from extreme low temperatures given the conditions
in which they currently operate,and low temperature protection features are installed in PacifiCorp
turbines where weather conditions warrant their inclusion.
There is limited research on site-specific impacts from extreme weather events and thus how to
plan to improve the resiliency of intermittent generation resources. Resiliency will be enhanced as
planning to ensure site access occurs in response to observed changes in extreme weather events
and as more research is available to locally forecast impacts of climate change and extreme weather
so those impacts can be factored into the resource planning process.
Impacts on wind and solar energy
The impact on renewable energy generation due to extreme weather events and climate change is
an evolving topic. For conclusive trends of climate change impact, data collection specific to
geographic locations is critical. Climate impacts both the demand and supply side of energy. Due
to daily or seasonal changes the demand for energy patterns is changing. On the supply side due
to increasing temperatures and variability in climate parameters it impacts estimated energy
outputs of projects as well as operational costs. However, there are limited studies in the North
American region that quantitatively document the impact of a climate parameter on the future of
wind and solar energy.' Some broad impacts anticipated from climate change are noted below:'
Wind Energy
• Changes to wind speed: could impact energy assessments
• Changes in temperature: with increased temperatures the air density could reduce energy
outputs
• Changes in seasonal or daily wind: could disrupt correlation between wind energy and
grid load demand
• Rising sea levels: could damage offshore wind farm infrastructure
s Climate change impacts on the energy system:a review of trends and gaps.Cronin,J.,Anandarajah,G.&Dessens,
O. Climatic Change volume 151,August 2018.
6 Climate change impacts on renewable energy generation.A review of quantitative projections.Kepa Solaun,
Emilio Cerda.Renewable and Sustainable Energy Reviews
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PACIFICORP—2025 IRP CHAPTER 5—RELIABILITY AND RESILIENCY
Solar Energy
• Changes in mean temperatures: increased global temperatures could reduce cell
efficiency
• Changes in solar irradiation, dirt, snow,precipitation etc.: increase in these variables
could reduce energy output
Integration of energy storage with wind and solar projects is a way to help make use of generated
energy more efficiently.
Wildfire Risk Mitigation
PacifiCorp's Wildfire Mitigation Plans (WMPs) are designed to meet regulatory requirements
while delivering safe and reliable power. These plans focus on enhancing situational awareness,
implementing robust operational practices, and hardening the power system to mitigate wildfire
risks while balancing customer and community impacts.'
PacifiCorp Wildfire Mitigation Plan Regulatory Compliance
PacifiCorp meets regulatory requirements through the submittal of Wildfire Mitigation Plans
(WMPs) with the specific regulatory alignments for each state stated below:
1. California: The WMP complies with California Senate Bill 901 and the California Public
Utilities Commission(CPUC)provisions under Section 8386.
2. Idaho: The WMP was submitted in accordance with Idaho Public Utilities Commission
Order No. 36045.
3. Utah: The WMP adheres to Utah Administrative Code R746-315-2, effective June 1,
2023, and complies with Subsection 54-24-201.
4. Oregon: The WMP meets the requirements set forth in Oregon Administrative Rule 860-
300-0040.
5. Washington: The WMP was submitted on October 31, 2024, and compliance with
statutory requirements was confirmed by the Washington Utilities and Transportation
Commission as complying with the Revised Code of Washington(RCW) 80.28.440.
Although Wyoming does not have regulatory requirements for a wildfire mitigation plan,
PacifiCorp has proactively filed one in conjunction with the general rate case.
Core Principles
All WMPs are publicly accessible via the PacifiCorp Wildfire Mitigation Plan website (linked
here). These plans detail the investments and strategies for constructing, maintaining, and
operating electrical lines and equipment for wildfire mitigation projects and programs. While there
Wildfire mitigation and impacts were discussed in the 2025 IRP public input meeting series and stakeholder
feedback. See Appendix M,stakeholder feedback form#18(Wyoming Office of Consumer Advocate).
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are state-specific requirements,the core strategy across all six states remains consistent,guided by
the following principles:
• Situational Awareness and Operational Readiness: Implementing systems that
enhance situational awareness, and operational readiness is crucial for mitigating fire
risks and their impacts.
• Operational Practices: Minimizing the impact of fault events through rapid isolation
using advanced equipment and trained personnel.
• System Hardening: Reducing the frequency of ignition events by engineering more
resilient systems that experience fewer faults.
Balancing Mitigation and Community Impact
PacifiCorp is committed to balancing wildfire risk mitigation with the needs of customers and
communities. Adjustments to power system operations, such as modifying protective device
settings and testing protocols, are carefully considered to reduce wildfire risks. These measures
are applied selectively to avoid unnecessary disruptions to the power supply.
The wildfire mitigation program approach includes deploying advanced technologies like fault
indicators and assessing outages to inform short-term mitigation projects. These efforts are
designed to enhance safety while maintaining reliable service.
PacifiCorp's Wildfire Mitigation Plans (WMPs) reflect the Company's dedication to balancing
costs,benefits, operational impacts, and risk mitigation with the goal to provide safe,reliable, and
affordable electric service,prioritizing the well-being of customers and communities.
Transmission-Based Reliability
PacifiCorp is required to meet mandatory FERC, NERC, and WECC reliability standards and
planning requirements. The operation of PacifiCorp's transmission system also responds to
requests issued by California Independent System Operator (CAISO) RC West as the NERC
Reliability Coordinator for PacifiCorp. The company conducts annual system assessments to
confirm minimum levels of system performance during a wide range of operating conditions, from
serving loads with all system elements in service to extreme conditions where portions of the
system are out of service. Factored into these assessments are load growth forecasts, operating
history, seasonal performance, resource additions or removals, new transmission asset additions,
and the largest transmission and generation contingencies. Based on these analyses, PacifiCorp
identifies any potential system deficiencies and determines the infrastructure improvements
needed to reliably meet customer loads. NERC planning standards define reliability of the
interconnected bulk electric system in terms of adequacy and security. Adequacy is the electric
system's ability to meet aggregate electrical demand for customers at all times. Security is the
electric system's ability to withstand sudden disturbances or unanticipated loss of system elements.
Increasing transmission capacity often requires redundant facilities to meet NERC reliability
criteria.
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With the increasing number of variable resources added to the grid throughout the west,
PacifiCorp's ability to meet federal reliability directives depends increasingly on an interconnected
transmission system across the western states and on the ability to move electricity throughout the
six states served by the company. PacifiCorp's planning process ensures that the company is
developing a portfolio that balances sufficient supply to serve all PacifiCorp customers with
sufficient resources and transmission to ensure that electricity can be moved from generation
sources to the communities served.
PacifiCorp's interconnection to other balancing authority areas and participation in the Energy
Imbalance Market provide access to markets and promote affordable and reliable service to
PacifiCorp's customers. Further, PacifiCorp's transmission capacity provides benefits to
customers by increasing reliability and allowing additional generation to interconnect to serve
customer load, as well as allowing PacifiCorp flexibility in designating generating resources for
reserve capacity to comply with mandatory reliability standards.
Federal Reliability Standards
The Energy Policy Act of 2005 included expanded reliability-related elements of the federal
regulatory structure and directed the FERC to institute mandatory reliability standards that all users
of the bulk electric system(BES)must follow.
FERC delegated the authority to NERC to develop reliability standards to ensure the safe and
reliable operation of the BES in the United States under a variety of operating conditions. These
standards are a federal requirement and are subject to oversight and enforcement by the WECC,
NERC, and FERC. PacifiCorp is subject to compliance audits every three years and may be
required to prove compliance during other reliability initiatives or investigations.
The transmission planning standards (TPL Standards), found within the NERC transmission
reliability standards, specify transmission system planning performance requirements to develop
a BES that will operate reliably over a broad spectrum of system conditions. They also require
study of a wide range of probable contingencies in short-term (1-2 years), medium term (5 years)
and long-term(10-20 years)scenarios to ensure system reliability.Together with regional planning
criteria, such as those established by the NERC/WECC, and utility-specific planning criteria, the
TPL Standards define the minimum transmission system requirements to safely and reliably serve
customers.
In addition to the TPL Standards, PacifiCorp is also required to comply with FERC Order 1000 as
detailed in Attachment K of the Open Access Transmission Tariff (GATT) which requires
PacifiCorp to participate in regional transmission planning processes that satisfy the transmission
planning principles of FERC Order 890 and produce a regional transmission plan. To meet this
requirement PacifiCorp is a member of the NorthernGrid regional planning association. The
development of the regional transmission plan ensures the regional reliability is maintained and/or
enhanced with the addition of new planned generation and transmission projects while reliably
serving PacifiCorp customers. In 2024, FERC issued Order 1920 which will further expand
regional planning processes, including a requirement for a long-term (20 year) regional plan.
PacifiCorp is working with NorthernGrid members to draft tariff revisions to outline the expanded
process in preparation for the FERC required compliance filing in August 2025.
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Power Flow Analyses and Planning for Generator Retirements
PacifiCorp transmission planning has performed various coal unit retirement assessments
analyzing potential impacts to the transmission system. These studies are performed outside of the
IRP process under PacifiCorp's OATT processes which includes either 1) a customer request to
perform a consulting study; or 2) a customer request to un-designate a network resource which
then triggers a system impact and facilities study if the study determines that mitigations are
required due to retirement.
Past studies have found that a number of factors are critical in determining transmission system
impacts and necessary mitigation, if any. These factors include: 1) location of the unit(s) to be
retired, 2) the number of units being retired, 3) the size of the units being retired, 4) year of
retirement, and 5) location, size, and type of replacement resources, if any. Based on the location,
number of units, and size of the retired unit/s, studies can identify if the retirement results in either
thermal or voltage issues on the transmission system. A retirement of a coal unit may result in
voltage issues due to lack of reactive support that was previously provided by the retired unit/s. A
retirement may also result in thermal overload of the transmission system due to changes in the
flows post unit retirement. As such, until official notification to PacifiCorp transmission of coal
unit designation/retirement is received, all such coal retirement analysis is considered preliminary.
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CHAPTER 6 - LOAD AND RESOURCE BALANCE
CHAPTER HIGHLIGHTS
• New for the 2025 IRP, PacifiCorp is calculating its capacity position based on Western
Resource Adequacy Program(WRAP)compliance requirements,with binding operations under
the program expected to begin by 2028. WRAP participants with projected resource shortfalls
on a day-ahead basis will be able to purchase from WRAP participants with excess supply.
• Every resource has a qualifying capacity contribution (QCC) for each month of the summer
(June-September) and winter (November-March) seasons. These values are calculated by
WRAP based on resource-specific historical performance and are based on the loads and
resource mix of the regional participants. These values are updated by WRAP ahead of each
compliance season.
• Seven months prior to the start of each season, WRAP participants must make a forward
showing, demonstrating that the QCC for their resources is sufficient to meet their peak load
plus a monthly planning reserve margin determined by WRAP.
• While WRAP is projected to enhance reliability by providing priority access to supply from
other participants, the monthly QCC values do not ensure a utility will be reliable or have
sufficient resources to meet its requirements from hour to hour, so hourly analysis of the load
and resource balance is also necessary.
• On both a capacity and energy basis, PacifiCorp calculates load and resource balances from
existing resources, forecasted loads and sales, and reserve requirements.
• The company's load obligation is calculated based on projected load less distributed generation,
energy efficiency savings, and demand response, including interruptible load.
• A distributed generation study prepared by DNV produced estimates on distributed generation
penetration levels specific to PacifiCorp's six-state territory. The study provided expected
penetration levels by resource type, along with high and low penetration sensitivities.
PacifiCorp's 2025 IRP load and resource balance reflects base case distributed generation
penetration levels as a reduction in load.
• Relative to WRAP compliance requirements, PacifiCorp's system is capacity deficient (before
adding proxy resources other than energy efficiency, and without considering short-term
capacity procurement, i.e. market purchases) in the summer beginning in 2026, and the winter
peaks throughout the planning horizon.
• The uncertainty in the company's load and resource balance is increasing as PacifiCorp's
resource portfolio and customer demand evolve over time. PacifiCorp's 2025 IRP reflects
renewable resource generation profiles based on the same patterns of historical weather
conditions used to develop its load forecasts, both on a normalized basis and for stochastic
analysis. While adjustments to account for climate change are included in the base forecast,
customer demand may be further influenced by climate change directly as well as indirectly
through electrification, with uncertain impacts on future demand. These resources and load
relationships ultimately drive the frequency and characteristics of the relatively extreme
conditions that are most likely to trigger reliability shortfalls.
This chapter presents PacifiCorp's assessment of its load and resource balance. PacifiCorp's long-
term load forecasts (both energy and coincident peak load) for each state and the system are
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
summarized in Volume II, Appendix A (Load Forecast Details). The summary-level system
coincident peak is presented first, followed by a profile of PacifiCorp's existing resources.Finally,
load and resource balances for capacity are presented. These balances are composed of a year-by-
year comparison of projected loads against the existing resource base, assumed coal unit
retirements and incremental new energy efficiency savings from the preferred portfolio, before
adding new generating resources.
System Coincident Peak Load Forecast
System Coincident Peak Load Forecast
The system coincident peak load is the annual maximum hourly load on the system. The 2025 IRP
relies on PacifiCorp's May 2024 load forecast. Table 6.1 shows the annual summer coincident
peak load stated in megawatts (MW) as reported in the capacity load and resource balance before
any load reductions from energy efficiency. The system summer peak load grows at a compound
growth rate (CAGR) of 1.91 percent over the period 2025 through 2044.
Table 6.1—Forecasted System Summer Coincident Peak Load in Megawatts,Before Energy
Efficient (MW)
2025 2026 2027 2028 2029 2030 2031 2032 2033 203
System 11,374 11,410 11,708 12,085 12,303 12,501 12,824 12,961 13,156 13,358
2035 2036 037 2038 1, 2039 h 2040 2041 2042 n& 2043 2044
System 13,603 13,919 14,190 14,479 14,764 15,065 15,368 15,785 16,026 16,307
Existing
Thermal Plants
Table 6.2 lists PacifiCorp's existing coal-fueled plants and Table 6.3 lists existing natural-gas-
fueled plants.The"End of Coal-fired Operation"reflects the year a resource must retire or converts
to natural gas (if option is available) as reflected in modeling inputs.
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Table 6.2 — Coal-Fired Plants
PacifiCorp Nameplate
Plant Percentage State Capacity End of Coal-fired Operation
Share(a/o) (AINV)
Colstrip 3 10 Montana 74 2025 (Transfer capacity to unit 4)
trip Cols4 10* Montana 74 2029(PacifiCorp exit)
Craig 1 19 Colorado 82 2025 (Assumed end of life)
Craig 2 19 Colorado 79 2028 (Assumed end of life)
Dave Johnston 1 100 Wyoming 99 2028 (Gas conversion option)
Dave Johnston 2 100 Wyoming 106 2028 (Gas conversion option)
Dave Johnston 3 100 Wyonnung 220 2027(Retire: Clean air compliance)
Dave Johnston 4 100 Wyoming 330
Hayden 1 24 Colorado 44 2028 (Assumed end of life)
Hayden 2 13 Colorado 33 2027(Assumed end of life)
Hunter 1 94 Utah 418
Hunter 2 60 Utah 269
Hunter 3 100 Utah 471
Huntington 1 100 Utah 459
Huntington 2 100 Utah 450
Jim Bridger 3 67 Wyoming 349
Jinn Bridger 4 67 Wyoming 351
Naughton 1 100 Wyoming 156 2025 (Gas conversion option)
Naughton 2 100 Wyoming 201 2025 (Gas conversion option)
Wyodak 8o Wyoming 268
TOTAL-Coal 4,533
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*PacifiCorp's share of Colstrip 4 is projected to include its current ownership of Colstrip 3 starting
in 2026.
Table 6.3 —Natural Gas-Fired Plants
PacifiCorp Nameplate
Plant Percentage tate Capacity
Share (%)
Chehalis 100 Washington 500
Currant Creek 100 Utah 540
Gadsby 1 100 Utah 64
Gadsby 2 100 Utah 69
Gadsby 3 100 Utah 105
Gadsby 4 100 Utah 40
Gadsby 5 100 Utah 40
Gadsby 6 100 Utah 40
Hermiston 100 Oregon 237
Jim Bridger 1 67 Wyoming 354
Jim Bridger 2 67 Wyoming 359
Lake Side 100 Utah 580
Lake Side 2 100 Utah 677
Naughton 3 100 Wyoming 247
TOTAL — Natural Gas 3,852
Renewable Resources
Wind
PacifiCorp either owns or purchases under contract 5,154 MW of wind resources. Table 6.4 shows
existing (or under construction) wind facilities owned by PacifiCorp, while Table 6.5 shows
existing wind power-purchase agreements (PPAs).
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Table 6.4—Owned Wind Resources
Utility-Owned Wind Projects State Capacity(MW)
Goodnoe Hills East WA 94
Leaning Juniper WA 101
Marengo I WA 156
Marengo II WA 78
Cedar Springs 2 WY 199
Dunlap 1 WY 111
Ekola Flats 1 WY 250
Foote Creek I WY 41
Glenrock I WY 99
Glenrock III WY 39
High Plains WY 99
McFadden Ridge 1 WY 29
Pryor Mountain WY 240
Rolling Hills WY 99
Seven Mile Hill WY 99
Seven Mile Hill II WY 20
TB Flats 1-2 WY 500
Foote Creek II-IV WY 43
Rock Creek I WY 190
Rock Creek II WY 400
Rock River WY 50
TOTAL—Owned Wind 2,937
Table 6.5—Non-Owned Wind Resources
Power Purchase Agreements State PPA or QF Capacity(MW)
Wolverine Creek ID PPA 65
Chopin-Schumann WA QF 8
Cedar Springs I WY PPA 199
Cedar Springs III WY PPA 133
Three Buttes Power WY PPA 99
Top of the World WY PPA 200
Meadow Creek Project Five Pine ID QF 40
Meadow Creek Project North Point ID QF 80
Latigo UT QF 60
Mountain Wind I UT QF 61
Mountain Wind 11 UT QF 80
Power County Park North UT QF 23
Power County Park South UT QF 23
Spanish Fork Park 2 UT QF 19
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Tooele 1 and 2 UT QF 3
Big Top WA QF 2
Butter Creek Power WA QF 5
Chopin WA QF 10
Four Corners WA QF 8
Four Mile Canyon WA QF 10
Orchard 1 WA QF 10
Orchard 2 WA QF 10
Orchard 3 WA QF 10
Orchard 4 WA QF 10
Oregon Trail WA QF 10
Pacific Canyon WA QF 8
Sand Ranch WA QF 10
Three Mile Canyon WA QF 8
Wagon Trail WA QF 3
Ward Butte WA QF 7
BLM Rawlins WY QF 0.1
Pioneer Park I WY QF 80
Cedar Creek ID PPA 152
Anticline Wy PPA 101
Boswell Wy PPA 320
Cedar Springs IV WY PPA 350
TOTAL—Purchased Wind 2217
Solar
PacifiCorp has a total of 97 solar projects under contract representing 3,615 MW of nameplate
capacity. Of these, two recently signed solar resources also include a total of 550 MW of battery
storage. Table 6.6 list solar power purchase agreements, and through Table 6.7 through Table 6.9
list solar qualifying facilities for each relevant state.
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Table 6.6—Solar Power Purchase Agreements
Power Purchase Agreements
Resource State Solar Capacity Storage Capacity
M M
Black Cap OR 2 -
Millican OR 60 -
Old Mill OR 5 -
Oregon Solar Incentive Project OR 9 -
Prineville OR 40 -
Appaloosa Solar IA UT 120 -
Appaloosa Solar IB UT 80 -
Castle Solar(Retail 1) UT 20 -
Castle Solar(Retail 2) UT 20 -
Cove Mountain UT 58 -
Cove Mountain II UT 122 -
Elektron Solar 20Yr UT 10 -
Elektron Solar 25Yr UT 70 -
Faraday UT 525 150
Graphite UT 80 -
Green River UT 400 400
Hornshadow Solar I UT 100 -
Hornshadow Solar II UT 200 -
Horseshoe UT 75 -
Hunter UT 100 -
Milford UT 99 -
Pavant III UT 20 -
Rocket UT 80 -
Sigurd UT 80 -
TOTAL—Power Purchase Agreements 2375 550
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Table 6.7— Solar Qualifying Facilities, Oregon
Oregon Qualifying Facilities
Resource Solar Capacity(MW) Storage Capacity(MW)
7 Mile Solar 1 -
Adams 10 -
Antelope Creek Solar 2 -
Bear Creek 10 -
Black Cap II 8 -
Blackwell Creek Solar* 1 -
Bly 8 -
Buckaroo Solar 1* 3 -
Buckaroo Solar 2* 3 -
Canyonville Solar I* 1 -
Can onville Solar 2* 2 -
Chapman Creek Solar* 3 -
Cherry Creek Solar* 0.4 -
CHoquin Solar 10 -
Elbe 10 -
Goodling Corimmmity Solar* 1 -
Green Solar* 3 -
Hay Creek Solar* 0.6 -
Klamath Falls Solar 1 0.8 -
Klamath Falls Solar 2 3 -
Linkville Solar* 3 -
Mernll 10 -
Norwest Energy 2(Neff) 10 -
Norwest Energy 4(Bonanza) 6 -
Norwest Energy 7(Eagle Point) 10 -
Norwest Energy 9 Pendleton 6 -
OR Solar 2,LLC(Agate Bay) 10 -
OR Solar 3,LLC(Turkey MR) 10 -
OR Solar 6,LLC(Lakeview) 10 -
OR Solar 8,LLC(Dairy) 10 -
Orchard Knob Solar 2 -
OSLH Collier 10 -
Pilot Rock Solar 1* 3 -
Pilot Rock Solar 2* 3 -
Pine Grove Solar 1 -
Round Lake Solar 1 -
Skysol 55 -
Solorize Rogue* 0.1 -
Sunset Ride Solar 2 -
Tumbleweed 10 -
Tutuilla Solar* 2 -
Waffowa County* 0.4 -
Whisky Creek Solar* 0.2 -
Wocus Marsh Solar* 0.9 -
Wood River Solar* 0.4 -
Woodline Solar 8 -
TOTAL—Oregon Solar QF Resources 264 0
*New project added in 2025 IRP
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Table 6.8—Solar Qualifying Facilities, Utah
Utah Qualifying Facilities
Resource Solar Capacity(MW) Storage Capacity(MW)
Beryl 3 -
Buckhorn 3 -
CedarValle 3 -
Enterprise 80 -
Escalante I 80 -
Escalante II 80 -
Escalante III 80 -
Ewauna 1 -
Ewauna II 3 -
Granite Mountain-East 80 -
Granite Mountain-West 50 -
GranitePeak 3 -
Greenville 2 -
Iron Springs 80 -
Laho 3 -
Mflford 2 3 -
Milford Flat 3 -
Pavant 50 -
Pavant II 50 -
Quichapa I 3 -
Quicha a II 3 -
Quichapa III 3 -
Red Hill 80 -
South Mflford 3 -
SunEl 3 -
SunE2 3 -
SunE3 3 -
Three Peaks 80 -
TOTAL—Utah Solar QF Resources 838 0
Table 6.9— Solar Qualifying Facilities, Wyoming
Wyoming Qualifying Facilities
Resource Solar Capacity(MW) Storage Capacity(MW)
*Sae 20 -
Sage II 20 -
Sage I1I 18 -
Sweetwater 80 -
TOTAL—Wyoming Solar QF Resources 138 0
Geothermal
PacifiCorp owns and operates the Blundell geothermal plant in Utah,which uses naturally created
steam to generate electricity. The plant has a net generation capacity of 34 MW. Blundell is a fully
renewable, zero-discharge facility. The bottoming cycle, which increased the output by 11 MW,
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
was completed at the end of 2007. The Oregon Institute of Technology has a new small qualifying
facility (QF) using geothermal technologies to produce renewable power for the campus that is
rated at 0.28 MW. PacifiCorp also has a power purchase agreement with the 20 MW Soda Lake
geothermal project located in Nevada, which became operational in November 2019.
BiomassBiogas
PacifiCorp has biomass/biogas agreements with 12 projects totaling approximately 80 MW of
nameplate capacity.
Distributed Generation Resources
Table 6.10 provides a breakdown of distributed generation capacity and customer counts from data
collected as of March 31, 2024. In addition to resources, PacifiCorp's customers also have over
60 MW of battery storage capacity. For forecasted growth in distributed generation and storage,
please refer to Volume II, Appendix L (Distributed Generation Study).
Table 6.10—Distributed generation Customers and Ca aci
Fuel Solar Wind Gas' Hydro Mixed'
Nameplate(kW) 772,160 847 784 96S 1,233
Capacity(percentage of total) 99.51% 0.11% 0.10% 0.12% 0.16
Number of customers 86,449 192 1 21 63
Customer(percentage of total) 99.68% 0.22% 0.00% 0.02% 0.07
'Gas includes:biofuel,waste gas,and fuel cells
'Mixed includes projects with multiple technologies, one project is solar and biogas and the others are solar and
wind
Energy Storage
In addition to the battery storage contracted with solar resources listed in Table 6.6 PacifiCorp has
existing or committed battery storage projects totaling approximately 523 MW of nameplate
capacity, as shown in Table 6.11.
Table 6.11 —Storage Resources
Power Purchase Agreements/ State Technology Capacity(MW)
Exchanges
Domin uez Storage* UT Battery 200
Enterprise* UT Battery 80
Escalante* UT Battery 80
Granite Mountain* UT Battery 80
Iron Springs* UT Battery 80
Pan itch UT Battery 1
Oregon Institute of Technology OIT OR Battery 2
TOTAL—Purchased Battery 523
*New project added in 2025 IRP
Hydroelectric Generation
PacifiCorp owns or purchases over 1,200 MW of hydroelectric generation capacity. In addition to
being non-emitting generation sources hydro resources provide various operational benefits that
can include flexible generation, spinning reserves, and voltage control. PacifiCorp-owned
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
hydroelectric plants are located in California, Idaho, Montana, Oregon, Washington, Wyoming,
and Utah.
The amount of electricity available from hydroelectric plants is dependent upon a number of
factors, including the water content of snowpack accumulations in the mountains upstream of its
hydroelectric facilities and the amount of precipitation that falls in its watershed. Operational
limitations of the hydroelectric facilities are affected by varying water levels, licensing
requirements for fish and aquatic habitat, and flood control.
Table 6.12 —PacifiCorp Hydroelectric Generation Facilities
Plant River System I State Capacity M
East-Owned
Cutler Bear UT 29
Grace Bear UT 33
Oneida Bear UT 27.9
Soda Bear UT 14
Small East 1 Other UT 20.5
West-Owned
Bend Other OR 1
Big Fork Other MT 4.6
Swift 1 21 Lewis WA 263.6
Yale Lewis WA 163.6
Merwin Lewis WA 151
Clearwater 1 N. Umpqua OR 17.9
Clearwater 2 N. Umpqua OR 31
Fish Creek N. Umpqua OR 10.4
Lemolo 1 N. Umpqua OR 32
Lemolo 2 N. Umpqua OR 38.5
Slide Creek N. Umpqua OR 18
Soda Springs N. Umpqua OR 11.6
Toketee N. Umpqua OR 45
Eagle Point Rogue OR 2.8
Pros ect 1 Rogue OR 4.6
Prospect 2 Rogue OR 36
Prospect 3 Rogue OR 7.7
Prospect 4 Rogue OR 0.9
Fall Creek Other OR 2
Wallowa Falls Other OR 1.1
Total Owned 968
Qualifying Facilities F
Q F Various CA 9.4
QF Various ID 22.7
F Various OR 40
F Various UT 2.2
F Various WA 2.9
Mid-Columbia Columbia WA 170
Total QF 247
Total Hydroelectric 1215
11 Includes Ashton,Paris,Pioneer,Weber, Stairs,Granite,Veyo, Sand Cove,Viva Naughton,and Gunlock.
21 Cowlitz County PUD owns Swift No. 2, and is operated in coordination with other Lewis River projects by
PacifiCorp.
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Demand-Side Management/Distributed Generation
For resource planning purposes, PacifiCorp classifies demand-side management(DSM)resources
into four categories, or"classes." These resources are captured through programmatic efforts that
promote efficient electricity use through various intervention strategies, aimed at changing energy
use during peak periods(load control),timing(price response and load shifting), intensity (energy
efficiency), or behaviors (education and information). The four categories include:
• Demand Response—Resources from fully dispatchable or scheduled firm capacity
product offerings/programs: 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 timing and persistence of the load reduction is
involuntary on their part within the agreed upon limits and parameters of the program.
Modeling includes program drop-opt rate and event non-performance rate assumptions to
account for program parameters. 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 particular program design or event
noticing requirements). Savings are typically only sustained for the duration of the event
and there may also be return energy associated with the program. These are considered
Class 1 DSM resources.
• Energy Efficiency—Resources from non-dispatchable, firm energy and capacity
product offerings/programs: Energy efficiency programs are energy and related capacity
savings which are achieved through facilitation of technological advancements in
equipment, appliances, structures, or repeatable and predictable voluntary actions on a
customer's part to manage the energy use at their business or home. These programs
generally provide financial incentives or services to customers to improve the efficiency of
existing or new residential or commercial buildings through: (1) the installation of more
efficient equipment, such as lighting,motors,air conditioners,or appliances; (2)increasing
building efficiency, such as improved insulation levels or windows; or (3) behavioral
modifications, such as strategic energy management efforts at businesses. The savings are
considered firm over the life of the improvement or customer action. These are considered
Class 2 DSM resources.
• Price Response and Load Shifting—Resources from price-responsive energy and
capacity product offerings/programs: Price response and load shifting programs seek to
achieve short-duration (hour by hour) energy and capacity savings from actions taken by
customers voluntarily,based on a financial incentive or signal.As a result of their voluntary
nature, participation tends to be low and savings are less predictable, making these
resources less suitable to incorporate into resource planning, at least until their size and
customer behavior profile provide sufficient information needed to model and plan for a
reliable and predictable impact. The impacts of these resources may not be explicitly
considered in the resource planning process; however, they are captured naturally in long-
term load growth patterns and forecasts. Program examples include time-of-use pricing
plans, critical peak pricing plans, and inverted block tariff designs. Savings are typically
only sustained for the duration of the incentive offering and, in many cases, loads tend to
be shifted rather than being avoided. These are considered Class 3 DSM resources.
122

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
• Education and Information—Non-incented behavioral-based savings achieved
through broad energy education and communication efforts: Education and
information programs promote reductions in energy or capacity usage through broad-based
energy education and communication efforts.The program objectives are to help customers
better understand how to manage their energy usage through no-cost actions such as
conservative thermostat settings and turning off appliances, equipment, and lights when
not in use. These programs are also used to increase customer awareness of additional
actions they might take to save energy and the service and financial tools available to assist
them. These programs help foster an understanding and appreciation of why utilities seek
customer participation in other programs. Similar to price response and load shifting
resources, the impacts of these programs may not be explicitly considered in the resource
planning process; however, they are captured naturally in long-term load growth patterns
and forecasts. Program examples include company brochures with energy savings tips,
customer newsletters focusing on energy efficiency, case studies of customer energy
efficiency projects, and public education and awareness programs. These are considered
Class 4 DSM resources.
PacifiCorp has been operating successful DSM programs since the late 1970s. Over time,
PacifiCorp's DSM acquisition has grown in investment levels, state presence, breadth of DSM
resources pursued and resource planning considerations.Work continues on the expansion of cost-
effective program portfolios and savings opportunities in all states while at the same time adapting
programs and measure baselines to reflect the impacts of advancing state and federal energy codes
and standards. In Oregon, PaciflCorp continues to work closely with the Energy Trust of Oregon
to help identify additional resource opportunities, improve delivery and communication
coordination, ensure adequate funding, and provide company support in pursuit of DSM resource
targets.
Table 6.13 summarizes PacifiCorp's existing DSM programs,their assumed impact, and how they
are treated for purposes of incremental resource planning. Note that since incremental energy
efficiency is determined as an outcome of resource portfolio modeling and is characterized as a
new resource in the preferred portfolio,existing energy efficiency in Table 6.13 is shown as having
zero MW.I Similarly, demand response resources available to the preferred portfolio, are
characterized as incremental to Table 6.13. For a summary of current DSM program offerings in
each state, refer to Volume II, Appendix D (Demand-Side Management Resources).
1 The historical effects of previous energy efficiency savings are captured in the load forecast before the modeling for
new energy efficiency.
123

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Table 6.13 —Ex sting DSM Resource Summary
as
Program Energy Savings or Included
Description Capacity at Generator Existing Resources for
2025-2045 Period
Residential/small
commercial air 135 MW summer'/ Yes.
conditioner load
control
Irrigation load 200 MW summer Yes.
Demand management
Response Interruptible 136 MW summer Yes.
contracts
Wattsmart® 32 MW summer Yes.
Batteries
Wattsmart® 45 MW summer Yes.
Business
PacifiCorp and No.Energy efficiency programs are
Energy modeled as resource options in the
Efficiency Energy Trust of 0 MW portfolio development process and
Oregon programs included in the preferred portfolio.
Energy and capacity
impacts are not No.Historical savings from customer
Time-based pricing available/measured responses to pricing signals are reflected
Price Response in the load forecast.
and Load
Shifting Energy and capacity
Inverted rate impacts are not No.Historical savings from customer
response to pricing structure is reflected
pricing available/measured
in load forecast.
Education and Energy and capacity No.Historical savings from customer
Information Energy education impacts are not participation are reflected in the load
available/measured forecast.
1 A/C load control is based on long duration event characterization which assumes 50%cycling of ACs.A faster event(<1 hr)is
characterized as 270 MW within the model.
Distributed Generation Forecast
For the 2025 IRP, PacifiCorp contracted with DNV to update the assessment of distributed
generation (DG)2 penetration with new market, policy, and incentive developments.3°4 The study
provided a forecast of adoption of non-utility owned, behind-the-meter (BTM) customer
generation resources in each of the six states served by PacifiCorp. Specific technologies studied
included solar photovoltaic, photovoltaic solar coupled with battery storage, small-scale wind,
small-scale hydro, and combined heat and power(CHP)for both reciprocating engines and micro-
turbines.
2 In the 2023 IRP,this study was referred to as the"Private Generation"assessment.
3 See Appendix L(Distributed Generation Study).
4 PacifiCorp's and DNV's decisions in the development of the DG study were topics of discussion in the 2025 IRP
public input meeting series and stakeholder feedback.
See Appendix M,stakeholder feedback form#6(Renewable Northwest).
See Appendix M,stakeholder feedback form#17(Oregon Public Utility Commission).
See Appendix M,stakeholder feedback form#26(Vote Solar).
124

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
DNV estimates approximately 4.18 gigawatts (GW) of DG capacity will be installed in
PacifiCorp's service area by 2043 in the base case scenario. As shown in Figure 6.1, the low and
high scenarios project a cumulative installed capacity of 3.12 GW and 4.87 GW by 2043,
respectively. The main drivers between the different scenarios include variation in technology
costs, system performance, and electricity rate assumptions. The Inflation Reduction Act of 2022
(IRA) extends tax credits for distributed generation that creates favorable economics for adoption
and is incorporated into each case. The DNV study identifies expected levels of customer-sited
DG, which is applied as a reduction to PacifiCorp's forecasted load for IRP modeling purposes
and informs customer cited demand response battery potential for the conservation potential
assessment(CPA).
See Appendix L for the full DNV Distributed Generation report.
Figure 6.1 —Cumulative Historical and New Capacity Installed by
Scenario (MW-AC), 2024-2043
5,000
4,500
4,000
i
i
3,500 dop i
� � y
Q 3,000 — 00
i
2,500 i
2,000
�6 i
1,500
E
v 1,000
500
0
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�O if 1 O 1 O 10 �O 1 O 1 O �O �O 1 O �O �O 1 O LO �O �O �O 'O 4O 4O 'O rO �O �O rO
— — 2022 Study Historical Low Base —High
Power-Purchase Agreements
PacifiCorp also meets capacity and energy requirements through long-term firm contracts. Figure
6.2 presents the contract capacity in place for 2025 through 2045. As shown, major capacity
reductions in solar purchases, wind purchases, and QF contracts occur. For planning purposes,
PacifiCorp assumes interruptible load contracts and demand response are extended through the
end of the IRP study period. After their current contract terms, QF contracts are extended at a
reduced level that reflects the historical renewal rate of 75%. All contracts are shown at their peak
capacity contribution levels.
125

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Figure 6.2—Contract Capacity in the 2025 IRP Summer Load and Resource Balance
2,000
1,800
1,600
1,400
1,200
1,000
800
400 - - - - - - - -
200 - -
0
oti 'o oy^ oti� oti� o'�o e"' o'�a ' ' oeb o$^ o' of o°ole**" o°ti o°" o°`°` o",
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
—Sale Purchase Qualifying Facilities mHydro
Wind Solar Demand Response Net Position
Capacity Load and Resource alanc
Capacity Balance Overview
The purpose of the load and resource balance is to compare annual obligations to the annual
capability of PacifiCorp's existing resources after retirements and future energy efficiency savings
from the 2025 IRP preferred portfolio, and without new generating resource additions.
The capacity balance compares generating capability to load obligations across both summer and
winter.For the 2025 IRP,the load and resource balance reflects values from the Western Resource
Adequacy Program (WRAP). WRAP calculates project-specific qualifying capacity contribution
values for all existing and contracted resources, and those values are used where data is available.
WRAP also provides the average contribution for wind, solar, energy storage and run of river
hydro in different geographic areas, and these estimates are used for proxy resources in the 2025
IRP. WRAP will update the capacity contributions for resources ahead of each season, reflecting
the current resource mix of the WRAP footprint through time. WRAP has also provided
projections for future years and different resource penetration levels —as the penetration of wind,
solar,and storage increases, contributions are expected to decline. Significant uncertainty remains,
due to resource mix and timing, along with indirect factors like climate impacts on load and hydro.
To better reflect future WRAP compliance requirements,PacifiCorp used the projections provided
by WRAP to estimate contributions in 2045 based on the regional resource mix developed as part
of the forward price curve used in the 2025 IRP. Because PacifiCorp is a relatively small portion
of the regional resource mix, the calculation is static and does not vary with PacifiCorp's specific
portfolio selections. WRAP contributions fall linearly from the current values for 2025 to the
projected values for 2045. Additional detail is provided in Appendix K(Capacity Contribution).
126

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Note— While Appendix K(Capacity Contribution) has not been completed for the Dec 31
distribution of the Draft 2025 IRP, the modeled WRAP contributions through time are
available from postings for the IRP public input process:
https.11www.pacificorp.comlcontent✓damlpcorp/documentslenlpacificorp/energylintegrated-
resource planl2025-irp/PacifiCorp 2025 IRP PIM September 25 2024 Supplemental pdf
For reporting purposes, the capacity balance summarized in this chapter is developed by first
reducing the hourly system load by hourly distributed generation projections to determine the net
system coincident peak load for each of the first ten years (2025-2034) of the planning horizon.
Then the annual firm capacity availability of the existing resources, reflecting assumed coal unit
retirements from the preferred portfolio, is determined. Interruptible load programs, existing load
reduction DSM programs, and new load reduction DSM programs from the preferred portfolio at
the time of the net system coincident peak are included as part of the existing resources. The
annual resource deficit or surplus is then computed by multiplying the obligation by the planning
reserve margin (14.4% for the 2025 IRP, reflecting the WRAP value for the month of July) and
then subtracting the result from existing resources. This view is presented both without and with
uncommitted Market purchases.
The economics of adding resources to the system to meet both capacity and energy needs are
addressed during the resource portfolio development process described in Chapter 8 (Modeling
and Portfolio Evaluation Approach).
Load and Resource Balance Components
The main component categories consist of the following: resources, obligation, reserves,position,
and available market purchases.
Under the calculations, there are negative values in the table in both the resource and obligation
sections. This is consistent with how resource categories are represented in portfolio modeling.
The resource categories include resources by type—coal, gas, hydroelectric, wind, solar, other
renewables, storage, QFs, demand response, and purchases. Categories in the obligation section
include load, distributed generation, and energy efficiency from the preferred portfolio.
Demand Response
Existing demand response program capacity is categorized as a resource. Under WRAP, demand
response must be designated as either a load reduction, where any impacts are captured in peak
loads, or as a resource,based on its availability and duration during peak conditions. For the 2025
IRP, demand response is used for operating reserves and dispatched within the PLEXOS model
based on economics and need, and is not targeted to reduce summer-time peak loads which often
occur during solar generation hours when net demand is lower. As a result,treatment as a resource
provides a larger capacity benefit at this time. PacifiCorp expects to continue evaluating this as the
WRAP gets underway, as some demand response programs may be suitable for peak load
reduction. Also included in the demand response category are interruptible contracts. PacifiCorp
has had interruptible contracts with large load customers for many years. These contracts are a
key aspect of the retail service provided to the associated customers, and absent these contracts
their demand would likely be different from that included in the load forecast. To maintain an
127

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
alignment with the load forecast, these contracts are assumed to continue indefinitely under their
current structure.
Obligation
The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted
retail load less distributed generation, energy efficiency from the preferred portfolio,. The
following are descriptions of each of these components:
Load Net of Distributed generation
The largest component of the obligation is retail load. In the 2025 IRP, the hourly retail load at a
location is first reduced by hourly distributed 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 BAAS thus reflect loads at the time of PacifiCorp's coincident system summer and winter
peaks.
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 is a level of 2024 energy
efficiency that is not incorporated in the forecast. The 2024 energy efficiency forecast has been
added to the energy efficiency line along with the energy efficiency selected in the 2025 IRP
preferred portfolio. Figure 6.3 shows the energy efficiency for the east and west control areas in
the 2025 IRP preferred portfolio.
Figure 6.3—Energy Efficiency Peak Contribution in Summer Capacity Load and Resource
Balance (reduction to load, in MW)
(500)
(1,000)
(1,500)
(2,000) —
(2,500)
�o2s �026 �02� �02� 2029 zoo 20�1 zo�2 �o�� �o�A �o�s 20�6 zo�� 20�� �0�9 2OFo 2�r 2OFa ��� 2OFQ 2�s
■East ■West
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).
Position
The position is the resource surplus or deficit after subtracting obligation plus required reserves
from total resources.
128

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Capacity Balance Determination
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 = Coal + Gas + Hydro + Renewable + Storage + Firm Purchases +
Qualifying Facilities+Demand Response
The peak load, distributed generation, 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—Distributed generation—Energy Efficiency
The level of reserves to be added to the obligation is then calculated. This is accomplished by
taking the net system obligation calculated above multiplied by the 14.4 percent PRM for July and
16.8 percent PRM for December adopted from WRAP for the 2025 IRP. The formula for this
calculation is:
Planning Reserves = Obligation x PRM
Finally,the annual capacity position is derived by adding the computed reserves to the obligation,
and then subtracting this amount from existing resources, including available Market purchases,
as shown in the following formula:
Capacity Position = (Existing Resources + Available Market purchases) — (Obligation +
Planning Reserves)
Capacity Balance Results
Table 6.14 and Table 6.15 show the annual capacity balances and component line items for the
summer peak and winter peak,respectively,using a target PRM of 14.4 percent in the summer and
16.8 percent in the winter to calculate the planning reserve amount.5 Balances for PacifiCorp's
system as well as 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 up to the limits of the transfer capability between the two areas. Also note that QF
wind and solar projects listed earlier in the chapter are reported under the QF line item rather than
the renewables line item.
5 PacifiCorp acknowledged errors in its 2023 IRP load and resource balance,which have been addressed in the 2025
IRP. See Appendix M,stakeholder feedback form 412(Utah Association of Energy Users).
129

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.14 -- Summer Peak-System Capacity Loads and Resources without Resource
Additions
MW
2030 2031
Coal 3,959 3,567 3,567 3,375 3,090 2,926 2,926 2,926 2,926 2,926
Gas 2,984 3,294 3,294 3,295 3,469 3,470 3,470 3,470 3,470 3,470
Hydroelectric 76 76 76 76 76 76 76 76 76 76
Wind 246 224 218 211 205 189 168 162 157 151
Solar 342 499 488 476 464 453 441 429 418 406
Other Renewable 46 45 44 42 41 40 38 37 36 34
Storage 1 939 925 909 894 879 865 849 834 819
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 413 404 395 386 377 368 359 348 334 323
Demand Response 305 300 295 290 286 281 276 271 266 262
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 0 (639) (685) (308) 0 0 0 0 0 0
East Existing Resources 8,373 8,710 8,617 8,753 8,902 8,681 8,619 8,570 8,517 8,468
Load 7,734 7,947 7,952 8,230 8,667 8,855 9,050 9,335 9,335 9,284
Distributed Generation (157) (143) (186) (234) (285) (341) (400) (458) (515) (354)
Energy Efficiency (92) (191) (234) (346) (457) (566) (561) (852) (880) (996)
East Total obligation 7,485 7,613 7,532 7,651 7,924 7,948 89089 8,025 7,940 7,934
Planning Reserve Margin(14.4%) 1,078 1,096 1,085 1,102 1,141 1,144 1,165 1,156 1,143 1,142
East Obligation+Reserves 8,563 8,710 8,617 8,753 9,065 9,092 9,254 9,180 9,083 9,076
East Position (190) 0 0 0 (164) (412) (635) (610) (566) (608)
Available Market Purchases 500 500 500 500 500 0 0 0 0 0
Coal 140 133 133 133 133 0 0 0 0 0
Gas 716 716 716 716 716 716 716 716 716 716
Hydroelectric 712 712 712 712 712 712 712 712 712 712
Wind 0 0 0 0 0 0 0 0 0 0
Solar 69 67 65 62 60 58 52 50 48 46
Other Renewable 0 0 0 0 0 0 0 0 0 0
Storage 2 1 1 1 1 1 1 1 1 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 229 224 212 207 198 194 188 178 174 170
Demand Response 60 59 58 58 57 56 55 55 54 53
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 0 639 685 308 0 0 0 0 0 0
West Existing Resources 1,927 2,551 2,583 2,197 1,877 1,737 1,724 1,712 1,704 1,696
Load 3,672 3,826 3,938 4,121 4,271 4,482 4,609 4,828 4,946 4,887
Distributed Generation (49) (54) (75) (99) (124) (152) (182) (213) (244) (148)
Energy Efficiency (63) (41) (123) (157) (191) (227) (231) (229) (334) (364)
West Total obligation 3,560 3,731 3,740 3,866 3,955 4,102 4,195 4,386 4,368 4,376
Planning Reserve Margin(14.4"/u) 513 537 539 557 570 591 604 632 629 630
West Obligation+Reserves 4,072 4,269 4,278 4,423 4,525 4,693 4,799 5,017 4,998 5,006
West Position (2,145) (1,718) (1,695) (2,226) (2,648) (2,956) (3,075) (3,306) (3,293) (3,309)
Available Market Purchases 2,603 2,603 2,603 2,603 2,603 0 0 0 0 0
Total Resources 10,300 11,260 11,200 10,950 10,779 10,417 10,343 10,281 10,221 10,164
Obligation 11,045 11,345 11,272 11,517 11,879 12,050 12,284 12,410 12,308 12,310
Planning Reserves(14.4%) 1,590 1,634 1,623 1,658 1,711 1,735 1,769 1,787 1,772 1,773
Obligation+Reserves 12,635 12,978 12,895 13,175 13,590 13,785 14,053 14,197 14,081 14,082
System Position (2,335) (1,718) (1,695) (2,226) (2,811) (3,368) (3,710) (3,916) (3,859) (3,918)
Available Market Purchases 3,103 3,103 3,103 3,103 3,103 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 2,335 1,718 1,695 2,226 2,811 0 0 0 0 0
Net Surplus/(Deficit) 0 0 0 0 0 (3,368) (3,710) (3,916) (3,859) (3,918)
130

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.14 (cont.)-Summer Peak System Capacity Loads and Resources without Resource
Additions
Coal 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926
Gas 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470
Hydroelectric 76 76 76 76 76 76 76 76 76 76 76
Wind 145 140 134 128 122 117 81 77 73 69 65
Solar 395 383 343 332 322 311 300 290 279 246 236
Other Renewable 33 32 30 11 11 10 9 9 8 8 0
Storage 804 788 773 759 744 728 714 699 684 668 654
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 314 302 240 231 223 211 204 196 189 182 176
Demand Response 257 252 247 243 238 233 228 223 218 214 209
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers 0 0 0 0 0 0 0 0 0 0 0
East Existing Resources 8,420 8,370 8,240 8,177 8,131 8,083 8,009 7,966 7,924 7,860 7,812
Load 9,411 9,557 9,767 9,935 10,083 10,201 10,339 10,480 10,664 10,745 10,883
Distributed Generation (385) (415) (445) (474) (503) (529) (557) (584) (609) (635) (660)
Energy Efficiency (1,110) (1,151) (1,024) (1,333) (1,462) (1,515) (1,580) (1,315) (1,562) (1,583) (1,613)
East Total obligation 7,916 7,990 8,298 8,129 8,118 8,156 8,202 8,581 8,492 8,528 8,610
Planning Reserve Margin(14.4%) 1,140 1,151 1,195 1,171 1,169 1,175 1,181 1,236 1,223 1,228 1,240
East Obligation+Reserves 9,056 9,141 9,493 9,299 9,287 9,331 9,383 9,817 9,715 9,756 9,850
East Position (636) (771) (1,253) (1,122) (1,156) (1,248) (1,374) (1,851) (1,791) (1,896) (2,038)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Coal 0 0 0 0 0 0 0 0 0 0 0
Gas 716 716 716 716 716 716 716 716 716 716 716
Hydroelectric 712 712 712 712 712 712 712 712 712 712 712
Wind 0 0 0 0 0 0 0 0 0 0 0
Solar 45 43 41 39 37 35 13 12 11 11 10
Other Renewable 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 165 160 143 138 133 129 125 121 100 96 94
Demand Response 52 52 51 50 49 49 48 47 46 46 45
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers 0 0 0 0 0 0 0 0 0 0 0
West Existing Resources 1,689 1,681 1,662 1,655 1,647 1,640 1,613 1,608 1,585 1,580 1,576
Load 4,944 5,009 5,082 5,189 5,258 5,330 5,397 5,473 5,660 5,651 5,730
Distributed Generation (163) (177) (192) (206) (221) (234) (249) (263) (277) (290) (304)
New Energy Efficiency (394) (426) (378) (502) (457) (461) (475) (399) (473) (463) (471)
West Total obligation 4,388 4,406 4,512 4,481 4,581 4,635 4,674 4,812 4,910 4,897 4,955
Planning Reserve Margin(14.4%) 632 634 650 645 660 667 673 693 707 705 713
West Obligation+Reserves 5,020 5,040 5,161 5,127 5,240 5,303 5,347 5,505 5,618 5,603 5,668
West Position (3,330) (3,359) (3,499) (3,472) (3,594) (3,662) (3,734) (3,897) (4,032) (4,023) (4,092)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Total Resources 10,109 10,051 9,902 9,831 9,778 9,723 9,622 9,574 9,509 9,439 9,388
Obligation 12,304 12,396 12,810 12,610 12,699 12,791 12,876 13,393 13,403 13,425 13,564
Planning Reserves(14.4%) 1,772 1,785 1,845 1,816 1,829 1,842 1,854 1,929 1,930 1,933 1,953
Obligation+Reserves 14,076 14,181 14,654 14,426 14,528 14,633 14,730 15,321 15,333 15,358 15,518
System Position (3,967) (4,130) (4,752) (4,594) (4,750) (4,910) (5,108) (5,748) (5,824) (5,919) (6,129)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 0 0 0 0 0 0 0 0 0 0 0
Net Surplus/(Deficit) (3,967) (4,130) (4,752) (4,594) (4,750) (4,910) (5,108) (5,748) (5,824) (5,919) (6,129)
131

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.15-Winter Peak System Capacity Loads and Resources without
Resource Additions
Coal 4,147 3,733 3,733 3,498 3,184 3,014 3,014 3,015 3,015 3,015
Gas 3,003 3,334 3,334 3,335 3,526 3,527 3,527 3,527 3,527 3,527
Hydroelectric 33 33 33 33 33 33 33 33 33 33
Wind 2,037 1,929 1,836 1,748 1,616 1,456 1,377 1,300 1,226 1,154
Solar 77 104 101 98 95 92 89 86 83 80
Other Renewable 41 39 38 37 35 34 33 31 30 28
Storage 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 186 181 177 171 167 162 155 150 130 125
Demand Response 139 135 132 129 125 122 119 116 112 109
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (1,600) (1,600) (1,600) (1,600) (1,256) (1,075) (803) (530) (445) (255)
East Existing Resources 8,062 7,890 7,785 7,449 79525 7,366 7,544 7,728 79711 7,817
Load 5,724 6,099 6,174 6,448 6,759 6,698 6,869 7,153 7,223 7,397
Distributed Generation (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Energy Efficiency (63) (116) (174) (243) (311) (385) (403) (528) (613) (695)
East Total obligation 5,659 5,981 5,997 6,201 6,443 6,306 6,459 6,617 69601 6,693
Planning Reserve Margin(16.8%) 951 1,005 1,007 1,042 1,082 1,059 1,085 1,112 1,109 1,124
East Obligation+Reserves 6,610 6,986 7,004 7,242 7,525 7,366 7,544 7,728 7,711 7,817
East Position 1,452 904 781 206 0 0 0 0 0 0
Available Market Purchases 500 500 500 500 500 0 0 0 0 0
Coal 147 147 147 147 147 0 0 0 0 0
Gas 735 735 735 735 735 735 735 735 735 735
Hydroelectric 726 726 726 726 726 726 726 726 726 726
Wind 64 61 59 57 54 52 50 47 45 43
Solar 1 1 1 1 1 1 0 0 0 0
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 68 68 60 60 57 56 56 55 55 55
Demand Response 0 0 0 0 0 0 0 0 0 0
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 1,600 1,600 1,600 1,600 1,256 1,075 803 530 445 255
West Existing Resources 3,341 3,339 3,329 3,326 2,978 2,645 2,370 2,094 2,007 1,814
Load 3,711 3,577 3,676 3,859 4,025 4,478 4,541 4,421 4,477 4,526
Distributed Generation (0) (0) (1) (1) (1) (1) (1) (2) (2) (2)
Energy Efficiency (45) (79) (118) (157) (199) (246) (236) (328) (370) (407)
West Total obligation 3,665 3,498 3,558 3,701 3,825 4,230 49303 4,091 49105 4,117
Planning Reserve Margin(16.8% 616 588 598 622 643 711 723 687 690 692
West Obligation+Reserves 4,281 4,086 4,156 4,322 4,467 4,941 5,026 4,778 4,794 4,809
West Position (939) (747) (827) (996) (1,490) (2,296) (2,656) (2,684) (2,788) (2,995)
Available Market Purchases 2,603 2,603 2,603 2,603 2,603 0 0 0 0 0
Total Resources 11,404 11,229 11,114 10,775 10,503 10,011 9,914 9,822 9,717 9,631
Obligation 9,324 9,479 9,555 9,902 10,268 10,537 10,762 10,708 10,706 10,810
Planning Reserves(16.8%) 1,343 1,365 1,376 1,426 1,479 1,517 1,550 1,542 1,542 1,557
Obligation+Reserves 10,667 10,844 10,931 11,327 11,746 12,054 12,312 12,250 12,248 12,366
System Position 737 384 183 (552) (1,243) (2,043) (2,398) (2,427) (2,531) (2,735)
Available Market Purchases 3,103 3,103 3,103 3,103 3,103 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 0 0 0 552 1,243 0 0 0 0 0
Net Surplus/(Deficit) 737 384 183 0 0 (2,043) (2,398) (2,427) (2,531) (2,735)
132

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.15 (coot.)-Winter Peak System Capacity Loads and Resources without
Resource Additions
Coal 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015
Gas 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527
Hydroelectric 33 33 33 33 33 33 33 33 33 33 33
Wind 1,082 1,014 948 883 820 674 621 570 522 474 429
Solar 77 74 71 68 66 63 60 57 46 44 41
Other Renewable 27 26 24 8 8 8 7 6 6 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 121 103 98 95 91 87 83 79 75 72 68
Demand Response 106 103 99 96 93 89 86 83 80 76 73
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers
East Existing Resources 7,988 7,896 7,816 7,725 7,652 7,496 7,431 7,370 7,304 7,240 7,186
Load 7,321 7,508 7,595 7,732 7,856 7,991 8,169 8,340 8,450 8,525 8,664
Distributed Generation (11) (11) (12) (13) (13) (14) (14) (14) (15) (15) (16)
Energy Efficiency (580) (891) (834) (824) (879) (926) (1,042) (979) (1,305) (1,268) (1,195)
East Total obligation 6,730 6,606 6,749 6,896 6,964 7,052 7,113 7,347 7,131 7,242 7,453
Planning Reserve Margin(16.88/6) 969 951 972 993 1,003 1,015 1,024 1,058 1,027 1,043 1,073
East Obligation+Reserves 7,699 7,557 7,721 7,889 7,966 8,067 8,137 8,405 8,158 8,285 8,526
East Position 289 338 95 (164) (314) (571) (706) (1,035) (854) (1,045) (1,340)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Coal 0 0 0 0 0 0 0 0 0 0 0
Gas 735 735 735 735 735 735 735 735 735 735 735
Hydroelectric 726 726 726 726 726 726 726 726 726 726 726
Wind 41 39 36 34 32 30 28 26 24 22 20
Solar 0 0 0 0 0 0 0 0 0 0 0
Other Renewable 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 55 53 53 52 51 51 50 50 49 49 49
Demand Response 0 0 0 0 0 0 0 0 0 0 0
Sale 0 0 0 0 0 0 0 0 0 0 0
West Existing Resources 1,556 1,552 1,550 1,547 1,544 1,542 1,539 1,536 1,534 1,532 1,529
Load 4,773 4,920 4,989 4,941 5,062 5,136 5,276 5,289 5,398 5,345 5,467
Distributed Generation (2) (3) (3) (3) (3) (3) (3) (4) (4) (4) (4)
Energy Efficiency (642) (543) (439) (755) (796) (837) (919) (614) (645) (538) (658)
West Total obligation 4,128 4,374 4,548 4,183 4,263 4,297 4,353 4,671 4,749 4,803 4,805
Planning Reserve Margin(16.8%) 694 735 764 703 716 722 731 785 798 807 807
West Obligation+Reserves 4,822 5,109 5,312 4,886 4,979 5,018 5,085 5,456 5,547 5,610 5,613
West Position (3,265) (3,557) (3,762) (3,338) (3,435) (3,477) (3,546) (3,920) (4,013) (4,079) (4,083)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Total Resources 9,545 9,448 9,366 9,272 9,196 9,038 8,970 8,907 8,838 8,772 8,716
Obligation 10,858 10,980 11,297 11,079 11,227 11,348 11,466 12,018 11,880 12,045 12,258
Planning Reserves(16.81/6) 1,564 1,581 1,627 1,595 1,617 1,634 1,651 1,731 1,711 1,735 1,765
Obligation+Reserves 12,422 12,561 12,924 12,674 12,843 12,983 13,117 13,749 13,591 13,780 14,023
System Position (2,877) (3,113) (3,558) (3,402) (3,647) (3,945) (4,148) (4,842) (4,753) (5,008) (5,308)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 0 0 0 0 0 0 0 0 0 0 0
NetSurplus/(Deficit) (2,877) (3,113) (3,558) (3,402) (3,647) (3,945) (4,148) (4,842) (4,753) (5,008) (5,308)
133

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Figure 6.4 through Figure 6.7 are graphic representations of the above tables for annual capacity
position for the summer system, winter system, east control area, and west control area. Also
shown in the system capacity position graph are available Market purchases,which can be used
to meet capacity needs. The market availability assumptions used for portfolio modeling are
discussed further in Chapter 7.
Figure 6.4 — Summer System Capacity Position Trend
16,000
14,000
• eseles
12,000
10,000
R
� 8,000
d
East Existing Resources
6,000
4,000
West Existing Remorees
2,000
0
vo,�'� v�,yb voyn ryoti4 rya v0,�0 v0,�1 ry�,�'L vp,�'S vO,�A
West Existing Resources East Existing Resources Uncommitted FOTs to meet remaining Need �Obligatian+Reserves — Obligation
134

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Figure 6.5—Winter System Capacity Position Trend
16,000
14,000
12,000
16.8%Reserves
10,000
Z+
R
R 8,000
t>D
East Existing Resources
6,000
4,000
2,000
0
ti�ry� ti�vb ti�ry^ ti�v� ti�vQ ti��o ti��, ti��� tiM b��p
aa�West Existing Resources East Existing Resources Uncommitted FOTs to meet remaining Need tObligation+Reserves —Obligation
135

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Figure 6.6—East Summer Capacity Position Trend
10,000
8,000
6,000
bW0
d
East Existing Resources
4,000
2,000
0
*11 ti�ryb *1 ti�ry� ti�ry� 4+1 ti� ti��v ti��1
aa�East Existing Resources East-Uncommitted FOTs to meet remaining Need tEast Obligation+Reserves — East Total obligation
136

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Figure 6.7 —West Summer Capacity Position Trend
10,000
8,000
6,000
bW0
d
East Existing Resources
4,000
2,000
0
*11 ti�ryb *1 ti�ry� ti�ry� 4+1 ti� ti��v ti��1
aa�East Existing Resources East-Uncommitted FOTs to meet remaining Need tEast Obligation+Reserves — East Total obligation
137

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
138

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
CHAPTER 7 - RESOURCE OPTIONS
CHAPTER HIGHLIGHTS
• PacifiCorp's resource attributes and costs for future generation resource options reflect
updated information, based on assumptions from the National Renewable Energy
Laboratory's 2024 Annual Technology Baseline to the extent data was available.'
• In addition to utility-scale resources (generally 200 megawatts (MW) or more), the 2025
IRP includes small-scale(20 MW)wind, solar, and biodiesel peaking options. These small-
scale resource options are assumed to be sited in relative proximity to load, such that they
do not require significant transmission system upgrades.
• Renewable resource generation profiles have been updated and expanded to include more
proxy resource locations as well as distinct profiles for utility-scale and small-scale wind
resources, rather than one generation profile per state as in the 2023 IRP. This update
extends to online and contracted resources, as well as proxy resource options, and also
includes expanded historical data for use with stochastic analysis.
• Options for utility-scale lithium-ion batteries (20 MW and 200 MW options), gravity
energy storage systems,pumped hydro energy storage(PHES),thermal energy storage,one-
hundred-hour iron-air storage, and adiabatic compressed air energy storage are included in
this IRP.In a change from prior IRPs,hydrogen peaking resources are also treated as storage
resources (rather than using pipelines and a market price for hydrogen). Hydrogen is
electrolyzed using excess generation output and stored in either high-pressure tanks or
underground caverns.
• The Plexos model endogenously models transmission upgrades, allowing for increases to
transfer limits and resource interconnection. Where applicable,upgrades are restricted until
all pre-requisites are in place.
• PacifiCorp continues to apply cost reduction credits to energy efficiency, reflecting risk
mitigation benefits, transmission and distribution investment deferral benefits, and a ten
percent market price credit for Washington and Oregon as allowed by the Northwest Power
Act.
Introduction
This chapter provides background information on the various resources considered in the IRP for
meeting future capacity and energy needs. Organized by major category, these resources consist
of utility-scale supply-side generation, demand-side management (DSM) programs, transmission
resources and market purchases. For each resource category, the chapter discusses the criteria for
resource selection, presents the options and associated attributes, and describes the various
technologies. In addition, for supply-side resources, the chapter describes how PacifiCorp
addressed long-term cost trends and uncertainty in deriving cost figures.
Jply-Side Resoles (SSR)
The list of supply-side resource options reflects the expected realities evidenced through external
studies, internally generated studies, permitting, regulatory requirements, and stakeholder input.
The process began with the list of major generating resources from the 2023 IRP. This resource
'https://atb.nrel.gov/electricity/2024/index
139

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
list was reviewed and modified to reflect stakeholder input, new technology developments,
environmental factors, cost dynamics and anticipated permitting requirements. The National
Renewable Energy Laboratory (NREL) Annual Technology Baseline (ATB)2 was used as much
as possible to maintain consistency. Some of the terminology used in this chapter is from the ATB.
A glossary of some of the terminology is provided below in Table 7.12 and a list of acronyms is
provided in Table 7.13.
The SSR options include the following technologies grouped by energy source. More information
about each technology is provided in the "Resource Option Descriptions" section of this chapter.
The terminology here matches that used in the SSR Table,although some may have been shortened
per the acronym list in Table 7.13.
• Natural Gas
o Internal Combustion Engines
o SCCT, Aero, &F-Frame
o CCCT, lxl, &2x1
■ Adjustments for 95% Carbon Capture
■ Adjustments for Brownfield Construction
■ Adjustments for advanced technology innovation scenario ("Innovations far
from market-ready today are successful and become widespread in the market.
New technology architectures could look different from those observed today.
Public and private R&D investment increases. For biopower technologies,
technology cost designations appearing in ATB tables and figures refer to
technology assumptions and the range of fuel price projections as described on
their respective technology pages.")
• Hydrogen
o Adjustments for 100% Hydrogen burning capability
o Adjustments for Hydrogen Storage
o Electrolyzer
• Coal, Carbon Capture Retrofits at existing plants.Note that although the common abbreviation
for carbon capture and storage (CCS) is used, data for these resources does not include
sequestration.
• Energy Storage
o Lithium-Ion Batteries (20 MW, 200 MW, and 1,000 MW all with 4-hour duration)
■ Adjustments for double duration(i.e., 8-hour duration)
■ Adjustments for co-location with other generating resources
■ Adjustments for advanced technology innovation scenario
o Gravity Batteries
o Adiabatic Compressed Air Energy Storage (ACAES)
0 100-Hour Iron Air Batteries
o PHES (single and double reservoirs)
o Pumped Thermal
• Solar
o Adjustments for advanced technology innovation scenario
• Wind (various on-shore wind classes and off-shore class 12, as appropriate for PacifiCorp's
service area)
2 https://atb.nrel.gov/electricity/2024/definitions#scenarios
3 https://atb.nrel.gov/electricity/2024/definitions#scenarios
140

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
o Adjustments for advanced technology innovation scenario
• Nuclea?
o Small Modular Reactor
■ Adjustments for adding thermal energy storage
o Large Light Water Reactor
■ Adjustments for advanced technology innovation scenario (in addition to the
earlier definition: "for nuclear technologies, technology cost designations
appearing in ATB tables and figures refer to technology assumptions and the
range of fuel price projections as described on their respective technology
pages.")
• Geothermal (near field enhanced geothermal system, binary)
o Adjustments for advanced technology innovation scenario
Derivation of Resource Attributes
Once a basic list of resources was determined, the cost-and-performance attributes for each
resource were estimated. The information sources used are listed below, followed by a brief
description on how they were used in the development of the SSR tables ,which is used to develop
inputs for IRP modeling:
• Annual Technology Baseline (ATB) prepared by the National Renewable Energy Laboratory
(NREL)5
• U.S. Energy Information Administration(EIA) "Capital Cost and Performance
Characteristics for Utility-Scale Electric Power Generating Technologies" (`EIA Report",
both the 20246 and 2020' editions)prepared by Sargent and Lundy
• Original equipment manufacturers capital and operation and maintenance estimates
• Developer cost and performance estimates
• Publicly available cost and performance estimates
• Actual PacifiCorp or electric utility industry installations,providing current
construction/maintenance costs and performance data with similar resource attributes
• Projected PacifiCorp or electric utility industry installations,providing projected
construction/maintenance costs and performance data of similar or identical resource options
• Additional references are provided in the Resource Option Descriptions section of this
chapter
Most of the supply-side resource options rely on the ATB and EIA reports. Some resources
contained in the SSR tables are not listed in the ATB, but were developed through other reports,
4 Nuclear technology is intentionally limited to years outside the 2-4 year action plan window.Nuclear resource
assumptions were discussed in the 2025 IRP public input meeting series and stakeholder feedback,
See Appendix M,stakeholder feedback form#1 (Peter Gross).
See Appendix M,stakeholder feedback form#41 (Nathan Strain).
5 https:Hatb.nrel.gov/electricty/2024/index.
6 Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating Technologies,
December 6,2023,Sargent&Lundy,prepared for the U.S.Energy Information Administration's Capital Cost and
Performance Characteristics for Utility Scale Electric Power Generating Technologies,January 2024
https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_cost_AE02025.pdf.
Cost and Performance Estimates for New Utility-Scale Electric Power Generating Technologies,December 2019,
Sargent&Lundy,prepared for the U.S.Energy Information Administration's Capital Cost and Performance
Characteristic Estimates for Utility Scale Electric Power Generating Technologies,February 2020
https://www.eia.gov/analysis/studies/powerplants/capitalcost/archive/2020/pdf/capital—cost AE0202O.pdf
141

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
conversations with industry experts, developers and original equipment manufacturers (OEM's).
The 2024 ATB with its numerous references and the 2024 EIA Report was used for:
• Natural Gas
o SCCT (Aero)
o CCCT (lxl & 2xl)
■ Adjustments for 95% Carbon Capture
■ Adjustments for advanced technology innovation scenario
• Energy Storage
o Lithium-Ion Batteries (20 MW, 200 MW, and 1,000 MW, 4-hour duration)
■ Adjustments for double duration
■ Adjustments for co-location
■ Adjustments for advanced technology innovation scenario
o PHES (single and double reservoirs)
• Solar
o Adjustments for advanced technology innovation scenario
• Wind
o Adjustments for advanced technology innovation scenario
• Nuclear
o Small Modular Reactor
o Large Light Water Reactor
o Adjustments for advanced technology innovation scenario
• Geothermal (near field enhanced geothermal system, binary)
o Adjustments for advanced technology innovation scenario
The 2020 EIA Report provided the Internal Combustion Engines(ICE)data because no ICE option
was included in the 2024 EIA report.The ICE option was included to address Oregon requirements
for small-scale resources under 20 MW. Although the ICE option consists of 4 x 5.6 MW engines
at ISO conditions, it is assumed that the engines, if not derated due to altitude or other factors, can
be curtailed to meet the 20 MW threshold.
The brownfield cost adjustment was developed based on prior IRP estimates.
Hydrogen capable resource data is based on the following:8
• Adjustments for 100% hydrogen burning capability are based on conversations with OEMs
and industry experts and the report "Exploring the competitiveness of hydrogen-fueled gas
turbines in future energy systems."9 A 15% cost adder for new gas turbines indicated by Table
3 in the report was corroborated by OEMs and other industry experts.
• Adjustments for hydrogen storage are based on information in the U.S. Department of Energy
(DOE)reports: "Pathways to Commercial Liftoff. Clean Hydrogen"10(Clean Hydrogen Liftoff
a The option of hydrogen as an alternative fuel,including electrolyzer cost and performance,was discussed in the
course of the 2025 IRP public input meeting series.For specific recommendations and PacifiCorp's response,see
Appendix M,stakeholder feedback form#23 (NP Energy,LLQ
9 Simon Oberg,Mikael Odenberger,Filip Johnsson"Exploring the competitiveness of hydrogen-fueled gas turbines
in future energy systems,"Division of Energy Technology,Chalmers University of Technology,412 96,
Gothenburg, Sweden,https://www.sciencedirect.com/science/article/pii/S0360319921039768
10 https:Hliftoff.energy.gov/
142

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
report), "2022 Grid Energy Storage Technology Cost and Performance Assessment,"" and the
Hydrogen and Fuel Cell Technologies Office's "Multi-Year Program Plan. ,12
• Electrolyzer costs are based on the DOE report "Hydrogen Production Cost from PEM
Electrolysis—2019,"13 and the NREL report"Updated Manufactured Cost Analysis for Proton
Exchange Membrane Water Electrolyzers."
Data for "Carbon Capture Retrofits at existing coal plants" is based on adjustments made to
incorporate capital and operational costs of emission control technologies (SCR and FGD)needed
to scrub flue gas prior to the carbon capture technology, and adjustments made to account for
economies of scale.
Gravity Batteries costs were escalated from the 2023 IRP.
Adiabatic Compressed Air Energy Storage(ACAES)were originally escalated from the 2023 IRP
which used data provided by Renewable Energy Storage Company (RESC), but later updated
based on input from Hydrostor.
100-Hour Iron Air Battery data is based on information provided by Form Energy.
Pumped Thermal energy storage is based on integrated thermal storage for nuclear, but with a
resistive heater for energy storage.
Data for "Adjustments for adding thermal energy storage to nuclear plants" represents thermal
energy storage and only stores energy from the heat of the reactor, not from a resistive heater.
The following costs were excluded from the cost estimates provided by the referenced sources,but
were added by the Company as appropriate, using confidential data specific to the Company's
business practices:I4
• Allowance for Funds Used During Construction(AFUDC)
• Capital Surcharge
• Escalation
• Property taxes
Interconnection costs and sales tax are included in the PLEXOS modeling depending on the
locational node in which each technology is being considered.
Wind and Solar Generation Profiles
For the 2025 IRP, PacifiCorp has updated the wind and solar generation profiles for both existing
resources and proxy resource options. PacifiCorp provided the location and expected generation
levels for existing and contracted resources to a consultant,Hendrickson Renewables,and received
11 https://www.energy.gov/sites/default/files/2022-
09/2022%20Grid%20Energy%20Storage%20Technology%20Cost%20and%20Performance%20Assessment.pdf
12 https://www.energy.gov/sites/default/files/2024-05/hfto-mypp-2024.pdf
13
https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/l 9009_h2_production_Cost_pem_electrolysi
s_2019.pdf?Status=Master
14 Additional cost considerations were the subject of discussion and feedback during the 2025 IRP public input
meeting series. See Appendix M,stakeholder feedback form#24(NP Energy,LLQ.
143

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
back an hourly generation profile for 2006-2023 that reflects expected performance under
historical weather conditions.
For existing resources, results were tuned to recent historical actual generation levels, while
resources that are not yet operating were tuned to forecasted output. For wind, hourly generation
is based on hourly wind speeds and air density from the ERAS reanalysis dataset,with scaling and
adjustments to represent project-specific power curves and expected Output.15 For solar, hourly
solar irradiance and weather data was extracted from a Vaisala satellite irradiance dataset16 and
configured in a PVsyst model17 that was tuned to correspond to actual or forecasted output.
For proxy resources, PacifiCorp identified locations across its system, and Hendrickson
Renewables determined the expected output of the equipment represented in NREL's ATB,which
was used to develop cost inputs. In the 2023 IRP, PacifiCorp used one wind and solar profile for
each of its five largest state jurisdictions (excluding California). For the 2025 IRP, wind and solar
profiles have been developed which to correspond to thirteen different transmission areas spread
across PacifiCorp's system. To account for technological differences that impact generation
output, generation profiles were also developed for five small-scale wind profiles for the west side
of the system, along with an off-shore wind profile for the potential lease area near Brookings)8
For many years, PacifiCorp has used a chaotic normal load forecast to account for the range of
load conditions experienced. For each month of the year, the chaotic normal load forecast is
derived from the most representative historical month from recent history (currently 2013-2022).
The pattern of load in each of the selected months from history is reflected in every year of the
forecast, with adjustments to account for the rotation of calendar days and weekdays from year to
year, as well as for forecasted changes in load over time. As a result, every day of PacifiCorp's
load forecast is tied to a specific day in history. For the 2025 IRP, the normalized wind and solar
output modeled in Plexos is drawn from the same historical day as the load forecast. The result is
a generation profile specific to each of the years of the IRP forecast (2025-2045) that inherently
represents the correlation between renewable generation and load. The expanded historical
generation data set developed for the 2025 IRP also enables stochastic analysis that captures the
relationship between renewable generation and load in each of the historical years (2006-2023).
Resource Options and Attributes
Table 7.2 through Table 7.11 report characteristics, attributes and costs for resource options
considered in the 2025 IRP. Unlike previous IRP's the SSR Table does not list multiple versions
of the same technology for various altitudes. Instead, the location adjustments from Appendix A
and B of the 2024 EIA19 report are applied in PLEXOS. Total resource cost attributes for supply-
"European Centre for Medium-Range Weather Forecasts.https://www.ecmwfint/en/forecasts/dataset/ecmwf-
reanalysis-v5
16 Vaisala.https://www.vaisala.com/
17 PVsyst•https://www.pvsyst.com/
'g Bureau of Ocean Energy Management.https://www.boem.gov/renewable-energy/state-activities/Oregon
19 https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital cost AE02025.pdf
144

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
side resource options are based on estimates of the first-year, real-levelized costs for resources,
stated in June 2024 dollars.20,2I Table 7.1 provides a listing of these ten tables for convenience.
Table 7.1 —Supply-Side Resource Option Tables
Operating Characteristics and
Characteristics and Costs Environmental Data
Thermal Table 7.2 Table 7.4
Non-Thermal and Storage Table 7.3 Table 7.5
Additional Attributes and Variable O&M,Total Cost and
d O&M Credits
Thermal Table 7.6 Table 7.9
Non-Thermal Table 7.7 Table 7.10
Storage Table 7.8 Table 7.11
A Glossary of Terms and a Glossary of Acronyms from the SSR is summarized in Table 7.12
and Table 7.13.
21 Supply-side resource attributes were discussed throughout the 2025 public input meeting series and generated
stakeholder feedback forms inquiries.2028 was determined to be the appropriate earliest commercial online year for
most proxy resource options.However,PacifiCorp does not preclude the possibility of achieving specific(non-
proxy)projects on an earlier timeline outside of the IRP.
See Appendix M,stakeholder feedback form#7(Renewable Northwest).
See Appendix M,stakeholder feedback form#36(Sierra Club).
21 The supply-side resource table was made publicly available during the 2025 IRP public input meeting series and
discussed extensively as it developed.IRP Support&Studies
145

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.2 - 2025 Thermal Supply-Side Resources, Characteristics and Costs (20245)
Characteristics Costs
Fraction
Var O&M
Adlusted
Net Resource Total Commercial Asset Base Fraction by Fiwed Fraction Demolitio
Elevation Capacity Availability Implementation Operation Life Capital Vat O&M Vat O&M Capacity O&M Fixed O&M n Cost
Fuel Resource Descri tion [AFSL) (MW) Year Time(yrs) Year (yrs) ($IkW) [$IMWh1 Capitalized Changes ($IkW-yr) Capitalized ($IkW)
BI„fuJ Internal Combustion Engine,renewable biofuel,with SCR&24-hout fuel tank 0 20 2025 2.5 2027 30 $2,131 $6.33 74% 91% $42.82 3*/ $14.59
Natural Gas SCCT Aero,with SCR 0 50 2025 3.5 2028 40 $2,613 € $7.40 87% 38% i $12.42 3% $32.46
Natural Gas SCCT Aero x4,with SCR 0 211 2025 3.5 2028 40 $1,789 € $5.32 87% 98% $9.93 i 3/. $32.46
Natural Gas SCCT Ram*"I"'A,with SCR 0 233 I 2025 I 5.0 2030 40 $1,387 i $7.75 100/ 99% $27.32 3/. I $12.13
Natural Gas CCCT Dry"H",1X1,DF,with SCR 0 649 2025 5.0 2030 40 $1,839 € $2.70 0% 100/ i $42.44 0/. $12.08
Natural Gas CCCT Div"H",2X1,DF,with SCR 0 1,227 2025 5.0 2030 40 1 $1,553 € $2.28 0% 100% $35.18 0/. $11.69
Natural Gas CCCT Dry"H",1X1,DF,with SCR+a for adding 95%CCS to new CCCT 1x1 0 565 2025 5.0 2030 i +40 $3,429 € $5.32 0% 100% i $77.07 0/. $65.28
Natural Gas CCCT Dr "H",2X1,OF,with SCR+a for adding 35%CCS to new CCCT 20 0 1085 2025 5.0 2030 i +40 $2,846 i $4.83 0% 100% i $62.99 0*/ $65.08
Natural Gas Internal Combustion Engine,renewable bicfuel,with SCR&24-hour fuel tank+afor CT Brownfield construction 0 { 20 I 2025 i 2.5 2027 i 30 $1,310 I $6.24 74% ; 91% $42.82 ! 3/. i $14.53
Natural Gas SCCT Aero,with SCR+afor CT Brownfield construction 0 50 2025 3.5 2028 40 $2,352 $6.66 87% 98% $12.42 3% $32.46
Natural Gas SCCT Aero x4,with SCR+afor CT Brownfield construction 0 211 2025 3.5 2028 40 $1,610 € $5.33 87% 38% $3.33 3'/. $32.46
Natural Gas SCCT Frame"F"xl,with SCR+efor CT Brownfield construction 0 233 2025 5.0 2030 40 $1,248 € $6.38 100% 99% i $27.32 3% $12.13
Natural Gas CCCT Dry"H",1X1,OF,with SCR+a For CT Brownfield construction 0 649 2025 5.0 2030 40 $1,655 € $2.43 0% 100% i $42.44 D'/. $12.08
Natural Gas CCCT Dr "H"2X1,OF,with SCR+afor CT Brownfield construction 0 1,227 2025 5.0 2030 40 $1,398 i S2.05 0% 100% $35.18 0*/ $11.89
Natural Gas CCCT Dry"H",1X1,OF,with SCR+a for adding 35%CCS to new CCCT 1xl+a For CT Brownfield construction 0 555 2025 5.0 2030 40 $3,086 $4.78 0% 100% i $77.07 fP/. $65.28
Natural Gas CCCT Dr "H",2X1,OF,with SCR+a for addina 95%CCS to new CCCT 2xl+a for CT Brownfield construction 0 i 1,085 2025 5.0 2030 40 $2561 i $4.34 0% 100% i $62.33 0'/. $65.08
Hydrogen SCCT Frame"F"xl,with SCR+efor 100%Hydrogen burning capability 0 233 2025 5.0 2030 40 $1,595 € $8.91 100% 33% i $27.92 3/. $13.35
Hydrogen CCCT Dry"H",1X1,OF,with SCR+efor 100%Hydrogen burning capability 0 649 2025 5.0 2030 40 $2,115 $3.11 0% 100% i $42.44 0/. $13.89
Hvdroaen CCCT Dr "H",2X1,OF,with SCR+a For 100%H dro en burning capability 0 1,227 2025 5.0 2030 40 $1,786 1 $2.62 0% 100% $35.18 0/. $13.67
Hydrogen SCCT Frame"F"xl,with SCR+afor Hydrogen storage,cavern,806ar,24 hour 0 233 2025 I 5.0 2030 40 $2,506 $8.10 100% j SS/ $35.12 3/. $27.13
Hydrogen CCCT Dry"H",1X1,DF,with SCR+e for Hydrogen storage,cavern,80 bar,24 hour 0 649 2025 5.0 2030 40 $3,038 € $3.13 0% 100/ $43.64 0% 527.08
H dro en CCCT Or "H",2X1,OF,with SCR+e for Hydrogen storage,cavern,806ar,24 hour 0 1,227 2025 5.0 2030 40 $2,752 € $2.70 0% 100% i $42.38 0/. $26.89
Hydrogen SCCT Frame"F"xl,with SCR+efor Hydrogen storage,tanks,SOO bar,24 hour 0 233 2025 5.0 2030 40 $2,098 € $8.32 100% 33% i $40.78 3% $27.13
Hydrogen CCCT Dry"H",1X1,OF,with SCR+afar Hydrogen storage tanks,SOO bar,24 hour 0 649 2025 5.0 2030 40 $2,550 $3.27 0% 100% i $55.30 0'/. $27.08
Hydrogen CCCT Dr "H"2X1,OF,with SCR+a forHydrogen storage,tanks,500 bar,24 hour 0 1227 2025 5.0 2030 40 $2264 85 0% 00% $48.04 ! 0% $26.89
Natural Gas CCCT Dry"H",1X1,OF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 1x1 0 649 2025 5.0 2030 +40 $1,832 $2.68 0% 100% $41.33 0% $12.08
Natural Gas CCCT Dr "H",2X1,DF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 20 0 1227 r 2025 5.0 2030 +40 $1,518 € $2.23 0% 100% i $34.07 0/. $11.89
Natural Gas CCCT Dry"H",1X1,OF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 10 with 35%CCS 0 565 1 2025 5.0 2030 i +40 $3,261 € $5.03 0% 100% i $72.60 0/. $65.28
Natural Gas CCCT Dr "H",2X1,OF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 2xl with 35%CCS 0 1085 2025 5.0 2030 i +40 $2637 $4.49 0% 100% i $57.74 D% $65.08
Hydrogen Electrol zer,Proton Exchange Membrane lPEM),50,000k Ida 0 -119 2025 5.0 2030 40 $561 $23.31 +0% 0.00 $10.28 i 100'/. $32.46
Coal CCS Dave Johnston 4(costs on post retrofit basis) 5,541 -55 2027 5.0 I 2032 30 $3,501 511.40 0% 0% $277.68 0% 553.20
Coal CCS Hunter 1-3(costs on post retrofit basis) 6,429 -237 2027 5.0 2032 30 $2,951 $9.73 0% 0% i $235.36 0% $53.20
Coal CCS Huntington 1&2(costs on post retrofit basis) 6,933 -233 2027 5.0 2032 30 $2,951 $9.63 0% 0% i $242.12 D/. $53.20
Coal CCS Jim Bridget 3&4(costs on post retrofit basis) 7,513 -174 2025 5.0 2030 30 $2,598 1 $10.57 0% 0% i $254.91 0/. $53.20
Coal CCS W odak(costs on post retrofit basis) 4,448 -63 2027 5.0 2032 30 $3504 i $11.63 0% 0% i $303.51 i 0'/. $53.20
Nuclear Small Modular Reactor or Advanced Reactor,Moderate Technology Case NIA 600 2030 5.0 2035 60 $3,662 $3.74 0% 0% $37.42 0% i $17.00
Nuclear Small Modular Reactor or Advanced Reactor,Advanced TechnologyCase NIA 600 2030 4.0 2034 so $6,368 $8.74 0% 0% $84.53 0'/. 512.00
Nuclear Small Modular Reactor or Advanced Reactor,Moderate Technology Case+a for nuclear integrated thermal storage NIA 750 2030 5.0 2035 60 $10,628 € $10.72 0% 0% i 5707.16 0%. $17.00
Nuclear Small Modular Reactor or Advanced Reactor,Advanced Technology Case+a for nuclear integrated thermal storage NIA 750 2030 4.0 2034 60 $7 005 i $9.61 0% 0% i 152.98 i D/. $12.00
Nuclear Large Light Water Reactor,Moderate Technology Case NIA 2,000 i 2030 7.0 2037 60 $7,563 i $3.38 0% 0% i $125.36 D'/. $10.00
Nuclear Large Light Water Reactor,Advanced Technology Case NIA 2,000 i 2030 5.0 2035 60 $6 265 $7.88
Geothermal Near Field Enhanhanced Geothermal System(NF-EGS)Binar NIA 707 2025 3.0 2028 30 $7,593 included in FOM % 5794.00 % i 5125.09
Geothermal Near Field Enhanhanced Geothermal System(NF-EGSI Binary+e Advanced Geothermal Technology Case NIA 707 2025 3.0 2028 1 30included in FOM 13/
146

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.3 -2025 Non-Thermal Supply-Side Resources, Characteristics and Costs (2024$)
Characteristics Costs
Var O&M
Adjusted
Net Resource Total Commercial Asset Bas Fraction by Fixed Fraction Demolitio
Elevation Capacity Availability Implementation Operation Life Capital Var O&M Var O&M Capacity O&M Fixed O&M n Cost
Fuel ResourceDescription (APSE) (MW) Year Time(yrs) Year [yrs) ($IkW) (SIIr1Wh) Capitalized Changes [$IkW-yrl Capitalized (SIkW)
Storage' Li-Ion,4-hour,20 MW NIA 20 2025 1.0 2026 20 81,746 nduded in FOM 0% 0% $45.05 D% $29.94
Storage' Li-Ion,4-hour,200 MW NIA 200 2025 2.0 2027 20 $1,498 included in FOM! W. W. ! 538.77 OY. $25.66
Storage' Li-Ion,4-hour,200 MW+a Double Duration,Li-lon,4-hour,200MW NIA 200 2025 2.0 € 2027 20 52,557 ;includedin FOM 0% 0%% $0.78 DY. S46.13
Storage Li-lon,4-hour,1000 MW NIA 1,000 2025 3.0 2028 20 $1,459 included in FOM 0% I fJ'/. $36.32 0% $25.66
Storage Gravity Battery,4-hour,1000 MW NIA 1,000 2025 3.0 2028 50 $2,021 included FOM! O% OY. ! $50.51 0% $0.13
Stara a Gravity Batter,4-hour,1000 MW+a Double Duration,Gravit,4-hour,1000MW NIA 1,000 2025 3.0 2028 50 $3006 !included in FOM! O% OY. $90.92 DY. $0.35
Storage Adiabatic CAES,500 MW,4000 MWh NIA 500 2025 3.0 2028 50 $3,754 $2.60 50% O% ! $19.20 42/. $49.31
Stara a 100-hourlron Air NIA 200 2030 2.0 2032 20 22730 ;includedin FOM! 0' S21.04 S171.06
Storage Pumped Hydro,Two New Reservoirs,4-hour NIA 400 2025 5.0 2030 100 22,984 ! 20.58 0% 0% 520.20 45% $143.21
Storage Pumped Hydro,Two New Reservoirs,l0-hour NIA 400 2025 5.0 2030 ! 100 $4,159 ! $0.58 O% OY. ! $20.20 45% ! $207.35
Storage Pumped Hydro,One New Reservoir,4-hour NIA 400 2025 5.0 2030 i 100 $2,883 ! $0.58 O% OY. ! $20.20 45% ! $144.16
Storage Pumped Hydro,One New Reservoir,10-hour NIA 400 2025 5.0 2030 i 100 $3,537 ! $0.58 O% 01/ ! $20.20 45% ! $176.87
Storage Pumped Thermal Energy Storage,10-hour NIA 100 2026 5.0 2031 60 $6,174 $0.70 AG W. $2.00 0;4 $60.00
Stara a Pum ed Thermal EnergyStorage,24-hour NIA 50 1 2026 I 5.0 2031 60 $11525 20.70 ! 2. ! 1 $1.00 4" $60.00
Solar PV,20 MW,Class 1-10 by location ! 20 1 2025 3.0 2028 25 57,965 !includedin FOM! O% OY. $78.16 12/. $39.29
Solar PV,200 MW,Class 1-10 by location i 200 2025 3.0 2028 25 $7,217 included in FOM O% OY. ! $20.52 12/. $24.33
Solar PV,20 MW,Class 1-10+a Advanced Solar Technology Case by location ! 20 2025 3.0 2028 25 $1,832 included in FOM! 0% OY. ! S17.24 12/. $37.33
Solar PV,200 MW,Class 1-10+a Advanced Solar Technology Case by location 200 5 1 V 115 included in FOM!
Wind Wind Class 1-10,20 MW by location 20 2025 3.0 IN 30 52,555 included in FOM! 0% I/. S38.T9 35% $63.57
Wind Wind Class 1-6,200 MW by location 200 2025 5.0 2030 30 $
7,421 included in FOM O% OY. M65 ! 35% $63.57
Wind Wind Class7,200MW by location ! 200 2025 5.0 2030 30 $1,432 ;includedin FOM! O% OY. ! $3165 35% $63.57
Wind Offshore,Wind Class 12 1 0 200 2027 5.0 2032 30 $8,341 ;includedin FOM! Me i 01/ $69.26 ! 35% $163.16
Wind Wind Class l-10,20 MW+a Advanced Onshore Wind Technology Case bylocation 20 2025 3 2028 30 $2,434 included in FOM 0% 0% S34.87 35% I $60.58
Wind Wind Class l-6,200 MW+a Advanced Onshore Wind Technology Case bylocation 200 1 2025 I 5 2030 30 57,354 :includedin FOM 0% I 0'/. $28.45 ': 35% ! 560.58
Wind Wind Class 7,200MW+a Advanced Onshore Wind Technology Case by location 1 200 1 2025 5 2030 € 30 $1,422 included in FOM! O% $28.45 35% $60.58
Wind Offshore,Wind Class 12+a Advanced Offshore Wind Technology Case a 200 2027 5 2032 3171 $6,011 !includedin FOM!
'Assumed co-located
147

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.4-2025 Thermal Supply-Side Resources, Operating Characteristics and Environmental Data (2024$)
Operating Characteristics Environmental Data
Average Full
Load Heat Water
Rate(HHV Consumed 302 NOx Hg CO2
Fuel Resource Description Btu1KWh) Efficiency EFOR M) POR(%) (GaIIMWh) (lbsIMMBtu) (lbsIMMBtu) (lbsITBTu) (lbsIMMBtu)
Biofuel Internal Combustion Engine,renew able biofuel,with SCR&24-hour fuel tank 8,235 41.13% 2.50% 5.0% 27.1 0.00152 0.02000 0.000 117
Natural Gas SCCT Aero,with SCR 3,447 36.12% 2.90% 3.3% 27.0 0.00150 1 0,00750 0.000 117
Natural Gas SCCT Aero x4,with SCR 9,447 36.12% 2.90'/. 3.3% 27.0 i 0.00150 0.00750 0.000 117
Natural Gas SCCT Frame"F"xl,with SCR 3,717 35.12% 2.70% 3.9% 28.4 i 0.00150 0.00750 0.000 117
Natural Gas CCCT Dry"H",1X1,OF,with SCR 6,040 56.49% 2.50% 3.8% 210.0 i 0.00150 0.00750 0.000 117
Natural Gas CCCT Dr "H",2X1,DF,with SCR 6,122 55.74% 2.50% 3.8% 210.0 0.00150 0.00750 0.000 117
Natural Gas CCCT Dry"H",1X1,DF,with SCR+a for adding 35%CCS to new CCCT 1x1 6,743 53.17% 2.50% 3.8% 323.4 0.00150 0.00563 0.000 6
Natural Gas CCCT Dr "H",2X1,OF,with SCR+p for adding 35%CCS to new CCCT 20 6,843 52.46% 2.50% 3.8% 323.4 0.00150 0.00563 0.000 6
Natural Gas Internal Combustion Engine,renewable biofuel,with SCR&24-hour fuel tank+a for CT Brownfield construction 8,235 41.13% 2.50% 5.0% 27.1 0.00152 0.02131 0.000 117
Natural Gas SCCT Aero,with SCR+n for CT Brownfield construction 3,447 36.12% 2.90% 3.3% 27.0 0.00150 0.00733 0.000 117
Natural Gas SCCT Aero x4,with SCR+a for CT Brownfield construction 9,447 36.12% 2.30% 3.9% 27.0 0.00150 0.00799 0.000 117
Natural Gas SCCT Frame"F"xl,with SCR+p for CT Brownfield construction 9,717 35.12% 2.70% 1 3.3% 28.4 0.00150 0.00799 0.000 117
Natural Gas CCCT Dry"H",1X1,DF,with SCR+p for CT Brownfield construction 6,040 56.49% 2.50% 3.8% 210.0 0.00150 1 0.00799 0.000 117
Natural Gas CCCT Dr "H",2X1,DF,with SCR+c for CT Brownfield construction 6,122 55.74% 2.50% 3.8% 210.0 0.00150 0.00733 0.000 117
Natural Gas CCCT Dry"H",1X1,OF,with SCR+p For adding 95%CCS to new CCCT 10+p for CT Brownfield construction 6,743 53.17% 2.50% 3.8% 323.4 0.00150 0.00593 0.000 6
Natural Gas CCCT Dr "H",2X1,DF,with SCR+p for adding 95%CCS to new CCCT 20 for CT Brownfield construction 6,843 52.46% 2.50% T 3.8% 323.4 0.00150 0.00599 0.000 6
Hydrogen SCCT Frame"F"xl,with SCR+p for 100%Hydrogen burning capability 9,717 35.12% 2.70% 3.90% 28.4 0.00000 0.00750 0.000 0
Hydrogen CCCT Dry"H",1X1,DF,with SCR+a for 100%Hydrogen burning capability 6,040 56.49% 2.50% 1 3.80% 210.0 0.00000 0.00750 0.000 0
Hydrogen CCCT Or "H",2X1,OF,with SCR+p for 100%Hydrogen burning capability 6,122 55.74% 2.SO1 3.80% 210.0 0.00000 0.00750 0.000 0
Hydrogen SCCT Frame"F"x1,with SCR+p for Hydrogen storage,cavern,80 bar,24 hour 3,717 35.12% 2.75% 3.90% 28.4 0.00196 0.00946 0.002 0
Hydrogen CCCT Dry"H",1X1,DF,with SCR+a for Hydrogen storage,cavern,80 bar,24 hour 6,040 56.43% 2.55% 3.80% 210.0 0.00196 0.00346 0.002 0
H dro en CCCT Or "H",2X1,OF,with SCR+p for Hydrogen storage,cavern,80 bar,24 hour 6,122 55.74% 2.55% 3.80% 210.0 0.00196 0.00346 0.002 0
Hydrogen SCCT Frame"F"x1,with SCR+a for Hydrogen storage,tanks,500 bar,24 hour 3,717 35.12% 2.75% 3.90% 28.4 0.00196 0.00946 0.002 1 0
Hydrogen CCCT Dry"H",1X1,OF,with SCR+o for Hydrogen storage,tanks,500 bar,24 hour 6,040 56.49% 2.55% 3.80% 210.0 0.00136 0.00346 0.002 0
Hydro en CCCT Dr "H",2X1,OF,with SCR+❑for Hydrogen storage,tanks,500 bar,24 hour 6,122 55.74% 2.55% 3.80% 210.0 0.00136 0.00946 0.002 0
Natural Gas CCCT Dry"H",1X1,OF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 10 6,040 56.49% 2.50% 3.8% 210.0 0.00150 0.00750 0.000 117
Natural Gas CCCT Dr "H",2X1,OF,with SCR,Advanced Technology Case+-a advanced technology case,CCCT 20 6,122 55.74% 2.50% 3.8% 210.0 0.00150 0.00750 0.000 117
Natural Gas CCCT Dry"H",1X1,DF,with SCR,Advanced Technology Case+a advanced technology case,CCCT 10 with 95%CCS 6,743 53.17% 2.50% 3.8% 323.4 0.00150 0.00563 0.000 6
Natural Gas CCCT Dr "H",2X1,OF,with SCR,Advanced Technology Case+ advanced technology case,CCCT 20 with 95%CCS 6,843 52.46% 2.501 3.8% 323.4 0.00150 0.00563 0.000 6
H dro en Electrol zer,Proton Exchange Membrane(PEM).50,000 kgfday NIA 79.13% 1.50% 1.5% 45.7 0.00000 0.00000 0.000 0
Coal CCS Dave Johnston 4(costs on post retrofit basis) 14,795 23.06% 7.50% 7.50% 186.0 10.00000 0.07100 0.304 10
Coal CCS Hunter 1-3(costs on post retrofit basis) 14,011 24.35% 7.50% 7.50% 186.0 10.00000 0.07100 0.304 10
Coal CCS Huntington 1&2(costs on post retrofit basis) 13,662 24.38% 7.50% 7.50% 186.0 10.00000 0.07100 0.304 10
Coal CCS Jim Bridget 3&4(costs on post retrofit basis) 14,483 23.56% 7.50% 7.50% 186.0 10.00000 0.07100 0.304 10
Coal CCS W odak(costs on post retrofit basis) 16,653 20.49% 7.50% 7.50% 186.0 10.00000 0.07100 0.304 10
Nuclear Small Modular Reactor or Advanced Reactor,Moderate Technology Case 9,180 37% 2% 5% 720.0 0.00000 0.00000 0.000 0
Nuclear Small Modular Reactor or Advanced Reactor,Advanced Technology Case 9,180 37% 2% 5% 720.0 0.00000 0.00000 0.000 0
Nuclear Small Modular Reactor or Advanced Reactor,Moderate Technology Case+p for nuclear integrated thermal storage 12,626 37.17% 2.00% i5.0% 720.0 0.00000 0.00000 0.000 0
Nuclear Small Modular Reactor or Advanced Reactor,Advanced Technology Case+p for nuclear integrated thermal storage 12,626 37.17% 2.00% i .0% 720.0 0.00000 0.00000 0.000 0
Nuclear Large Light Water Reactor,Moderate Technology Case 10,497 33% 2% 5% 720.0 0.00000 0.00000 0.000 0
Nuclear Lar a Light Water Reactor,Advanced Technology Case 10 497 1 33% 2% 5% 720.0 0.00000 0.00000 0.000 0
Geothermal Near Field Enhanhanced Geothermal System(NF-EGS)BinaryNIA NIA 10% 10% 510.0 nfa nfa nfa n1a
Geothermal Near Field Enhanhanced Geothermal System[NF-EGS)Binary+a Advanced Geothermal TechnologyCase NIA NIA 1 10.00% 10.00% 510.0 nfa nfa nfa nla
148

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.5-2025 Non-Thermal Supply-Side Resources, Operating Characteristics and Environmental Data (2024$)
Operating Characteristics Environmental Data
Average Full
Load Heat Water
Rate(HHV Consumed 302 NOx Hg CO2
Resource Description BtulKWh1 Efficiency EFOR(%) POR(%) (GaI1MWhl (lbsIMMBtu) (lbsIMMBtu) (IbsITBTu) (lbsIMMBtu)
Storage' Li-Ion,4-hour,20 MW nfa 85% 1.0% included in CF nfa 0.00000 0.00000 0.000 0
Storage' Li-Ion,4-hour,200MW nfa 85% 1% included in CF nfa 0.00000 0.00000 0.000 0
Storage' Li-Ion,4-hour,200 MW+a Double Duration,Li-Ion,4-hour,20OMW nfa 85.00% 1.00% included in CF nfa i 0.00000 0.00000 0.000 0
Storage Li-Ion,4-hour,1000 MW nfa 85% 1.0% included in CF nfa 0.00000 0.00000 0.000 0
Storage Gravity Battery,4-hour,1000 MW nfa 83% 1 1.0% i included in CF nfa 0.00000 a00000 0.000 0
Storage Gravity Battery,4-hour,1000 MW+a Double Duration,Gravity,4-hour,1000MW nfa 83.00% 1 1.00% i included in CF nfa I 0.00000 0.00000 0.000 0
Storage Adiabatic CAES,500 MW,4000 MWh nfa 63% 1.1% 1.1% nfa 0.00000 1 0.00000 0.000 0
Storage 100-hour Iron Air nfa 43% 1.0% [ included in CF 0.0 0.00000 0.00000 0.000 0
Storage Pumped Hydro,Two New Reservoirs,4-hour nfa 80% 2.0% 4.0% nfa 0.00000 0.00000 0.000 0
Storage Pumped Hydro,Two New Reservoirs,l0-hour nfa 80% 2.0% 1 4.0% nfa 0.00000 0.00000 0.000 0
Storage Pumped Hydro,One New Reservoir,4-hour nfa 80% 2.0% I4.0% War 0.00000 0.00000 0.000 0
Storage Pumped Hydro,One New Reservoir,l0-hour, nfa 80% 2.0% 4.0% nfa 0.00000 0.00000 0.000 0
Storage Pumped Thermal Energy Storage,10-hour nfa 55% 2.0% 3.0% nfa 0.00000 0.00000 1 0.000 0
Stora a Pumped Thermal Energy Storage,24-hour nfa 55% 2.0% 3.0% nfa 0.00000 0.00000 0.000 0
Solar PV,20 MW,Class 1-10 NIA i by location i Included with CF i Included with CF nfa nfa nfa nfa i n1a
Solar PV,200 MW,Class 1-10 NIA by location €Included with CF;Included with CF nfa nfa nfa nfa
Solar PV,20 MW,Class 1-10+a Advanced Solar Technology Case NIA € by location i Included with CF i Included with CF nfa nfa nfa nfa nfa
Solar PV,200 MW,Class 1-10+a Advanced Solar TechnologyCase NIA ` by location iIncluded with CFi nfa nfa nfa I nfa -
Wind Wind Class l-10,20MW NIA i by location €Included with CF'iIncluded with CF nfa nfa nfa I nfa nfa
Wind Wind Class 1-6,200 MW NIA by location ;Included with CF:Included with CF nfa nfa nfa Infa nfa
Wind Wind Class 7,200 MW NIA i by location i Included with CF;;Included with CF nfa nfa nfa nfa nfa
Wind Offshore,Wind Class 12 NIA 1 max CF:47% Included withCF;Included w ith CFInfa nfa nfa nfa nfa
Wind Wind Class 1-10,20 MW+a Advanced Onshore Wind Technology Case NIA i by location €Included with CF i Included with CF nfa nfa nfa nfa nfa
Wind Wind Class 1-6,200 MW+a Advanced Onshore Wind Technology Case NIA bylocation ;Included with CF i Included with CF nfa nfa nfa nfa nfa
Wind Wind Class 7,200 MW+a Advanced Onshore Wind Technology Case NIA i by location i Included with CF;Included with CF nfa nfa nfa nfa nfa
Wind Offshore,Wind Class 12+a Advanced Offshore Wind TechnologyCase NIA mam CF:47%i Included with CF i nfa nfa nfa nfa nfa
Assumed co-located
149

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.6-2025 IRP Thermal Supply-Side Resources, Additional Attributes and Fixed O&M
Additional Attributes Fixed O&M
Total Total Total Fixed
Total Annual O&M Gas Fixed Fixed Cost
Modeled Elevation Capital Demolition Pas t Payment Capaciq Storage O&M Ca alized Capitalized Transport OkM Cost Converted
Resource Description IRP (AFSL) Cost F ($fkV-Yr) Factor EFFicienq ($fkV-Yr) m [$lkV-Yr) [slkV-Yr) [$fkV-Yr) $fkV-Yr $fMVh
Internal Combustion Engine.renewable biofuel,with SCR a 24 hour fuel rank Yes i 0 i $ 2.130.94 i$ 14.59 6.890'/. $14Z83 1 41.13% 0% $42.82 1 2.62% $t12 $0.00 i $43.94 $191.77 i $53.22
SCCT Aero,with SCR No i 0 i$ 2.612.801$ 32.46 i 6.101% $161.39 36.12% 0% $12.42 2.62'/. i $0.32 i $0.00 i $12.74 $174.13 $55.03
SCCT Aero x4,with SCR No 1 0 1$ 1.789.35 i$ 32.46 i 6.104% $111.20 36.12% 0% $9.93 2.62% 1 $0.26 i $0.00 $10.19 $121.40 $38.37
SCCT Frame"F"x1,with SCR No 1 0 i$ 1,366.92 i$ 12.13€ 6.100'/. $85.34 35.12'/. 0% $27.92 2.62% $0.73 $0.00 $28.65 $114.00 $37.06
CCCT Dry"H",1X1,OF,with SCR No 0 $ 1,839.00 $ 12.08' 6.233% $115.38 56.49'/ 0% $42.44 2.62'/ $1.11 $0.00 $43.55 $158.93 $32.12
Goshen Yes 2,814 $ 1,857.39 i$ 12.08[ 6233% $116.52 56.49'/. 0% 542.44 2.62% $1.11 $60.34 $103.89 $220.41 $44.54
Wasatch Front Yes 4,225 E 1,820.61 $ 12.08€ 6233% $114.23 56.49% € 0% $42.44 2.62% $1.11 $9.25 $52.81 $167.04 $33.75
W omin East Yes 6,130 i$ 1,820.61 $ 12.08€ 6.233% $114.23 56.49'i 0% $42.44 2.62'/. $1.11 $16.33 i $59.88 $174.11 $35.18
CCCT Dry"H",2X1,OF.with SCR No 1 0 $ 1.553.28 i$ 11.89€ 6234% $97.57 55.74% 0% $35.18 2.62% $0.92 $0.00 $36.10 $133.67 $27.38
Goshen Yes 2,814 E 1,568.79 j$ 11.891 6234% $98.54 55.74/ [ 0% $35.18 2.62% $0.92 $61.16 $97.28 $195.80 $40.10
Wasatch Front Yes 4.225 $ 1,537.73 $ 11.89€ 6.234% $96.60 55.74% [ 0% $35.18 2.62'/. i $0.92 1 $9.38 $45.48 $142.08 $29.10
W omin East Yes 6130 1537.73 i$ 11.89€ 6234% $96.60 55.74% 0% $35.18 2.62% $0.92 $16.55 $52.65 $149.26 $30.57
CCCT Dr"H",1X1,OF,with SCR.a for adding 95%CCS to new CCCT 1x1 No 0 i$3,429.38 i$ 65.28€ 6239% $218.03 53.17/ 0% $77.07 5.54% $4.27 $0.00 $81.34 $299.37 $64.28
CCCT Or"H",2X1,DF,with SCR•e for addin 95'/.CCS to new CCCT 2x1 No 0 i$2,846.02 i$ 65.08€ 6.24t/. $181.68 52.46'/. 0'/. $62.99 5.54'/. $3.49 $0.00 $66.48 $248.16 $54.00
Internal Combustion En ine,renewable biofuel,with SCR•e for CT Brownfield construction No 0 i$ 1.917.851$ 14.59 i 6.891% $133.16 41.13% 0% $42.82 2.62% $1.12 $0.00 $43.94 $177.10 $49.15
SCCT Aero,with SCR•a For CT Brownfield construction No 1 0 1$ 2.351.521$ 32.46i 6.102'/. $145.47 36.12% 0% $12.42 2.62% $0.32 1 $0.00 i $12.74 $158.21 $50.00
SCCT Aero 0,with SCR•a For CT Brownfield construction No i 0 i$ 1.610.42i$ 32.461 6.105% $100.30 36.12'% r 0% $9.93 2.62'/. $0.26 1 $0.00 $10.19 $110.49 1 $34.92
SCCT Frame"F"x1.with SCR-e for CT Brownfield construction No 1 0 $ 1,248.23 i$ 12.13€ 6.100% $76.88 35.12% 0% $27.92 2.62% $0.73 $0.00 $28.65 $105.53 $34.31
Goshen-Brownfield Yes 2.814 $ 1.260.71 $ 12.13€ 6.100'/. $77.64 35.12% 0% $27.92 1 2.62% $0.73 $96.20 $124.85 $202.50 $65.83
Wasatch Front-Brownfield Yes 4,225 1$ 1,235.75 $ 12.13€ 6.100% $76.12 35.12/. 0% $27.92 2.62'/. $0.73 $14.72 $43.38 $119.50 $38.85
W omin East-Brownfield Yes 6,130 i$ 1,235.75 i$ 12.13€ 6.100% $76.12 35.12% 0% $27.92 2.62% $0.73 $25.80 $54.45 $130.57 $42.45
CCCT Dry"H",1X1,OF,with SCR.a For CT Brownfield construction No 0 $ 1.655.10 $ 12.08€ 6234% $103.93 56.49% 0% $42.44 2.62% $1.11 $0.00 $43.55 $147.48 $29.80
Goshen-Brownfield Yes 2.814 $ 1,671.65 $ 12.08 6234'/. $104.96 56.49% 0% $42.44 2.62% $1.11 $60.34 $103.89 $208.85 $42.20
Wasatch Front-Brownfield Yes 4,225 $ 1.638.55 i$ 12.08 6234% $102.90 56.49% 0% $42.44 2.62% $1.11 $9.25 $52.81 $155.71 $31.46
W omin East-Brownfield Yes 1 6.130 i$ 1.638.55 i$ 12.08 i 6234% $102.90 1 56.49% 0% $42.44 i 2.62% 1 $1.11 i $16.33 $59.88 $162.78 $32.89
CCCT Or"H",2X1,OF.
with SCR For CT Brownfield construction No 0 i$ 1,397.93 1$ 11.89 i 6234% $87.89 55.74% 1 0% $35.16 2.62% $0.92 $0.00 $36.10 $123.99 i $25.40
CCCT Or"H",1X1,DF,with SCR•n for adding 95'/.CCS to new CCCT 181.e for CT Brownfield construction No 0 i$3,086.44 i$ 65.28? 6.240% $196.67 53.17'/. 0% $77.07 5.54% $4.27 $0.00 $81.34 $278.00 $59.69
CCCT Dr"H",2X1,OF.with SCR-e for adding95%CCS to new CCCT 2x1-a For CT Brownfield construction No i 0 i$ 2.561.42 i$ 65.08 i 6242% $163.95 52.46% i 0% $62.99 1 5.54% i $3.49 i $0.00 i $66.48 $230.43 i $50.14
SCCT Frame"F"x1,with SCR.e for 100'/.H dro en burningcapability No 0 i$ 1,594.96 i$ 13.95 i 5.605'/. $90.18 35.12'/. 0'/. $27.92 2.6Y/. $0.73 $0.00 $28.65 $118.83 $38.63
CCCT Or"H",1X1,DF,with SCR•n for 100'/.H dro en burnin ca abilit No 0 i$ 2,114.85 I$ 13.89' 5.604'/. $119.29 56.49% 0% $42.44 2.62% $1.11 $0.00 $43.55 $182.85 i $32.91
CCCT Dr"H",2X1,OF.with SCR•a for 100%H dro en burnin ca abilit No 0 i$ 1,786.25 i$ 13.67 i 5.604% $100.87 55.74% i 0% $35.18 2.62% $0.92 $0.00 $36.10 $136.97 i $28.05
SCCT Frame"F"x1,with SCR.e for Hydrogen storage,cavern,80 bar,24 hour No 0 i$2,565.93 i$ 27.13 i 9.27t/. $242.26 i 35.12'/. 0'/. $35.12 $0.92 $0.00 $36.04 $278.30 i $90.47
CCCT Dr e,"H",1X1,OF,with SCR•n For Hydrogen en stora cavern,80 bar.24 hour No 0 i$ 3.038.01 i$ 27.08€ 9.254% $283.64 56.49% 0% $49.64 22.62'/..62'/. 1 $1.3 i $0.00 $50.94 $334.59 $67.61
CCCT Dr"H",2X1,OF.with SCR•a for Hydrogen storage.cavern,80 bar,24 hour No 1 0 i$2.752.27 i$ 26.89 i 9263% $257.43 i 55.74% i 0% $42.38 2.62% $1.11 $0.00 $43.49 $300.93 i $61.63
SCCT Frame"F"x1,with SCR•a For Hydrogen storage,tanks,500 bar,24 hour No 0 i$2,097.84 i$ 27.13 i 9.255'/. $198.67 35.12Y 0% $40.78 1 2.62% 1 $1.07 $0.00 1 $41.85 $238.51 i $77.54
CCCT Dr"H",1X1,OF,with SCR-n For Hydrogen storage,tanks,500 bar.24 hour No 0 i$ 2,549.91 i$ 27.08€ 9.245% $238.24 56.49% 0% $55.30 2.62% $1.45 $0.00 $56.75 $294.99 i $59.61
CCCT Or"H",2X1,OF,with SCR-e for Hydrogen storage.tanks,500 bar,24 hour No 0 i$ 2,264.18 i$ 26.89 i 9250% $211.22 55.74% i 0% $48.04 2.62% $1.26 $0.00 $49.30 $261.22 i $53.50
CCCT Or"H",1X1,DF,with SCR,Advanced Technology Case-a advanced technollogg case.CCCT 1x1 No 1 0 i$ 63 i$ 12.08 i 6233'/. $114.92 56.49% i 0% $41.33 2.62% $1.08 $0.00 i $42.41 $157.33 i $31.79
CCCT Dr"H",2X1,OF,with SCR,Advanced Technology Case•a advanced technology case,CCCT 2x1 Noi 0 i$ 1,1,831.517.84 $ 11.891 6.234% $95.36 55.74% 0'/. $34.07 2.62'/. $0.89 $0.00 i $34.96 $130.32 i $26.69
CCCT Or"H",1X1,OF,with SCR,Advanced Technology Case.e advanced technology case.CCCT 1x1,95%CCS No i 0 i$3,260.883$ 65.28i 6233% $207.32 53.17% 0% $72.80 1 5.54% i $4.02 i $0.00 i $76.62 $283.94 i $60.97
CCCT Dr"H",2X1,OF,with SCR,Advanced Technology Case•a advanced technology case.CCCT 2x1,95Y CCS No 1 0 1$ 2.637.12 1$ 85.08 i 6234'/. $168.46 52.46% i 0% $57.74 1 5.54% 1 $3.20 1 $0.00 i $60.94 $229.40 i $4F92
Electrol zer,Proton Exchange Membrane PEM),50,000 kg1day Yes 0 i$ 560.99 i$ 32.46 i 6.628% $33.40 79.13'% f 0% $10.28 i 0.00'% i $0.00 $0.00 1 $10.28 $43.68 $6.30
CCS Dave Johnston 4 costs on post retrofit basis No 1 5541 i$3.500.78 i$ 53.20 i 6.447% $229.12 23.06% :, 0% $277.68 i 5.54% 1 $15.38 i $0.00 i $293.06 $522.19 i $258.46
CCS Hunter 1-3 costs on post retrofit basis No i 6,429 i$ 2,951.20 i$ 53.20 i 6.451% $193.81 24.35% i 0% $235.36 1 5.54% 1 $13.04 1 $0.00 i $248.39 $442.21 i $207.29
CCS Huntin ton 1&2 costs on post retrofit basis No 6,933 i$ 2,951.40 $ 53.20€ 6.451'/. $193.83 24.98'/. 0'/. $242.12 5.54'/. $13.41 $0.00 i $255.53 $449.36 i $205.39
CCS Jim Brid er 3h4 costs on ost retrofit basis No 7513 i$2598.38i 53.20i 6.454% $171.13 23.56% 0% 254.91 5.54% $14.12 $0.00 1 $289.03 $440.16 i $213.28
CCS W odak costs on post retrofit basis No 1 4.448 1$3.504.25 i$ 53.20 i 6.447% $229.35 ? 20.49% i 0% $309.51 1 5.54% 1 $17.15 i $0.00 i $326.65 $556.00 i $309.76
Small Modular Reactor or Advanced Reactor,Moderate Technology Case Yes NIA i$9,662.09 i$ 17.00 i 3.919'/. $379.32 i 37.17'/. 0% $97.42 9.42% $9.18 $0.00 i $106.60 $485.92 i $149.24
Goshen Yes 2.814 $9.855.33 i$ 17.00 i 3.919i $388.90 i 37.17% 0% $97.42 9.42% $9.18 $0.00 i $106.60 $493.50 i $151.56
Wasatch Front Yes 4,225 $9,855.33 j$ 17.00 i 3.545% $349.97 i 37.17% 0% $97.42 9.42% $9.18 $0.00 $106.60 $456.57 i $140.22
W omin East Yes 6.130 1$9,565.47 1$ 17.00 i 3.545% $339.70 i 37.17% 0% $97.42 9.42'% $9.18 $0.00 i $106.60 $446.30 i $137.07
Small Modular Reactor or Advanced Reactor,Advanced TechnologyCase No NIA i$6,368.23 i$ 12.00 3.919'r. $250.04 i 37.17% 0% $84.53 9.42% $7.97 $0.00 i $92.49 $342.53 [ $105.20
Small Modular Reactor or Advanced Reactor,Moderate Technolo Case•e for nuclear inte rated thermal stora a No NIA $10,628.30 i$ 17.00 i 3.919/. $417.19 37.17% 0% $107.16 9.42% $10.10 $0.00 i $117.28 $534.45 i $164.14
Small Modular Reactor or Advanced Reactor,Advanced Technology Case•e for nuclear integrated thermal storage No i NIA 1$7,005.05 i$ 12.00 3.918'/. $275.00 i 37.17% 0% $92.98 1 9.42'% $8.76 $0.00 i $101.74 $376.74 i $115.70
Large Li ht Water Reactor,Moderate Technology Case No NIA i$7,562.871$ 10.00 i 3.919r/ $296.78 32.51/. 0% $125.36 1 9.42% i $11.81 i $0.00 i $137.17 $433.95 i $152.40
Large Li ht Water Reactor,Advanced Technology Case No NIA 1$6,265.251$ 9.00 i 3.919% $245.89 i 32.51% 0% $90.26 1 0.87% 1 $0.79 i $0.00 i $91.04 $336.93 i $118.32
Near Field Enhanhanced Geothermal System(NF-EGS)Binary Yes i NIA i$7,593.08 i$ 125.09 i 5.178/. $399.65 i 90.00'/. 0% $194.00 0.00% $0.00 $0.00 i $194.00 $593.65 i $75.30
Southern OR Yes 497 $8.883.88 i$ 125.09€ 5.178'. $466.48 90.00% 0% $194.00 0.00% $0.00 $0.00 i $194.00 $660.48 i $83.78
Wasatch Front Ves 4.225 1$7.593.06 i$ 125.09 i 4.817% $371.78 90.00% 0% $194.00 0.87% $1.69 $0.00 1 $195.69 $567.47 i $71.98
150

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Table 7.7- 2025 IRP Non-Thermal Supply-Side Resources, Additional Attributes and Fixed O&M
Additional Attributes Fixed Ohm
Total Total Total Fixed
Total Annual Ohm Gas Fixed Fixed Cost
Modeled Elevation Capital Demolition Payment Payment Capacity Storage D&M Capitalized Capitalized Transport O&M Cost Converted
Resource Description IRP (AFSL) 2M Cost Factor _MNI&LFactor Efficiency. (SfkV-Yr) Premium [=fkV-Yr) (sfkV-Yr) [sfkV-Yr] jfkV-Yr =fmvh
PV,20 MW,Class 1-10 Yes by location $ 1,964.64 $ 39.29 6.861'/. $137.49 by location 0'/. $18.18 1.37/. 1 $0.25 $0A0 $18.41 $155.90 $0.00
Portland North Coast Yes 19 $ 2.082.51 $ 39.291 6.861% $145.58 24.49% i 0% $18.16 1.37% $0.25 $0.00 $18.41 $163.99 '. $76.45
Southern OR Yes 497 $ 2,180.75 $ 39.29 6.861% $152.32 29.29% 0% $18.16 1.37Y. $0.25 $0.00 $18.41 $170.73 i $66.54
Walla Walla Yes 2.353 $2.003.93 $ 3929' 6.86P/. $140.19 25.96% ! 0% $18.16 1.37% $0.25 $0.00 $18.41 $158.60 $69.74
Goshen Yes 1 Z814 $ 1.984.28::$ 39.29[ 6.86P/, V38.84 27.79% i 0% $18.16 1.37% $0.25 $0.00 $18.41 $157.25 i $64.59
Wasatch Front Yes 4.225 $ 1,964.64 $ 39291 8.861% $137.49 29.00% ': 0% $18.16 1.37% $0.25 $0.00 $18.41 $155.90 i $81.38
Wuornina East Yes 6,130 $ 1,964.64[$ 3929? 8.861% $137.49 27.47% ! 0% $18.18 1.37% $0.25 $0.00 $18.41 L$%
0 $64.79
PV,200 MW,Class 1.10 Yes by location $ 1,216.55'$ 24.33 6.861% $85.14 by location 0'/. $20.52 1.37% $0.28 $0.00 $20.803 i $0.00
Portland North Coast Yes 19 $ 1,289.55 i$ 24.33': 6.861% $90.15 24.49% ': 0% $20.52 1.37Y. 50.28 $0.00 $20.804 $51.72
Southern OR Yes 497 $ 1.350.37 $ 24.33 6.86P/. $94.32 29.29% � 0% $20.52 1.37% $0.28 $0.00 $20.802 $44.87
Walla Walla Yes 2.353 i$ 1.240.88 $ 24.33 6.861% $86.81 25.96% 0'/. $20.52 1.37% $0.28 $0.00 $20.800 $47.32
Goshen Yes 1 2,814 $ 1,228.72 $ 24.33 6.861% $85.97 27.79% ': 0% $20.52 1.37Y. $0.28 $0.00 $20.807 i $43.86
Wasatch Front Yes 4,225 $ 1,216.55 $ 24.33[ 6.861'/. $85.14 29.00'/. i 0% $20.52 1.37Y. $0.28 $0.00 $20.803 i $41.71
W omin East Yes 8.130 $ 1,218.55 $ 24.33€ 6.861% $85.14 27.47% 0% $20.52 1.37% $0.20 $0.00 $20.8093 $44.02
PV,20 MW,Class l-10.e Advanced Solar TechnologyCase No b location;$ 1.832.22 i$ 37.33 i 8.862% $128.29 b location i 0% $17.24 1.37% $0.24 $0.00 $17.4876 $0.00PV,200 MW,Classl-10a AdvancedSolar Technolo Case No b location:$ 1,13456 $ 23.11i 6.862'/. $79.44 b location i 0'/. $19.47 1.37% $0.27 $0.00 $19.74 .8 $0.00
Wind Class 1-10,20 MW Yes by location $2,554.58 $ 63.57 6.292% $164.73 by location 0% $38.79 4.39% $1.70 $0.00 $40.49 $205.22 i $0.00
Portland North Coast Yes 19 $2,835.59?$ 63.57[ 8.292% $182.42 24.91% 0% $38.79 4.39% $1.70 $0.00 $40.49 $222.90 $102.14
Southern OR Yes 497 $ 3,014.41 $ 63.57 6.292% $193.67 25.18% 0% $38.79 4.39'/. $1.70 $0.00 $40.49 $234.15 i $106.14
Walla Walla Yes 2,353 $2,656.77 $ 63.57 i 6292% $171.16 23.13% 0% $38.79 4.39% $1.70 $0.00 $40.49 $211.85 VO4.46
Goshen Yes 2.814 $2.605.88[$ 93.57 6292% $167.95 #NIA 0% $38.79 4.39% $1.70 $0.00 $40.49 $208.44 $0.00
Wasatch Front Yes 4.225 $ 2.580.13 $ 63.57 6.292% $166.34 #NIA j 0% $38.79 4.39% $1.70 $0.00 $40.49 $206.83 i $0.00
Wuomina East Yes 6.130 $2,503.49 $ 63.57 i 6292% $161.52 #NIA 0% $38.79 4.39% $1.70 $0.00 $40.49 $202.01 1 $0.00
Wind Class 1-6.200 MW Yes ?by location $ U21.10'.S 63.57[ 8.318% $93.77 1 by location i 0'/. $31.65 4.39% $1.39 $0.00 $33.04 $126.81 $0.00
Portland North Coast Yes 19 i$ 1.577.43 $ 63.57 6.316% $103.65 37.62% 0'/. $31.65 4.39'/. $1.39 $0.00 $33.04 $136.68 $41.47
Southern OR Yes 497 $ 1,676.90 S 63.57 6.316% SI09.93 34.06% 0% $31.65 4.39% $1.39 $0.00 $33.04 $142.97 i $47.92
Walla Walla Yes 2,353 $ 1,477.95'.$ 63.57 6.316'/. $97.36 32.59'/. i 0% $31.65 4.39'/. $1.39 $0.00 $33.04 $130.40 i $45.68
Goshen Yes 2.814 $ 1.449.53 $ 63.57 6.316% $95.57 30.28% 0% $31.65 1 4.39% $1.39 $0.00 $33.04 $128.61 $48.49
Wasatch Front Yes 4,225 $ 1,435.32 S 63.57[ 6.316% $94.67 30.42% 0% $31.65 4.39% $1.39 $0.00 $33.04 $127.71 $47.93
W omin East Yes 6,130 $ 1.392.68 $ 63.57€ 6.316'/. $91.98 41.25% 0% $31.65 4.39% $1.39 $0.00 $33.04 $125.02 i $34.60
Wind Class 7.200 MW No b location $ 1,491.78 $ 63.57 i 6.313i $98.19 b location i 0% $31.65 4.39% $1.39 $0.00 $33.04 $131.23 $0.00
Offshore,Wind Class 12 Yes 0 $8.340.57[S 169.16€ 6286% $534.92 #NIA 0'/. $89.26 4.39% $3.04 $0.00 $72.30 $607.22 i $0.00
Wind Class 1-10,20 MW•e Advanced Onshore Wind TechnologyCase No b location:$2,434.26 $ 60.581 6.292'/. $156.98 b location i 0'/. $34.87 4.39'/. $1.53 $0.00 $36.40 $193.37 i $0.00
Wind Class 1-6.200 MW.a Advanced Onshore Wind TechnologyCase No b location $ 1.354.17 S 80.58i 8.316% $89.36 b location i 0% $28.45 4.39% $1.25 $0.00 $29.70 $119.06 $0.00
Wind Class 7.200 MW-a Advanced Onshore Wind TechnologyCase No b location:$ 1,421.51[S 60.58i 6.313Y. $93.56 b location i 0'/. $28.45 4.39% $1.25 $0.00 $29.70 1 $123.27 $0.00
Offshore,Wind Class 12•e Advanced Offshore Wind Technology Case No 0 i$ 6.011.05 i$ 121.921 6.286'% 1 $385.52 #N1A 0'/. $63.21 4.39% $2.78 $0.00 i $65.99 1 $451.51 $0.00
151

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.8-2025 IRP Storage Supply-Side Resources, Additional Attributes and Fixed O&M
Additional Attributes Fixed O&M
Total Total Total Fixed
Total Annual O&M Gas Fixed Fixed Cast
Modeled Elevation Capital Demolition Payment Payment Capaciq Storage D&M Capitalized Capitalized Transport D&M Cost Converted
Resource Description IRP (AFSL) Cost Cost Factor ($IkV-Yr) Factor Efficiency ($IkV-Yr) Premium ($IkV-Yr) ($IkV-Yr) ($IkV-YFJ $IkV-Yr) j$1MVh
Li-Ion,4-hour,20 MW' No NIA i$ 1,747.61 i$ 29.94 5.354% $95.17 16.67% 85% $45.05 i Uo% i $0.00 i $0.00 1 $45.05 $140.22 $96.04
Li-lon,4-hour,200 MW' No NIA $ 1.497.89 i$ 25.66 5.354'/. $81.57 16.67'/. 85% $38.77 j 0.00'/. $0.00 $0.00 $38.77 $120.34 $82.42
Portland North Coast Yes 19 $ 1,587.77 i S 25.66 i 5.354% $86.38 16.67% 85Y $38.77 0.00% $0.00 $0.00 $38.77 $125.15 $85.72
Southern OR Yes 497 $ 1,617.73 S 25.66€ 5.354'/. $87.99 16.67'/. 85'/. $38.77 i 0.00'/. $0.00 $0.00 $36.77 $126.75 $66.82
Walla Walla Yes 2.353 $ 1.542.83 i$ 25.66€ 5.354'/. $83.98 16.67% 85'/. $38.77 0.00'/. $0.00 $0.00 $38.77 $122.74 $84.07
Goshen Yes 2.814 $ 1.527.85 $ 25.66 5.354% $83.18 16.67% 85% $38.77 0.00% $0.00 $0.00 $38.77 $121.94 $83.52
Wasatch Front Yes 4.225 $ 1.542.831$ 25.66€ 4.452% $69.83 16.67% 85% $38.77 0.00'/. $0.00 $0.00 $38.77 $108.60 $74.38
W omin East Yes 6,130 i$ 1.402.92 1$ 25.66€ 4.452% $67.16 16.67: 85% $38.77 0.00'/. $0.00 $0.00 $38.77 $105.93 $72.55
Li-lon,4-hour,200 MW.a Double Duration,Li-Ion,4-hour,200MW' No NIA I$2,556.57 i$ 46.19i 5.355'/. $139.38 33.33'/. 85'/. $69.78 1 0.00'/. 1 $0.00 $0.00 i $69.78 $209.16 $71.63
Portland North Coast Yes 1 19 $2,709.97 i$ 46.19 i 5.355% $147.59 33.33% 85% $69.78 0.00% $0.00 $0.00 $69.78 $217.37 i $74.44
Southern OR Yes 497 $ 2,761.10 1$ 46.19 5.355% $150.33 33.33% i 85'/. $69.78 1 0.00'/. i $0.00 $0.00 $69.78 $220.11 $75.38
Walla Walla Yes 2.353 i$2.633.27 i$ 46.19 5.355% $143.40 33.33% i 85% $69.78 i 0.00% $0.00 $0.00 $69.78 $213.27 i $73.04
Goshen Yes 2.814 $ 2.607.71 i$ 46.19 5.355% $142.12 33.33% 85% $69.78 0.00% $0.00 $0.00 $69.78 $211.90 $72.57
Wasatch Front Yes 4.225 $2.633.27 $ 46.19 4.453'/. $119.32 33.33% i 85'/. $69.78 0.00% $0.00 $0.00 $69.78 $189.10 $64.76
Wyoming East Yes 6.130 i$ 2,531.01 i$ 46.19€ 4.453% $114.76 33.33% 65'/. $69.78 0.00'/. $0.00 $0.00 i $89.78 $184.54 $63.20
Li-Ion,4-hour,1000 MW' No NIA i$ 1,459.50 i$ 25.66€ 5.356'/. $79.55 16.67'/. 85% $36.92 0.00'/. $0.00 $0.00 i $36.92 $116.47 $79.77
Li-Ion,4-hour,200 MW No NIA i$ 1,497.89 i$ 25.66 i 5.354% $81.57 16.67% 85% $38.77 0.00% $0.00 $0.00 i $38.77 $120.34 i $82.42
Portland North Coast Yes 19 $ 1.587.77 $ 25.66€ 5.354% $86.38 18.87% 85% $38.77 0.00% $0.00 $0.00 $38.77 $125.15 $85.72
Southern OR Ye i 497 i$ 1.617.73'$ 25.66€ 5.354% $87.99 16.67% 85% $38.77 0.00% $0.00 $0.00 $38.77 $126.75 i $86.82
Walla Walla Yes 2.353 $ 1,542.83 i$ 25.66 i 5.354% $83.98 16.67% 85% $38.77 0.00% $0.00 $0.00 $38.77 $122.74 i $84.07
Goshen Yes 2.814 $ 1.527.85 $ 25.66€ 5.354%. $83.16 16.67% 85'/. $38.77 0.00% $0.00 $0.00 $38.77 $121.94 $83.52
Wasatch Front Yes 4.225 $ 1.542.83 i$ 25.66€ 4.452% $69.03 16.67% 85'/. $38.77 0.00'/. $0.00 $0.00 $38.77 $108.80 $74.38
W omin East Yes 6,130 i$ 1,482.92 i$ 25.66 i 4.452% $67.16 16.67% 85% $38.77 0.00% 1 $0.00 i $0.00 $38.77 $105.93 i $72.55
Gravity Battery,4-hour,1000 MW Yes NIA 1$2.020.99 1$ 0.19€ 2.916% $58.94 16.67'/. 83% $50.51 i 0.00'/. 1 $0.00 $0.00 i $50.51 $109.45 i $74.97
Gravity Battery.4-hour,1000 MW.a Double Duration,Gravity.4-hour,1000MW No NIA i$3.008.34 i$ 0.35 i 2.916% $87.68 33.33'/. 83% $90.92 1 5.48'/. 1 $4.98 i $0.00 i $95.90 $183.58 $62.87
Adiabatic CAES,500 MW,4000 MWh No 1 NIA i$3,754.00 i S 49.31 i 4.288% $163.09 33.33% i 63% $19.20 0.00% $0.00 $0.00 $19.20 $182.29 i $62.43
100-hour Iron Air Yes NIA i$2,729.67 1$ 171.08€ 4.581% $132.88 1 30.07% 43% $21.04 1 2.62'% i $0.55 1 $0.00 i $21.59 $154.47 $58.64
Pumped Hydro,Two New Reservoirs,4-hour No NIA i$2.984.23 i$ 149.21 i 3.121% $97.79 16.67% 80% $20.20 1 2.62% 1 $0.53 j $0.00 i $20.73 $118.52 $81.18
Pumped Hydro,Two New Reservoirs,10-hour Yes NIA i$ 4.158.90 i$ 207.95 1 3.121% $136.29 41.87% 80% $20.20 2.62% $0.53 $0.00 i $20.73 $157.02 i $43.02
Portland North Coast Yes 19 1$4.408.44 $ 207.95 3.121% $144.08 41.67% 80% $20.20 2.62% $0.53 $0.00 i $20.73 $164.81 $45.15
Southern OR Yes 497 $ 4,491.61 i$ 207.95 i 3.121% $146.67 41.67% 80% $20.20 1 2.62% $0.53 $0.00 $20.73 $167.40 i $45.86
Goshen Yes 2,814 $4,242.08 $ 207.95 3.121'/. $138.89 41.67% 80% $20.20 2.62% $0.53 $0.00 $20.73 $159.61 $43.73
Wasatch Front Yes 4.225 $4.283.67'$ 207.95' 2.582% $115.97 4L67% 80% $20.20 2.62% $0.53 $0.00 $20.73 $136.70 $37.45
W omin East Yes 1 6,130 i$ 4,117.31 i$ 207.95 i n ew 2.582 $111.68 47% 90% $20.20 2.62% $0.53 $0.00 $20.73 $132.41 $36.28
Pumed Hdro,OOnee NNe Reservoir,4-hour No NIA i$2,883.24 i$ 144.16 .12%
1% $94.49 18.87% 80% $20.20 2.62% $0.53 $0.00 $20.73 $115.21 $78.91
Pum edH o
Reservoir,l0-hour No NIA i$ 3,537.41 i$ 176.87 i 3.121% 1 $115.92 41.67% 80% 1 $20.20 1 2.62% $0.53 i $0.00 i $20.73 1 $138.65 $37.44
Pumped Thermal Energy Storage,10-hour 1 NIA 1$ 6.173.76 i$ 60.00 i 3.361% 1 $209.52 i 35.48% i 55% $2.00 1 .62% 1 $0.05 i $0.00 $2.05 $211.57 $68.06
Pumped Thermal Energy Storage,24-hour I No NIA i$ 11.525.17 i$ 60.00 i 3.362'/. 1 $389.49 i 35.48'/, i 55% $1.00 1.37% i $0.01 $0.00 $1.01 $390.51 i $125.63
152

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.9- 2025 IRP Thermal Supply-Side Resources, Variable O&M, Total Cost and Credits
Variable OhM Credits
Total Adjusted
Resource Total
Total Cost with Resource
Levelized O&M Resource Tax PTC I ITC Cost with
Fuel O&M Capitalized Capitalized Cost Credits Credits PTC I ITC
Resource Description [$IMVh1 [$IMVh) Premium [$IMVh] $IMVh ($IMVh) ($IMVh] Credits
Internal Combustion Engine.renewable bioluel,with SCR&24-hour fuel tank $ 357.85 i $6.93 i 14.33% $1.00 $418.99 $418.99 $387.57
SCCT Aero,with SCR $ 53.04 i $7.40 € 14.39'% i $1.07 $116.54 $116.54
SCCT Aero x4,with SCR $ 53.04 i $5.92 € 14.39% $0.85 $98.18 $98.18
SCCT Frame"F"x1,with SCR $ 54.56 $7.75 14.39% $1.12 $100.48 1 $100.48
CCCT Dry"H",1X1,OF,with SCR $ 33.91 $2.70 i 14.39% $0.39 $69.12 $69.12 -
Goshen $ 34.65 $2.70 i 14.39% $0.39 $82.28 $82.28 $77.10
Wasatch Front $ 34.74€ $2.70 ; 14.39% $0.39 $71.58 $71.58 $67.07
Wyoming East $ 30.05 i $2.70 1 14.39% $0.39 $68.32 $68.32 $64.02
CCCT Dry"H",2X1,DF,with SCR $ 34.37 $2.28 € 14.39% $0.33 $64.36 $64.36 -
Goshen $ 35.12€ $2.28 14.39% $0.33 $77.83 $77.83 -
Wasatch Front $ 35.21 $2.28 14.39% $0.33 $66.91 $66.91 -
W omin East $ 30.45 1 $2.28 1 14.39% $0.33 $63.63 i $63.63
CCCT Or "H",1X1,OF,with SCR•a for adding 95%CCS to new CCCT 1x1 $ 37.86€ $5.32 ? 11.52% $0.61 $108.07 $108.07
CCCT Dr "H",2X1,DF,with SCR•a For adding 95%CCS to new CCCT 20 $ 38.42 $4.83 i 11.52% $0.56 $97.80 i $97.80
Internal Combustion Engine.renewable biofuel,with SCR.a For CT Brownfield construction $ 46.57 i $6.24 1 14.39% $0.90 $102.86 1 $102.86
SCCT Aero,with SCR•a for CT Brownfield construction $ 53.04€ $6.66 € 14.39% $0.96 $110.67 i $110.67
SCCT Aero 0,with SCR•a For CT Brownfield construction $ 53.04 $5.33 1 14.39% $0.77 $94.06 i $94.06
SCCT Frame"F"A.with SCR•a For CT Brownfield construction $ 54.56 $6.98 14.39% $1.00 $96.85 $96.85 -
Goshen-Brownfield $ 54.23€ $6.98 14.39% $1.00 $128.04 $128.04 $119.59
Wasatch Front-Brownfield $ 54.29 $6.98 i 14.39% $1.00 $101.11 $101.11 $94.44
W omin East-Brownfield $ 53.90€ $6.98 i 14.39% $1.00 $104.33 $104.33 $97.45
CCCT Dry"H",1X1,OF,with SCR•a For CT Brownfield construction $ 33.91 $2.43 i 14.39% $0.35 $66.50 $66.50 -
Goshen-Brownfield $ 34.01 i $2.43 ; 14.39% $0.35 $79.00 $79.00 $74.02
Wasatch Front-Brownfield $ 34.12€ $2.43 € 14.39% $0.35 $68.36 $68.36 $64.06
W omin East-Brownfield $ 34.12€ $2.43 € 14.39% $0.35 $69.79 i $69.79 $65.40
CCCT Dr "H",2X1,DF,with SCR•a for CT Brownfield construction $ 34.37 $2.05 1 14.39% $0.30 $62.11 1 $62.11
CCCT Dr "H",1X1,OF,with SCR•a For adding 95%CCS to new CCCT 1x1•a for CT Brownfield construction $ 37.86. $4.78 1 11.52% $0.55 $102.89 $102.89
CCCT Dr "H",2X7,OF,with SCR.a For adding 95%CCS to new CCCT 2x1•a For CT Brownfield construction $ 38.42€ $4.34 € 11.52% $0.50 $93.40 1 $93.40
SCCT Frame"F"x1,with SCR.a For 100%H dro en burning capability $ 54.56 $8.91 i 14.39% $1.28 $103.39 $103.39
CCCT Or "H",1X1,OF,with SCR•a For 100%H dro en burning capability $ 33.91 $3.11 14.39% $0.45 $70.38 i $70.38
CCCT Dr "H",2X1,DF,with SCR.a for 100%H dro en burning capability $ 34.37 i $2.62 € 14.39% $0.38 $65.42 1 $65.42
SCCT Frame"F"A.with SCR•a for Hydrogen storage,cavern,80 bar,24 hour $ 54.56€ $8.18 € 14.39% $1.18 $154.38 i $154.38
CCCT Dr "H",1X1.OF,with SCR•a For Hydrogen storage.cavern,80 bar,24 hour $ 33.91€ $3.13 € 14.39% $0.45 $105.10 i $105.10
CCCT Dr "H",2X1,DF,with SCR•a for Hydrogen storage,cavern,80 bar,24 hour $ 34.37 i $2.70 14.39% $0.39 $99.10i $99.10
SCCT Frame"F"A.with SCR•a for Hydrogen storage,tanks,500 bar,24 hour $ 54.56 $8.32 14.39% $1.20 $141.62 i $141.62
CCCT Or "H",1X1,OF,with SCR-a For Hydrogen storage,tanks,500 bar,24 hour $ 33.91€ $3.27 i 14.39% $0.47 $97.27 $97.27
CCCT Dr "H",2X7,DF,with SCR.A for Hydrogen Storage,tanks,500 bar,24 hour $ 34.37 $2.85 i 14.39% $0.41 $91.14 $91.14
CCCT Dr "H",1X1,OF.with SCR,Advanced Technology Case•a advanced technology case.CCCT 1x1 $ 33.91€ $2.68 i 14.39% 1 $0.39 $68.77 1 $68.77
CCCT Or "H",2X1,DF,with SCR,Advanced Technology Case•a advanced technology case.CCCT 2x1 $ 34.37 i $2.23 € 14.39% 1 $0.32 $63.62 1 $63.62
CCCT Dr "H",1X1,OF.with SCR,Advanced Technology Case•a advanced technology case.CCCT 1x1,95%CCS $ 37.86€ $5.03 1 11.52% $0.58 $104.43 i $104.43
CCCT Dr "H",2X1,DF,with SCR,Advanced Technology Case•a advanced technologg case.CCCT 2x1,95%CCS $ 38.42€ $4.49 i 11.52% $0.52 $93.34 i $93.34
Electrol zer,Proton Exchange Membrane PEM,50.000 k Ida $ $23.91 € 0.00% $0.00 $30.21 $30.21
CCS Dave Johnston 4 costs on post retrofit basis $ $11.40 1 11.52% $1.31 $271.17 $ 43.09 $228.08
CCS Hunter 1.3 costs on post retrofit basis $ $9.73 ? 11.52% $1.12 $218.14 $ 40.81 i $177.33
CCS Huntington 1&2 fcosts on post retrofit basis $ $9.63 i 11.52% $1.11 $216.13 $ 39.79 i $176.34
CCS Jim Bridget 3&4 costs on post retrofit basis $ € $10.57 i 11.52% $1.22 $225.06 $ 42.18 i $182.88
CCS W odak costs on post retrofit basis $ € $11.69 € 11.52% $1.35 $322.79 $ 48.50 i $274.29 i
Small Modular Reactor or Advanced Reactor,Moderate Technology Case $ - $9.74 € 0.00% $0.00 $158.98 $ (33.32); $125.66 -
Goshen $ - $9.74 0.00% $0.00 $161.31 $ (33.99) $127.31 $120.95
Wasatch Front $ - $9.74 0.00-/. $0.00 $149.97 $ (45.31) $104.66 $99.42
Wyoming East $ $9.74 0.00% $0.00 $146.81 $ 43.98 i $102.83 $97.69
Small Modular Reactor or Advanced Reactor,Advanced Technology Case $ $8.74 I 0.00% $0.00 $113.94 $ (21.96)1 $91.97
Small Modular Reactor or Advanced Reactor,Moderate Technology Case.n For nuclear integrated thermal store $ $10.72 0.00% $0.00 $174.86 $ 36.66 i $138.20
Small Modular Reactor or Advanced Reactor,Advanced Technology Case.a for nuclear integrated thermal store $ $9.61 0.00% $0.00 $125.32 $ 24.16 i $101.16
Large Light Water Reactor,Moderate Technology Case $ $9.38 € 0.00% $0.00 $161.78 $ (29.8311 $131.95
Large Light Water Reactor,Advanced Technology Case $ $7.88 1 0.00% $0.00 1 $126.20 $ (24.7111 $101.50
Near Field Enhanhanced Geothermal System(NF-EGS)Binary $ - $0.00 0.00% $0.00 $75.30 $ (10.44); $64.86 -
Southern OR $ $0.00 0.00% $0.00 $83.78 $ (12.21) $71.56 -
Wasatch Front $ $0.00 1 0.00% $0.00 $71.98 $ (13.92)1 $58.06
153

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.10- 2025 1RP Non-Thermal Supply-Side Resources, Variable O&M, Total Cost and Credits
Variable O&M Credits
Total Adjusted
Resource Total
Total Cost with Resource
Levelized O&M Resource Taz PTC I ITC Cost with
Fuel O&M Capitalized Capitalized Cost Credits Credits PTC I ITC
00- Resource Description ($IMVh) ($IMVh) Premium ($1MVh) JSIMWhj ($IMVhJ ($IMVh) Credits
PV,20 MW,Class 1-10 £ $0.00 0.00'r' $0.00 $0.00
Portland North Coast £ $0.00 0.00% $0.00 $76.45 $ (25.15) $51.30 1 $10.31
Southern OR £ $0.00 0.00% $0.00 $66.54 $ (25.15) $41.39 1 $8.32
Walla Walla £ $0.00 0.00% $0.00 $69.74 $ (25.15)1 $44.59 $8.96
Goshen £ $0.00 0.00% $0.00 $64.59 $ (25.15)1 $39.44 1 $7.93
Wasatch Front £ $0.00 0.00% $0.00 $61.38 $ (27.63)1 $33.75 1 $6.78
W omin East $ $0.00 0.00% $0.00 $64.79 $ (27.6311 $37.16 $7.47
PV,200 MW,Class 1-10 $ $0.00 0.00% $0.00 $0.00
Portland North Coast $ $0.00 0.00% $0.00 $51.72 $ (25.15) $26.57 $5.34
Southern OR £ $0.00 0.00% $0.00 $44.87 $ (25.15)1 $19.72 i $3.96
Walla Walla £ $0.00 0.00% $0.00 $47.32 $ (25.15)1 $22.17 $4.46
Goshen £ $0.00 0.00% $0.00 $43.86 $ (25.15)1 $18.71 1 $3.76
Wasatch Front £ $0.00 1 0.00% $0.00 $41.71 $ (27.63)1 $14.08 $2.83
Wyoming East £ 1 $0.00 0.00% $0.00 $44.02 $ 27.63 1 $16.40 $3.30
PV,20 MW,Class 1-10.a Advanced Solar Technology Case £ ? $0.00 1 0.00% $0.00 $0.00
PV,200 MW,Class 1-10.a Advanced Solar Technology Case £ $0.00 1 0.00% i $0.00 $0.00
Wind Class 1-10.20 MW £ $0.00 0.00% 1 $0.00 $0.00
Portland North Coast £: $0.00 1 0.00% $0.00 $102.14 $ (23.46): $78.68 $19.12
Southern OR 3: $0.00 1 0.00Y $0.00 $106.14 $ (23.46): $82.68 $20.09
Walla Walla $ $0.00 0.00'/. $0.00 $104.46 $ (23.46): $81.00 $19.68
Goshen $ : $0.00 1 0.00% $0.00 $0.00 $ (23.46):
Wasatch Front $ : $0.00 1 0.00% $0.00 $0.00 $ (25.77):
W omin East $ 1 $0.00 1 0.00% $0.00 $0.00 $ 25.77 1
Wind Class 1-6,200 MW £ 1 $0.00 1 0.00% $0.00 $0.00
Portland North Coast £ $0.00 1 0.00% $0.00 $41.47 $ (23.46)1 $18.01 $4.38
Southern OR £ $0.00 1 0.00% $0.00 $47.92 $ (23.46)1 $24.46 $5.94
Walla Walla £ : $0.00 0.00% $0.00 $45.68 $ (23.46): $22.22 $5.40
Goshen £ $0.00 0.00% $0.00 $48.49 $ (23.46)1 $25.03 $6.08
Wasatch Front £: $0.00 0.00% $0.00 $47.93 $ (25.77)1 $22.16 1 $5.38
W omin East $ $0.00 0.00% $0.00 $34.60 $ 25.77 1 $8.83 $2.14
Wind Class 7,200 MW $ $0.00 1 0.00% $0.00 $0.00
Offshore,Wind Class 12 $ $0.00 1 0.00% $0.00 $0.00
Wind Class 1.10,20 MW•a Advanced Onshore Wind Technology Case $ $0.00 0.00% i $0.00 $0.00
Wind Class 1-6,200 MW•a Advanced Onshore Wind Technology Case $ $0.00 0.00'/. i $0.00 $0.00
Wind Class 7.200 MW-A Advanced Onshore Wind Technology Case $ $0.00 0.00% $0.00 $0.00
Offshore,Wind Class 12-a Advanced Offshore Wind Technology Case $ $0.00 0.00% $0.00 $0.00
154

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.11 - 2025 1RP Storage Supply-Side Resources, Variable O&M, Total Cost and Credits
Variable O&M Credits
Total Adjusted
Resource Total
Total Cost with Resource
Levelized O&M Resource Tax PTC I ITC Cost with
Fuel O&M Capitalized Capitalized Cost Credits Credits PTC I ITC
Resource Description ($IMVh) ($IMVh) Premium ($IMVh) $IMVh ($IMVh) ($IMVh) Credits
Li-Ion,4-hour,20 MW' $ $0.00 0.00'/. $0.00 $96.04 $ 32.40 $63.64
Li-Ion,4-hour,200 MW' $ $0.00 i 0.00% $0.00 $82.42 $ (27.77): $54.65
Portland North Coast $ $0.00 i 0.00'/. $0.00 $85.72 $ (29.44) $56.28 $50.15
Southern OR $ $0.00 i 0.00'/. $0.00 $86.82 $ (29.99)f $56.82 $50.63
Walla Walla $ $0.00 i 0.00'/. $0.00 $84.07 $ (28.61) $55.47 $49.42
Goshen $ $0.00 j 0.00'/. $0.00 $83.52 $ (28.33) $55.19 $49.18
Wasatch Front $ $0.00 i 0.00'/. $0.00 $74.38 $ (38.14) $36.24 $32.29
W omin East $ $0.00 0.00% $0.00 $72.55 $ 36.66 $35.90 $31.98
Li-Ion,4-hour,200 MW.A Double Duration,Li-Ion,4-hour,200MW' $ $0.00 0.00'/. $0.00 $71.63 $ (23.69) $47.94
Portland North Coast $ $0.00 i 0.00'/. $0.00 $74.44 $ (25.11)f $49.33 $48.84
Southern OR $ $0.00 i 0.00% $0.00 $75.38 $ (25.59): $49.79 $49.29
Walla Walla $ $0.00 i 0.00'/. $0.00 $73.04 $ (24.40): $48.63 $48.15
Goshen £ $0.00 i 0.00% $0.00 $72.57 $ (24.17): $48.40 $47.92
Wasatch Front i $0.00 's 0.00% $0.00 $64.76 $ (32.54): $32.22 $31.90
W omin East $ $0.00 0.00% $0.00 $63.20 $ 31.27 j $31.93 $31.61
Li-Ion,4-hour,1000 MW' $ $0.00 i 0.00'/. $0.00 $79.77 $ 27.05 `: $52.72
Li-Ion,4-hour,200 MW $ $0.00 i 0.00% $0.00 $82.42 $ (27.77) $54.65
Portland North Coast $ $0.00 0.00% $0.00 $85.72 $ (29.44) $56.28 $50.15
Southern OR $ $0.00 i 0.00% $0.00 $86.82 $ (29.99) $56.82 $50.63
Walla Walla $ $0.00 's 0.00% $0.00 $84.07 $ (28.61) $55.47 $49.42
Goshen $ $0.00 0.00% $0.00 $83.52 $ (28.33) $55.19 $49.18
Wasatch Front $ $0.00 0.00% $0.00 $74.38 $ (38.14): $36.24 $32.29
W omin East $ $0.00 i 0.00% $0.00 $72.55 $ 36.66 $35.90 $31.98
GravityBattery,4-hour,1006 MW $ $0.00 0.00% $0.00 $74.97 $ 33.10 f $41.87
Gravity Battery.4-hour,1000 MW-A Double Duration,Gravity.4-hour,1000MW $ $0.00 6.27% $0.00 $62.87 $ 24.62 ': $38.25
Adiabatic CAES,500 MW,4000 MWh $ $2.60 0.00'/. $0.00 $65.03 $ 27.92 ': $37.10
100-hour Iron Air $ $0.00 0.00% $0.00 $58.64 $ 37.40 $21.24
Pumped Hydro,Two New Reservoirs,4-hour $ $0.58 0.00% $0.00 $81.76 $ 33.01 $48.75
Pumped Hydro,Two New Reservoirs.10-hour $ $0.58 i 0.00% $0.00 $43.60 $ (18.40)`: $25.20
Portland North Coast $ $0.58 0.00% $0.00 $45.73 $ (19.51): $26.23
Southern OR $ $0.58 0.00% $0.00 $46.44 $ (19.87): $26.57
Goshen $ $0.58 i 0.00% $0.00 $44.31 $ (18.77) $25.54
Wasatch Front $ $0.58 's 0.00% $0.00 $38.03 $ (25.28) $12.75
W omin East $ $0.58 i 0.00% $0.00 $36.86 $ 24.30 j $12.56
Pumped Hydro.One New Reservoir,4-hour $ $0.58 0.00'/. $0.00 $79.49 $ 31.89 ': $47.60
Pumped Hydro.One New Reservoir,l0-hour, $ $0.58 0.00'/. $0.00 $38.02 $ 15.65 $22.37
Pumped Thermal EnergyStorage,10-hour $ $0.70 0.00'/. $0.00 $68.76 $ 34.12 $34.64
Pumped Thermal Energy Storage,24-hour $ $0.70 0.00% $0.00 $126.33 $ (63.70)1 $62.63
155

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.12 - Glossar of Terms Used in the Su 1 -Side Resource Tables
Term Description
Fuel Primary fuel used for electricity generation or storage.
Resource Primary technology used for electricity generation or storage.
Elevation(afsl) Average feet above sea level for the proxy site for the given resource.
Net Capacity(MW) For natural gas-fired generation resources, the Net Capacity is the net
dependable capacity (net electrical output) for a given technology, at
the given elevation, at the annual average ambient temperature in a
"new and clean" condition.
Resource Availability The earliest year the Company would sign a contract for a Resource
Year being studied in this IRP. If available prior to the development of this
database, this defaults to IRP year.
Total Implementation Number of years necessary to implement all phases of resource
Time development and construction after signing a contract to build the
Resource: permitting (e.g., air, land,water, and wildlife), maintenance
contracts, owner's engineering, construction, testing, and grid
interconnection.
Commercial Year when the Resource is available for generation and dispatch. It is
Operation Year based on the Resource Availability Year plus the Total
Im lementation Time.
Design Life (years) Average number of years the resource is expected to be "used and
useful."
Base Capital ($/kW) Total capital expenditure in dollars per kilowatt($/kW) for the
development and construction of a Resource including: direct costs
(equipment, buildings, installation/overnight construction,
commissioning, contractor fees/profit, and contingency), owner's
costs (land, water rights, permitting,rights-of-way, design
engineering, spare parts,project management, legal/financial support,
grid interconnection costs, and owner's contingency), and financial
costs (allowance for funds used during construction (AFUDC), capital
surcharge,property taxes, and escalation during construction, if
a licable .
Var O&M ($/MWh) Includes real levelized variable operating costs such as combustion
turbine maintenance, water costs,boiler water/circulating water
treatment chemicals,pollution control reagents, equipment
maintenance, and fired hour fees in dollars per megawatt hour
$/MWh .
Fixed O&M ($/kW- Includes labor costs, combustion turbine fixed maintenance fees,
ear) contracted services fees, office equipment, and training.
Demolition Cost Total cost to decommission and demolish the generating unit at the
$/kW end of life in dollars per kilowatt($/kW).
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PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Term Description
Full Load Heat Rate Net efficiency of the resource to generate electricity for a given heat
HHV Btu/kWh input in a "new and clean" condition on a higher heating value basis.
Efficiency Typical operational round trip efficiency of energy storage of
alternating current (AC) energy delivered to the grid divided by AC
energy stored from the grid.
EFOR(%) Estimated Equivalent Forced Outage Rate, which includes forced
outages and derates fora given Resource at the given site.
POR(%) Estimated Planned Outage Rate for a given Resource at the given site.
Water Consumed Average amount of water consumed by a Resource for make-up,
(gal/MWh) cooling water make-up, inlet conditioning and pollution control.
S02 (lbs/MMBtu) Expected permitted level of sulfur dioxide (S02) emissions in pounds
of sulfur dioxide per million Btu of heat input.
NOx(lbs/MMBtu) Expected permitted level of nitrogen oxides (NOx) (expressed as
NO2) in pounds of NOx per million Btu of heat input.
Hg(lbs/TBtu) Expected permitted level of mercury emissions in pounds per trillion
Btu of heat input.
CO2 (lbs/MMBtu) Pounds of carbon dioxide (CO2) emitted per million Btu of heat input.
Table 7.13 - Glossary of Acronyms Used in the Supply-Side Resource Tables
Acronyms Description
ACAES Adiabatic Compressed Air Energy storage
AFSL Average Feet (Above) Sea Level
ATB Annual Technology Baseline
CAES Compressed Air Energy Storage
CCCT Combined Cycle Combustion Turbine
CCS Carbon Capture and Storage (though storage costs are not included in
the SSR Tables
CCUS Carbon Capture, Utilization and Storage (though utilization and
storage costs are not included in the SSR Tables
CF Capacity Factor
CSP Concentrated Solar Power
CT Combustion Turbine
DF Duct Firing
DOE United States Department of Energy
EIA Energy Information Agency
FGD Flue Gas Desulfurization
GAIN Gateway for Accelerated Innovation in Nuclear
HRSG Heat Recovery Steam Generator
ICE Internal Combustion Engine (reciprocating engine)
IGCC Integrated Gasification Combined Cycle
ISO International Standards Organization(Temperature = 59 degrees
fahrenheit(°F)/ 15 degrees Celsius (°C), Pressure= 14.7 psia/1.013
bar
Li-Ion Lithium Ion
LFP Lithium Iron Phosphate (sub-chemistry of lithium-ion)
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
MW Megawatt
NCM Nickel Cobalt Manganese (sub-chemistry of lithium-ion)
NREL National Renewable Energy Laboratory
OEM Original Equipment Manufacturer
OSTI Office of Scientific and Technical Information
OSW Offshore Wind
PCCC Post Combustion CO2 Capture
PEM Proton Exchange Membrane
PPA Power Purchase Agreement
PC CCUS Pulverized Coal retrofitted with Carbon Capture, Utilization and
Storage
PHES Pumped Hydro Energy Storage
PV Poly-Si Photovoltaic modules constructed from poly-crystalline silicon
semiconductor wafers
Recip Reciprocating Engine
RTE Round Trip Efficiency (typical operational AC to AC energy storage
efficiency)
SCCT Simple Cycle Combustion Turbine
SCR Selective catalytic reduction
STG Steam turbine generator
Resource Option Descriptions
The following are brief descriptions of each of the resources listed in Table 7.2 through Table 7.11.
For all technology that is included in the 2024 NREL ATB, the ATB costs were used. For
incremental items, a percentage difference between the technology with and without the
incremental resource was used. Where data is available for an advanced technology innovation
scenari022, there is a resource row for that scenario.
Natural Gas, Internal Combustion Engine x4, renewable biofuel, with SCR & fuel tank —
This is "a reciprocating internal combustion engine (RICE)power plant based on four large-scale
natural-gas-fired engines. Each engine is rated nominally at 5.6 MW with a net capacity of 21.4
MW."23 It is presented in the IRP as a 20 MW resource to meet Oregon's regulatory requirements
for distributed generation resource, under the assumption that it could be derated to meet the
requirements. The 24 hour fuel tank was added to the 2020 EIA Report's resource based on
available market information on in ground gas tanks.
Natural Gas, Simple Combined Cycle Turbine (SCCT) Aero x 4 — This is "four of
aeroderivative dual-fuel CTs in a simple-cycle configuration, with a nominal output of
approximately 54 MW gross per turbine. After deducting internal auxiliary power demand,the net
output of the plant is approximately 211 MW. Each CT's inlet air duct has an evaporative cooler
22 https:Hatb.nrel.gov/electricity/2024/definitions#scenarios
23 Cost and Performance Estimates for New Utility-Scale Electric Power Generating Technologies,December 2019,
Sargent&Lundy,prepared for the U.S.Energy Information Administration's Capital Cost and Performance
Characteristic Estimates for Utility Scale Electric Power Generating Technologies,February 2020
https://www.eia.gov/analysis/studies/powerplants/capitalcost/archive/2020/pdf/capital—cost AE0202O.pdf
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
to reduce the inlet air temperature in warmer seasons to increase the CT output. Each CT is also
equipped with burners designed to reduce the CT's emission of NOx. Included are SCR units for
further reduction of NOx emissions and CO catalysts for further reduction of CO emissions."24
Natural Gas, SCCT Frame "F" x 1,with SCR—This is "one industrial frame Model F dual fuel
CT in simple-cycle configuration with a nominal output of 237.2 MW gross. After deducting
internal auxiliary power demand, the net output of the plant is 232.6 MW. The inlet air duct for
the CT is equipped with an evaporative cooler to reduce the inlet air temperature in warmer seasons
to increase the CT output. The CT is also equipped with burners designed to reduce the CT's
emission of NOx."25 Although the 2020 EIA Report does not include an SCR for this resource, to
be on par with the other IRP resources, the approximate cost of an SCR was added based on the
cost difference on a percentage basis from previous IRP's.
Natural Gas, CCCT "H", 1x1,DF,with SCR—This is "one Model HL dual-fuel CT in a lxlxl
single-shaft CC configuration. The CT generates approximately 453 MW gross and the STG
generates 192 MW gross. After deducting internal auxiliary power demand, the net output of the
plant is approximately 627 MW."26
Natural Gas, CCCT "H", 2x1, DF, with SCR—This is "a pair of Model H, dual-fuel CTs in a
2x2xl CC configuration (two CTs, two heat recovery steam generators [HRSGs], and one steam
turbine). Each CT generates approximately 436 MW gross; the STG generates approximately 393
MW gross. After deducting internal auxiliary power demand, the net output of the plant is 1227
MW.,,27
Natural Gas, a for adding 95% CCS—This option reflects incremental changes for a greenfield
"power plant w/ commercially available solvent-based post combustion CO2 capture (PCCC)
designed for 95%capture."28 The 95%option was chosen because that is the most economic option
available in the NREL ATB that meets the EPA 111 regulations.
Natural Gas, e for CT Brownfield construction—This option reflects incremental changes for
construction of a resource at an existing powerplant site with the same technology.
Hydrogen,a for 100%Hydrogen burning capability—This option reflects incremental changes
for a CT to burn a mixture of fuel up to 100%hydrogen.
24 Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating
Technologies,December 6,2023,Sargent&Lundy,prepared for the U.S.Energy Information Administration's
Capital Cost and Performance Characteristics for Utility Scale Electric Power Generating Technologies,January
2024.https://www.eia.gov/analysis/studies/Powerplants/capitalcost/pdf/capital_Cost_AE02025.pdf
25 Cost and Performance Estimates for New Utility-Scale Electric Power Generating Technologies,December 2019,
Sargent&Lundy,prepared for the U.S.Energy Information Administration's Capital Cost and Performance
Characteristic Estimates for Utility Scale Electric Power Generating Technologies,February 2020
https://www.eia.gov/analysis/studies/powerplants/capitalcost/archive/2020/pdf/capital_cost_AE0202O.pdf
26 Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating
Technologies,December 6,2023,Sargent&Lundy,prepared for the U.S.Energy Information Administration's
Capital Cost and Performance Characteristics for Utility Scale Electric Power Generating Technologies,January
2024.https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_Cost_AE02025.pdf
27 Ibid 17
212024 ATB Excel Workbook,available at https:Hatb.nrel.gov/electricity/2024/data.
159

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Hydrogen, a for Hydrogen storage, cavern, 80 bar, 1 week—This option reflects incremental
changes for storing hydrogen underground in a solution-mined geologic salt dome. Hydrogen gas
is compressed and stored at ambient temperature in at elevated pressure (70-190 bar). Salt domes
only exist in a limited number of locations (-2000 salt caverns in North America with an average
capacity of 105-101 m3). There are at least two salt domes under development within PacifiCorp's
area of operation. This assumes a "600 tons per day (TPD) pipeline throughput for 7-days at 80
bar; cushion gas is —40% of volume."29 In addition to the Pathways to Commercial Liftoff. Clean
Hydrogen (Clean Hydrogen Liftoff Report), the Hydrogen and Fuel Cell Technologies Office
Multi-Year Program Plan30 was used for cost and technical data.
Hydrogen,e for Hydrogen storage,tanks,500 bar,24 hour — This option reflects incremental
changes for storing hydrogen in tanks constructed above ground. "H2 gas is compressed at ambient
temperature to 300—700 bar. Storage capacity is limited due to the low volumetric density of H2
at room temperature. Assumes 950 kg stored at 500 bar with 1 cycle per week."31
Electrolyzer, Proton Exchange Membrane (PEM), 50,000 kg/day — Also known as polymer
electrolyte membrane, including balance of plant(BOP)costs,the"electrolyzer design is intended
to represent the current state-of-the-art(2022)stacks with respect to catalyst loadings(3 milligrams
per square centimeter [mg/cm2] total platinum group metal [PGM] loading) and material
specifications."32 Data from the DOE Hydrogen and Fuel Cells Program Record33 was also used
in the development of this resource.
Coal, CCS— These are retrofits of an existing conventional coal-fired boiler and steam-turbine
generator resources with amine based post-combustion carbon capture technology. Costs include
the reduction in plant output due to higher auxiliary power requirements and reduced steam turbine
output. The CCS would remove 90 percent of the carbon dioxide and would provide reductions in
other emissions.34
Storage, Lithium Ion Battery—This is lithium-ion batteries rated at 20 and 200 MW capacities
with 4-hour duration. The 20 MW option uses the ATB's "Commercial Battery" data, while the
200 MW option uses the ATB's "Utility-Scale" data.
29 Pathways to Commercial Liftoff. Clean Hydrogen,U.S.Department of Energy,Office of Technology Transitions:
Hannah Murdoch;Office of Clean Energy Demonstrations:Jason Munster;Hydrogen&Fuel Cell Technologies
Office: Sunita Satyapal,Neha Rustagi;Argonne National Laboratory:Amgad Elgowainy;National Renewable
Energy Laboratory:Michael Penev,https:Hliftoff.energy.gov/wp-content/uploads/2023/05/20230523-Pathways-to-
Commercial-Liftoff-Clean-Hydrogen.pdf
3°Hydrogen and Fuel Cell Technologies Office Multi-Year Program Plan,Dr. Sunita Satyapal,U.S.Department of
Energy,https://www.energy.gov/eere/fuelcells/hydrogen-and-fuel-cell-technologies-office-multi-year-program-plan
31 ibid 20
32 Badgett,Alex,Joe Brauch,Amogh Thatte,Rachel Rubin,Christopher Skangos,Xiaohua Wang,Rajesh
Ahluwalia,Bryan Pivovar,and Mark Ruth.2024. Updated Manufactured Cost Analysis for Proton Exchange
Membrane Water Electrolyzers. Golden,CO:National Renewable Energy Laboratory.NREL/TP-6A20-87625.
https://www.nrel.gov/docs/fy24osti/87625.pdf.
33 David Peterson,James Vickers,Dan DeSantis,Hydrogen Production Cost From PEM Electrolysis—2019,
February 3,2020,
https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/19009_h2_production_cost_pem_electrolysi
s_2019.pdf?Status=Master
34 Carbon capture costs and parameters were the subject of discussion and feedback during the 2025 IRP public
input meeting series.
See Appendix M,stakeholder feedback form#25 (NP Energy,LLC).
See Appendix M,stakeholder feedback form#44(Sierra Club).
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Storage, a double duration—This option reflects incremental changes for doubling the duration
of a battery energy storage resource, modifiers on this row must be applied to the data in the
appropriate resource row. Appropriate resources are limited to those utilizing lithium-ion energy
storage, including lithium-ion energy storage collocated with other resources.
Storage, 0 for Co-Located Energy Storage — This option reflects incremental changes for
lithium-ion energy storage collocated with another resource,modifiers on this row must be applied
to the appropriate energy storage data.
Storage, Gravity Battery, 4-hour, 1000 MW—This is an estimate for any technology that uses
the potential energy differential of a large mass, but excludes pumped hydro. Pumped hydro is a
well-established technology and because of this there is more accurate data available for pumped
hydro. Examples include dense weights lifted vertically, heavy rail cars moved up and down a
steep track, or a piston displacing a fluid vertically. Costs were escalated from the 2023 IRP.
Storage, Adiabatic CAES — Compressed air energy storage (CAES) system consists of an air
storage reservoir pressurized by a compressor similar to a conventional gas turbine compression
section but driven by an electric motor coupled with an adiabatic power generation turbine. The
compressed air powers the adiabatic turbine. Energy is stored by compressing air into the storage
reservoir. Only the system sizes of 500 MW is included because that size was the lowest cost per
kWh in the 2023 IRP. The air storage reservoir is an engineered tank. "Adiabatic" means the
system does not burn natural gas to generate power.
Storage,Pumped Hydro,Two New Reservoirs—Also known as closed-loop pumped hydro,this
technology pumps and releases water between a higher and a lower reservoir. It is modeled as a
nominal 400 MW PHES system using a combination of natural and constructed water storage
combined with elevation difference to enable a system capable of discharging the rated capacity
for 10 or 4 hours. The development and construction time is estimated at 5 years assuming that
early permitting and development has occurred prior to contracting with PacifiCorp. The IRP uses
ATB National Class 1 data.
Storage, Pumped Hydro, One New Reservoirs — Also known as an open-loop system, this
technology pumps and releases water between a higher reservoir and a lower natural water body,
usually a river. It is modeled as a nominal 400 MW PHES system using both natural and
constructed water storage combined with elevation difference to enable a system capable of
discharging the rated capacity for 10 or 4 hours. The development and construction time is
estimated at 5 years assuming that early permitting and development has occurred prior to
contracting with PacifiCorp. The IRP uses ATB National Class 5 data.
Storage, 100-hour Iron Air — This is a low capital cost battery option with the trade off a low
round trip efficiency. "While discharging,the battery breathes in oxygen from the air and converts
iron metal to rust. While charging,the application of an electrical current converts the rust back to
iron and the battery breathes out oxygen."35
Storage, Pumped Thermal Energy Storage — This is a system using a storage tank of high
temperature fluid to store energy. A resistive heater converts electric energy to heat energy in the
35 https:Hformenergy.com/technology/battery-technology/
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
fluid. To generate electricity,the fluid boils water which powers a steam turbine attached to electric
generator.
Solar, PV, Class 1 - 10 — This is ATB PV Class 1 through 10 (20 MW or 200 MW) solar
photovoltaic resources using crystalline silica solar panels in a single axis tracking system. The 20
MW option uses the ATB's"Commercial"data,while the 200 MW option uses the ATB's"Utility-
Scale" data. A consultant was hired to provide location specific capacity factors for each node
modeled in PLEXOS.
Wind, Wind Class 1-10, 20 MW—This is ATB "Distributed Wind, Large Turbine Technology
Class."It is a wind resource of 1,500 kW turbines with 107 meter rotor diameter and 80 meter hub
height. A consultant was hired to provide location specific capacity factors for each node modeled
in PLEXOS.
Wind,Wind Class 1-6,and 7200 MW—This is ATB Land-Based Wind technology configuration
T1. It is a wind resource of 34 x 6 MW turbines with 170 meter rotor diameter and 115 meter hub
height. A consultant was hired to provide location specific capacity factors for each node modeled
in PLEXOS.
Wind, Wind Class 7, 200 MW — This is the same as wind classes 1- 6, but different wind
conditions and cost data.
Wind, Offshore, Wind Class 12 —This is ATB "Floating Offshore Wind." It is a wind resource
of 12 MW turbines with 216 meter rotor diameter and 137 meter hub height. Wind Class 12
represents the wind conditions off the coast of northern California and southern Oregon. The ATB
lists a net capacity factor of 47% for Offshore Wind Class 12.
Nuclear, Small Modular Reactor or Advanced Reactor—This is a conceptual technology that
could be a small modular reactor or small advanced reactor. "Modular"refers to a reactor that can
be built off site and easily transported to the installation location, however scale of economy
requires multiple modular reactors to share support facilities at a single powerplant site. Data is
from the ATB and relies heavily on a DOE Office of Scientific and Technical Information,
Gateway for Accelerated Innovation in Nuclear report36 ("OSTI GAIN Report").
Nuclear, a for nuclear integrated thermal storage, 5 hours - This option reflects incremental
changes for a system using a storage tank of high temperature fluid. To store energy, heat from a
nuclear reactor is transferred in a heat exchanger to the storage fluid. To generate electricity, the
fluid boils water which powers a steam turbine attached to electric generator. This method
eliminates the resistive heater losses in the stand-alone thermal storage, and therefore has a much
higher RTE.
36 Abdalla Abou-Jaoude,Levi M Larsen,Nahuel Guaita,Ishita Trivedi,Frederick Joseck,and Christopher Lohse,
Idaho National Laboratory;Edward Hoffman and Nicolas Stauff.Argonne National Laboratory;Koroush Shirvan,
Massachusetts Institute of Technology;Adam Stein,Breakthrough Institute;Gateway for Accelerated Innovation in
Nuclear(GAIN);Meta-Analysis of Advanced Nuclear Reactor Cost Estimations,July 2024,
https://inldigitallibrary.inl.gov/sites/sti/sti/Sort 107010.pdf
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Nuclear, Large Light Water Reactor—This is a modern dual unit reactor similar to most of the
existing utility reactors in the United States. Data is from the ATB and relies heavily on the OSTI
GAIN Report.
Geothermal, Near Field Enhanced Geothermal System (NF-EGS) Binary— This is the ATB
geothermal plant utilizing an 175°C thermal resource with 1.5 km wells and production well flow
rates of 60 kg/s.37
Locational Modifiers and Selected Cost Forecasts
Appendix A of the EIA reports contain cost modifiers for selected cities within each state, and
Appendix B of the EIA reports contains locational modifiers for combustion turbines that are
largely dependent on altitude and ambient temperatures. The ATB contains cost forecasts for most
resource options in the SSR. For any resource option without a technology specific cost forecast,
escalation is assumed to be level. These locational modifiers and cost forecasts are applied in
PLEXOS. Cost forecast histories for selected resource types are shown in the following sections.
PV Cost Forecast History
Figure 7.1 shows a history of capital cost forecasts used in the SSR for PV resources in Utah from
2017 through 2023 IRPs (the red lines). The 2025 IRP Capital cost estimates for solar resources
are based on the ATB forecast. The data from IRP's prior to 2021 was based on a 50 MW scale;
however,the 50 MW scale is no longer included as a resource option. The solid blue line indicates
the 2025 IRP price forecast at the 200 MW scale in Utah. The observed market correction used in
the 2023 IRP has been mitigated largely by federal policy changes and the forecast is essentially
the same as the trend line of the 2021 IRP.
37 Geothermal modeling was the subject of stakeholder feedback during the 2025 IRP public input meeting series.
See Appendix M,stakeholder feedback form#11 (Utah Environmental Caucus).
See Appendix M,stakeholder feedback form#41 (Nathan Strain).
163

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Figure 7.1 —History of SSR PV Cost & Forecast
History of SSR Utah PV Costs & Forecast
adjusted for inflation
$2,400
$2,200
$2,000
v
N
CD
$1,800
U b
m $1,600 /
••CL
• e.
U s.. ....
mIle
a
$1,200
a ft.
N
� O
$1,000
$800
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Calendar Year
— 2017 IRP UT A 2018 IRP UT ••0••2019 IRP UT —O—2021 IRP UT
2021 IRP UT 20OMW —2023 IRP UT 20OMW 2025 IRP 200 MW
Wind Cost Forecast History
Figure 7.2 shows a history of capital cost forecasts used in the SSR for resources in Wyoming
from 2017 through 2023 IRPs (the red lines). The 2025 IRP Capital cost forecast for wind
resources is based on the ATB forecast. The observed market correction used in the 2023 IRP has
been mitigated largely by federal policy changes and the forecast is close to the trend line of the
2021 IRP.
164

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Figure 7.2—History of SSR Wind Costs & Forecast
History of SSR Onshore Wind Costs & Forecast
$2,300 adjusted for inflation
$2,100 -
�F t ---* ---# ---#---# *`
Y
vki $1,900
0 / \
o
o $1,700 / R\
U
M $1,500 \
U
N
Ln
M _
C° $1,300
M A
$1,100
$900
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Calendar Year
- 2017 IRP WY ♦ 2018 IRP WY ••■••2019 IRP WY
-Ar- 2021 IRP WY 2023 IRP WY 2025 IRP WY
Energy Storage
Figure 7.3 shows a history of capital cost forecasts used in the SSR for BESS resources in Utah
from 2017 through 2023 IRPs (the red lines). The 2025 IRP capital cost forecast for BESS
resources is based on the ATB forecast. The data from IRP's prior to 2021 was based on a 50 MW
scale; however, the 50 MW scale is no longer included as a resource option. The solid blue line
indicates the 2025 IRP price forecast at the 200 MW scale in Utah. The observed market correction
used in the 2023 IRP has been partially mitigated by federal policy changes and the forecast costs
are about midway between the less expensive 2021 IRP and the more expensive 2023 IRP.
165

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Figure 7.3—History of SSR Battery Energy Storage System Costs & Forecast
History of SSR Battery Energy Storage System Costs & Forecast
adjusted for inflation
$1,200
3
Y
i/►
N $1,000
N
N
o O.
u $800
FCL
ca
U
vi �O► +p
w
ai $400 �� • `�� •�
m ~ • �� y�
$200
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
Calendar Year
2017 IRP Li-ion NCM A 2018 IRP Li-ion NCM
••E3••2019 IRP Li-ion NCM —f- 2021 IRP Li-ion NCM
—40-- 2021 IRP Li-ion NCM (Utility Scale)­0 —20231RP Li-Ion LFP 4-hour
2025 IRP LI-ion LFP 4-hour
Utility-scale Energy Storage Resources
PacifiCorp has contracted for the following utility-scale energy storage resources:
• Faraday solar and storage (525 MW solar, 150 MW battery storage with 4-hour duration) is a
project supporting customer clean energy goals under Utah Schedule 34.
• Green River solar and storage (400 MW solar, 400 MW battery storage with 4-hour duration)
is a project that was originally part of the final shortlist in the 2020 All-Source Request For
Proposals. An amendment to the contract expanded the battery from 200 MW with two-hour
duration to 400 MW with four-hour duration.
• Dominguez Grid (200 MW battery storage with four-hour duration) is a stand-alone energy
storage resource.
• Enterprise/Escalante/Granite Mountain East/Iron Springs storage: each of these contracts is an
80 MW battery storage resource with four-hour duration. Battery storage is being added at
existing solar resources,and will use surplus interconnection.A surplus interconnection allows
for resources to be added at any existing interconnection location so long as the total output to
the grid is kept within the existing interconnection capacity.
166

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
As a result of the contracts described above, PacifiCorp expects to bring more than one gigawatt
of energy storage resources online by the summer of 2026.
Demand-Side Resourc
Resource Options and Attributes
Source of Demand-Side Management Resource Data
PacifiCorp conducted a Conservation Potential Assessment (CPA) with for 2025-2044, which
provided DSM resource opportunity estimates for the 2025 IRP. The study was conducted by
Applied Energy Group (AEG) on behalf of the company. The CPA provided a broad estimate of
the size,type, location and cost of demand-side resources.38 For the purpose of integrated resource
planning, the DSM information from the CPA was converted into supply curves by type of
resource (i.e. energy-based energy efficiency and demand response) for modeling against
competing supply-side alternatives.
Demand-Side Management Supply Curves
DSM resource supply curves are a compilation of point estimates showing the relationship between
the cumulative quantity and cost of resources, providing a representative look at how much of a
particular resource can be acquired at a particular price point. Resource modeling utilizing supply
curves allows the selection of least-cost resources (e.g. products and quantities) based on each
resource's competitiveness against alternative resource options.39 Due to the timing of the 2025
IRP planning and modeling, PacifiCorp had established, funded and begun acquiring 2025 DSM
program acquisition targets. To ensure that the 2025 IRP analysis is consistent with existing and
planned demand response and energy efficiency acquisition levels (i.e., Class 1 & 2 DSM),
expected DSM savings in each state were fixed for calendar year 2025. In 2026, energy efficiency
resources were optimized to reflect ongoing program experience and knowledge of current market
conditions and timing challenges, to develop near terms levels of selected acquisition.
As with supply-side resources, the development of DSM supply curves requires specification of
quantity, availability, and cost attributes. Attributes specific to DSM curves include:
• Resource quantities available in each year either in terms of megawatts or megawatt-hours,
recognizing that some resources may come from stock additions not yet built, and that elective
resources cannot all be acquired in the first year of the planning period;
• Persistence of resource savings (e.g., energy efficiency equipment measure lives);
• Seasonal availability and hours available (e.g., irrigation load control programs);
• The hourly shape of the resource (e.g., load shape of the resource); and
• Levelized resource costs (e.g., dollars per kilowatt-hour per year for energy efficiency, or
dollars per megawatt over the resource's life for demand response resources).
ss The 2025 Conservation Potential Study is available on PacifiCorp's IRP Support & Studies web page:
www.pacificorp.com/energy/integrated-resource-plan/support.html.
39 Demand-side management modeling and methodology was a frequent topic of discussion in the 2025 IRP public
input meeting series and in stakeholder feedback forms.
See Appendix M,stakeholder feedback form#17(Oregon Public Utilities Commission).
See Appendix M,stakeholder feedback form#36(Sierra Club).
See Appendix M,stakeholder feedback form#45(Utah Clean Energy).
167

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Once developed, DSM supply curves are treated like discrete supply-side resources in the IRP
modeling environment.
Demand Response: DSM Capacity Supply Curves
The potential and costs for demand response resources were provided at the state level, with
impacts specified separately for summer and winter peak periods. Prior to 2025, PacifiCorp has
launched and expanded a number of demand response programs to acquire resource needs
identified in the 2021 IRP update. Several demand response resources characterized as potential
demand response resources in the previous IRP are now considered existing or planned demand
response resources which will be effective in 2025.
Table 7.14—DemandftResonseExistingand Planned Pro rams
Mro u Wtate isting or Planned Offering
Res—HVAC DLC UT Existing
Res—HVAC DLC OR, WA Planned
Res—EV Load Control OR, WA, UT Planned
Res—Battery DLC OR, WA Planned
Res—Battery DLC ID, UT Existing
C&I—Battery DLC ID, UT Existing
C&I—Third Party OR, WA, UT Existing
C&I—Third Party ID Planned
A —Irrigation DLC UT, ID, OR, WA Existing
Table 7.15 and Table 7.16 show the summary level demand response resource supply curve
information,by control area. For additional detail on demand response resource assumptions used
to develop these supply curves, see Volume 2 of the 2025 CPA.40 Potential shown is incremental
to the existing DSM resources identified in Table 7.15. For existing program offerings, it is
assumed that the PacifiCorp could begin acquiring incremental potential in 2025. For resources
representing expanded product offerings, it is assumed PacifiCorp could begin acquiring potential
in 2026. New program offerings are assumed to be available in 2026 accounting for the time
required for program design, regulatory approval, vendor selection, procurement and
implementation.
Table 7.15—Demand Res onse Pro ram Attributes West Control Area,ai*
Summer W Winter
Average Average
20-Year Levelized 20-Year Levelized
Potential Cost Potential Cost
roduct (MW) ($/kW- r) (MW) ($/kW- r)
Res—EV DLC 15.1 $412 15.1 $412
Res—DLC of Smart Home 0.1 $1,306 0.1 $686
Res—HVAC DLC 17.4 $175 81.7 $73
ao The CPA can be found at:www.pacificorp.com/energy/integrated-resource-plan/support.html.
41 Demand response resources derived from the demand response RFP are not included to protect confidential 3rd
party pricing information.
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PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Summer F Winter
7qoqw Average Average
20-Year Levelized 20-Year Levelized
Potential Cost Potential Cost
Product MW ($/kW- r) (MW ($/kW- r)
Res-Pool Pump DLC 0.2 $742 0.1 $1,956
Res-Water Heater DLC 2.7 $134 4.0 $90
Res- Smart Thermostat 40.2 $37 28.9 $29
Res-Grid Interactive Water Heaters 14.6 $97 24.5 $66
Battery DLC 6.1 $31 4.9 $30
C&I-Third Party 8.5 $46 12.4 $54
A -Irrigation DLC 1.8 $24 0.0 $0
*Average levelized cost weighted by the 20-year cumulative potential in each state
Table 7.16-Demand Res onse Program Attributes East Control Area,42*
Summer IF V Winter
Levelized
20-Year Cost 20-Year Levelized
Potential ($/kW- Potential Cost
Prod MW r)& (MW $/kW- r)
Res-EV DLC 24.8 $416 24.8 $416
Res-DLC of Smart Home 0.1 $1,601 0.3 $772
Res-HVAC DLC 234.2 $158 141.3 $272
Res-Pool Pump DLC 0.2 $834 0.1 $2,199
Res-Water Heater DLC 12.8 $175 17.5 $117
Res- Smart Thermostat 90.4 $38 50.2 $94
Res-Grid Interactive Water Heaters 1.1 $209 2.0 $139
Battery DLC 65.3 $36 65.2 $41
C&I-Third Party 66.6 $52 72.7 $50
A -Irrigation DLC 1 19.1 1 $29 0.0 $0
*Average levelized cost weighted by the 20-year cumulative potential in each state
Energy Efficiency DSM, Energy Supply Curves
The 2025 CPA provided the information to fully assess the potential contribution from DSM
energy efficiency resources over the IRP planning horizon. The CPA analysis accounts for known
changes in building codes, advancing equipment efficiency standards, market transformation,
resource cost changes, changes in building characteristics and state-specific resource evaluation
considerations (e.g., cost-effectiveness criteria).
42 Demand response resources derived from the demand response RFP are not included to protect confidential 3rd
party pricing information.
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DSM energy efficiency resource potential was assessed by state down to the individual measure
and building levels (e.g., specific appliances, motors, lighting configurations for residential
buildings, and small offices). The CPA provided DSM energy efficiency resource information at
the following granularity:
• State: Washington, California, Idaho, Utah, Wyoming"
• Measure:
— 120 residential measures
— 146 commercial measures
— 105 industrial measures
— 19 irrigation measures
• Facility type:"
— 18 residential facility types
— 28 commercial facility types
— 30 industrial facility types
— Two irrigation facility type
The 2025 CPA levelized total resource costs over the study period at PacifiCorp's cost of capital,
consistent with the treatment of supply-side resources. Costs include measure costs and a state-
specific adder for program administrative costs for all states except Utah and Idaho. Consistent
with regulatory mandates, Utah and Idaho DSM energy efficiency resource costs were levelized
using utility costs instead of total resource costs (i.e. incentive and a state specific adder for
program administration costs).
The technical potential for all DSM energy efficiency resources across all states except Oregon
over the 20-year CPA planning horizon totaled approximately 15.1 million MWh.45 The technical
potential represents the total universe of possible savings before adjustments for what is likely to
be realized(i.e.technical achievable potential).When the achievable assumptions described below
are considered the technical potential is reduced to a technical achievable potential for modeling
consideration of 12.8 million MWh for all five states. The technical achievable potential for all six
states, i.e. including Oregon, for modeling consideration is 17.2 million MWh. The technical
achievable potential, representing available potential at all costs, is provided to the IRP model for
economic screening relative to supply-side alternatives.
Despite the granularity of DSM energy efficiency resource information available, it was
impractical to model the resource supply curves at this level of detail.The combination of measures
by building type and state generated just over 50,500 separate permutations or distinct measures
that could be modeled using the supply curve methodology. To reduce the resource options for
consideration without losing the overall resource quantity available or its relative cost, resources
as Oregon's DSM potential was assessed in a separate study commissioned by the Energy Trust of Oregon.
as Facility type includes such attributes as existing or new construction, single or multi-family, and income level for
the residential sector. Facility types represent a combination of market segment and vintage and are more fully
described in Volume 1 of the 2025 CPA.
45 The identified technical potential represents the cumulative impact of DSM measure installations in the 20t'year of
the study period for California,Idaho,Washington,Wyoming, and Utah.This may differ from the sum of individual
years' incremental impacts due to the introduction of improved codes and standards over the study period. ETO
provides PacifiCorp with technical achievable potential.
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were consolidated into bundles, using ranges of levelized costs and net cost of capacity to reduce
the number of combinations to a more manageable number.
Bundle development began with the energy efficiency technical potential identified by the 2021
CPA. To account for the practical limits associated with acquiring all available resources in any
given year,the technical potential by measure was adjusted to reflect the amount that is realistically
achievable over the 21-year planning horizon. Consistent with the Northwest Power and
Conservation Council's achievability assumptions in the 2021 Power Plan as, which typically
assume that 85% of the technical potential could be acquired over the 20-year period.46
For Oregon,the company does not assess potential for the Energy Trust of Oregon(ETO). Neither
PacifiCorp nor the ETO performed an economic screening of measures in the development of the
DSM energy efficiency supply curves used in the development of the 2025 IRP, allowing resource
opportunities to be economically screened against supply-side alternatives in a consistent manner
across PacifiCorp's six states.
Twenty-seven cost bundles, with a separate bundle reserved for home energy reports, were
available across six states (including Oregon), which equates to 162 DSM energy efficiency
resource supply curves. Table 7.17 shows the 21-year MWh potential for DSM energy efficiency
net cost of capacity bundle categorization.
Bundles are classified based on their measure's temperature dependency, as either heating or
cooling. A measure is considered temperature dependent if at least 25% of annual kWh savings
are derived from temperature dependent end-uses. Measures that have both heating and cooling
savings are classified based on whichever has greater volume. Measures that are not temperature
dependent, such as lighting, are classified based on whichever season (summer or winter) the
measure has a greater capacity contribution. Measures are then ranked based on their net cost of
capacity ($/kW-yr) and assigned to a bundle with measures of a similar net cost. There is little
need to differentiate bundles that will provide value in nearly all conditions. Measures with a net
cost less or equal to zero have energy benefits that exceed their costs, such that their capacity value
(reliability benefits) are "free." These measures are assigned to a zero-cost temperature-sensitive
bin or a zero-cost non-temperature sensitive bin, which together comprise roughly half of all
potential. For non-zero cost measures,roughly equal volumes are distributed among the remaining
bundles of heating,cooling,summer,or winter measures.The number of each type of bundle varies
by state depending on the potential and load profile used in each state.
"The Northwest's achievability assumptions include savings realized through improved codes and standards and
market transformation,and thus,applying them to identified technical potential represents an aggressive view of
what could be achieved through utility DSM programs.
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Table 7.17— 2045 Total Cumulative Energy Efficiency Potential by
Cost Bundle Category (MWh)
Bundle California Idaho Oregon Utah Washington Wyoming
Cooling Measures 24,136 51,160 650,856 1,099,451 91,251 102,441
Heating Measures 1,395 29,701 871,974 334,629 76,938 50,792
Summer Measures 59 0 0 0 0 0
Winter Measures 46,268 127,649 1,398,502 1,903,672 241,406 208,044
Zero Cost Temperature 30,050 76,633 295,605 1,400,650 130,845 112,492
Dependent Measures
Zero Cost Non-
Temperature 62,363 327,503 1,262,937 5,940,760 667,159 1,151,675
Dependent Measures
Cost credits afforded to DSM energy efficiency resources include the following:
• A state-specific transmission and distribution investment deferral cost credit (Table 7.18)
• Stochastic risk reduction credit47
• Northwest Power Act 10-percent credit(Oregon and Washington resources only)48
Table 7.18— State-specific Transmission and Distribution Credits (2024$)
Transmission Distribution
State Deferral Value Deferral Value X
($/kW-year) ($/kW-year)
California $5.83 $11.23 $17.06
Oregon $5.83 $15.65 $21.49
Washington $5.83 $18.93 $24.76
Idaho $5.83 $23.11 $28.94
Utah $5.83 $18.62 $24.46
Wyoming $5.83 $9.61 $15.44
PacifiCorp relies on simulated load shapes tied to weather stations in PacifiCorp's service territory.
Weather is a major driver of PacifiCorp's load and in any given month weather results in a range
of high and low load conditions. Weather also impacts the hourly timing of energy efficiency
savings particularly for measures that are weather dependent. As in the 2023 IRP, PacifiCorp has
reshaped daily energy efficiency volumes to better align with seasonal variations in the load
forecast. The highest demand for temperature-sensitive end use loads is expected to occur at the
time of the winter and summer peaks in PacifiCorp's service territory. For temperature dependent
measures, the simulated savings are proportionate with the temperature-sensitive load across in
each month, so that the highest savings occur on the highest load days in the load forecast. To
47 PacifiCorp develops this credit from two sets of production dispatch simulations of a given resource portfolio,and
each set has two runs with and without DSM. One simulation is on deterministic basis and another on stochastic basis.
Differences in production costs between the two sets of simulations determine the dollar per MWh stochastic risk
reduction credit.
48 The formula for calculating the $/MWh Power Act credit is: (Bundle price - ((First year MWh savings x market
value x 10%) + (First year MWh savings x T&D deferral x 10%))/First year MWh savings. The levelized forward
electricity price for the Mid-Columbia market is used as the proxy market value.
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capture the time-varying impacts of energy efficiency resources, each bundle uses an annual 8,760
hourly load shape. These shapes reflect measure-level annual energy savings, differentiated by
state, sector, market segment, and end use. These hourly impacts are then aggregated for all
measures in each bundle to create a single weighted average load shape for that bundle.
Distribution Efficiency
PacifiCorp continues to develop its CYME CYMDIST® (power flow software) investment in
ways that improve engineering response time and, indirectly, distribution system efficiency. In the
last biennial period, more than 275 large (Level 2 and Level 3) distributed energy resource (DER)
applications were studied in CYME across the Pacific Power and Rocky Mountain Power service
areas. This resulted in more than 34 MW (nameplate) of approved private generation across the
company. Any energy savings resulting from these approvals across the service territory has not
been determined.
These distribution energy efficiency activities were not modeled as potential resources in this
IRP.
Transmission Resources
In developing resource portfolios for the 2025 IRP,PacifiCorp included modeling to endogenously
select transmission options, in consideration of relevant costs and benefits. These costs are
influenced by the type, timing, location, and number of new resources as well as any assumed
resource retirements, as applicable, in any given portfolio. Additional information can be found in
Volume I, Chapter 8.
Market Purchases
PacifiCorp and other utilities engage in purchases and sales of electricity on an ongoing basis to
balance the system and maximize the economic efficiency of power system operations.
Market transactions can encompass a wide variety of product types that can be classified as either
forward (entered well in advance of delivery) or spot (entered no more than a day or two before
delivery). Currently,the most commonly traded forward products are for heavy load hours (HLH)
and/or light load hours (LLH), and are typically for calendar quarters (e.g. "Q3" spanning July,
August, and September) or individual months. Other timeframes are less common, but could
include super-peak products (noon to 8:00 p.m.). All of the common forward market products
represent undifferentiated system power supplied at a point, but forward transactions can also be
based on the costs, availability, options, and/or restrictions of specific physical resources. Some
examples include slices of hydropower resources, or a tolling agreement for a natural gas-fired
resource.
Examples of spot market transactions include day-ahead HLH and LLH products, day-ahead
hourly transactions in the CAISO market,hour-ahead products, and intra-hour products facilitated
by the Western Energy Imbalance Market(EIM).
In the next few years, two changes are coming that will change the landscape of markets in both
forward and spot timeframes. First, the Western Resource Adequacy Program (WRAP) requires
a showing of capacity resources a number of months in advance of the summer and winter seasons.
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Current HLH and LLH market products will not count as capacity for WRAP unless the two
counterparties agree to a capacity transfer, which may incur a higher cost or reduce a
counterparty's willingness to sell. While contracts for physical resources would count as capacity
for WRAP, it is unclear how much capacity of that sort is likely to be available,particularly as the
many WRAP participants all seek to become compliant. Second, CAISO's Enhanced Day-Ahead
Market (EDAM) will expand day-ahead resource optimization beyond the current CAISO
footprint and will impact spot market participation. While EDAM takes over much of the
optimization function in the day-ahead timeframe, to prevent leaning participants will be required
to pass balancing tests to ensure they bring sufficient resources to meet their load, and this may
necessitate transactions ahead of the EDAM.
In past IRPs, PacifiCorp included front office transactions (FOT) as proxy resource options,
assumed to be firm,that represent procurement activity made on an on-going forward basis to help
the company cover short positions. Consistent with the current WRAP rules for unspecified-source
purchases, FOTs are not included in the calculation of WRAP compliance in the 2025 IRP, so
forward market purchases will not count as capacity. While the 2025 IRP does not allow FOTs to
meet WRAP compliance requirements, PacifiCorp expects to continue pursuing economic short-
term and intermediate term market opportunities that assist with WRAP compliance and/or
balancing.
Spot market purchases and sales also provide opportunities to economically balance loads and
resources. The economic opportunities are expected to be enhanced by the EDAM, relative to
current operations, but it is unclear how the EDAM will compare to the IRP model's hourly
balancing optimization of market purchase and sales volumes against static hourly market prices.
In the EDAM and EIM, market prices are based on marginal supply and demand, so significant
increases in supply are likely to reduce prices while increases in demand are likely to increase
prices. When demand is high and begins to approach the limits of available supply, economic
opportunities will diminish and adequate capacity will still be needed to participate. The 2025 IRP
has incorporated historical relationships between daily prices, loads, and resource supply to better
account for the impacts of supply and demand; however, it still relies upon a static forecast of
prices that do not account for portfolio selections through time. With these various factors in mind,
hourly market purchase volumes have been restricted during key hours on the top five load days
within each month. These restrictions apply from 4:00 p.m. to 12:00 a.m. throughout the year, and
in the winter an additional restriction applies in the morning, from 4:00 a.m. to 8:00 a.m. Outside
of these hours (and all day on lower load days), market purchases are allowed up to modeled
transmission limits. Similarly, hourly market sales volumes have been restricted to historical
levels, to avoid increasing reliance on wholesale sales at favorable prices that may not persist in
an organized market.
Chapter 5 describes the relationship of front office transactions (FOTs) to reliability and WRAP
compliance, and FOTs are also considered a resource.Front office transactions can be made years,
quarters or months in advance of use, however, they are generally committed to balance
PacifiCorp's system on a balance of month,day-ahead,hour-ahead,or intra-hour basis. The terms,
points of delivery, and products vary by individual market point.
Additional discussion of how FOTs are considered in the 2025 IRP, refer to Chapter 5 and
Chapter 8.
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CHAPTER 8 - MODELING AND PORTFOLIO
EVALUATION
CHAPTER HIGHLIGHTS
• The Integrated Resource Plan(IRP)modeling approach is used to assess the comparative cost,
risk, and reliability attributes of resource portfolios.
• PacifiCorp used PLEXOS software to produce unique resource portfolios across a range of
different planning cases. Informed by the public-input process, PacifiCorp identified case
assumptions that were used to produce optimized resource portfolios, each one unique
regarding the type, timing, location, and number of new resources that could be pursued to
serve customers over the next 21 years.'
• The PLEXOS Long-Term (LT model) was used to generate initial portfolios and identify the
resulting fixed costs. Each initial portfolio was evaluated for cost and risk among three natural
gas price scenarios (low, medium, and high) and three federal carbon dioxide (CO2) policy
scenarios (zero compliance requirements,a high price on CO2 emissions, and compliance with
current Environmental Protection Agency (EPA) CO2 regulations). An additional CO2 policy
scenario was developed to evaluate performance assuming a price signal that aligns with the
social cost of greenhouse gases (SC-GHG). Taken together,there are five distinct price-policy
scenarios(medium gas/current EPA regulations,medium gas/zero CO2,high gas and coal/high
CO2, low gas/zero CO2, and medium gas/social cost of greenhouse gases).
• Each initial portfolio was also evaluated in the Short-Term model (ST model) to establish
system costs over the entire 21-year planning period. The ST model accounts for resource
availability and system requirements at an hourly level, producing reliability and resource
value outcomes as well as a present-value revenue requirement (PVRR) which serves as the
basis for selecting least-cost least-risk portfolios.
• A selection of competitive "variant"portfolios was analyzed using the other four price-policy
scenarios in PLEXOS modeling to evaluate how each portfolio performs under differing future
market and policy conditions.
• Taking into consideration stakeholder comments and regulatory requirements, PacifiCorp
produced additional studies that examine the potential impact of portfolio options on the
system.
• Informed by comprehensive modeling, PacifiCorp's preferred portfolio selection process
involves evaluating cost and risk metrics reported from ST reporting and stochastic modeling,
comparing resource portfolios based on expected costs, low-probability high-cost outcomes,
reliability, CO2 emissions and other criteria.
'PacifiCorp's IRP is typically modeled with a 20-year planning horizon,expanded in the 2025 IRP to 21 years to
accommodate a specific Washington State requirement extending through 2045. Some discussions and data graphs
in the 2025 IRP will refer to the standard 20-year horizon.
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[ntroduction
IRP modeling is used to assess the comparative cost, risk, and reliability attributes of different
resource portfolios, each meeting reliability requirements. These portfolio attributes form the basis
of an overall quantitative portfolio performance evaluation.
The first section of this chapter describes the screening and evaluation processes for portfolio
selection. Following sections summarize portfolio risk analyses, document key modeling
assumptions, and describe how this information is used to select the preferred portfolio. The last
section of this chapter describes the cases examined at each modeling and evaluation step. The
results of PacifiCorp's modeling and portfolio analysis are summarized in Volume I, Chapter 9
(Modeling and Portfolio Selection Results).
Modeling and Evaluation Steps
All IRP models are configured and loaded with the best available information at the time a model
run is produced. Figure 8.1 summarizes the modeling and evaluation steps for the 2025 IRP. The
process flow begins at left with the development of key inputs and assumptions. Next, studies are
mathematically optimized using PLEXOS software tools2, as illustrated in the six steps at right
("Iterative Optimization", highlighted in blue). Results are evaluated to determine the least-cost
least-risk preferred portfolio from among all eligible portfolios. Finally, the preferred portfolio is
used to develop the action plan.3
2 PLEXOS technical modeling assumptions and parameters were discussed in the 2025 IRP public input meeting
series and in stakeholder feedback.
See Appendix M,stakeholder feedback form#21 (Renewable Northwest).
See Appendix M,stakeholder feedback form#42(First Principals Advisory).
3 The topic of portfolio change was discussed extensively in the 2025 IRP public input meeting series.The modeling
and evaluation steps explain how updated inputs are processed—such as updated resource costs as presented in
Chapter 7—resulting in new portfolio outcomes.
See Appendix M,stakeholder feedback form#13 (Joan Entwistle).
See Appendix M,stakeholder feedback form#15 (Sierra Club).
See Appendix M,stakeholder feedback form#27(Vote Solar).
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Figure 8.1 —Portfolio Evaluation Steps within the IRP Process
Key
Including Planning
o ST hourly
fuel costs,granularity definitions,operating portfolio
constraints,reserve requirements, 1 dispatch
weather year data,etc.
� �Report 3
LT Expansion ST Model
hourly
y
shortfalls by
bubble
PreferredPortfolio i
Iterative � '
Selected on a least-cost least-risk basis from Optimization
competing portfolios -All 6Create LT
Calculate 4
Model with ST granularity
new SCICCHOR adjustment
drivers
Process new
selection
drivers(files,
Action Plan scenarios)
5
The portfolio development process in the 2025 IRP is an iterative process, whereby PacifiCorp
completes initial Long Term capacity expansion modeling runs for each portfolio. Portfolios are
evaluated for cost, reliability and compliance using the Short Term, dispatch focused, modeling
results. Data regarding resource value and unserved energy quantities from the Short Term model
is fed back into PLEXOS, and the next phase of iterative portfolio optimization is launched. Each
cycle through the six steps is one modeling "phase". Iterations continue until the Long Term
capacity expansion model has produced a portfolio that demonstrates no unserved energy in the
Short Term dispatch model run, and then for several phases thereafter, so as to identify a range of
potentially economic candidate portfolios. Each price-policy scenario and each candidate variant
study follows this iterative optimization process. Once a completed portfolio phase achieves
reliability, as measured using Short Term model results, evaluation is completed and results can
be compared to other portfolios.
Overview of Steps in an Iterative Phase
Step 1
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 short-term (ST) model. The ST model
performs an hourly dispatch of the portfolio
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
Step 3
The ST model reports shortfalls as megawatts of unserved energy. These megawatts must
be covered for each location(or"bubble") in the IRP transmission topology. Greater detail
regarding use of these reported shortfalls to create the reliability adjustment is below.
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. Greater detail regarding the calculations which
comprise the granularity adjustment is below.
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,if necessary,where shortfalls are represented
as an additional load requirement and the granularity adjustment is represented as a cost
adjustment(either an increase or decrease in costs) 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 4 blocks of hours per month over the 21-year horizon.
This means the LT model groups similar hours into a block, calculates the average load and
resource parameters specific to each block,and then concurrently solves the entire 21-year horizon.
In contrast,the ST model concurrently solves (or dispatches) of a given week, or roughly 52 steps
per year of 168 hours each,for a specified portfolio of resources as selected in the LT model.When
PLEXOS optimizes the system in the 4-block LT view, it calculates a locational marginal price
(LMP) specific to each block of hours. The value of a resource in the LT is equal to its generation
in each block, multiplied by the LMP during that block specific to its location, and this value is
part of the reported results based on the 48 blocks the LT evaluates during each year(4 blocks per
month times 12 months). When the ST model dispatches the same resources at an hourly
granularity, it calculates the LMP based on hourly conditions, multiplies by a resource's hourly
generation, and reports the resulting value for each resource on an annual basis. The ST model
also assigns specific resources to hold operating reserves necessary to meet reliability
requirements, calculates the marginal price of reserves, and includes this as part of the reported
resource value. The mathematical difference between the ST value and the LT value is the
granularity adjustment.
The 4 blocks used by the LT model include the top ten percent highest net load hours (load net of
wind and solar generation), the highest wind generating hours, the highest solar generating hours,
and the remainder of the hours. While these blocks are intended to help the LT model differentiate
between key resource types, they can't capture the full range of hourly conditions.
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
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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 8.2 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.
Figure 8.2 —Granularity Adjustment Determination
IF Energy value of a resource's > Energy value of a resource's
output in LT Model output in ST Model ♦ Increase Fixed Cos[ ♦ Less likely to pick resource
Energy value of a resource's Energy value of a resource's More likely to pick
IF output in LT Model output in ST Model ♦ Decrease Fixed Cost ♦ 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 2025 IRP, 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 hourly 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.
In order to avoid diluting singular hourly shortfalls across the entirety of a block, the highest
monthly shortfall figure is taken, divided by 4 and applied to each hour in the top ten percent of
highest net load hour block. The highest shortfall in a month is divided by 4 to avoid overshooting
the total amount of resources needed. As an example, suppose the phase zero portfolio (the very
first iteration of the six steps for a particular study)reports a maximum shortfall of 400 megawatts
in Wasatch Front on June 8, 2032, at 8 PM. The 400 megawatt shortfall is divided by 4 to create a
100 megawatt adder to Wasatch Front load. This 100 megawatt adder is added to the base load file
for all of the top ten percent net load hours in Wasatch Front in June of 2032, and phase 1 is run
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with the adjusted load file. If the portfolio selected in phase 1 reports a maximum shortfall of 100
megawatts in Wasatch Front in 2032, the same process is undertaken and 25 megawatts is added
to all ten percent top net load hours, such that the load for that block is now 125 megawatts higher
than the original phase zero 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 reliability and granularity adjustments result in an iterative loop from the LT model to the
ST model and back to the LT model,with results that 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 no longer
results in additional cost reductions.
Cost and Risk Anal
Note—PaciftCorp is working to complete the stochastic analysis described below, and will
include it in the final published IRP.
Sufficiently reliable resource portfolios developed by the LT model are simulated through
stochastics to produce metrics that support comparative cost and risk analysis among the different
resource portfolio alternatives. New to the 2025 IRP, stochastic risk modeling of resource
portfolios is performed using actual historical conditions. These conditions, including weather
patterns,thermal outages, fuel and market prices,hydro generation, and wind and solar generation
profiles, are mapped to the historical dates underlying PacifiCorp's chaotic normal load forecast.
PacifiCorp has 18 distinct years of historical data, and ran each portfolio using historical data for
one specific historical year for all years of the 21-year horizon. The results from these runs are
used to calculate a risk adjustment which is combined with ST model system costs to achieve a
final risk-adjusted PVRR to guide portfolio selection.
Portfolio Selection
The portfolio selection process is based on modeling results from the resource portfolio
development and cost and risk analysis steps. The screening criteria are based on the PVRR of
system costs, assessed across a range of price-policy scenarios on a deterministic basis and on an
upper-tail stochastic risk basis. Portfolios are ranked using a risk-adjusted PVRR metric, a metric
that combines the deterministic PVRR with upper-tail stochastic risk PVRR. The final selection
process considers cost-risk rankings,robustness of performance across pricing scenarios and other
supplemental modeling results, including reliability,resource adequacy, compliance with all state
laws/regulations, and CO2 emissions data as an indicator of risks associated with greenhouse gas
emissions.
Resource expansion plan modeling, performed with the LT model, is used to produce resource
portfolios with sufficient capacity to achieve reliability over the 21-year study horizon by
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
evaluating groups of hours on an aggregated basis.Each resource portfolio is refined for reliability
at an hourly granularity during the reliability assessment step as described above. Each portfolio
is uniquely characterized by the type, timing, location, and number of new resources in
PacifiCorp's system over time. These resource portfolios reflect a combination of planning
assumptions such as resource retirements, CO2 prices, wholesale power and natural gas prices,
load growth net of assumed private generation penetration levels, cost and performance attributes
of potential transmission upgrades, and new and existing resource cost and performance data,
including assumptions for new supply-side resources and incremental demand-side management
(DSM) resources. Changes to these input variables cause changes to the resource mix, which
influences system costs and risks.
Long-Term (LT) Capacity Expansion Model
In the 2025 IRP, the LT model is used to establish an initial portfolio under expected conditions
(medium gas, zero CO2), and then modified for each case,based on study parameters,to eliminate
shortfalls and maintain reliability. The LT model operates by minimizing operating costs for
existing and prospective new resources, subject to system load balance, reliability, and other
constraints. Over the 21-year planning horizon, the model optimizes resource additions subject to
resource costs and load constraints. These constraints include seasonal loads, operating reserves,
and regulation reserves plus a minimum planning reserve margin (PRM)4 for each load area
represented in the model.
The resource portfolios developed using the iterative approach outlined at the beginning of this
chapter are appropriately reliable to its granularity and performance limitations. Operating reserve
requirements include contingency reserves, which are calculated as 3% of load and 3% of
generation. The planning reserve margin in the 2025 IRP is based on compliance with the Western
Resource Adequacy Program(WRAP) at each load area in the topology,as provided in Figure 8.3.
If an early retirement of an existing generating resource is assumed or selected for a given planning
scenario, the LT model will select additional resources as required to meet loads plus reliability
requirement in each period and location. The LT model may also select additional resources that
are more economic than an existing generating resource. In the 2025 IRP, the model is
simultaneously considering resource additions for reliable and economic system operation both
before and after existing generation resources retire, as well as the years in which to retire existing
resources.
To accomplish these optimization objectives, the LT model performs a least-cost dispatch for
existing and potential planned generation, while considering cost and performance of existing
contracts and new DSM alternatives within PacifiCorp's transmission system. Resource dispatch
is based on representative data blocks for each of the 12 months of every year. To enhance the
ability of the LT model to differentiate key resource types and system conditions, for the 2025
IRP, each month was split into four blocks of hours based on load,wind, and solar,based on wind
and solar generation profiles based on weather conditions during the specific days used to develop
PacifiCorp's chaotic normal load forecast:
a The PLEXOS model uses `capacity reserve margin' for what PacifiCorp has traditionally described as `planning
reserve margin' ("PRM").While capacity reserve margin is slightly more precise,PRM is used in the 2023 IRP to
reduce confusion over the use of multiple similar terms and because PRM is the industry standard term.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
1. The top ten percent highest net load hours. 10% is approximately 70 hours per month, or
an average of 2-3 per day, though some days may not have any hours in this group at all.
2. The top ten percent highest wind generation hours on a system basis.
3. The top ten percent highest solar generation hours on a system basis.
4. All other hours
The result of this modeling is to indicate to the LT model that wind and solar have very high
availability in some hours,and very low availability in others.This would be expected to contribute
to more moderate selections of wind and solar, as they will saturate some periods and have lower
value. It would also be expected to contribute to selections of storage and peaking resources,
targeted to cover periods in which wind and solar provide little generation supply.
PLEXOS LT model dispatch among blocks of hours in a month is not chronological, so it cannot
constrain energy storage charging and discharging,except to ensure that over the course of a month
these remain balanced. But within that limitation, PLEXOS determines generation and storage
dispatch, optimal electricity flows between zones, and optimal market transactions for system
balancing. The model minimizes the system PVRR, which includes the net present value cost of
existing contracts, market purchase costs, market sale revenues, generation costs (fuel, fixed and
variable operation and maintenance, decommissioning, emissions, unserved energy, and unmet
capacity),costs of DSM resources,amortized capital costs for existing coal resources and potential
new resources, and costs for potential transmission upgrades.
Key modeling elements and inputs for the LT capacity expansion model include the following:
Transmission System
PacifiCorp uses a transmission topology that captures major load centers, generation resources,
and market hubs interconnected via firm transmission paths.' Transfer capabilities across
transmission paths are based upon the firm transmission rights of PacifiCorp's merchant function,
including transmission rights from PacifiCorp's transmission function and other regional
transmission providers.
5 Continued interest was expressed on stakeholder feedback regarding the assumption of a Wyoming market hub to
represent the opportunity afforded by certain transmission constraints. In light of the restrictions on the types of
market products that can count toward WRAP capacity requirements,PacifiCorp's modeling does not count any
short-term market products toward WRAP compliance,and has limited market purchases at all points during the
highest load conditions in each month,to represent potential market liquidity limits. See Appendix M,stakeholder
feedback form#39(Western Resource Advocates).
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Figure 8.3—Transmission System Model Topology with Major Options
2025 IRP
Washington Transmission topology
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anmme. Nemingway•g2 BorahPopl D3 D3 Add'I..�®east
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This map is for general reference only regarding IRP topology.
PacifiCorp is reevaluating the timing and needs analysis underlying 13211 because of factors such as changed native
load growth and a lack of capacity available on neighboring transmission systems to deliver to load pockets.
Figure 8.3 illustrates the 2025 IRP modeled topology where each transmission area or"bubble" is
defined by any load and generation capability, it's location on the system and its connections to
other bubbles.
Transmission Options
In addition to topology,Figure 8.3 illustrates modeled options for endogenous selection by the LT
model. Over a span of three public input meetings, PacifiCorp presented information about
transmission modeling as it was developed and presented interconnection and Cluster study results
used to establish resource and transmission options based on the best available data.6,7
"Interconnection" requires modifications, additions, or upgrades to physically and electrically
connect a generating facility to the transmission system. Which requirements apply can be
6 Wildfire mitigation in the context of transmission was discussed in the 2025 IRP public input meeting series and
stakeholder feedback. See Appendix M,stakeholder feedback form#18(Wyoming Office of Consumer Advocate).
7 Transmission modeling,cluster studies and details of resource-to-transmission relationships were discussed
extensively during the 2025 IRP public input meeting series and in stakeholder feedback. See Appendix M,
stakeholder feedback form#40(Renewable Northwest).
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
impacted by the generation facility type, detailed project specifications, location, prior/existing
generation facilities and load.
Studies needed to identify interconnection requirements are interdependent and extensive.
Interconnection is carefully regulated for the safety,reliability,and efficiency of the electrical grid.
Requests for interconnection made by any project are regulated and managed in various ways,
such as:
• Serial queue: Signed agreements and near-final serial queue requests.
• Transition Cluster: Remaining serial queue requests and 2020 requests.
• Cluster Study 1: Spring 2021 requests.
• Cluster Study 2: Spring 2022 requests.
• Cluster Study 3: Spring 2023 requests
• Colstrip: Interconnection to jointly-owned Colstrip transmission assets.
• Surplus: Interconnection of additional resources at the same point as an existing generator,
with aggregate output not exceeding the existing limit.
• Provisional: Interconnection study identifies maximum permissible output before
transmission upgrades that are not yet in service.
• Oregon Community Solar: projects under 3MW seeking to participate in the Oregon
Community Solar program.
• Informational Studies:Informational only,proposal and results are not considered part of later
interconnection requests and cannot lead to an interconnection agreement.
The process of evaluating the viability of future projects is complex and time-consuming,resulting
in many pending interconnection requests. In 2020, PacifiCorp transitioned from a serial queue
study process (one generator at a time) to an annual cluster study process (one study for all new
requests in a given area). In the 2023 IRP PacifiCorp significantly enhanced its study of resource
and transmission potential to better align with project expectations and costs resulting from these
advanced studies. For the 2025 IRP,PacifiCorp has transitioned to using cluster studies to indicate
the earliest year a resource type is eligible for selection in any given location (as well as using
recent cluster study data as compiled by PacifiCorp Transmission to indicate potential transmission
upgrades and costs). Cluster studies are described further in Chapter 4.
Surplus Interconnections
Surplus interconnections add more generation to an existing interconnection without requiring
additional transmission lines. However, while installed nameplate capacity is increased at a site,
the total megawatt output at any given time at that location cannot exceed the original
interconnection capacity.
Added generation can be of the same type and can take the form of additional generating unit or
increased generation capability, such as wind repowering resulting in higher nameplate capacity
than the existing interconnection. In the event an added resource is of a different type, a hybrid is
created. For example, a hybrid resource combination of solar,wind and storage allow a higher net
capacity factor among all three resources, increasing overall generation, while avoiding the need
for added transmission.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
PacifiCorp has submitted surplus interconnection requests to evaluate the addition of solar to
several wind resource sites in Wyoming.
Transmission Costs
In developing resource portfolios for the 2025 IRP,PacifiCorp included modeling to endogenously
select transmission options, in consideration of relevant costs and benefits. These costs are
influenced by the type, timing, location, and number of new resources as well as any assumed
resource retirements, as applicable, in any given portfolio.
Resource Adequacy
In its 2025 IRP, PacifiCorp included the monthly planning reserve margin requirements from the
Western Resource Adequacy Program (WRAP) in the LT model. The planning reserve margin
applies in all periods and must be met by available resources within that area or imports from
adjacent areas with excess resources available, subject to transmission constraints. While WRAP
is expected to enhance reliability, the monthly capacity contribution values assigned to each
resource may not be sufficient to meet hourly requirements in every location, so it does not
eliminate the need for reliability assessment. Taken together,these reliability requirements ensure
that PacifiCorp has sufficient resources to meet load in all periods,recognizing the uncertainty for
load fluctuation and extreme weather conditions, fluctuation of variable generation resources, a
possibility for unplanned resource outages, and reliability requirements to carry sufficient
contingency and regulating reserves.
Granularity and Reliability Adjustments
As detailed during the 2025 IRP public-input process, the granularity adjustment reflects the
difference in economic value in resource options and transmission between an hourly 8760 cost
calculation in ST modeling, and the monthly blocking representation used in the LT model.'
This adjustment is needed because resources with high variable costs that are rarely dispatched
may provide a large value in a few intervals in the ST study, while not dispatching in any of the
LT model blocks. Also, storage resources allow for arbitrage among high value and low value
hours in each day; however, the block granularity smooths out many of the storage arbitrage
opportunities and also doesn't fully capture the effect of storage duration limits.
In parallel with the granularity adjustment, the reliability adjustment addresses unmet capacity
needs by hour in the LT model portfolio selection. Much of the peak load hour requirements in
mid-afternoon in the summer are adequately met by solar resources. However, resource
requirements are driven by portfolio-dependent net load peaks (load less renewable resource
output), which are harder for the LT model to identify.
While the granularity and reliability adjustments help direct the LT model to more cost-effective
resources and a more reliable portfolio, in a single pass,the LT model cannot guarantee reliability
at an hourly operational level. Marginal benefits decline as any resource type becomes a larger
a See Appendix M,stakeholder feedback form#17(Oregon Public Utilities Commission)for responses to questions
regarding modeling transmission and granularity adjustments. The method for evaluating granularity value for
transmission is the same as for supply-side resources,in that the model reports values used for the granularity
adjustments based on the resource's contribution to reducing cost and risk.
See also Appendix M,stakeholder feedback form#36(Sierra Club).
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share of a portfolio, as it saturates the need in the hours it is available. A similar effect occurs with
storage, where each incremental MW of system storage capacity must cover a longer duration.
Because of the performance limitations of capacity expansion optimization, the ST model is
leveraged to refine the portfolio to achieve a final balanced and reliable mix of resources, as
described under the Cost and Risk Analysis section of this analysis, further below.
Thermal Resource Options
Continuing best practice from the 2023 IRP, all majority-owned and operated coal plant sites are
considered candidates for surplus interconnection in the 2025 IRP. Other renewable technologies
can be added prior to the coal plant's retirement, with the aggregate of the existing and surplus
resource output limited to the current maximum output of the coal resource. As a result, the LT
model simultaneously evaluates the value of surplus resources both before and after the associated
coal units retire, while at the same time evaluating when, or whether, they should retire.
Table 8.1 and Table 8.2 report the coal unit options modeled in the 2025 IRP, whereas Table 8.3
summarizes the options available for natural gas-fired units.
Table 8.1 —Majority-Owned Coal Generator Resource Options9,I0
Jim Bridger Units 3 and 4 2025 12026 12027 12028 2029 2030 2031 2032 12033 12034 2035 2036 1203712038 2039 2040 2041 2042 2043 20" 2045
Coal 2028thru 2045
- - - - - - - - - - - - - - - - - - -
Cofire-2030/2039111(d Dual Fuel - Gas
Coal-CCS 2030 CC5+45Q CCS
Dave Johnston l aod2 2025 12026 1 2027 2028 2029 2030 12031 1 20321 2033 12034 12035 1 2036 2037 1 2038 1 2039 12040 1 2041 2042 2043 2044 2045
Coal 2028-2029/Gas Conv.2029 - lGas
- - - - - - - - - - - - - - - -
Dave Johnston 3 2025 12026 12027 20281 2029 2030 12031 12032 12033 12034 12035 12036 12037 12038 1 2.039 12040 12041 2042 2043 2044 2045
Coal 2028 Retired
Dave Johnston 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Coal 2028thru 2045 -
_ _
Cofire-2030/2039111(d) Dual Fuel - Gas -
CoalCCS+SCR 2032 CCS+45Q CCS -
Wyodak 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Coal 2028 thru 2045
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Cofire-2030/2039111(d) Dual Fuel - - - - - - - - Gas - - - - - -
CoalCCS+SCR2032 CCS+45Q CCS -
Hunterl-3 2025 12026 12027 1 2028 2029 1 2030 12031 2032 12033 1203412035 12036 12037 12038 1 2039 1204012041 1 2042 2043 2044 2045
Coal 2028 thru 2045 - - - - - - - - - - - - - - -
Cofire Alt.Fuel-2030/2D391111d Dual Fuel - Alt.Fuel-
CoalCCS+SCR 2032 CCS+45Q CCS -
Huntington 1-2 2025 12026 12027 2028 1 2029 1 2030 12031 2032 2033 2034 2035 2036 2037 2038 2039 12040 2041 2042 2043 20" 2045
Coal 2028 thru 2045 - - - - -
Cofire Alt.Fuel-2030/20391111d IDualFuel - Alt.Fuel- -
CoalCCS+SCR2032 i CCS+45Q CCS -
Key Default/current operation 45Q CCS
Retirement Option Alternative Fuel
Gas conversion option Assumed retired
9 While 111(d)compliance can be met with dual fuel operations in 2030-2038,due to engineering uncertainty and
modeling complexity,starting in 2030 100%of the fuel input for these options comes from natural gas or alternative
fuel.For Hunter and Huntington,which are not located in proximity to natural gas pipeline transport,the alternative
fuel modeled in the 2025 IRP is biodiesel.
10 After the filing of the 2023 IRP Update on March 31,2024,a change occurred in the timing of implementation of
carbon capture on Jim Bridger Units 3 and 4.CCS assumption for these units is updated for the 2025 IRP. See
Appendix M,stakeholder feedback form#5(Powder River Basin).
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Table 8.2 -Minority-Owned Coal Generator Resource Options
Minority-Owned Units 2025 12026 12027 12028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Colstrip 3 PAC share moves to Unit 4
Colstrip 4 Includes Unit 3 share
Craig 1
Craig 2
Hayden 1
Hayden 2
Key Default/current operation Assumed retired
Table 8.3 - Natural Gas Generator Resource Optionsii
Chehalis 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045
_
Cofire/non-emitting 2030
Currant Creek 2025 1 2026 1 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045
_
Hermiston 1/2 2025 2026 2027 2023 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 1 2042 2043 2044 2045
Gas-2028 thru 2039/Alt.Fuel
Jim Bridger Units land 2 2025 1 2026 1 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Gas 2028 thru 2045
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Lakeside 1 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045
Lakeside 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 '037M1032
2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045
_ _ _Nau hton Units Sand 2 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 20372040 2041 2042 2043 2044 2045
Gas-2026 thru 2045 _ _Naughton Unit3 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2 337 2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045 _ _ _Gadsby Steam 1-3 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2040 2041 2042 2043 2044 2045
Gas 2028thru 2045Gadsby Crs 4-6 2025 202 22027 2028 2029 20302031 2032 2033 2034 2035 2036 2037 2040 2041 2042 2043 2044 2045
Gas 2028 thru 2045
Key Default/current operation Alternative Fuel
Retirement option Current(Coal)
Assumed retired
New Resource Options
Demand-Side Mannement
Energy efficiency resources are characterized with supply curves that represent achievable
technical potential of the resource by state, by year, and by measures specific to PacifiCorp's
service territory. For modeling purposes, these data are aggregated into cost bundles. Each cost
bundle of the energy efficiency supply curves specifies the aggregate energy savings profile of all
measures included within the cost bundle. Each cost bundle has both a summer and winter capacity
contribution based on aggregate energy savings during on-peak hours in July and December
aligning with periods where PacifiCorp is most likely to exhibit capacity shortfalls.
Demand response resources, representing direct load control capacity resources, are also
characterized with supply curves representing achievable technical potential by state and by year
for specific direct load control program categories (i.e., air conditioning, irrigation, and
commercial curtailment). Operating characteristics include variables such as total number of hours
per year and hours per event that the demand response resource is available.
Wind and Solar Resources
" PacifiCorp has insufficient detail at this time to evaluate alternative fueling options at its Chehalis and Hermiston
natural gas-fired facilities,particularly in light of possible impacts on cost-allocation and market participation,and
has adopted Action Plan item 1 h to advance options for potential implementation by 2030.
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
Proxy wind and solar resources available for inclusion in the preferred portfolio are dispatchable
by the model up to fixed energy profiles that vary by day and month. The fixed energy profiles for
wind and solar resources are based on the weather conditions from the same historical days used
to develop the load forecast.
The ability for wind and solar resources to reliably meet demand over time is impacted by the
forecasted profiles, along with mix of other resources in the portfolio.
Non-Emitting Resources
Four non-0O2-emitting thermal resources are considered: nuclear projects, small renewable fuel
peaking resources, geothermal resources, and non-emitting hydrogen peaking units leveraging on-
site electrolysis with 24 hours of tank storage.Nuclear resources and geothermal are characterized
by continuous operation, with the Natrium project combining this operation with storage in the
form of heat stored as molten salt. In contrast, peaking resources are designed to run infrequently
to support system reliability by dispatching only when needed to meet shortfalls. The small
renewable peaking resource for the 2025 IRP is assumed to use biodiesel or renewable diesel,both
of which are commercially available.While combustion of these fuels releases CO2 it is not derived
from fossil sources and is eligible to meet compliance requirements in both Oregon and
Washington.
Energy Storage Resources
Energy storage resources are distinguished from other resources by the following three attributes:
• Energy take — generation or extraction of energy from a storage reservoir for a specified
period;
• Energy return—energy used to fill (or charge) a storage reservoir; and
• Storage cycle efficiency—an indicator of the energy loss involved in storing and extracting
energy over the course of the take-return cycle.
Modeling energy storage resources requires specification of the size of the storage reservoir,
defined in gigawatt-hours. The model dispatches a storage resource to optimize energy used by the
resource subject to constraints such as storage-cycle efficiency,the daily balance of take and return
energy, and variable costs, if applicable.
Market Purchases
Market purchases are transactions by the company's front office and represent short-term firm
agreements for physical delivery of power. PacifiCorp is active in the western wholesale power
markets and routinely makes short-term firm market purchases for physical deliveries on a forward
basis (i.e., future months or quarters, balance of month, day-ahead, and hour-ahead). These
transactions are used to balance PacifiCorp's system as market and system conditions become
more certain when the time between an effective transaction date and real time delivery is reduced.
Balance of month and day-ahead physical firm market purchases are most routinely acquired
through a broker or an exchange, such as the Intercontinental Exchange (ICE). Hour-ahead
transactions can also be made through an exchange. For these types of transactions, the broker or
the exchange provides a competitive price. Non-brokered transactions can also be used to make
firm market purchases among a wide range of forward delivery periods.
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From a modeling perspective, it is not feasible to incorporate all of the short-term firm physical
power products, differing by delivery pattern and delivery period, which are available through
brokers, exchanges, and non-brokered transactions. However, considering that PacifiCorp
routinely uses these types of firm transactions, which obligate the seller to back the transaction
with reserves when balancing its system, it is important that the contribution of short-term firm
market purchases is accounted for in the portfolio-development process.
Capital Costs
Annual capital recovery factors are used to convert capital investment dollars into nominal
levelized revenue requirement costs. Use of nominal levelized revenue requirement costs is an
established methodology for analyzing capital-intensive resource decisions among resource
alternatives that have unequal lives and/or when it is not feasible to capture operating costs and
benefits over the entire life of any given resource. To achieve this, the nominal levelized revenue
requirement method spreads the return of investment (book depreciation), return on investment
(equity and debt), property taxes, income taxes, and demolition costs over the life of the
investment. The result is an annuity or annual payment that remains constant such that the PVRR
is identical to the PVRR of the nominal requirement when using the same nominal discount rate.
General Assumptions
Study Period and Date Conventions
PacifiCorp executes its 2025 IRP models for a 21-year period beginning January 1, 2025 and
ending December 31, 2045. Future IRP resources reflected in model simulations are given an in-
service date of January 1 st of a given year, except for coal unit natural gas conversions,which are
given an in-service date of June 1 st of a given year, recognizing the desired need for these
alternatives to be available during the summer peak load period after ceasing coal-fired operation
at the end of the prior year.
Inflation Rates
The 2025 IRP simulations and cost data reflect PacifiCorp's corporate inflation rate schedule
unless otherwise noted. A single annual escalation rate value of 2.18 percent is assumed. This
escalation rate reflects the average of annual inflation rate projections for the period 2025 through
2045,using PacifiCorp's September 2024 inflation curve.PacifiCorp's inflation curve is a straight
average of forecasts for the Gross Domestic Product inflator and the 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 2025 IRP is 6.69 percent. 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.12 PVRR
figures reported in the 2025 IRP are reported in 2024 dollars.
12 Public Utility Commission of Oregon,Order No. 07-002,Docket No.UM 1056,January 8,2007.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
CO2 Price Scenarios
PacifiCorp used three different CO2 price scenarios in the 2025 IRP—zero, high, and a price
forecast that aligns with the social cost of greenhouse gases (SCGHG), plus a scenario reflecting
compliance with current federal regulations including the currently published EPA rule I I I(d).
The high greenhouse gas scenario is derived from forecasts of greenhouse gas costs in Washington
and California, but is applied like a federal obligation throughout the system starting in 2030.
Impacts in the scenario which includes current federal regulations also become relevant in 2030,
as coal-fired resources must select between retirement, carbon capture, or co-firing by this time.
The SCGHG scenario is in compliance with Washington RCW 19.280.030 including an adjusted
cost of greenhouse gas emissions reflecting inflation, defined by the Washington Utilities and
Transportation Commission.13 The social cost of greenhouse gas emissions is assumed to apply in
all years of the study horizon. The social cost of greenhouse gases 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 suggested treatment, 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
by the Washington Legislature in 2021.14 This is in addition to the assumed federal CO2 policy
represented in the zero, high, and social cost of greenhouse gas scenarios described above. The
modeled allowance cost is based on the allowance cost cap identified by the Washington
Department of Ecology, and starts at$88 metric ton in 2024.1s
13 Washington Utilities and Transportation Commission,Order 05,Docket No.U-190730,July 25,2024. Available
online at:https:Hapiproxy.utc.wa.gov/cases/GetDocument?docID=27&year=2019&docketNumber=190730
(Accessed 11/8/2024).
14 Stakeholder feedback requested modeling Chehalis without consideration of Washington's Climate Commitment
Act.Notwithstanding that certain commissions have declined to allow the company to recover these costs,the
company continues to incur these costs,which are therefore modeled. See Appendix M,stakeholder feedback form
#19(Wyoming Office of Consumer Advocate).
15 Washington Cap-and-Invest Program 2024 Annual Allowance Price Containment Reserve Tier Price and Price
Ceiling Unit Price Notice. December 2023. Available online at:
https:Happs.ecology.wa.gov/publications/documents/2302066.pdf(Accessed 11/8/2024).
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Figure 8.4 —COz Prices Modeled by Price-Policy Scenario
$360
�WA CCA CO2
$340 (ChehaUs)
$320 — —231RP(M)
$300 ---231RP(H)
$280
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$240 25 IRP HH
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o $160
z
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Wholesale Electricity and Natural Gas Forward Prices
For 2025 IRP modeling purposes, five electricity price forecasts were used: the official forward
price curve(OFPC)and four scenarios.Unlike scenarios,which are alternative spot price forecasts,
the OFPC represents PacifiCorp's official quarterly outlook. The OFPC is compiled using market
forwards, followed by a market-to-fundamentals blending period that transitions to a pure
fundamentals-based forecast.
At the time PacifiCorp's 2025 IRP modeling inputs were prepared,the September 2024 OFPC was
the most current OFPC available. For both gas and electricity, starting with the prompt month, the
front 36 months of the OFPC reflects market forwards at the close of a given trading day.16 As
such, these 36 months are market forwards as of September 2024. 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 price forecast. The fundamentals
portion of the electricity OFPC reflects prices as forecast by AURORAxmp17 (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 each quarter for the OFPC and, as a corollary,the electricity
OFPC is also updated.
Scenarios using high or low gas prices do not incorporate any market forwards since scenarios are
designed to reflect an alternative view to that of the market.. As such,the low and high natural gas
price scenarios are purely fundamental forecasts.Low and high natural gas price scenarios are also
16 The September 2024 OFPC prompt month is November 2024;October 2024 would be traded as"balance of
month"when the OFPC is released.
17 AURORAxmp is a proprietary production cost simulation model,developed by Energy Exemplar,LLC.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
derived from an expert third-party forecast. Similarly, the SCGHG scenario does not incorporate
any market forwards since that greenhouse gas policy represents an alternative view that applies
throughout the study period.
New to the 2025 IRP, in response to stakeholder feedback and requests related to volatility in coal
pricing, the high gas and market price-policy scenario also includes an elevated coal fuel supply
cost. This represents risks such as supply-chain issues as well as the potential for increased
transportation costs or other increased variable coal costs which are not present in the base forecast
for coal pricing.18
Figure 8.5 summarizes the five wholesale electricity price forecasts and three natural gas price
forecasts used in the base and scenario cases for the 2025 IRP.
Figure 8.5—Nominal Wholesale Electricity and Natural Gas Price Scenarios
Wholesale Electricity Prices Natural Gas Prices
Ay erage of Palo Verde and.kfid-C(Flat) Henry Hub
$120 $14
$110 $13
$100 $12
$90 $11
$>m $10
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.....Nlgas_1fCO2(�f r 2os1) •e■••Xh;g _\fCd:(Sep 20=) .....Medium(�tsr 2021) —Med®(5�2021)
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—Hgu_HCO2(Sep 2022) —I1ge:_SCO2(Sep 2022) _ _ _Low(Sep 2022) Ifth(SQ 2022)
Cost and Risk Analysis
Short-Term (ST) Schedule Model
The ST model uses the same common input assumptions described for the LT model coupled with
the portfolio selected by the LT model. LT results provide the initial capacity expansion plan for
the ST model to dispatch.
11 Coal supply,costs and risks were discussed in the 2025 IRP public input meeting series and stakeholder feedback.
In the 2025 IRP,PacifiCorp considers base coal cost assumptions,the Jim Bridger Long-term Fuel Plan sensitivity,
and coal-related variant studies.For stakeholder feedback and responses:
See Appendix M,stakeholder feedback form#28(Utah Citizens Advocating Renewable Energy).
See Appendix M,stakeholder feedback form#29(Utah Clean Energy).
See Appendix M,stakeholder feedback form#30(Katie Pappas).
See Appendix M,stakeholder feedback form#31 (Jane Myers).
See Appendix M,stakeholder feedback form#32(Sara Kenney).
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
Reliability Assessment and System Cost
The ST model begins with a portfolio from the LT model that has not yet been refined to reflect
the reliability and compliance needs of a particular study (e.g., a particular sensitivity or price-
policy scenario). The ST model is first run at an hourly level for 21 years in order to retrieve two
critical pieces of data: 1) shortfalls by hour, and 2) the value of every potential resource to the
system that is specific to the portfolio itself, and the other input assumptions, such as the price-
policy scenario.
As discussed at the start of the chapter, these data points are fed back into the LT model to prompt
endogenous selections of resources that lead to a reliable portfolio.
Resource Value
PLEXOS calculates a locational marginal price (LMP) specific to each area in each hour that is
based on supply and demand in that area and available imports and exports on transmission links
to adjacent areas. This is also known as a shadow price. PLEXOS also calculates the marginal
price specific to ancillary services(i.e., operating reserves)in each hour. PLEXOS then multiplies
these prices by a resource's optimized energy and operating reserve provision for each hour and
reports the total as a resource's estimated revenue. In an organized market, this would represent
the expected payments based on market-clearing prices.
When variable costs (such as fuel, emissions, and VOM) are subtracted out, the result is a
resource's "net revenue". Net revenue provides a clear model-optimized assessment of every
resource's value to the system,which is then used to assess resource additions needed to preserve
reliable operation of the system.
While the net revenue approach is demonstrably superior to past resource value measures,
especially as it is evaluated simultaneously for all potential resources, modeling capabilities, net
revenue has limitations that should be acknowledged. Net revenue represents the value of the last
MW of capacity from a given resource—as resources grow larger, the average value from the first
MW of capacity to the last MW of capacity will tend to be somewhat higher than the reported
marginal value. Conversely, adding more of a particular resource will result in declining values.
While marginal prices will be very high in hours with supply shortfalls, this only indirectly
contributes to reliable operation by helping to identify beneficial replacement resources. Once
sufficient resources are added, shortfalls will mostly be eliminated, and marginal prices will again
reflect the variable cost of an available resource.
Portfolio Refinements
While many resource options are evaluated,utility scale generation resources are mostly restricted
to two circumstances: surplus or replacement resources at generators that are eligible to retire, and
new resources at locations with interconnection or transmission upgrade options.New for the 2025
IRP, small resources (those with a capacity of fewer than 20 megawatts) are eligible to be sited
within any of the load regions and unconstrained by new transmission requirements, as
PacifiCorp's studies have shown resources that are sufficiently small and sized consistent with the
local grid can be feasible without large transmission investments.Like small resources,PacifiCorp
has added a"local"battery option within each of the load areas which is available for selection at
a higher cost than those co-located with other resources (per the supply side table).
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These interconnection and transmission upgrade options are limited and can be expensive.
Replacing existing thermal generators with resources that provide only a portion of their
interconnection capacity in "firm" capacity creates a need for additional interconnection capacity
elsewhere, and a key strategy is maximizing the "firmness" of each MW of interconnection
capacity to provide greater value. For this reason, the modeling of replacement and expansion
resources is not limited by the nameplate of resources being added, but rather to by an hourly
maximum generation constraint.As such,the model is able to select any combination of resources
leading to a smoothing of hourly capacity among various renewable or peaking/firm resources.
Within a transmission constraint, batteries are assumed to always be co-located with other
resources, enabling them to shift energy accumulated during periods of high solar radiance, wind
speed or other generation, and increase the effective capacity contribution of the combination of
resources in a given location.
Portfolio Cost
The second run of the ST model produces an optimized dispatch of each portfolio to reflect least-
cost operations while meeting all requirements and adhering to modeled constraints. The ST
model's hourly granularity means that this system cost will be highly accurate,taking into account
operational nuances that are obscured in the less granular LT model. This in turn means that when
evaluating the constellation of all competitive portfolios, the comparison will be based on
appropriate relationships among all system components to yield an accurate PVRR.
Additional Measures
• Annual and energy not served (ENS)
• Annual CO2 emissions.
Stochastic Modeling
Once unique resource portfolios are developed using the LT and ST models, additional modeling
is performed to produce metrics that support comparative cost and risk analysis among the
different resource portfolio alternatives. For the 2025 IRP, stochastic risk modeling of resource
portfolio alternatives is performed with the ST model.
The standard ST model inputs reflect a normalized view of future conditions that reflects the
typical range of outcomes. For stochastic modeling in the 2025 IRP, alternative inputs are used
that reflect conditions analogous to actual results in a specific historical. Stochastic inputs for the
2025 IRP have been expanded and now include wind and solar generation profiles, along with the
energy efficiency profiles for weather-sensitive bundles, in addition to the variables reflected in
past IRPs: load, wholesale electricity and natural gas prices, hydro generation, and thermal unit
outages.
Volume II, Appendix H (Stochastics) discusses the methodology for developing the stochastic
inputs for the 2025 IRP.
Note—PacifiCorp is working to complete the stochastic analysis described above, and will
include it in the final published IRP.
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Monte Carlo Simulation
For the 2025 IRP, PacifiCorp has data reflecting eighteen discrete annual conditions, specifically
the historical data and variances from 2006-2023 for each of the stochastic inputs. By running
eighteen ST model scenarios covering each of these conditions, results can encompass the full
range of conditions. However, each of these ST model scenarios represents conditions from a
single year repeating in every year of the study horizon, with slight differences from year to year
to account for days of the week,plus load growth, climate change impacts on load and hydro, and
changes in the resource portfolio. For instance, every year from 2025-2045 would be a dry hydro
year(below average). There are benefits to compiling the results in this way, as it will be easier to
identify specific historical weather conditions that are leading to high costs and ENS. But to
produce portfolio performance measures, Monte Carlo sampling of the annual results may be
appropriate,particularly for assessment of multi-year compliance requirements such as renewable
portfolio standards (RPS) and Washington's Clean Energy Transformation Act(CETA).
Stochastic Portfolio Performance Measures
Stochastic simulation results for each unique resource portfolio are summarized, enabling direct
comparison among resource portfolio results during the preferred portfolio selection process. The
cost and risk stochastic measures reported from the Monte Carlo annual draws include:
• Stochastic mean PVRR
• Upper-tail Mean PVRR
• 5th,90th and 95th percentile PVRR
• Standard deviation
• Risk-adjustment(5% of the 95th percentile)
• Energy Not Served(ENS)
• Environmental Compliance: Washington CETA and Oregon HB 2021
Stochastic Mean PVRR
The stochastic mean PVRR is the average of system net variable operating costs among 20
iterations, combined with the nominal levelized capital costs and fixed costs corresponding to the
LT model for any given resource portfolio. The net variable cost from stochastic simulations,
expressed as a net present value,includes system costs for fuel,variable O&M,long term contracts,
system balancing market purchase expenses and sales revenues,reserve deficiency costs, and ENS
costs applicable when available resources fall short of load obligations. Capital costs for new and
existing resources are calculated on a nominal-levelized basis. Other components in the stochastic
mean PVRR include CO2 emission costs for any scenarios that include a CO2 price assumption.
The stochastic mean PVRR, is not used directly in portfolio selection; instead, the more granular
ST PVRR serves as the base measure of net system cost,modified appropriately by stochastic risk.
Upper-Tail Mean PVRR
The upper-tail mean PVRR is a measure of high-end stochastic cost risk. This measure is derived
by identifying the Monte Carlo iterations with the three highest production costs on a net present
value basis. The portfolio's fixed costs, taken from the LT model, are added to these three
production costs, and the arithmetic average of the resulting PVRRs is computed.
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5th and 951h Percentile PVRR
The 51h and 95th percentile PVRRs are also reported from the 20 Monte Carlo iterations. These
measures capture the extent of upper-tail(high cost)and lower-tail(low cost) stochastic outcomes.
As described above, the 95th percentile PVRR is used to derive the high-end cost risk premium for
the risk-adjusted mean PVRR measure. The 5th percentile PVRR is reported for informational
purposes.
Production Cost Standard Deviation
To capture production cost volatility risk, PacifiCorp uses the standard deviation of the stochastic
production cost from the 20 Monte Carlo iterations. The production cost is expressed as a net
present value of annual costs over the IRP horizon. This measure meets Oregon IRP guidelines to
report a stochastic measure that addresses the variability of costs in addition to a measure
addressing the severity of bad outcomes.
Risk-Adjustment
The model outcomes of the 20 stochastic samples are used to calculate a risk-adjustment measuring
the relative risk of low-probability,high-cost outcomes. This measure is calculated as five percent
of system variable costs from the 95th percentile. This metric expresses a low-probability portfolio
cost outcome as a risk premium based on 20 Monte Carlo simulations for each resource portfolio
and applied to the hourly-granularity deterministic PVRR. The rationale behind the risk-adjusted
PVRR is to have a consolidated cost indicator for portfolio ranking, combining the most precise
available system cost and high-end cost-risk concepts.
Energy Not Served(ENS)
In past IRPs, the use of the reduced granularity in the PLEXOS MT model limited the relevance
of the reported ENS. In the 2025 IRP, the ST model's full 8760 granularity is being reflected in
stochastic analysis,so reported ENS is representative of a portfolio's performance in the real-world
historical conditions that underlie the stochastic inputs.
Environmental Compliance
With the 2025 IRP's shift to stochastics based on calendar year conditions, it is now possible to
evaluate annual compliance requirements under a realistic range of conditions. This has been less
relevant when evaluating annual RPS compliance as the Company's recent IRPs have generally
exceeded compliance requirements by a significant margin, particularly when banking and inter-
year flexibility are taken into account. Because the level of compliance is significantly higher
under Washington's CETA statute and Oregon HB 2021, year-to-year variations in renewable
resources and load may result in shortfalls when conditions are less favorable than normal. Under
CETA, compliance is based on multi-year periods and allows for use of unbundled renewable
energy credits for up to twenty percent of the obligation through 2044, so overall compliance can
be achieved without achieving full compliance in the least favorable years, though it may require
more resources than under normal conditions. Oregon HB 2021 measures compliance within each
calendar year,but allows the Oregon Public Utility Commission to consider the extent that excess
emissions from generation used to meet load is a result of lower than expected generation from
nonemitting resources, so it is unclear what level of compliance certainty is appropriate. The
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
stochastic results will indicate the level of compliance over a range of conditions, and should help
identify the types of resources that can increase compliance during less favorable conditions.
Forward Price Curve Scenarios
Preferred portfolio variants developed during the portfolio-development process are analyzed
under up to five price-policy scenarios.
Other PLEXOS Modeling Methods and Assumptions
Transmission System
The base transmission topology shown in Figure 8.3 is used in each of the PLEXOS models. Any
transmission upgrades selected by LT and ST model processes that provide incremental transfer
capability among bubbles in this topology are part of the portfolio and thus included in normalized
and stochastic ST optimizations.
Resource Adequacy
The reality of modeling large complex power systems in a world of significant variable resources
is that availability must be compared to requirements in all modeled periods, as measurements
only at peak do not adequately establish system reliability. For the 2025 IRP, PRM and resource
contributions based on WRAP are used as part of portfolio selection,but this is not part of resource
dispatch. In addition to WRAP compliance, ST reliability modifications to the portfolio evaluate
hourly resource availability and system requirements to directly determine reliability shortfalls and
any additional resource need at the hourly level.
Energy Sy torage Resources
Storage resources have many potential advantages, including storage for frequency regulation, grid
stabilization, transmission loss reduction, reduced transmission congestion, renewable energy
smoothing, spinning reserve,peak-shaving, load-levelling, transmission and distribution deferral, and
asset utilization.
Each PLEXOS model dispatches storage resources endogenously, subject to any applicable
constraints,for example requirements to charge from onsite solar or for the combined solar and storage
output and reserves to remain within a single interconnection limit. The model can deploy energy
storage for the most cost-effective uses, including any combination of load ramping and leveling,
reserve carrying, and to complement the benefits of renewable resource additions, particularly co-
located renewables.
Other Cost and Risk Considerations
In addition to reviewing the risk-adjustment, ENS, and CO2 emissions data, PacifiCorp considers
other cost and risk metrics in its comparative analysis of resource portfolios. These metrics include
fuel source diversity, and customer rate impacts.
Fuel Source Diversity
PacifiCorp considers relative differences in resource mix among portfolios by comparing the
capacity of new resources in portfolios by resource type, differentiated by fuel source. PacifiCorp
also provides a summary of fuel source diversity differences among top performing portfolios
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based on forecasted generation levels of new resources in the portfolio. Generation share is
reported among thermal resources, renewable resources, storage resources, DSM resources and
market purchases.
Customer Rate Impacts
To derive a rate impact measure, PacifiCorp computes the change in nominal annual revenue
requirement from top performing resource portfolios (with lowest risk adjusted mean PVRRs)
relative to a benchmark portfolio selected during the final preferred portfolio screening process.
Annual revenue requirement for these portfolios is based on the risk adjusted PVRR results from
the models and capital costs on a nominal levelized basis. While this approach provides a
reasonable representation of relative differences in projected total system revenue requirement
among portfolios, it is not a prediction of future revenue requirement for rate-making purposes.
Market Reliance
To assess market reliance risk,PacifiCorp quantifies market purchases for each portfolio allowing
comparisons among cases in Chapter 9 (Modeling and Portfolio Selection Results). Starting in the
2021 IRP, market purchases were restricted compared to past IRPs, as described in Volume I,
Chapter 7 (Resource Options).
Portfolio Selection
Portfolios are measured for relative performance regarding system costs, risk-adjusted system
costs, ENS, CO2 emissions, and compliance with state and federal policies. The risk-adjusted
PVRR accounts for relative risk of volatility among portfolios.
Each portfolio under examination at a given step in the analysis is compared based on cost-risk
metrics, and the least-cost, least-risk portfolio is chosen. Risk metrics examined include stochastic
PVRR, risk-adjusted PURR, ENS and emissions. As noted above, market reliance risk was also
evaluated. The comparisons of outcomes are detailed, ranked, and assessed in the next chapter.
Additional quantitative analysis can be performed to further assess the relative differences among
top-performing portfolios; qualitative analysis can also be considered where appropriate during
portfolio selection on the basis of known factors that could not be readily captured in models.
Final Evaluation and Preferred PortfoliTSelec i
Due to the lengthy nature of the IRP cycle,the final step is the last opportunity to consider whether
top-performing portfolios merit additional study based on observations in the model results across
all studies, additional sensitivities, possible updates driven by recent events, and additional
stakeholder feedback. Additional sensitivities may refine the portfolio selection based on portfolio
optimization and cost and risk analysis steps.
During the final screening process, the results of any further resource portfolio developments will
be ranked by risk-adjusted PVRR, the primary metric used to identify top performing portfolios.
Portfolio rankings are reported for the five price-policy price curve scenarios. Resource portfolios
with the lowest risk-adjusted PVRR receive the highest rank.Final screening also considers system
cost PVRR data from the PLEXOS models and other comparative portfolio analysis.At this stage,
PacifiCorp reviews additional metrics from the models looking to identify if ENS and CO2
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emissions results can be used to differentiate portfolios that might be closely ranked on a risk-
adjusted PVRR basis.
Case definitions specify a combination of planning assumptions used to develop each unique
resource portfolio analyzed in the 2025 IRP, organized here into major development categories:
• Initial Portfolios—including all Variants
o Initial portfolios and variants are evaluated under three distinct sets of jurisdictional
requirements:
■ Utah/Idaho/Wyoming/California
■ Oregon
■ Washington
o Integrated Portfolios incorporates selections from the top performing initial
portfolios under each set of jurisdictional requirements
o The preferred portfolio is selected based on the integrated portfolio results
• Jurisdictional Analysis'9
• Sensitivity Cases
Additional portfolio detail can be found in Volume II, Appendix I (Capacity Expansion Results).
Initial Portfolios
Informed by the public-input process, the initial cases endogenously explore a multitude of
potentially significant interactions among retirement options including the potential to convert coal
units to natural gas operations, install carbon-capture equipment on coal-fired facilities, or retire
units during the study horizon. In addition to the core functionality of selecting the optimal timing,
size, and location of proxy resources, PLEXOS also optimizes existing natural gas and coal
retirements. The modeling continues to include a wide range of transmission options for selection,
assessed simultaneously with all other competing elements. The initial portfolios also consider
how resource selections change with price-policy assumptions that deviate from the medium
natural gas price and zero CO2 price assumptions used to develop many resource portfolios. All
the initial portfolios rely on the combined capabilities of the optimization models within PLEXOS.
Portfolios generated with SCGHG price-policy assumptions are consistent with RCW
19.280.030 in Washington.
Table 8.4 provides the initial portfolio definitions for this IRP. Additional information, including
coal unit retirement assumptions, are provided for each case in Volume II, Appendix I (Capacity
Expansion Results).
i9 Includes informational portfolios that are not eligible for selection as the state-wide preferred portfolio.
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Table 8.4—Price-Policy Case Definitions
Price- Existing Coal(b) Existing Gas(b) Other Existing Proxy Resources(')
Policy Resources
MN Optimized Optimized End of Life All allowed
MR Optimized Optimized End of Life All allowed
LN Optimized Optimized End of Life All allowed
HH Optimized Optimized End of Life All allowed
SC Optimized Optimized End of Life All allowed
(a) Thermal coal and gas resources are endogenously optimized for retirements,conversions and technology installations.
(b) Optimized proxy portfolio selections include renewables, off-shore wind, storage, natural gas, transmission, DSM,
purchases and sales,etc.
All portfolios consider variations in retirement timing, the impact of regional haze compliance
operating limits and options for gas conversion or CCUS retrofit for certain units. The initial
portfolios differ based on planning assumptions around coal unit retirement options and retirement
timing.
Certain additional cases were developed based on stakeholder feedback and state requirements to
evaluate the impacts of specific future scenarios. These cases are all eligible to be adopted into the
preferred portfolio if the analysis warrants their inclusion. In the 2025 IRP,there are the following
variant portfolio selection cases as shown in Table 8.5:
Table 8.5—Portfolio Variants
Variant + •
L Refer to Case
No CCS No coal units are able to select -
CCS technology
No Nuclear No nuclear resources are -
eligible for selection
No Coal 2032 All coal must retire or gas -
convert by January 1, 2032
Offshore Wind Counterfactual to the Preferred -
Portfolio selection
All Coal End of Life Continue 2025 coal technology See the No CCS variant
No New Gas No new gas resources allowed See the Preferred Portfolio
Force All Gas Conversions Force all coal-to-gas options See the No Coal 2032 variant
No Forward Technology No nuclear, hydro storage or See the No Nuclear variant
biodiesel peaking
Each variant case begins with the same PLEXOS dataset inputs and assumptions, and adds the
constraints to either force a selection, disallow a specific resource or resource type, delay a
project or force retirements as outlined below.
No CCS
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
This variant removes the CCS option at Jim Bridger 3 and 4. The endogenous portfolio was
integrated using the same method as the preferred portfolio. The purpose of this variant is to
evaluate how the preferred portfolio would change if CCS is not a commercially viable option.
No Nuclear
This variant removes the NatriumTM demonstration project in 2030 and all other nuclear
resources from available resource options. The endogenous portfolio was integrated using the
same method as the preferred portfolio. The purpose of the variant is to evaluate resource
alternatives in the absence of nuclear resource options.Additionally, this sensitivity seeks to
evaluate the potential risk if nuclear resources are unable to achieve online and operating status
for any reason.
No Coal 2032
In this variant all coal plants are assumed to retire no later than 2032. Coal plants are eligible to
run past 2032 if gas conversion is selected at that plant. No CCUS options are available in this
variant. The endogenous portfolio was integrated using the same method as the preferred
portfolio. The purpose of this variant is to evaluate how the preferred portfolio would change if
external factors required coal plants to cease coal-fired operations by 2032.
Offshore Wind
Offshore wind was available for selection in the preferred portfolio beginning in 2033, based on
the timing of necessary transmission upgrades.As offshore wind has not been endogenously
selected in the preferred portfolio, a minimum of 1000 MW was required to be selected in this
variant.Additionally,the necessary onshore transmission required to enable offshore wind was
available for selection by offshore wind or by any other appropriately located proxy resources to
ensure that co-located resources could be selected to complement the offshore wind and that it is
competitive with other options. This counterfactual is used to assess system impacts and the
magnitude of the costs and benefits associated with offshore wind.
All Coal End of Life
The No CCS run selects coal at all current coal sites and does not choose to retire any
eligible units. Please refer to the No CCS variant for results.
In this variant all coal plants are assumed to run as coal-fired units using the technology present
on the plant as of January 1, 2025, and are not eligible to retire during the study horizon unless
otherwise required to do so. Dave Johnston units 1-3 along with Naughton units 1 and 2 still
retire or cease coal-fired operation as necessary. Minority owned coal plants are also assumed to
retire as necessary. The portfolio is fully endogenous and has gone through the same level of
integration as the preferred portfolio. The purpose of this variant is to evaluate how the preferred
portfolio would change if majority-owned coal resources were allowed to run as coal-fired to
end-of-life.
No New Gas
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
The unconstrained integrated MN case does not select new natural gas resources. Please
refer to the Preferred Portfolio for results.
This variant assumes no new gas resources are allowed to be selected. This does not include the
conversion of coal plants from coal-fired to gas-fired. The purpose of this variant is to evaluate
the cost and risk impacts of replacing new gas resources selected in the preferred portfolio with
other energy resources..
Force All Gas Conversions
The No Coal 2032 selected all plants eligible for gas conversion. Please refer to the No
Coal 2032 variant for results.
In this variant all coal plants eligible for gas conversion are forced to do so. The gas converted
coal plants are allowed to retire endogenously, and the portfolio is re-optimized. The purpose of
this variant is to evaluate the cost and risk impacts associated with gas conversion becoming the
only future option for all coal-fired plants.
No Forward Technology
The No Nuclear study did not select hydrogen storage, biodiesel peaking or nuclear
resources. Please refer to the No Nuclear variant for results.
In this variant all nuclear, hydrogen storage and biodiesel peaking resources are removed from
the preferred portfolio and the portfolio is re-optimized. The purpose of this variant is to evaluate
the cost and risk impacts of limited new resource types becoming available in the future.
Integrated Portfolios
Portfolio integration involves combining resource selections from each of the initial jurisdictional
portfolio results under a given price-policy scenario or variant.Every initial jurisdictional portfolio
evaluates the entire system and all proxy resource options, plus the constraints specific to that
jurisdiction. For proxy resources that can be allocated to any jurisdiction, the integration step
adopts the largest quantity of each individual resource by year that was included in any of the
jurisdictional studies (UT/ID/WY/CA & OR & WA). Because of interconnection limits, it is
generally not possible to sum the selections across the various jurisdictions, and the overall
quantity might not be economic. For resources that are specific to a single jurisdiction, including
demand-side resources and existing thermal resources, the integration step adopts the quantity
from that specific jurisdiction's initial portfolio result.
Resources that are shared among multiple jurisdictions are allocated based on the amounts selected
in their initial jurisdictional portfolio — if a resource was not picked in a jurisdiction's initial
portfolio,that jurisdiction would not be allocated any of that resource. The resource is split among
those jurisdictions in which it was selected, with any quantity selected in multiple jurisdictions,
allocated between them based on their share of system load (the System Generation or SG share
under the 2020 Protocol), or the equivalent including only those jurisdictions for whom that
quantity of a resource was selected. An example is provided below in Table 8.6.
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Table 8.6—Portfolio Integration Resource Example
Next 30 MW
1st 20 MW shared by Last 50 MW
shared by all OR/WA WA only
Approximate Initial Portfolio Allocation Allocation Allocation Total Allocation
Jurisidiction Load Share Selection(MW) Step 1 Step 2 Step 3 (MW)
UT/ID/WY/CA 60% 20 12 n/a n/a 12
Oregon 30% 50 6 22.5 n/a 28.5
Washington 10% 100 2 7.5 50 59.5
Total 100% 20 30 50 100
In this way, resource allocations are fixed based on jurisdictional selections in the year in which
they are built and do not change over time. Where a proxy resource has additions in multiple years,
only the quantity added in a given year is allocated,based on portfolio selections in that year. This
integration process is applied to every initial portfolio.
Allocation among the jurisdictions has the potential to result in compliance shortfalls, as a portion
of the resources that were identified for compliance may be allocated to other jurisdictions. If
shortfalls are identified after running through the ST model, the initial portfolio analysis for that
jurisdiction can be repeated with the shortfall quantity added to the jurisdictional requirement.This
results in the model identifying the next lowest-cost compliance option specific to that jurisdiction.
The resulting portfolio would go through the same integration process described above.
Washington Portfolios
As discussed above —the integrated preferred portfolio reflects is optimized to meet Washington
customer energy and capacity needs, and the Washington Clean Energy Transformation Act
(CETA) clean energy standards from 2030 onwards. The final integrated portfolio presents a
CETA-compliant path towards a greenhouse gas neutral, and ultimately zero-emitting, supply of
electricity for Washington customers, as described in further detail in Appendix O, Clean Energy
Action Plan(CEAP). This CETA-compliant portfolio, as described in the CEAP, serves as a draft
portfolio that will be the basis for the forthcoming 2025 Clean Energy Implementation Plan(CEIP)
expected to be filed with the Washington Commission in October 2025.
The focus of this draft IRP filing is to present, at a minimum, a draft of an integrated preferred
portfolio that meets all state-specific requirements. As described in this chapter and further in
Appendix O, Clean Energy Action Plan,the draft IRP preferred portfolio presents a strategy to get
to a portfolio that is optimized to meet Washington CETA clean energy standards over the next
twenty years. Additional scenarios and sensitivities as required by Washington rule, will be
included in the final IRP filing.
Per WAC 480-100-620(10): the IRP must also include a range of possible future scenarios and
input sensitivities. These include:
• Alternative Lowest Reasonable Cost - WAC 480-100-620(10)(a) instructs utilities to
"describe the alternative lowest reasonable cost and reasonably available portfolio that the
utility would have implemented if not for the requirement to comply"with CETA's Clean
Energy Transformation Standards. This case is comparable to the initial SCGHG price-
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policy scenario study, but includes Washington-specific capacity requirements based on
WRAP. This sensitivity includes the requirement to use the social cost of greenhouse gases
(SC) price-policy assumption in resource acquisition decisions. In Chapter 9 — Modeling
and Portfolio Selection Results, the company will analyze this portfolio in the context of
both CETA and non-CETA compliant outcomes.
• Climate Change - WAC 480-100-620(10)(b) instructs utilities to "incorporate the best
science available to analyze impacts including, but not limited to, changes in snowpack,
streamflow, rainfall, heating and cooling degree days, and load changes resulting from
climate change."Please see Appendix A for additional detail regarding how climate change
is incorporated into the base load forecast. Climate change impacts are also incorporated
in the base hydro forecast. Because the base forecast includes climate change, all of the
IRP analysis reflects impacts related to climate change, so a separate sensitivity to include
these impacts is not necessary.
• Maximum Customer Benefit-WAC 480-100-620(10)(c) instructs utilities to"model the
maximum amount of customer benefits described in RCW 19.405.040(8)prior to balancing
against other goals." The maximum customer benefit scenario focuses on adding
distributed generation, demand response, and energy efficiency in Washington, as well as
avoiding high-voltage transmission upgrades in PacifiCorp's Yakima and Walla Walla
communities to minimize burdens and maximize benefits to Washington customers.
Washington load forecast reflects the high private generation forecast. The portfolio
assumes the social cost of greenhouse gas price-policy scenario and includes all available
Washington energy efficiency and demand response. The study also removes Yakima and
Walla Walla area transmission options and relies on increased small-scale renewables.
Each of these studies is most pertinent to the State of Washington and are further discussed in
Chapter 9 (Modeling and Portfolio Selection Results).
Sensitivity Case Definitions
Note—Sensitivity cases, which are not eligible for selection as the preferred portfolio, are
under development and will be evaluated and included in the March 31, 2025 filing of the
2025 IRP. The list of planned sensitivities is described below.
PacifiCorp identified ten sensitivities outlined in Table 8.7 and discussed further in Volume 1,
Chapter 9.
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Table 8.7—Sensitivi Case Definitions
Sensitivi Definition
High Load Growth Base load forecast replaced by a high load version
Low Load Growth Base load forecast replaced by a low load version
1-20 Peak Load Base load forecast replaced by a high load version using historical 20 year
highest load
High Private Generation Assumes lower load due to high private generation adoption
Low Private Generation Assumes higher load due to low private generation adoption
Large Metered Load Growth Assumes significant large metered customer load growth
Low Cost Renewables Assumes high adoption of IRA/IIJA benefits leads to large cost declines
Low PTC/ITC eligibility Assumes changes to IRA/IIJA leading to shorter PTC/ITC eligibility window
All CCUS Allows CCUS to be selected at any coal site
Jim Bridger Long Term Fuel Adjusts the long term fuel plan at Jim Bridger to assess impacts of change
B2H Delayed to 2030 In the Large Metered Load Growth scenario,B2H is not eligible until 2030
Business as Usual Portfolio if no state requirements existed
Business Plan First 3 years are aligned with the current business plan
High Load Growth
In this sensitivity the base load forecast is replaced with a high load forecast. The preferred
portfolio is re-optimized with this new load forecast to evaluate the cost and risk impacts of higher
loads.
Low Load Growth
In this sensitivity the base load forecast is replaced with a low load forecast.The preferred portfolio
is re-optimized with this new load forecast to evaluate the cost and risk impacts of lower loads.
1 in 20 Peak Load
In this sensitivity the base load forecast is replaced with a high load forecast based on a historical
20-year high load year. The preferred portfolio is re-optimized with this new load forecast to
evaluate the cost and risk impacts of the 20-year high load year.
High Private Generation
In this sensitivity the base load forecast is replaced with a new load forecast incorporating high
private generation which reduces load. The preferred portfolio is re-optimized with this new load
forecast to evaluate the cost and risk impacts of a future with high private generation.
Low Private Generation
In this sensitivity the base load forecast is replaced with a new load forecast incorporating low
private generation which increases load. The preferred portfolio is re-optimized with this new load
forecast to evaluate the cost and risk impacts of a future with low private generation.
Large-Metered Load Growth -All State Compliant
In this sensitivity the base load forecast is replaced with a new load forecast incorporating high
large-metered load growth. The preferred portfolio is re-optimized with this new load forecast to
evaluate the cost and risk impacts of future high large-metered load growth. This portfolio has
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gone through the same integration process to fill any state compliance shortfalls as the preferred
portfolio.
Force Small Scale Resources
In this sensitivity small-scale resources are forced into the preferred portfolio in place of utility
scale resources. While the number of small-scale resources is forced into the portfolio, the type,
timing, and location of these small-scale resources is selected endogenously. The portfolio is re-
optimized to evaluate the cost and risk impacts of small-scale resources.
No Small-Scale Resources
In this sensitivity small-scale resources are removed from the preferred portfolio and replaced
with utility scale resources. The amount of utility scale resources forced into the portfolio is the
same as the amount of small scale removed, but the type, timing and location of these utility
scale resources is selected endogenously. The portfolio is re-optimized to evaluate the cost and
risk impacts of replacing small scale resources with utility scale resources.
Low Cost Renewables
This sensitivity assumes high IRA/IIJA adoption results in significant cost reductions for
PTC/ITC eligible resources. which replace non-PTC/ITC eligible resources. The portfolio is
fully endogenous and has gone through the same level of integration as the preferred portfolio.
The purpose of this sensitivity is to show how greater than anticipated IRA/IIJA eligible resource
availability might impact cost and risk.
Low PTC and ITC Eligibility
This sensitivity assumes IRA/IIJA changes result in PTC and ITC eligibility ending in 2030.
Resources coming online after 2030 do not have the cost reductions associated with PTC and
ITC. The portfolio is fully endogenous and has gone through the same level of integration as the
preferred portfolio. The purpose of this sensitivity is to show how lower than anticipated
IRA/IIJA eligible resource availability might impact cost and risk.
All CCUS
This sensitivity allows all CCUS to be selected at appropriate coal sites, assuming that it is
feasible to complete installation across the entirety of the eligible majority-owned coal fleet prior
to 2032. The portfolio is fully endogenous and has gone through the same level of integration as
the preferred portfolio. The purpose of this variant is to evaluate how the preferred portfolio
would change if CCUS is a commercially viable option at more than one coal site before 2032.
Jim Bridger Long Term Fuel Plan Adjustment
This sensitivity uses a different long term fuel plan for the Jim Bridger plant compared to the
base assumption. The purpose of this variant is to show how a different long term fuel plan for
Jim Bridger impacts costs and risks in the preferred portfolio while maintaining reliability.
B2H Delayed 2030
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In this sensitivity, where B2H may be economic to support significant growth in large-metered
load, the transmission segments associated with the Boardman-to-Hemingway project are
delayed from 2027 until 2030.All incremental lines dependent on these lines are also delayed
three years. The portfolio is then re-optimized to determine a portfolio necessary to maintain
reliability. The purpose of this sensitivity is to evaluate the cost and risk impacts associated with
the Boardman-to-Hemingway line becoming available to support growth in large-metered load
later than anticipated.
Business As Usual20 (No Pending Legislation or State Requirements; Locked Coal
Assumptions)
In this sensitivity, all pending legislation and state requirements are removed so that the only
obligations to be met are load and federal policy obligations. Coal outcomes are also locked to
assumptions in the 2017 IRP Update except to the extent that updated commitments or
requirements supersede the older assumptions. The portfolio is otherwise fully endogenous and
has gone through the same level of integration as the preferred portfolio. The purpose of this
variant is to evaluate how the preferred portfolio would change if no potential state requirements
or early economic retirements were considered.
Business Plan Sensitivity
In the 2025 IRP, this case is aligned with the integrated preferred portfolio due to the base
assumptions being aligned. For this reason,no additional sensitivity is needed. The case complies
with the Utah requirement to perform a business plan sensitivity consistent with the commission's
order in Docket No. 15-035-04. Over the first three years, resources align with those assumed in
PacifiCorp's current Business Plan.Beyond the first three years of the study period,unit retirement
assumptions are aligned with those identified in the preferred portfolio. All other resource
selections are optimized using the Plexos models.
20 Per the Wyoming Public Service Commission's(WPSC)2019 Investigation Order(DOCKET NO.90000-144-
XI-19,and DOCKET NO.90000-147-XI-19),"reference case"is the formal terminology for the business-as-usual
study.Regarding this study,the WPSC mandates the following:
"In the anticipated 2021 IRP,and in IRPs and updates thereto filed by the Company
thereafter,Rocky Mountain Power shall:
a)Include a Reference Case based on the 2017 IRP Updated Preferred
Portfolio,incorporating updated assumptions,such as load and market prices and any
known changes to system resources and only incorporate environmental investments or
costs required by current law"
This case was the subject of stakeholder feedback and discussion in the 2025 IRP public input meeting series. See
Appendix M,stakeholder feedback form#35 (Wyoming Energy Authority).
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CHAPTER 9 - MODELING AND PORTFOLIO
SELECTION RESULTS
CHAPTER HIGHLIGHTS
• Using cost and risk metrics to evaluate a wide range of resource portfolios,PacifiCorp selected
a preferred portfolio that builds on its vision to deliver energy affordably, reliably, and
responsibly.
• PacifiCorp's selection of the 2025 IRP preferred portfolio is supported by comprehensive data
analysis and an extensive public-input process. The preferred portfolio continues to include
continued operation of most of its existing fleet, plus substantial new renewables, facilitated
by incremental transmission investments, along with demand-side management (DSM)
resources, storage resources, and advanced nuclear.
• The 2025 IRP preferred portfolio includes resources which have been contracted since the
2023 IRP, including 520 megawatts (MW) of new storage resources. The 2025 IRP preferred
portfolio includes near-term proxy resource selections that align with recent transmission
cluster studies, and it is expected that a forthcoming RFP as outlined in the action plan will
soon be soliciting and evaluating resources to fulfill these needs.
• The 2025 IRP preferred portfolio also includes the 500 MW advanced nuclear Natrium'
demonstration project, anticipated to achieve online status by summer 2030. Over the planning
horizon, the 2025 IRP preferred portfolio includes 6,379 MW of new wind, 2,308 MW of
which is small-scale, and 5,492 MW of new solar.
• To facilitate the delivery of new renewable energy resources to PacifiCorp customers across
the West,the preferred portfolio includes additional transmission investment. Specifically,the
portfolio includes multiple upgrades increasing connection from Utah South into the Wasatch
Front area, a new 230 kV line from the Willamette Valley to Central Oregon, and Gateway
South 2, a new 500 kV line from the Aeolus substation in Wyoming to the Clover substation
in Utah.
• Driven in part by the need for low-cost firm capacity, existing coal-fired facilities generally
continue to operate through the end of the planning period. Majority-owned coal units which
are required to cease coal-fired operation are converted to natural gas where the option is
available.
• In the 2025 IRP, four factors drive a reduction in CO2 emissions after 2025. These factors are:
retirements (minority-owned units and Dave Johnston 3), additional natural gas conversions
(Naughton 1 and 2 and Dave Johnston I and 2), reduced capacity factors at existing coal and
natural gas facilities, and installation of carbon capture and sequestration (CCS) technology
(Jim Bridger 3 and 4). In combination these factors result in 2030 emissions that are less than
half of the 2025 level. After 2030, changes in capacity factors are the primary driver, with
capacity factors falling initially as a result of renewable resource additions, but rising back to
the 2030 level by the end of the horizon in response to growing loads and the expiration of
existing contracted resources.
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Introduction
This chapter reports modeling and portfolio selection results for the resource portfolios developed
with a broad range of input assumptions informed by the PLEXOS modeling. Using model data
from the portfolio-development process and subsequent cost and risk analysis of unique portfolio
alternatives, the following discussion describes PacifiCorp's preferred portfolio selection process
and presents the 2025 IRP preferred portfolio.
This chapter is organized around the portfolio development, modeling and evaluation steps
identified in the previous chapter and covers the portfolio, cost and risk analysis for the variant
portfolios, including selection of the preferred portfolio. The final preferred portfolio selection is
informed by all relevant modeling results. This chapter also presents modeling results for
additional scenarios supporting Washington's Clean Energy Transformation Act (CETA)I and
discussion of Oregon's compliance position in the preferred portfolio.
Results of resource portfolio cost and risk analysis from each step are presented in the following
discussion of PacifiCorp's portfolio evaluation processes. Stochastic modeling results are also
summarized in Volume II, Appendix J (Stochastic Simulation Results).
Initial Portfolio Development
As discussed in Volume 1, Chapter 8 the portfolio development process in the 2025 IRP is an
iterative process where each case, both by jurisdiction and variant, is looped through multiple
phases of LT and ST modeling, leveraging results from a prior phase to inform the next phase.
Once sufficient phases are complete, an initial study with high reliability and low costs over the
study horizon is selected from each jurisdiction's results for integration. Table 9.1 below shows
the various phases of the Utah, Idaho, Wyoming and California (UIWC) MN fully initial
jurisdictional run to demonstrate a snapshot of how iterative jurisdictional portfolios were
evaluated and selected for integration. Given the initial views of these runs, and subsequent
integrating, the present-value revenue requirement (PVRR) and unserved energy stream over 21
years were the key factors determining which phase is selected for integration. In Table 9.1,phase
5 was selected as the UIWC initial portfolio for inclusion in the MN integrated portfolio. This
selection takes into consideration the PVRR of$21,842 million,and the stream of unserved energy
costs that led to a total cost of$1 million which had no unserved energy after 2027.No other phase
had both a lower PVRR and a lower unserved energy cost. Other phases which were considered
were phase 1, phase 3 and phase 9, however the higher PVRR of phases 3 and 9, and the fact that
phase 1 had small amounts of unserved energy through the 21-year study horizon led to phase 5
being selected.
'Volume II,Appendix O provides additional detail relevant to Washington requirements.
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Table 9.1 —Iterative phases of Utah, Idaho, Wyoming and California MN portfolio
Phase Jurisdiction Price-Policy 21 Year PVRR Unserved Energy Cost
0 UIWC Medium Gas, No CO2 20,628 14
1 UIWC Medium Gas, No CO2 21,587 1
2 UIWC Medium Gas, No CO2 21,212 10
3 UIWC Medium Gas, No CO2 21,848 1
4 UIWC Medium Gas, No CO2 22,036 22
5 UIWC Medium Gas, No CO2 21,842 1
6 UIWC Medium Gas, No CO2 20,942 29
7 UIWC Medium Gas, No CO2 21,999 1
8 UIWC Medium Gas, No CO2 21,128 30
9 UIWC Medium Gas, No CO2 21,932 1
10 UIWC Medium Gas, No CO2 21,145 25
11 UIWC Medium Gas, No CO2 22,143 1
12 UIWC Medium Gas, No CO2 21,157 19
13 UIWC Medium Gas, No CO2 22,216 1
14 UIWC Medium Gas, No CO2 20,526 18
15 UIWC Medium Gas, No CO2 22,503 3
The fully integrated portfolios and variants differ based on retirement timing,the impact of federal
CO2 policy, requested or required resource availability variations, and options for gas conversion
or CCS retrofit for certain units. The portfolios also differ based on natural gas and proxy CO2
policy assumptions, resulting in uniquely optimized combinations of resources, transmission and
thermal retirement options.
As discussed in Volume 1, Chapter 8 (Modeling and Portfolio Evaluation Approach), each variant
portfolio went through the iterative process.
Final selection of the top-performing portfolio and preferred portfolio selection also include an
assessment of compliance with CETA and Oregon's HB 2021.
Table 9.2 through Table 9.4 present each jurisdiction's share of total portfolio resources as
developed from the initial portfolios, prior to integration. For more information about how
jurisdictional portfolios are determined,refer to Chapter 8.
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Jurisdictional Shares Prior to Integration
Table 9.2 —Oregon Initial Share
OR Shares by Resource Type and Year,Installed MW
Installed Capacity(MW)
Resource 2025 2026 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 2045 Total
Expansion Options
DSM-Energy Efficiency 55 79 81 84 87 93 94 94 93 93 83 89 89 87 90 91 101 169 160 151 1,966
DSM-Demand Response 24 7 38 6 60 7 4 2 3 1 - 53 51 3 21 30 $234
3 37 7 361
Nuclear 130 130
Renewable-Utility Wind 83 - 83
Renewable-Small Scale Wind - 380 505 4 85 0 246 4 37 5 - 1,267
Renewable-Utility Solar 109 165 848 102 579 45 4 1,888 1 3,741
Renewable-Battery 132 940 7 10 2 3 1 1 2 2 3 7 1 1 1 1,346
Renewable-Battery(Long Duration) 1 26F2 590 166 11 93 44 17 - 1 1 35 1 53 1001 140 1981 139 44 1,720
Table 9.3 — Washington Initial Share
Installed Capacity(MW)
Resource 2025 2026 2027 2028 2029 1 2030 2031 2032 2033 2034 2035 2036 1 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Eq)ansion Options
DSM-Energy Efficiency - 14 13 14 15 15 16 16 16 15 15 13 12 10 9 8 7 7 7 6 4 233
DSM-Demand Response 15 4 8 1 - 6 1 - 1 0 - 0 11 1 12 1 1 1 3 1 67
Nuclear - 32 - - - - - - - - - - - - - - 32
Renewable-Utility Wind 594 0 3 1,988 2,585
Renewable-Small Scale Wind - 5 5
Renewable-Utility Solar 136 17 794 0 4 0 237 1,189
Renewable-Battery - 37 354 6 400 93 173 247 4 78 1 95 58 1921 274 9 2,020
Renewable-Battery(Long Duration) 1 1 1 4 71 8 12 1 5 1 - 311 6 - 83
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Table 9.4-Utah, Idaho,Wyoming and California Initial Share
UIWC Shares by Resource Type and Year,Installed MW
Installed Capacity(NM)
Resource 2025 2026 2027 2028 2029 2030 2031 2032 1 2033 1 2034 2035 2036 2037 2038 1 2039 2040 2041 2042 2043 2044 1 2045 Total
Expansion Options
DSM-Energy Efficiency 50 57 145 167 172 182 233 219 197 174 157 159 149 134 123 109 102 123 107 103 84 2,947
DSM-Demand Response 14 1 1 98 26 21 - 31 - 42 23 12 13 13 38 18 16 30 68 22 135 622
Nuclear - - 338 338
Renewable-Utility Wind - 403 211 - 451 338 1,403
Renewable-Small Scale Wind - 236 802 1,039
Renewable-Utility Solar - 226 0 333 3 - - - - 563
Renewable-Battery - 352 2 103 30 14 224 2 - 11 4 4 - 4 197 63 4 4 1,018
Renewable-Battery(Long Duration) 65 44 46 285 405 200 180 - 35 187 35 1,481
Full Jurisdictional Portfolios
The following portfolios shown in Table 9.5 through Table 9.7 report the entirety of portfolio selections made when planning for the entire
system, not just the jurisdictional share, according to each jurisdiction's constraints.
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Table 9.5—Oregon Full Jurisdictional Portfolio
Summary �ortFolio Capacity by Aesource r type and Year,Installed MW
Installed Capacity,MW
esource 1 2025 1 2026 1 2027 1 2028 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 1 2036 2037 1 2038 1 2039 2040 2041 2042 2043 2044 2045 Total
xpansion Options
Gas-CCCT - - - - - - - - - - - - - - - - - - -
Gas-Peaking
Nuclear 500 500
Renewable Pealing -
DSM-Energy Efficiency 89 89 233 253 261 275 325 322 302 277 260 248 250 233 219 208 201 232 283 269 235 5,064
DSM-Demand Response 18 25 7 38 86 60 7 4 2 3 1 - 255 85 47 46 46 27 79 61 43 940
Renewable-Wind 222 166 - 594 - - - - 3 - 31 256 - - - - - - - 1,272
Renewable-Small Scale Wind - - 380 505 4 85 246 4 37 9 1,270
Renewable-Utility Solar 109 165 - 848 102 807 45 4 2 2,221 4 4,307
Renewable-Small Scale Solar -
Renewable-Geothermal
Renewable-Battery 520 1,091 10 1 19 5 3 25 3 4 146 6 7 16 504 67 6 6 2,438
Renewable-Battery(Long Duration) - 1 26 62 655 166 22 93 88 67 130 174 634 381 97 277 332 80 3,285
Other Renewable
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal (357) - (205) (700) (1,262)
Coal-CCS - - 526 526
Coal-Gas Conversions - 357 - - 205 - - - - - - - - - - - - - - - - 562
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (32) - 1 (35)
Retire-Wind - - - - - - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - - - - - - - - - - -
Expire-Wind PPA (64) (99) (200) (333) - (696)
Expire-Solar PPA - (2) - (9) (100) (65) (230) (407)
Expire-QF - - - - (47) (3) (50)
Expire-Other (20) (20)
-#� - - - - �7
Total 107 487 1 1,663 403 666 3,035 1 400 1,243 467 372 337 2,715 444 855 1 455 1 895 1 246 860 659 435 344
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Table 9.6—Washington Full Jurisdictional Portfolio
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 2028 2029 1 2030 2031 1 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 2044 2045 Total
Expansion Options
Gas-CCCT - - - - 221 - - - - - - - - - - - 179 - - - - 400
Gas-Pealdng - - - - - - - - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Pealdng
DSM-Energy Efficiency 89 89 214 236 243 252 326 322 300 283 265 258 260 243 229 217 210 230 285 271 236 5,058
DSM-Demand Response 18 17 4 8 37 - 185 35 - 54 57 - 26 44 42 52 24 45 30 78 40 796
Renewable-Wind 1,008 - 594 - 17 - 3 1,990 130 - - - - - - - - 3,742
Renewable-Small Scale Wind 121 157 - 194 660 1 1,132
Renewable-Utility Solar 136 17 794 630 4 1 406 - - 237 - - 2,225
Renewable-Small Scale Solar
Renewable-Geothermal
Renewable-Battery 520 490 6 5 747 296 196 269 28 471 177 152 347 285 15 4,004
Renewable-Battery(Long Duration) 25 - 132 121 139 224 92 395 107 108 1,343
Other Renewable
Storage-Other
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386)
Coal Plant Retirements - (220) - (220)
Coal Plant Ceases as Coal (357) - (205) (1,030) (1,592)
Coal-CCS - - 526 526
Coal-Gas Conversions 357 205 330 892
Gas Plant Retirements - - -
Retire-Hydro -
Refire-Non-Thermal (3) (32) (35)
Retire-Wind - -
Refire-Solar -
Expire-Wind PPA (64) (99) (200) (333) - (696)
Expire-Solar PPA - (2) - (9) (100) (65) (230) (407)
Expire-QE (47) (3) (50)
Expire-Other - - (20) (20)
Total 107 1 479 1 1,852 1 12 1 972 1 3311 1,1011 1,776 1 304 1 6311 653 1 2,248 1 316 1 1,051 1 559 1 1,121 1 5211 822 1 722 1 703 931
216

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.7—Utah, Idaho, Wyoming, California (UIWC) Full Jurisdictional Portfolio
nim Installed Capacity,MW
Resource 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 1 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Expansion Options
Gas-CCCT - - - - - - - - - - - - - - - - - - -
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking -
DSM-Energy Efficiency 89 89 203 247j256 271 331 319 298 273 255 259 250 233 220 208 207 232 283 271 239 5,033
DSM-Demand Response 18 1 - 157 40 33 - 46 - 86 29 27 17 17 47 47 46 33 74 61 144 923
Renewable-Wind 486 211 1,045 - 340 - - - - - - - - - 2,082
Renewable-Small Scale Wind - - - - 143 390 802 1,335
Renewable-Utility Solar 1,675 4 1 670 4 - - - 2,353
Renewable-Small Scale Solar - - - - - - - - - - - - - - - - - - - - - -
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery 520 4 444 355 134 389 232 4 - 11 6 6 - 14 462 65 6 6 2,658
Renewable-Battery(Long Duration) 130 - 100 78 368 383 359 466 312 325 - 51 332 70 2,974
Other Renewable - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-MinorityOwned (82) (33) (123) (148) (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal (357) - (205) (700) (1,262)
Coal-CCS - - 526 526
Coal-Gas Conversions - 357 - - 205 - - - - - - - - - - - - - - - - 562
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - 1 (3) - - - (32)1 - - - - - - (35)
Retire-Wind - - - - - - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - - - - - - - - - - -
Expire-Wind PPA (64) (99) (200) (333) (696)
Expire-Solar PPA - (2) - (9) (100) (65) - (230) (407)
Expire-QE (47) (3) (50)
Expire-Other 1 (20) (20)
Total 107 463 1 207 1,079 1 739 647 1 122 1 3,474 298 692 366 1,664 1 565 1 583 739 567 1 337 1 1,117 1,228 1 437 439
217

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
218

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
ie 0251RPTreferred Portfolio
PacifiCorp's selection of the 2025 IRP preferred portfolio is supported by comprehensive data
analysis and an extensive public-input process, described in the chapters that follow. Figure 9.1
shows that PacifiCorp's 2025 preferred portfolio continues to include substantial new renewables,
facilitated by incremental transmission investments, demand-side management(DSM) resources,
significant storage resources, and advanced nuclear.
The 2025 IRP preferred portfolio is in addition to previously contracted resources, some of which
have not yet achieved commercial operation, including: 1,564 MW of wind, 1,736 MW of solar
additions,and 1,072 MW of battery storage capacity.These resources will come online in the 2024
to 2026 timeframe.
The 2025 IRP preferred portfolio includes the advanced nuclear NatriumTM demonstration project,
anticipated to achieve online status by summer 2030. By the end of 2032, the preferred portfolio
includes 2,801 MW of energy storage resources, including 844 MW of iron-air batteries with one-
hundred-hour storage capability. Advancement of these technologies will be critical to meeting
growing loads and achieving environmental compliance requirements. Over the 21-year planning
horizon,the 2025 IRP preferred portfolio includes 6,379 MW of new wind and 5,492 MW of new
solar.
Figure 9.1 —2025 IRP Preferred Portfolio All Resources
50000
45000
40000
35000
30000
25000
2000 ■■■.
� 15000 .
10000 @ON MINERS memo NNEMEN 0 0
5000
0
ti ti N ti ti ti ti ti ti ti ti ^� ti ry ti ti ti ti ^� ti ti
■Coal ■Converted Gas ■Gas ■Hydrogen Storage Peaker
Renewable Peaking ■QF Hydro vNuclear
■Hydro Storage ■Battery Solar ■Wind
■Geothermal ■Energy Efficiency Demand Response
New since the 2023 IRP,the 2025 IRP preferred portfolio includes a second 416-mile transmission
line, known as Energy Gateway South 2, running from the new Aeolus substation near Medicine
Bow,Wyoming,to the Clover substation near Mona,Utah. This line is scheduled to be operational
by 2036. Additionally, smaller upgrades will enhance transfer capability between southern Utah
and the Wasatch Front, between Walla Walla and Yakima in Washington, and between the
Willamette Valley and Deschutes County in Oregon.
219

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Many of the transmission upgrades and interconnection options modeled for the 2025 IRP reflect
the results of PacifiCorp's "cluster study" process for evaluating proposed resource additions.
Since 2020,PacifiCorp has been evaluating all newly proposed resource additions in an area at the
same time, using a cluster study process that identifies collective solutions that can allow projects
that are ready to move forward to do so in a timely fashion. Table 9.8 summarizes the incremental
transmission projects in the 2025 IRP preferred portfolio.
Table 9.8—Transmission Projects Included in the 2025 IRP Preferred Portfolio 1,2
Build long
Export Import Interconnect Investment Build
2026 Rebuild existing Cameron-Sigurd 138 kV 250 250 250 30 100% Utah South Wasatch Front
2027 Cluster 1 Area 11-Willamette Valley 0 0 199 13 100% n/a n/a
Serial queue-Central Oregon 0 0 152 3 100% n/a n/a
2028 Cluster 2 Area 23-Willamette Valley 0 0 393 2 100% n/a n/a
2030 Cluster 1/2/3-Walla Walla 0 0 628 66 100% n/a n/a
2031 Cluster 1/2/3-Walla Walla 0 0 393 348 100% n/a n/a
Walla Walla-Wine Country 230 kV 400 400 400 145 100% n/a n/a
2032 Cluster 1 Area 14-Summer Lake 400 400 400 120 100% Summer Lake Hemingway
Cluster 2/3-Willamette Valley-Fry-Full Circle 230 kV 450 450 450 413 100% Willamette Valley Central OR
2036 Gateway South 2:Aeolus Clover#2 500 kV 1,500 1,500 1,990 1,810 100% Wyoming East Clover
Huntington-Clover 345 kV 800 800 800 264 100% Utah South Wasatch Front
Spanish Fork-Mercer 345 kV 300 300 1 300 153 1 100% Utah South Wasatch Front
West Cedar-Three Peaks 138 kV 200 200 200 14 100% Utah South Wasatch Front
S.Lebanon-Dixonville 500 kV,Dbl-Ckt Fry-S.Lebanon 230 kV 1,500 1,500 665 1,117 100% Willamette Valley Southern OR
2042 Serial through Cluster 1 Area 13-Southern Oregon 0 0 231 52 100% n/a n/a
Grand Total 5,800 5,800 7A51 4,551
'Export and import values represent total transfer capability(TTC).The scope and cost of transmission upgrades are
planning estimates.Actual scope and costs will vary depending upon the interconnection queue,the transmission
service queue,the specific location of any given generating resource and the type of equipment proposed for any
given generating resource.
2 Transmission upgrades frequently include primarily all-or-nothing components, though the cluster study process
allows for project-specific timing and some costs are project-specific.
New Solar Resources
The 2025 IRP draft preferred portfolio includes 245 MW of new solar by the end of 2027, 1,275
MW by the end of 2030, and more than 5,492 MW by the end of 2045, as shown in Figure 9.2.
Figure 9.2 —2025 IRP Preferred Portfolio New Solar Capacity
9,000 -
8,000
7,000 ______________
------
6,000
5,000
M 4,000
3,000
7 2,000
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP O251RPOR =251RPWA =251RPUIWC ---20231RPUpdate 231RP
New Wind Resources
As shown in Figure 9.3,PacifiCorp's 2025 IRP draft preferred portfolio includes 486 MW of new
wind generation by the end of 2028, 2,175 MW by the end of 2030, and 6,379 MW of cumulative
new wind by the end of 2045.
220

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.3—2025 IRP Preferred Portfolio New Wind Capacity
10,000 --------------
---------------
8,000 t+Ar r a r _~
v
� 6,000
co
75 4,000 ♦'
E
2,000 -
_-------�_-®®
o - -
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
�251RP =251RPOR =251RPWA =251RPUIWC ---20231RPUpdate --231RP
New Storage Resources
New storage resources in the 2025 IRP draft preferred portfolio are summarized in Figure 9.4. The
2025 IRP draft preferred portfolio includes 1,818 MW of new storage resources by the end of
20272 including both 4 and 8-hour lithium-ion storage. By year-end 2030, the 2025 draft IRP
includes 2,716 MW of storage which includes nearly 656 MW of 100-hour iron air storage, and
by year-end 2045, the 2025 IRP draft preferred portfolio includes 7,668 MW of new storage.
Figure 9.4—2025 IRP Preferred Portfolio New Storage Capacity'
10,000
8,000 ————————-- --------- ——————————-—-- -
j 6,000 T
C
=, 4,000 -
s
U 2,000
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP =251RPOR =251RPWA =251RPUIWC ---20231RPUpdate ---23IRP
'The 2023 IRP Update includes 400 MW of PVS battery (Green River solar+storage) in 2026 that has since been
signed and is not included as new storage capacity in the 2025 IRP.
2 The 1,818 MW of new storage resources by the end of 2027 includes 520 MW of signed battery storage contracts
that have been committed since the filing of the 2023 IRP Update.
New Nuclear Resources
The 2025 IRP draft includes new advanced nuclear as part of its least-cost, least-risk preferred
portfolio.As shown in Figure 9.5,the 500 MW advanced nuclear NatriumTm demonstration project
is currently scheduled to come online by summer 2030.
221

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.5 —2025 IRP New Nuclear
1,600
---------------------------
1,400 ♦ -
1,200 -
1,000
800 -
3 600
U 200
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
�251RP =251RPOR =251RPWA C 25IRPUIWC ---20231RPUpdate 231RP
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 therefore results in the selection of 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. Figure 9.6 shows
that PacifiCorp's load forecast before incremental energy efficiency savings has decreased relative
to projected loads used in the 2023 IRP. On average, forecasted system load is down 3.9 percent
and forecasted coincident system peak is down 0.6 percent when compared to the 2023 IRP. Over
the planning horizon, the average annual growth rate, before accounting for incremental energy
efficiency improvements, is 2.03 percent for load and 1.91 percent for peak. Changes to
PacifiCorp's load forecast are driven by lower projected demand from new large customers who
are expected to bring their own resources lowering the commercial forecast.
Figure 9.6 —Load Forecast Comparison between Recent IRPs (Before Incremental Energy
Efficiency Savings)
Forecasted Annual System Load Forecasted Annual System Coincident Peak
(GWh) (km
120,000 18,000
16,000
100,000
14,000
80,000 �c 12,000
60,000 10,000
8,000
40,000 6,000
20,000 4,0002,000
0 0 _
O, QQ N NO 1"� 00 01 O �+ N M V1 10 1"� W O. N M
N N N N N M M M M M M M M M M q N N N N N M M M M M M M M M M
O O O O O O O O O C. O O O C. C. G O GG O O O O O O O O O O O O O O O . .
N N N N N CAN 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
—2025IRP —2023IRP —2025IRP —2023 MP
DSM resources continue to play a key role in PacifiCorp's resource mix. The chart to the left in
Figure 9.7 compares total energy efficiency capacity savings in the 2025 IRP preferred portfolio
222

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
relative to the 2023 IRP preferred portfolio and includes 5,149MW 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 9.7 compares
cumulative demand response program capacity in the 2025 IRP draft preferred portfolio relative
to the 2023 IRP Update preferred portfolio and does not include capacity from existing programs.
The 2025 draft IRP has a cumulative capacity of demand response programs reaching 695 MW by
2040. By year-end 2045, the 2025 IRP draft preferred portfolio has a cumulative capacity of
demand response programs reaching 1,052 MW, a 6.3% decrease from the cumulative capacity of
demand response programs by the end of the planning horizon in the 2023 IRP Update (1,123
MW).
Figure 9.7—2025 IRP Preferred Portfolio Energy Efficiency and Demand Response Capacity
Energy Efficiency Demand Response
6,000 1,500
5,000
4,000 ,- 1,000
3,000
2,000 - - 500 - -
1,000 ■■■�■■ •� ■
0 0
O O O O O O O O O CD O O O O O O O O CD O O O O O O O O O O O O O O O O O O O O O Cl CDN 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 N
—25 IRP =25 IRP OR 25 IRP 025 IRP OR
=25IRPWA 025 IRP UIWC O25 IRP WA O25 IRP UIWC
---2023 IRP Update ---23 IRP ---2023 IRP Update ---23 IRP
1 Energy efficiency and demand response in the 2023 IRP Update began escalating two years prior to when
escalation begins in the 2025 draft IRP preferred portfolio. Cumulative energy efficiency and demand response in
2045 in the 2025 draft IRP preferred portfolio is similar to cumulative energy efficiency and demand response by
2042 in the 2023 IRP Update,the end of the planning horizon.
Wholesale Power Market Prices and Purchases
Figure 9.8 illustrates that the 2025 IRP's base case forecast for natural gas prices has increased
along with an increase in wholesale power prices for most years past 2030 relative to those in the
2023 IRP Update. Prior to 2030, Figure 9.8 reports that the 2025 IRP's base forecast for natural
gas and wholesale power prices are lower than those in the 2023 IRP Update. These forecasts are
based on prices observed in the forward market and on projections from third-party experts.
223

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.8—Comparison of Power Prices and Natural Gas Prices in Recent IRPs
Average of MidC/Palo Verde Flat Power Prices Henry Hub Natural Gas Prices(Nom$/MMBtu)
(Nom$/MWh) $te
5v0
510
$10o
58
% 56
$60 %
54
$40
$2
$20
$0
$O N N N N N M M M M M M M M 3 d
-
N N N N N N N N N N N N N N N N N
N N O O O N N O O O O N N O O S pO eO S pO
N N N N N N N N N N N N N N N f 2025 IRP(Sept 2024)
t 2025 IRP(Sept 2024) —2023IRP(Sep 2022)
—2023 IRP(Sep 2022) 2023 IRP Update(Sep 2023)
2023 IRP Update(Sep 2023
Coal and Gas Retirements/Gas Conversions
Coal resources have been an important resource in PacifiCorp's resource portfolio for many years.
However,there have been material changes in how PacifiCorp has been operating these assets(i.e.,
by lowering operating minimums and optimizing dispatch through the EIM) that has enabled the
company to reduce fuel consumption and associated costs and emissions, and instead buy
increasingly 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. New for the 2025 IRP, coal-
fired units that do not have an enforceable environmental compliance requirement have the option
to continue coal-fired operation through the end of the study horizon. Where natural gas supply is
expected to be reasonably available, an option to convert to natural gas was modeled, and is
required for continued operations at units that are required to cease coal-fired operation. As shown
in Figure 9.9, the 2025 IRP converts 562 MW of coal fueled generation to natural gas fueled, and
exits PacifiCorp's share in 386.2 MW of minority-owned coal, and an additional 220 MW of
majority-owned coal by the end of the study horizon. The balance of the coal units continue to
operate through the end of the study horizon, with 700 MW at Jim Bridger 3 and 4 converting to
carbon capture in 2030.
Figure 9.9—2025 IRP Preferred Portfolio Thermal Resources
9,000
8,000 -
7,000
al 6,000
5,000
4,000
3,000 —
7 2,000
U
1,000
0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
�Coal m Coal-CCUS �Gas-Steam �Gas-CT/CCCT ---2023 1 RP Update ---23 IRP
A summary of the coal unit exits,retirements, and conversions in the 2025 IRP preferred portfolio
and the 2023 IRP Update preferred portfolio is shown in Table 9.9. In addition to these coal unit
224

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
exits,retirements, and conversions,the preferred portfolio continues to operate all existing natural
gas units through the end of the study horizon.2
Table 9.9—2025 IRP Coal Resource Results
Majority--Owned Coal
Unit 2023 IRP Update Retirement Year 2025 IRP Retirement Year
As Selected As Selected
Dave Johnston 1 &?7
2028(Coal ash compliance) Not retired(Gas conversion 2029)
Dave Johnston 3 2027(Clean air compliance) 2027(Clean air compliance)
Dave Johnston 4 2039(Assumed end of life) Not retired
Hunter 1-3 2042(Assumed end of life) Not retired
Huntington 1 &2 2036(Assumed end of life) Not retired
Jim Bridger 1 &2 2037(Gas conversion 2024/Assumed end of life) Not retired(Gas conversion 2024)
Jim Bridger 3 &4 2039(CCS/Assumed end of life) Not retired(CCS)
Naughton 1 &2 2036(Gas conversion 2026/Assumed end of life) Not retired(Gas conversion 2026)
Wyodak 2039(Assmned end of life) Not retired(Coal)
'nority-Owned Coa
2023 IRP Update Retirement Year 2025 IRP Retirement Year
lU�it As Input As Input
Colstrip 3 2025 (Transfer capacity to unit 4) 2025 (Transfer capacity to unit 4)
Colstrip 4 2029(PacifiCorp exit) 2029(PacifiCorp exit)
Craig 1 2025 (Assumed end of life) 2025 (Assumed end of life)
Craig 2 2028(Assumed end of life) 2028(Assumed end of life)
Hayden 1 2028(Assumed end of life) 2028(Assumed end of life)
Hayden 2 2027(Assumed end of life) 2027(Assumed end of life)
Carbon Dioxide Equivalent Emissions
The 2025 IRP preferred portfolio reflects PacifiCorp's on-going efforts to provide cost-effective
clean-energy solutions for our customers and accordingly reflects an overall declining trajectory
of carbon dioxide and other carbon dioxide equivalent emissions resulting in a total (CO2e)
emissions decline. PacifiCorp's emissions have been declining and continue to decline because of
several factors including PacifiCorp's participation in the EIM,which reduces customer costs and
maximizes use of clean energy; on-going transition to clean-energy resources including new
renewable resources, new advanced nuclear resources, storage and transmission advancements;
and Regional Haze compliance that capitalizes on flexibility.
The chart on the left in Figure 9.10 compares projected annual CO2e emissions across the 2025
IRP, 2023 IRP, and 2023 IRP Update preferred portfolios and is inclusive of emissions attributed
to market purchases. The 2025 IRP delivers greater emission reductions between 2025 to 2032
outperforming both the 2023 IRP and 2023 IRP Update, with average annual CO2e emissions
down 8%by 2030 relative to the 2023 IRP.After 2032,emissions are forecasted to rise moderately
above the 2023 IRP due in part to a higher load forecast in the 2025 IRP and the expiration of
2 PacifiCorp's Chehalis and Hermiston natural gas units are subject to Washington and Oregon regulation,
respectively,and a final determination of state allocations,potential operational restrictions and economics continue
to be evaluated.
225

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
existing contracted resources.The difference in emissions from the 2023 IRP also reflects the 2025
IRP's balanced strategy to maintaining low-cost firm capacity by allowing existing coal plants to
operate through the planning period at a reduced capacity. In addition, some coal plants convert to
natural gas or install CCS technology. Through these shifts, the overarching trend points to
continued emissions reductions, supporting long-term decarbonization goals. By the end of the
planning horizon, system CO2e emissions are projected to fall from 22.0 million metric tons in
2025 to 10.6 million tons in 2045—a reduction of 52 percent.
The chart on the right in Figure 9.10 includes historical data, assigns emissions at a rate of 0.428
metric tons CO2 equivalent per MWh 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 CO2
equivalent emissions are down 60 percent in 2025, 80 percent in 2030, and 85 percent in 2040.
226

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.10—2025 IRP Preferred Portfolio CO2 Emissions and PacifiCorp CO2 Equivalent
Emissions Trajectory'
30 IRP CO2e Emissions Comparison
25
a�
O 20
..
ro
0 15
H
10
� 5
0
r" 0
wl' �10 t­ 00 (7) O --i N M W') 1.0 t— 00 ON O -- N M :I, v',
N N N N fV 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
fV fV fV fV fV fV fV fV fV fV fV fV fV fV fV N fV fV fV fV fV
■2025 IRP CO2e 2023 IRP Update CO2e 2023 IRP CO2e
PacifiCorp CO2e Emissions Trajectory
,1 60
N 100%
O 50 ..
U-1 ...••...,,... 80%
0 40
60%
30 c
N
20 40% o
0
10 20%
Iloilo
0 0%
O O O O O O O O O O O O O O O O O O O O
�PacifiCorp Emissions(Million MT) —2005 Base Emission
......%Reduction from 2005 Base
1 PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2022 from owned facilities,specified sources
and unspecified sources. 2023 emissions have yet to be updated for actuals and 2024 emissions were not forecasted in the 2025
IRP. Therefore both 2023 and 2024 reflect the forecast from the 2023 IRP. From 2025 through the end of the 21-year planning
period in 2045,emissions reflect those from the 2025 IRP preferred portfolio with emissions from specified sources reported in
CO2 equivalent.Market purchases are assigned a default emission factor(0.428 metric tons CO2e/MWh)—emissions from sales
are not removed. Beyond 2045, emissions reflect the rolling average emissions of each resource from the 2025 IRP preferred
portfolio through the life of the resource or the end of the contract. The emissions trajectory does not incorporate clean energy
targets set forth in Oregon House Bill 2021 or any other state-specific emissions trajectories.PacifiCorp expects these targets,and
an Oregon-specific emissions trajectory,to be discussed in more detail in its Clean Energy Plan.
227

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Renewable Portfolio Standards
Figure 9.11 shows PacifiCorp's renewable portfolio standard (RPS) compliance forecast for
California, Oregon, and Washington after accounting for unbundled REC purchases and new
renewable resources in the preferred portfolio. While new 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.
Oregon RPS compliance is achieved through 2045 with the addition of new renewable resources.
Washington RPS compliance is also achieved through 2045 with the addition of new renewable
resources. Under PacifiCorp's 2020 Protocol, and the Washington Inter urisdictional Allocation
Methodology, Washington receives a share of renewable resources across PacifiCorp's system;
however, Washington may also benefit from the situs allocation of new renewable resources as
necessary for compliance.
The California RPS compliance position will be met with owned and contracted renewable
resources, as well as unbundled REC purchases throughout the 2025 IRP study period. The
increasing RPS requirement results in an increased need for unbundled REC purchases to meet the
annual and compliance period targets in the long term. The company will rely on a combination
of new renewable resources from the preferred portfolio and unbundled RECs to meet future
shortfalls.
228

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Although not depicted in Figure 9.11, PacifiCorp achieves Utah's 2025 state target of supplying
20 percent of adjusted retail sales with eligible renewable resources through a combination of
existing owned and contracted resources, along with new renewable resources and transmission
included in the 2025 IRP preferred portfolio.
229

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.11 —Annual State RPS Compliance Forecast
800 California RPS
a 600
re
0
oa 400
W 200
c� 0
o�,a �o �ti o°� �^� cQ`'k
ti c4�
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
t Bundled Bank Surrendered ®Year-end Unbundled Bank Balance Year-end Bundled Bank Balance
Shortfall Requirement
Oregon RPS
100,000 —
T 80,000
d
60,000
0
t40,000
WUW
A4 20,000
04 wi
Cb °,yao � °�,ti °,��, � � b � °,�� °,�a �o �N ti ti �ti ti�^ ti ti
� �� cps
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
6,000 Washington RPS
,T 5,000
4,000
0
3,000
U 2,000
1,000
0
. L--11 11 11
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230

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Oregon HB2021 Compliance
In 2021, Oregon adopted House Bill 2021, an energy policy seeking to reduce emissions from
electric generation facilities used to serve customers in the state. HB 2021 sets targets to reduce
emissions associated with Oregon retail sales from a baseline, calculated as the average emissions
reported from years 2010 through 2012,by 80 percent in 2030,90 percent by 2035 and 100 percent
by 2040. For PacifiCorp, this requires the company to reduce baseline emissions of 8.99 million
metric tons (MMT)of carbon dioxide equivalents(CO2e)to 1.79 MMT CO2e by 2030,0.89 MMT
CO2e by 2035, and zero by 2040. The law also increased Oregon's small-scale renewable energy
project purchase requirement from 8 to 10 percent by 2030.
The 2025 IRP preferred portfolio was developed to incorporate resources specifically selected to
meet all state-specific requirements,including Oregon's greenhouse gas emission reduction targets
defined by HB 2021. PacifiCorp also modeled the small-scale renewable portfolio requirement to
ensure that at least 10 percent of Oregon-allocated capacity will be small-scale (20 MW or less),
in each year from 2030 onwards.
Greenhouse gas emissions methodology
PacifiCorp's greenhouse gas accounting framework for HB 2021 compliance,including emissions
forecast and reduction targets, is based on the statute itself and rules and guidance from Oregon
Department of Environmental Quality's (ODEQ)longstanding greenhouse gas reporting program.
ODEQ is responsible for verifying utility emissions forecasts to determine compliance with HB
2021's clean energy targets.3 Consistent with this responsibility, ODEQ developed guidance for
projecting and reporting emissions for HB 2021 purposes that leverages methodologies from the
agency's Greenhouse Gas Reporting Program rules.' This guidance includes proposed emission
factors for utilities to use in emissions forecasts for CEPs.' The agency has not yet provided
PacifiCorp with updated 2025 CEP emission factors, so this draft uses the emission factors
developed by ODEQ for the 2023 CEP. In addition to emissions factors,ODEQ provided guidance
for multi jurisdictional utility reporting, adjustments for netting wholesale sales or non-retail
electricity, accounting for transmission losses, and accounting for electricity purchased from
specified and unspecified sources.' Finally, HB 2021 requires PacifiCorp to exclude emissions
from net metering of customer resources and qualifying facilities under the terms of the Public
Utility Regulatory Policies Act from its determination of compliance with clean energy targets.7
3 ORS §469A.420;Oregon Department of Environmental Quality,"DEQ's Evaluation of Clean Energy Targets:
Overview of DEQ's role in verification and determination of emissions data required by HB 2021"(available at
https://www.oregon og v/deq/jzhgp/Documents/CEPBack rg ggpd.pdf).
4 OAR 340-215-0010 through-0125;Oregon Department of Environmental Quality,"GHG Emissions Accounting
for House Bill 2021 Reporting and projecting emissions from electricity using DEQ methodology"(available at
https://www.oregon.gov/deq/ghgp/Documents/HB2021EFGuidance.pd .
5 Oregon Department of Environmental Quality,"Greenhouse Gas Emission Factors for HB 2021 Electricity Sector
Emission Projections"(available at https://www.oreo�n.gou v/deq/jzhgp/Documents/HB2021-EmissionFactors.xlsx).
'Oregon Department of Environmental Quality,"Multi jurisdictional Utilities:Instructions for reporting greenhouse
gas emissions"(available at https://www.oregon og v/deq/aq/Documents/GHGRP-MutlijurisdictionalPigigcI l.pdf).
'PacifiCorp has updated its methodology for calculating progress toward HB2021 targets since the 2023 CEP.In the
2023 CEP,both emissions and generation from QFs were excluded from the progress calculation. However,upon a
close review of the regulation, it was determined that the statute only requires the exclusion of emissions associated
with QFs.This revised approach has been applied in the 2025 CEP.
231

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Based on emissions factors and methodology framework, the modeling process allows for
endogenous selection of proxy resources and optimized dispatch of resources and market
transactions to determine a resource portfolio that meets HB 2021 obligations for Oregon
customers. The emissions trajectory associated with serving Oregon retail customers is depicted
in Figure 9.12. Resources allocated to Oregon customers exceed annual energy requirements,
and compliance can be achieved through economic specified-source wholesale sales of a portion
of the excess supply, where the purchaser is responsible for the associated emissions.
Figure 9.12—Oregon Allocated Emission Reduction Relative to HB 2021 Target
100% -
W 90%
80% ��•
a 70%
60% .. .. . . .. . . . .• ••.. . . •
a� •
50% .•
O •• •
y
40%
0'~
—%Emissions Reduction Target .... 2023 IRP Preferred Portfolio
2023 IRP Update Preferred Portfolio —2025 IRP Preferred Portfolio w/o Spec. Sales
- — 2025 IRP Preferred Portfolio w/Spec. Sales
Capacity and Energy
Figure 9.13 and Figure 9.14 show how PacifiCorp's system energy and nameplate capacity mix is
projected to change over time. In developing these figures, purchased power is reported in
identifiable resource categories where possible. Energy mix figures are based upon base price
curve assumptions. Renewable capacity and generation reflect categorization by technology type
and not disposition of renewable energy attributes for regulatory compliance requirements.$On an
energy basis, coal generation drops below 20 percent in 2026, falling below 10 percent in 2036,
and remaining below 10 percent through the end of the planning period. On a capacity basis, coal
resources drop to 12 percent. Reduced energy and capacity from coal is offset primarily by
increased energy and capacity from renewable and storage resources, nuclear resources and DSM
resources.
'The projected PacifiCorp 2021 IRP 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
wind,biomass,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 2021 IRP preferred portfolio energy mix includes owned resources and purchases from third parties.
232

PACIFICORP-2025 IRP CHAPTER 1-MODELING AND PORTFOLIO SELECTION RESULTS
Projected 1 Preferred PI 1 o Resources
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PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Detailed Preferred Portfolio
Table 9.10 provides line-item detail of PacifiCorp's 2025 IRP preferred portfolio showing new
resource capacity along with changes in existing resource capacity through the 21-year planning
horizon.
Table 9.11 and Table 9.12 report line-item detail of PacifiCorp's peak load and resource capacity
balance for summer, including preferred portfolio resources, over the 21-year planning horizon.
Table 9.13 and Table 9.14 report line-item detail of PacifiCorp's peak load and resource capacity
balance for winter, including preferred portfolio resources, over the 21-year horizon.
234

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.10—PacifiCorp's 2025 IRP Preferred Portfolio
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 2031 1 2032 1 2033 2034 1 2035 1 2036 2037 1 2038 1 2039 2040 1 2041 1 2042 1 2043 1 2044 1 2045 Total
Expansion Options JML
Gas-CCCT - - - -
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking -
DSM-Energy Efficiency 89 89 238 262 270 285 342 329 308 282 265 255 250 233 220 208 201 232 283 269 239 5,149
DSM-Demand Response 18 40 11 144 33 81 13 36 2 46 24 12 66 76 42 51 46 33 71 63 144 1,052
Renewable-Wind - 486 804 - - 451 - - 3 2,327 - - - - - - - - - 4,071
Renewable-Small Scale Wind - - 380 505 4 85 - 246 4 37 9 - 236 802 2,308
Renewable-Utility Solar 245 182 - 848 896 805 49 5 2,221 4 237 - - 5,492
Renewable-Small Scale Solar -
Renewable-Geothermal -
Renewable-Battery 520 1,297 116 39 - 416 3 317 176 11 253 10 81 105 488 257 279 15 4,383
Renewable-Battery(Long Duration) - 1 26 62 655 166 22 93 88 67 326 466 312 325 - 264 332 80 3,285
Other Renewable - - -
Storage-Other
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal (357) - (205) (700) (1,262)
Coal-CCS
Coal-Gas Conversions 357 205 562
Gas Plant Retirements - -
Retire-Hydro - - - - - - - - - - - - - - I - - - - - - - -
Retire-Non-Thermal (3) (32) (35)
Retire-Wind - - - - - - - - - - - - - - - - - - - - - -
Retire-Solar
Expire-Wind PPA (64) (99) (200) (333) (696)
Expire-Solar PPA - (2) - (9) (100) (65) (230) (407)
Expire-QE (47) (3) (2) (52)
Expire-Other (20) (20)
Total 107 502 1,792 961 1,426 1,966 1 1,212 1 2,144 1 455 1 735 535 5,061 235 1 893 1 747 652 1 516 989 1,630 1 710 456
235

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
236

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.11 -Preferred Portfolio Summer Capacity Load and Resource Balance (2025-2034)
2025 2030 2032
Coal 3,959 3,567 3,567 3,375 3,090 2,926 2,926 2,926 2,926 2,926
Gas 2,984 3,294 3,294 3,295 3,469 3,470 3,470 3,470 3,470 3,470
Hydroelectric 76 76 76 76 76 76 76 76 76 76
Wind 246 224 218 211 205 189 168 162 157 151
Solar 342 499 488 476 464 453 441 429 418 406
Other Renewable 46 45 44 42 41 40 38 37 36 34
Storage 1 939 925 909 894 879 865 849 834 819
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 413 404 395 386 377 368 359 348 334 323
Demand Response 305 300 295 290 286 281 276 271 266 262
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 0 (639) (822) (627) (335) (1,131) (1,021) (595) (628) (494)
Fast listing Resources 8,373 8,709 8,480 8,434 8,567 7,549 7,598 7,975 7,889 7,974
Additional Proxy/Short-Term Purchases 190 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 2 2 2 2 2 2
Wind 0 0 0 85 185 268 263 273 267 263
Solar 0 0 0 0 0 0 0 0 0 0
Storage 0 0 136 160 220 867 1,029 1,049 1,139 1,224
Nuclear 0 0 0 0 0 300 300 300 300 300
Demand Response 0 0 0 73 92 106 106 127 127 157
Fast Planned Resources 190 0 137 319 499 1,543 1,701 1,751 1,836 1,947
Fast Total Resources 8,563 8,710 8,617 8,753 9,065 9,092 9,299 9,726 9,725 9,920
Load 7,734 7,947 7,952 8,230 8,667 8,855 9,050 9,335 9,335 9,284
Distributed Generation (157) (143) (186) (234) (285) (341) (400) (458) (515) (354)
Energy Efficiency (92) (191) (234) (346) (457) (566) (561) (852) (880) (996)
Fast Total obligation 7,485 7,613 7,532 7,651 7,924 7,948 8,089 8,025 7,940 7,934
Fast Reserve Margin 14.4% 14.4% 14.4% 14.4% 14.4% 14.4% 15.0% 21.2% 22.5% 25.0%
Coal 140 133 133 133 133 0 0 0 0 0
Gras 716 716 716 716 716 716 716 716 716 716
Hydroelectric 712 712 712 712 712 712 712 712 712 712
Wind 0 0 0 0 0 0 0 0 0 0
Solar 69 67 65 62 60 58 52 50 48 46
Other Renewable 0 0 0 0 0 0 0 0 0 0
Storage 2 1 1 1 1 1 1 1 1 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 229 224 212 207 198 194 188 178 174 170
Demand Response 60 59 58 58 57 56 55 55 54 53
Transfers 0 639 822 627 335 1,131 1,021 595 628 494
West Existing Resources 1,927 2,551 2,719 2,516 2,212 2,868 2,745 2,307 2,332 2,191
Additional Proxy/Short-Term Purchases 2,145 1,711 568 720 1,079 166 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 64 64 64 112 112 111
Solar 0 0 133 225 218 627 1,031 1,363 1,333 1,285
Storage 0 0 847 920 908 923 912 1,186 1,171 1,369
Nuclear 0 0 0 0 0 0 0 0 0 0
Demand Response 0 6 9 42 44 44 48 49 49 50
West Planned Resources 2,145 1,718 1,559 1,907 2,313 1,825 2,055 2,710 2,665 2,815
West Total Resources 4,072 4,269 4,278 4,423 4,525 4,693 4,799 5,017 4,998 5,006
Load 3,672 3,826 3,938 4,121 4,271 4,482 4,609 4,828 4,946 4,887
Distributed Generation (49) (54) (75) (99) (124) (152) (182) (213) (244) (148)
Energy Efficiency (63) (41) (123) (157) (191) (227) (231) (229) (334) (364)
West Total obligation 3,560 3,731 3,740 3,866 3,955 4,102 4,195 4,386 4,368 4,376
West Reserve Margin 14.4% 14.4% 14.49/6 14.4% 14.49/o 14.4916 14.4% 14.4% 14.4% 14.4%
Total Resources 12,635 12,978 12,895 13,175 13,590 13,785 14,099 14,743 14,723 14,926
Obligation 11,045 11,345 11,272 11,517 11,879 12,050 12,284 12,410 12,308 12,310
Planning Reserves(14.4%) 1,590 1,634 1,623 1,658 1,711 1,735 1,769 1,787 1,772 1,773
Obligation+Reserves 12,635 12,978 12,895 13,175 13,590 13,785 14,053 14,197 14,081 14,082
System Position 0 0 0 0 0 0 45 546 642 844
Reserve Margin 14.4% 14.4% 14.4% 14.4% 14.4% 14.4% 14.8% 18.8% 19.6% 21.3%
237

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.12-Preferred Portfolio Summer Capacity Load and Resource Balance (2036-2045)
2035 2039 2043
Coal 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926
Gas 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470 3,470
Hydroelectric 76 76 76 76 76 76 76 76 76 76 76
Wind 145 140 134 128 122 117 81 77 73 69 65
Solar 395 383 343 332 322 311 300 290 279 246 236
Other Renewable 33 32 30 11 11 10 9 9 8 8 0
Storage 804 788 773 759 744 728 714 699 684 668 654
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 314 302 240 231 223 211 204 196 189 182 176
Demand Response 257 252 247 243 238 233 228 223 218 214 209
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers (469) (310) (491) (366) (567) (653) (663) (627) (708) (607) (765)
Fast Usting Resources 7,950 8,060 7,749 7,811 7,564 7,430 7,346 7,339 7,216 7,252 7,047
Additional Proxy/Short-TerraPureha 0 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0 0
Gas 2 2 3 3 3 3 3 3 3 3 3
Wind 258 641 629 621 609 596 583 601 691 675 658
Solar 0 316 306 297 287 278 268 258 249 239 230
Storage 1,288 1,286 1,284 1,605 2,064 2,371 2,690 2,688 2,947 3,273 3,350
Nuclear 301 301 301 301 301 301 301 301 301 301 302
Demand Response 172 181 189 198 230 241 251 265 294 307 401
Fast Planned Resources 2,022 2,726 2,711 3,024 3,494 3,789 4,095 4,116 4,484 4,799 4,943
Fast Total Resources 9,972 10,786 10,460 10,835 11,058 11,219 11,441 11,454 11,700 12,051 11,990
Load 9,411 9,557 9,767 9,935 10,083 10,201 10,339 10,480 10,664 10,745 10,883
Distributed Generation (385) (415) (445) (474) (503) (529) (557) (584) (609) (635) (660)
Energy Efficiency (1,110) (1,151) (1,024) (1,333) (1,462) (1,515) (1,580) (1,315) (1,562) (1,583) (1,613)
Fast Total obligation 7,916 7,990 8,298 8,129 8,118 8,156 8,202 8,581 8,492 8,528 8,610
Fast Reserve Margin 26.0% 35.0% 26.1% 33.3% 36.2% 37.6% 39.5% 33.5% 37.89/ 41.3% 39.3%
Coal 0 0 0 0 0 0 0 0 0 0 0
as 716 716 716 716 716 716 716 716 716 716 716
Hydroelectric 712 712 712 712 712 712 712 712 712 712 712
Wind 0 0 0 0 0 0 0 0 0 0 0
Solar 45 43 41 39 37 35 13 12 11 11 10
Other Renewable 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 165 160 143 138 133 129 125 121 100 96 94
Demand Response 52 52 51 50 49 49 48 47 46 46 45
Transfers 469 310 491 366 567 653 663 627 708 607 765
West Existing Resources 2,159 1,992 2,153 2,021 2,213 2,293 2,276 2,235 2,293 2,187 2,341
Additional Proxy/Short-TerraPurcha 0 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 0 0 0 0 0 0 0
Wind ill ill 110 110 109 109 109 108 108 107 107
Solar 1,235 1,444 1,382 1,320 1,259 1,197 1,208 1,140 1,074 1,008 942
Storage 1,466 1,444 1,431 1,569 1,551 1,576 1,617 1,881 2,001 2,130 2,102
Nuclear 0 0 0 0 0 0 0 0 0 0 0
Demand Response 50 50 85 107 108 128 138 141 142 170 175
West Planned Resources 2,861 3,048 3,008 3,106 3,027 3,010 3,071 3,270 3,325 3,415 3,327
West Total Resources 5,020 5,040 5,161 5,127 5,240 5,303 5,347 5,505 5,618 5,603 5,668
Load 4,944 5,009 5,082 5,199 5,258 5,330 5,397 5,473 5,660 5,651 5,730
Distributed Generation (163) (177) (192) (206) (221) (234) (249) (263) (277) (290) (304)
Energy Efficiency (394) (426) (378) (502) (457) (461) (475) (399) (473) (463) (471)
West Total obligation 4,388 4,406 4,512 4,481 4,581 4,635 4,674 4,812 4,910 4,897 4,955
West Reserve Margin 14.49/ 14.4% 14.4% 14.49/ 14.4% 14.4% 14.4% 14.49/ 14.49/ 14.49/ 14.4%
Total Resources 14,992 15,826 15,621 15,961 16,299 16,522 16,788 16,959 17,318 17,653 17,658
Obligation 12,304 12,396 12,810 12,610 12,699 12,791 12,876 13,393 13,403 13,425 13,564
Planning Reserves(14A%) 1,772 1,785 1,845 1,816 1,829 1,842 1,854 1,929 1,930 1,933 1,953
Obligation+Reserves 14,076 14,181 14,654 14,426 14,528 14,633 14,730 15,321 15,333 15,358 15,518
System Position 917 1,645 967 1,536 1,771 1,888 2,059 1,638 1,985 2,295 2,141
Reserve Margin 21.8% 27.7% 21.9% 26.6% 28.3% 29.2% 30.4% 26.6% 29.2% 31.5% 30.2%
238

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.13 -Preferred Portfolio Winter Capacity Load and Resource Balance (2025-2034)
2025 2030 2032
Coal 4,147 3,733 3,733 3,498 3,184 3,014 3,014 3,015 3,015 3,015
Gas 3,003 3,334 3,334 3,335 3,526 3,527 3,527 3,527 3,527 3,527
Hydroelectric 33 33 33 33 33 33 33 33 33 33
Wind 2,037 1,929 1,836 1,748 1,616 1,456 1,377 1,300 1,226 1,154
Solar 77 104 101 98 95 92 89 86 83 80
Other Renewable 41 39 38 37 35 34 33 31 30 28
Storage 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 186 181 177 171 167 162 155 150 130 125
Demand Response 139 135 132 129 125 122 119 116 112 109
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (1,600) (1,600) (1,281) (11299) (1,403) (1,600) (1,600) (1,176) (1,225) (1,002)
Fast Existing Resources 8,062 7,890 8,104 7,749 7,379 6,841 6,748 7,083 6,931 7,070
Additional Proxy/Short-Term Purchases 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 2 2 2 2 2 2
Wind 0 0 0 225 484 691 672 688 666 645
Solar 0 0 0 0 0 0 0 0 0 0
Storage 0 0 90 113 173 821 983 1,003 1,093 1,178
Nuclear 0 0 0 0 0 300 300 300 300 300
Demand Response 0 0 0 73 92 106 106 127 127 157
Fast Planned Resources 0 0 90 412 750 1,920 2,063 2,120 2,188 2,283
Fast Total Resources 8,062 7,890 8,194 8,161 8,129 8,760 8,811 9,202 9,119 9,353
Load 5,724 6,099 6,174 6,448 6,759 6,698 6,869 7,153 7,223 7,397
Distributed Generation (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Energy Efficiency (63) (116) (174) (243) (311) (385) (403) (528) (613) (695)
Fast Total obligation 5,659 5,981 5,997 6,201 6,443 6,306 6,459 6,617 6,601 6,693
Fast Reserve Margin 42.5% 31.9% 36.6% 31.6% 26.2% 38.9% 36.4% 39.1% 38.1% 39.7%
Coal 147 147 147 147 147 0 0 0 0 0
Gas 735 735 735 735 735 735 735 735 735 735
Hydroelectric 726 726 726 726 726 726 726 726 726 726
Wind 64 61 59 57 54 52 50 47 45 43
Solar 1 1 1 1 1 1 0 0 0 0
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 68 68 60 60 57 56 56 55 55 55
Demand Response 0 0 0 0 0 0 0 0 0 0
Transfers 1,600 1,600 1,281 1,299 1,403 1,600 1,600 1,176 1,225 1,002
West Existing Resources 3,341 3,339 3,010 3,026 3,124 3,171 3,167 2,740 2,787 2,561
Additional Proxy/Short-Term Purchases 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 64 64 64 112 ill ill
Solar 0 0 34 57 55 158 259 340 331 316
Storage 0 0 1,102 1,197 1,180 1,200 1,182 1,538 1,517 1,770
Nuclear 0 0 0 0 0 0 0 0 0 0
Demand Response 0 6 9 42 44 44 48 49 49 50
West Planned Resources 0 6 1,146 1,297 1,343 1,466 1,553 2,039 2,008 2,248
West Total Resources 3,341 3,345 4,156 4,322 4,467 4,637 4,720 4,778 4,794 4,809
Load 3,711 3,577 3,676 3,859 4,025 4,478 4,541 4,421 4,477 4,526
Distributed Generation (0) (0) (1) (1) (1) (1) (1) (2) (2) (2)
Energy Efficiency (45) (79) (118) (157) (199) (246) (236) (328) (370) (407)
West Total obligation 3,665 3,498 3,558 3,701 3,825 4,230 4,303 4,091 4,105 4,117
West Reserve Margin -8.89/o -4.4% 16.8% 16.8% 16.8% 9.6916 9.7% 16.8% 16.8% 16.8%
Total Resources 11,404 11,235 12,350 12,484 12,596 13,397 13,531 13,980 13,913 14,161
Obligation 9,324 9,479 9,555 9,902 10,268 10,537 10,762 10,708 10,706 10,810
Planning Reserves(16.8%) 1,566 1,593 1,605 1,663 1,725 1,770 1,808 1,799 1,799 1,816
Obligation+Reserves 10,891 11,072 11,160 11,565 11,993 12,307 12,570 12,507 12,505 12,626
System Position 513 163 1,190 919 604 1,091 960 1,474 1,408 1,536
Reserve Margin 22.3% 18.5% 29.3% 26.1% 22.7% 27.2% 25.7% 30.6% 30.0% 31.0%
239

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.14-Preferred Portfolio Winter Capacity Load and Resource Balance (2035-2045)
2035 2039 2043
Coal 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015
Gas 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527
Hydroelectric 33 33 33 33 33 33 33 33 33 33 33
Wind 1,082 1,014 948 883 820 674 621 570 522 474 429
Solar 77 74 71 68 66 63 60 57 46 44 41
Other Renewable 27 26 24 8 8 8 7 6 6 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 121 103 98 95 91 87 83 79 75 72 68
Demand Response 106 103 99 96 93 89 86 83 80 76 73
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers (911) (1,183) (1,390) (789) (927) (938) (950) (1,006) (965) (865) (921)
Fast Usting Resources 7,078 6,712 6,426 6,936 6,725 6558 6,481 6,365 6,339 6,375 6,265
Additional Proxy/Short-TermPurcha 0 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0 0
Gas 2 2 3 3 3 3 3 3 3 3 3
Wind 625 1,530 1,476 1,436 1,383 1,329 1,273 1,286 1,447 1,378 1,311
Solar 0 81 78 75 71 68 65 62 59 55 52
Storage 1,242 1,239 1,234 1,552 2,008 2,312 2,628 2,623 2,880 3,203 3,277
Nuclear 301 301 301 301 301 301 301 301 301 301 302
Demand Response 172 181 189 198 230 241 251 265 294 307 401
Fast Planned Resources 2,342 3,334 3,281 3,564 3,996 4,254 4,521 4,540 4,983 5,247 5,345
Fast Total Resources 9,420 10,046 9,707 10,500 10,721 10,812 11,001 10,905 11,322 11,622 11,610
Load 7,321 7,508 7,595 7,732 7,856 7,991 8,169 8,340 8,450 8,525 8,664
Distributed Generation (11) (11) (12) (13) (13) (14) (14) (14) (15) (15) (16)
Energy Efficiency (580) (891) (834) (824) (879) (926) (1,042) (979) (1,305) (1,268) (1,195)
Fast Total obligation 6,730 6,606 6,749 6,896 6,964 7,052 7,113 7,347 7,131 7,242 7,453
Fast Reserse Margin 40.0% 52.1% 43.8% 52.3% 54.0% 53.3% 54.7% 48.4% 58.89/ 60.5% 55.8%
Coal 0 0 0 0 0 0 0 0 0 0 0
as 735 735 735 735 735 735 735 735 735 735 735
Hydroelectric 726 726 726 726 726 726 726 726 726 726 726
Wind 41 39 36 34 32 30 28 26 24 22 20
Solar 0 0 0 0 0 0 0 0 0 0 0
Other Renewable 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 55 53 53 52 51 51 50 50 49 49 49
Demand Response 0 0 0 0 0 0 0 0 0 0 0
Transfers 911 1,183 1,390 789 927 938 950 1,006 965 865 921
West Existing Resources 2,467 2,736 2,940 2,336 2,471 2,480 2,489 2,542 2,499 2,397 2,451
Additional Proxy/Short-TermPurcha 0 0 0 0 0 0 0 0 0 0 0
Hydrogen Storage Peaker 0 0 0 0 0 0 0 0 0 0 0
Gas 0 0 0 0 0 0 0 0 0 0 0
Wind ill 110 110 109 109 109 108 108 107 107 106
Solar 301 349 331 312 294 276 274 254 235 215 195
Storage 1,893 1,865 1,845 2,021 1,997 2,027 2,076 2,412 2,564 2,722 2,685
Nuclear 0 0 0 0 0 0 0 0 0 0 0
Demand Response 50 50 85 107 108 128 138 141 142 170 175
West Planned Resources 2.355 2,374 2,372 2,549 2,508 2,539 2,596 2,914 3,048 3,213 3,162
West Total Resources 4,822 5,109 5,312 4,886 4,979 5,018 5,085 5,456 5,547 5,610 5,613
Load 4,773 4,920 4,989 4,941 5,062 5,136 5,276 5,289 5,398 5,345 5,467
Distributed Generation (2) (3) (3) (3) (3) (3) (3) (4) (4) (4) (4)
Energy Efficiency (642) (543) (439) (755) (796) (837) (919) (614) (645) (538) (658)
West Total obligation 4,128 4,374 4,548 4,183 4,263 4,297 4,353 4,671 4,749 4,803 4,805
West Reserve Margin 16.89/ 16.8% 16.8% 16.8% 16.8% 16.8% 16.8% 16.89/ 16.89/ 16.8% 16.8%
Total Resources 14,241 15,155 15,018 15,386 15,700 15,830 16,086 16,361 16,869 17,232 17,223
Obligation 10,858 10,980 11,297 11,079 11,227 11,348 11,466 12,018 11,880 12,045 12258
Planning Reserres(16.8%) 1,564 1,581 1,627 1,595 1,617 1,634 1,651 1,731 1,711 1,735 1,765
Obligation+Reserves 12,422 12,561 12,924 12,674 12,943 12,983 13,117 13,749 13,591 13,780 14,023
System Position 1,820 2,594 2,095 2,711 2,857 2,849 2,969 2,612 3,278 3,452 3,200
Reserve Margin 31.2% 38.0% 32.9% 38.9% 39.8% 39.5% 40.3% 36.1% 42.0% 43.1% 40.5%
240

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Integrated Portfolio Resource Comparisons by Technology and Year
Table 9.15 through Table 9.25 report the incremental capacity of each technology type for each integrated portfolio and integrated variant
portfolio. Table 9.26 through Table 9.28 report the capacity of coal generating units that are retired, converted to natural gas fueling, or
augmented with carbon capture technology.
Table 9.15—New Gast
Study Installed Capacity,MW
2025 2026 2 227 2028 2029 2030 2031 2032 2033 2034 1 2035 2036 1 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - - - - - - - - - - - - -
MR Base 489
MN-No Coal Post 2032
MN-No CCS 40
MN-No Nuclear 40
MN-Offshore Wind
IN Base
HH Base
SC Base
I Positive values indicate installed capacity in the first full year of operations
Table 9.16 -Nuclear'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - - 500 - - - - - - - - - - - - - - -
MR Base 500
MN-No Coal Post 2032 500
MN-No CCS 500
MN-No Nuclear
MN-Offshore Wind 500
IN Base 500
HH Base 500
SC Base 500
1 Positive values indicate installed capacity in the first full year of operations
241

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.17—Renewable Peakin 1
Study Cumulative Energy,Gwh
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - - - -
MR Base
MN-No Coal Post 2032
MN-No CCS
MN-No Nuclear
MN-Offshore Wind
IN Base
HH Base
SC Base
'Positive values indicate installed capacity in the first full year of operations
Table 9.18—DSM—Energy Efficient
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base 89 89 238 262 270 285 342 329 308 282 265 255 250 233 220 208 201 232 283 269 239
MR Base 89 89 238 259 266 285 338 329 308 282 265 249 250 239 227 214 210 235 286 271 239
MN-No Coal Post 2032 89 89 238 259 266 281 336 329 303 282 265 248 250 234 220 208 201 232 283 269 240
MN-No CCS 89 89 238 262 270 285 343 329 308 282 270 255 250 234 220 208 202 232 287 272 239
MN-No Nuclear 189
89 238 262 275 289 345 331 308 283 265 252 250 233 227 214 207 235 286 275 239
MN-Offshore Wind 89 238 259 270 285 338 329 308 283 265 252 250 233 219 208 207 232 283 271 236
IN Base 89 237 257 265 280 334 328 307 281 264 254 249 232 218 206 199 225 276 266 227
HH Base 89 244 268 276 291 347 333 312 286 268 268 261 243 229 217 210 235 286 272 240
SC Base 89 244 265 272 286 347 333 310 283 265 258 252 240 227 209 210 1 234 286 271 235
Table 9.19—DSM—Demand Response
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base 18 40 11 144 33 81 13 36 2 46 24 12 66 76 42 51 46 33 71 63 144
MR Base 18 40 11 126 43 76 12 39 2 46 16 12 80 80 42 48 48 34 71 43 62
MN-No Coal Post 2032 18 40 11 141 32 60 47 27 2 46 16 12 66 84 42 48 48 34 71 62 43
MN-No CCS 18 40 11 139 38 81 13 36 2 46 24 12 66 76 45 48 60 68 23 153 53
MN-No Nuclear 18 40 19 126 53 94 23 21 18 39 16 1 136 28 42 77 23 29 72 62 144
MN-Offshore Wind 18 40 23 135 38 49 7 37 18 30 24 1 136 47 42 72 24 28 79 61 43
IN Base 18 40 25 138 53 34 13 36 18 31 16 21 85 76 43 50 46 33 72 118 88
HH Base 18 40 23 134 45 34 13 36 2 50 16 12 105 25 39 104 50 19 81 28 65
SC Base 18 40 13 27 115 21 82 26 2 46 16 1 32 91 94 30 67 27 77 27 40
242

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.20—Utility Scale Wind'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - 486 804 451 - - 3 2,327 - - - - - - -
MR Base 1,417 594 - 451 3 2,954 187
MN-No Coal Post 2032 1,077 594 153 78 350 2 3,132 178
MN-No CCS 439 970 602 - - 273 2,634 -
MN-No Nuclear - 422 834 412 199 1,374 616
MN-Offshore Wind 452 792 200 41 270 864 1,126
IN Base 594 - 3 3,015 -
HH Base 1,187 721 975 233 451 3 2,492 -
SC Base 1,417 - 594 - 451 297 3,236 152
I Positive values indicate installed capacity in the first full year of operations
Table 9.21 —Small Scale Wind'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - 380 505 4 85 - - - 246 4 37 9 - - 236 802 - -
MR Base - 745 - 60 52 300 98 9 9 552 28 414 40
MN-No Coal Post 2032 380 505 4 85 246 4 37 9 - - 176 660
MN-No CCS 380 505 4 85 246 4 37 9 176 660
MN-No Nuclear - 246 7 21 207 111 17 9 105 211
MN-Offshore Wind - 113 79 1
IN Base 500 349 34 26 29 29 29 41 33 9 109 - - - 194 660
HH Base 133 876 89 14 172 76 75 49 - 402 486 120 125 37
SC Base 20 302 616 35 89 1 8 215 32 103 119 875 92 454
'Positive values indicate installed capacity in the first full year of operations
Table 9.22 —Utility Solar'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - 245 182 - 848 896 805 49 5 - 2,221 4 - - - 237 - - - -
MR Base 137 107 505 794 1,081 522 1 - 2,736 2 406 237
MN-No Coal Post 2032 245 182 848 896 805 87 5 480 4,291 4 - 237
MN-No CCS 245 182 848 896 805 567 5 - 4,291 2 237
MN-No Nuclear 290 237 44 181 451 521 2 2,079 2,103 4 -
MN-Offshore Wind 297 101 385 411 634 521 4 405 4 670 393
IN Base 136 317 49 683 985 452 522 300 105 1 4 6 23l
HH Base 419 411 546 2,865 452 4 1 2,648 800 406 237
SC Base 336 500 281 1,156 415 55 1 66 3,363 1,584 564 1 139 1 237 1 793
Positive values indicate installed capacity in the first full year of operations
243

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.23 —Small Scale Solar'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - - - - - - - - - - - - - - -
MR Base 61 110 27
MN-No Coal Post 2032
MN-No CCS
MN-No Nuclear 591 1 26 17
MN-Offshore Wind 731 55 72 3 165 54 8 9 244
IN Base -
HH Base 1,121
SC Base 156
' Positive values indicate installed capacity in the first full year of operations
Table 9.24—Battery Storage'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - 520 1,297 116 - 39 - 416 3 317 176 - 11 253 10 81 105 488 257 279 15
MR Base 520 1,135 26 181 390 108 537 37 197 277 176 341 73 81 79 651 589 639 15
MN-No Coal Post 2032 520 1,297 116 - 19 4 639 12 71 365 56 602 220 422 128 227 242 411 17
MN-No CCS 520 1,297 16 43 19 4 464 14 242 389 438 417 65 488 214 214 355 592 15
MN-No Nuclear 520 734 124 318 879 110 317 15 309 148 314 14 861 174 95 108 43 96
MN-Offshore Wind 520 1,360 328 220 558 140 69 122 118 47 - 127 10 1,067 322 405 313 244 15
IN Base 520 1,235 160 3 - - 401 6 242 546 156 368 245 412 863 211 456 380 851 9
HH Base 520 1,133 66 108 347 141 452 141 12 200 - 74 50 12 193 136 505 399 276 34
SC Base 520 1,011 98 - 708 2 592 91 14 181 - 13 313 307 94 393 41 370 695 139
'Positive values indicate installed capacity in the first full year of operations
Table 9.25—Long Duration Storage 1
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base 1 26 62 655 166 22 93 88 67 - - 326 466 312 325 - 264 332 80
MR Base - - 378 - - - - 60 167 496 261 50 108 71 -
MN-No Coal Post 2032 1 26 62 655 166 22 93 88 67 130 174 634 381 97 277 332 80
MN-No CCS 1 26 62 655 166 22 93 88 67 130 174 634 381 97 277 332 80
MN-No Nuclear 251 109 123 249 97 258 126 36 152 120 277 229 246 160 104 33
MN-Offshore Wind 45 15 79 166 31 339 178 382 675 305 206 274 327 362 122
IN Base 93 2 803 151 66 102 58 58 94 554 89 109 257 345 23
HH Base 243 86 131 1 274 375 106 555 135 346 90
SC Base 197 103 78 1 24 14 399 130 469 373 108 -
'Positive values indicate installed capacity in the first full year of operations
244

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.26-Majority Owned Coal Retirements'
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - 220 - - - - - - - - - - - - - - -
MR Base (220) (268)
MN-No Coal Post 2032 (220) (268)
MN-No CCS (220)
MN-No Nuclear (220)
MN-Offshore Wind 220
IN Base (220)
HH Base (220)
SC Base (220)
I Negative values indicate retirement of coal capacity
Table 9.27-Carbon Capture and Sequestration Selections
udy Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - - - - - 526 - - - - - - - - - - - - - - -
MRBase 526
MN-No tCoal Post 2032
MN-No CCS
MN-No Nuclear 526
MN-Offshore Wind 526
IN Base 526 (264)
HH Base 526
SC Base 526 -
Table 9.28-Coal to Gas Conversion Selections
Study Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
MN Base - 357 - - 205 - - - - - - - - - - - - - - - -
MR Base 357 205 2,397
MN-No Coal Post 2032 357 205 3,097
MN-No CCS 357 205
MN-No Nuclear 357 205
MN-Offshore Wind 357 205
IN Base 357 205 330
HH Base 357 205 330
SC Base 357 205 330 -
245

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
246

PACIFICORP—2023 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Preferred Portfolio Variants
Driven by emergent federal and state law and stakeholder interest, the 2025 IRP features 9
preferred portfolio variants developed to analyze key resource and transmission decisions. The
iterative deterministic process consistently yields portfolios that are reliable once proxy resources
are available for selection. As a consequence, there is no meaningful comparison of unserved
energy between the various portfolios, and cost and risk comparison tables below do not include a
measure of ENS.
Table 9.29—Preferred Portfolio Variant Studies
No CCS No coal units are able to select CCS technology
No Nuclear No nuclear resources are eligible for selection
No Coa12032 All coal must retire or gas convert by January 1 2032
Offshore Wind Counterfactual to the Preferred Portfolio selection
All Coal End of Life Current coal units cannot gas convert OR select CCS
No New Gas Proxy as plants are not eligible for selection
Force All Gas Conversions All coal plants that can gas convert,must
No Forward Technology Nuclear,Hydrogen and Biodiesel units are not eligible
Table 9.30 summarizes the cost and risk results of the variant studies under expected conditions
represented by the MN (medium gas price/no CO2)price-policy scenario.
Table 9.30—Initial and Variant Cases Under Medium Gas/Zero CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2023-2042 Lowest
PVRR Portfolio (Thousand Emission
Case-MN ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base MN 22,930 0 1 220,325 66,013 5
7Inte rated No Coal Post 2032 MN 23,844 914 4 154,979 668 2
Integrated No CCS MN 23,199 269 3 218,003 63,691 4
Integrated Offshore Wind MN 29,231 6,301 6 216,728 62,417 3
Integrated No Nuclear MN 24,295 1,365 5 239,932 85,621
Integrated Base MR 22,985 55 2 154,311 0
LLA
Table 9.31, below, summarizes the cost and risk results of the variant studies under conditions
represented by the LN (low gas price/zero CO2)price-policy scenario.
247

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.31 -Initial and Variant Cases Under Low Gas/Zero CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2023-2042 Lowest
PVRR Portfolio (Thousand Emission
Case-I'MA ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base LN**
Integrated Base MN 20,981 101 2 215,698 38,760 5
Integrated No Coal Post 2032 MN 21,598 718 4 178,027 1,089 2
Integrated No CCS MN 21,470 589 3 204,546 27,608 MENEW 3
Integrated Offshore Wind MN 27,395 6,515 208,244 31,305 4
Integrated No Nuclear MN 22,085 1,205 5 1 235,603 58,664 6
Integrated Base MR 1 20,880 1 0 IS 176,938 0
"The Integrated LN Base case was not able to evaluated in ST prior to publishing the draft. The
comparative data for this table will be provided prior to final publication.
Table 9.32 summarizes the cost and risk results of the variant studies under conditions represented
by the HH (high gas price/high CO2) price-policy scenario. Summarized results include energy
shortfalls and emissions metrics.
Table 9.32 -Initial and Variant Cases Under High Gas/High CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2023-2042 Lowest
PURR Portfolio (Thousand Emission
Case-IM ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base HH 25,554 0 1 121,431 0 1
Integrated Base MN 27,549 1,995 5 141,740 20,308 6
Integrated No Coal Post 2032 MN 27,315 1,760 3 129,468 8,037 2
Integrated No CCS MN 27,351 1,797 4 132,543 11,111 4
Integrated Offshore Wind MN 33,701 8,146 7 140,389 18,957 5
Integrated No Nuclear MN 29,601 4,047 6 147,714 26,283 7
Integrated Base'IR 26,776 1,222 2 1 130.846 9,414 2
248

PACIFICORP—2023 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.33 summarizes the cost and risk results of the variant studies under conditions represented
by the SCGHG (medium gas price/social cost of greenhouse gas) price-policy scenario.
Summarized results include energy shortfalls and emissions metrics.
Table 9.33 —Initial and Variant Cases Under Medium Gas/ Social Cost of CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2023-2042 Lowest
PVRR Portfolio (Thousand Emission
Case-SC ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base SC 29,603 0 61,102 0 1
Integrated Base MN 30,766 1,163 68,506 7,404
Integrated No Coal Post 2032 MN 30,773 1,170 62,173 1,071 3
Integrated No CCS MN 1 30,665 1,062 61,948 847 2
Integrated Offshore Wind MN 36,933 7,330 66,925 5,823 4
Integrated No Nuclear AIN 3_'.606 — 03 71,961 10,859 6
Initial and Variant Cases Under Medium Gas/Federal Regulation (MR)
The only variant cases which would be compliant under the current language in EPA 111(d) are
the MR case and the No Coal Post 2032 case. The Base MR portfolio is $807 million less in PURR
than the No Coal Post 2032 portfolio when dispatched under the MR gas and market pricing
structure. CO2 emissions are 972 tons higher in the Base MR portfolio than the No Coal post 2032
portfolio.
Variant Study Analysis
No CCS Variant
This variant does not allow Jim Bridger 3 and 4 to convert to CCS during the study horizon. The
Jim Bridger units are allowed to either operate as base coal fired with no additional equipment
installed, or to convert to gas in 2030. The analysis explores the potential costs and benefits of
alternatives to CCS at Jim Bridger 3 and 4 if CCS were not to be commercially viable at these
locations.
Figure 9.15 shows the cumulative (at left) and incremental (at right) portfolio changes when coal
is not allowed on the system starting in 2032. A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated. When Jim
Bridger units 3 and 4 do not convert to CCS,they continue to run as coal. Given the lower capacity
factor of coal plants without CCS, additional resources are needed over the course of the horizon
to generate enough energy to meet retail demand. This results in 1,447 MW of additional wind,
2,588 MW of additional solar and 1,420 MW of additional storage as compared to the integrated
MN view.
249

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.15-Increase/(Decrease in Proxy Resources with No CCS
Cumulative Changes Incremental Portfolio Changes
6,000 3,000
2,500
5,000
2,000
4,000 - 3 1,500
b3.000 b 1.000
.ra' 1.000 .ra 0 ��� ■ � -- ■
0 ■�, „1 arm———— (S00) '
���� (1,000)
(1.000) (1"0"
Oryy Oryb O~ O~�OryQ OHO Off`Off~O��Oho-O1h Orb O��CPO CP,�~ Off~O1 e O�h Orb Off^ �`�N G4�GT G4h
N N N N N ti ti ti ti ti '� '� '� '� '� '� '� '� '� ti '� ti '� ti ti h ti ti '� '� '� h '� '� '� '� ti '�
•Coal ■Gas ■QF ■Hydro ■Cc•1 ■Gas ■QF ■Hydro
■Nuclear ■Hydro Storage ■Banery ■Sde ■Nuclear ■Hydro Storage ■Battery ■Solar
•Wind •Geotlrrrrwl ■Energy ERciency ■D—IM Re 7wuse ■Wind .Geothermal ■Eaergy Efrci=y ■Demaud Re parse
•Converted Gas Hydrogen Storage Peaker •Renewable Peaking •Cmveted Gas .Hydrogen Stoage Peaker Renewable Peaking
Figure 9.16 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions,when CCS is removed from the portfolio.The graph on the left shows annual changes
in cost by category and the graph on right shows annual net changes in total costs (the solid black
line)and the cumulative PVRR(d)of changes to net system costs over time(the dashed black line).
When CCS is removed from the portfolio, the resulting portfolio has a $269 million increase in
costs compared to the preferred portfolio.
Despite the significant reduction in capital cost without installing CCS, the loss of the 45Q tax
credits more than overtakes the capital savings over the course of the 21-year study period.
Figure 9.16 - Increase/(Decrease) in System Costs with No CCS
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,000
$l,000
$sou S269
$0 _ $sou
($sou) so
($1,000) — ($sou)
($1,500) ($l,000)
($2,000)
($2,500) ($1,500)
N N N N N a V V V a V 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 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 N N N N N
■Coal&Gas Faced ■Coal&Gas Variable ■Proxy Resornce Costs
■Emissions is Net Market ltansactions is 7)' rnissim —Net Cost/(Beneft) ---Ctnnlative PVRR(d)
No Nuclear Variant
This variant does not allow the NatriumTM demonstration nuclear project to be selected as a
resource option in 2030. Additionally, this variant does not allow any other nuclear to be selected
as a potential replacement of the NatriumTM project. The analysis explores the potential costs and
benefits of replacement resource options should the NatriumTM demonstration or other nuclear
project prove not to be commercially viable..
Figure 9.17 shows the cumulative (at left) and incremental (at right) portfolio changes when
nuclear options are not allowed on the system. A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated. Given the
currently selected nuclear siting at Naughton, overall portfolio changes are somewhat smaller than
250

PACIFICORP—2023 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
in cases where significant coal changes are tested. The variant case selects 40 MW of new gas
peaking resources, an additional 468 MW of energy efficiency, 998 fewer MW of wind which is
offset by 1,293 additional MW of solar. Finally an additional 81 MW of storage is selected.
Figure 9.17 - Increase/(Decrease) in Proxy Resources with No Nuclear
Cumulative Changes Incremental Portfolio Changes
3.000
4,000
2.500
3.000
2.000
z.000 3 1500
1.000 ' 1.000
y v
0 500
(1,000) 1
I (soo)
'loll
1
(3,000) (1"0")
.y5'1 tib '� tib tiQ 'h0 'yam 11111
^IP 'y" 'yl° 'h 11 ,y9 0 . ti yM. pb. h ,�`1 b ry� * q ,yo ,yam 111,11
,yb ,y''1 „Ib „In „14 „IQ o * h M ti
ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo �O ry0 ryo ryo ryo rycp'rycp'rycY'ry5} ry5J ti$ ry0 rylSl ryo ryo h�ry0 ti0 ryo ryo ryo ryo ryo ryo ryo ryo I�CP'ryCY ryCY ryCT ryC1 ryC�
■Coal ■Gas ■QF •Hydro ■Coal ■Gas ■QF ■Hydro
■Nuclear ■Hydro Storage ■Battery •Solar •Nuclear ■Hydro Stmmge ■Battery ■Solar
•Wind •Geothermal •Energy Efficiency •Demand Respo se -Wind -Geothermal •Energy Efficiency ■Demand Rewmase
■Convened Gas a Hydrogen Storage Peaker Renewable Peaking •Converted Gas Hydrogen Stonspe Peeker Renewable Peaking
Figure 9.18 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions, when nuclear projects are removed from the portfolio. The graph on the left shows
annual changes in cost by category and the graph on right shows annual net changes in total costs
(the solid black line) and the cumulative PVRR(d) of changes to net system costs over time (the
dashed black line). When the NatriumTM demonstration project is removed from the portfolio,the
resulting portfolio has a $1.365 billion increase in costs compared to the preferred portfolio.
As seen in Figure 9.18 below,these increases come primarily from significant early proxy resource
additions needed to offset the loss of firm nuclear capacity. Although there is an eventual decrease
in proxy resource costs in the final years of the study horizon, the need for early investment
overcomes these later potential savings.
Fi ure 9.18 - Increase/(Decrease) in System Costs with No Nuclear
Annual Changc in Cost by Line Item Net Differencc In Total System Cost
$600
$2,000 S1=6S
$400 :1.500 —————
__i�lllllll.
$200
$1.000
so _
$500
($200)
($400) so
($600) ($500)
($800) (si,000)
N N 0 N 0 N 0 N 0 rR 0 0 M 0 0 0 0 s 0 0 o rr S 8 3 N O O N N N N N N N N O N 0 0 0 0 0 0 0
0 0 s 3 e 3
N N N N N N N N N N NI N N NI N N N N N N N
•Coal&Gas Fixed •Coen&Gas variable ■Proxy Resotoce Costs
■Emissions ■Net Market Transactions■Tramtaission —Net CoW(Bene6t) ---Ctmidative PN'Md)
No Coal Post 2032 Variant
This variant does not allow coal to be on the system in any form after 2032. This means current
coal facilities must either convert from coal fired to gas fired or retire. In this view, CCS was not
allowed as this would still result in the unit using coal fuel. The analysis explores the potential
costs and benefits of early retirement or conversion of the entirety of the coal fleet. This variant is
251

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
distinct from the medium gas with federal regulation (MR) price policy study in that it does not
allow for CCS while the MR does allow for CCS.
Figure 9.19 shows the cumulative (at left) and incremental (at right) portfolio changes when coal
is not allowed on the system starting in 2032. A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated. Due to the
significant changes to the operating characteristics of more than 3,300 MW of the existing coal
fleet, large portfolio changes occur. The variant case selects new gas peaking resources whereas
the integrated MN view does not. Additionally, more solar and wind is selected in the variant, and
less long duration storage is partially offset by additional 4 hour storage.
Figure 9.19 - Increase/(Decrease in Proxy Resources with No Coal Post 2032
Cumulative Changes Incremental Portfolio Changes
5.000
1o.0o0
4.000
B.000
3.000
6.000
3 2.000
4.000 ��� 1.000
a "111
rs (I.000)
�(z,000)
(z,000)
(4.000) (3,000)
(61000) (4,000) $
ryy .fib,o rho'� hb ti tiq h0 ,�o 41414,11„tom �ryt „ I li`S,1�p e 1P
4 ro �o �o0 0 �o o �� �8 ti$ro$ �cY c4 0 �o �o �o �o ry �o No �o �o �o �o �o �o �o . . . . .
■Coal ■Gas ■QF ■Hydro ■Coal ■Gas ■QF -Hydro
-Nuclear -Hydro Storage -Battery -Solffi ■N-1— ■Hydro Storage ■Battery S.I.■
•Wind -Geothermal -Energy Efficiency -Demand Response ■Wind -Ce hennal -Energy Erficimcy •Demand Req—e
•C­WW Gan Hydrogen Storage Peaker Renewable Peaking -Ca Ic dGas Hydrogen Stmage Peeker Rwweble Peaking
Figure 9.20 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions, when coal is no longer allowed in the portfolio after 2032. The graph on the left
shows annual changes in cost by category and the graph on right shows annual net changes in total
costs (the solid black line) and the cumulative PVRR(d) of changes to net system costs over time
(the dashed black line). When all coal must be retired or gas converted by 2032, the resulting
portfolio has a $914 million increase in costs compared to the preferred portfolio.
As seen in Figure 9.20 below,like in the No CCS case,the loss of 45Q tax credits more than offsets
the reduced capital cost to install CCS. Additionally, this case has higher levels of market
purchases,and additionally has higher proxy resource costs in nearly all years of the study horizon.
Figure 9.20-Increase/(Decrease)in System Costs with No Coal Post 2032
Annual Change in Coat by Line Item Net Difference In Total System Cost
$1,000
$2,000
$500 31,500 $911
( WN''' $500
$500)
i
$O f
($1,000) ✓
($500) f
($1,500) (5000)
(S2,000) (S I,500)
_ tV rO� rrt C001 tOVr O . N m . vi
N N N N N N N N N N N N N N N N N N N N N
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs
■Emissions ■Net Market Transactions mTransutission —Net Cost/(Benefit) ---C1®dativePVRR(d)
252

PACIFICORP—2023 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Force Offshore Wind
Since offshore wind was not selected in any of the integrated MN jurisdictional runs, this variant
serves as a counterfactual forcing this resource into all jurisdictional runs. The analysis explores
the potential costs and benefits of replacing resources selected in various jurisdictional runs with
a higher capacity factor offshore wind resource.
Figure 9.21 shows the cumulative (at left) and incremental (at right) portfolio changes when
offshore wind is forced into the portfolio in 2030. A positive value indicates an increase in
resources and a negative value indicates a decrease when a resource is reduced or eliminated. The
higher capacity factor of the offshore wind resource results in 300 MW less utility scale wind being
selected in the portfolio compared to the preferred portfolio. Additionally, the portfolio has 1,669
MW less utility scale solar. Less small scale wind is offset by more small scale solar. For capacity
and reliability needs, 1,824 more MW of storage is selected in the offshore wind case, 1,603 MW
of which is 4 hour storage. Retirements are the same between the studies.
Figure 9.21 - Increase/(Decrease) in Proxy Resources with Offshore Wind
Cumulative Changes Incremental Portfolio Changes
3,000 _ 2,000
2,000 — 1.000
y(z,000)
� �(z,000)
(3.000)
(4.000)
(3,000)
(5,000) (4*.)
tih tib ti� H� tiw „to h� „tN ,y'h hd' „lh ,stb ,sty „t4 ,tiq o � N 'h h ryh b n 4 q h� ,yam ,yry a,"l ,yb ,yh ,yb ,yn „t4 "Q o � ti h P h
ry � �' rv� ti� ti� ti� ti� ti ti ti ti v� ti� � ti`Y ti`Y rye`,�eP,�e4b,�e4 ti� �ti�ti�ro�ti� ti° ti� ti° ti� ti° ry n° �° no tic4'ti`P ti`A ticY,ycY ticY
■Coal G. ■QF •Hydro ■Cod G. ■QF ■Hydm
■Nudes ■Hydro Storage .Bwn y •Solar ■Nuclear ■Hydro Storage ■Battery ■Seim
•Wind •Gmthe l •Energy Efficimcy -Demand Response •Wind •Geoth-1 ■Energy Effidmcy ■De dRespm.
•C—ve dGas •Hydrogen Storage Peace Rmmable Peabng -Cw ed Gas -Hydrogen Storage Peaker Renewable Peking
Figure 9.22 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions,when offshore wind is forced into the various jurisdictional portfolios. The graph on
the left shows annual changes in cost by category and the graph on right shows annual net changes
in total costs (the solid black line) and the cumulative PVRR(d) of changes to net system costs
over time (the dashed black line). When offshore wind and the required Coos Bay area
transmission upgrades are forced into the portfolio, the resulting portfolio has a $6.301 billion
increase in costs compared to the preferred portfolio.
As seen in Figure 9.22 below, these increases come primarily from higher overall proxy resource
costs, driven by a reduction in production tax credit generating resources. Since the offshore wind
resource receives an investment tax credit the loss of production tax credits on approximately 2,900
MW of renewable resources is significant. The balance of the cost in this portfolio is related to the
significant overall transmission investments required to enable both the offshore wind resource
itself, but also the various transmission upgrades which are required to enable the offshore wind
specific transmission line.
253

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.22 -Increase/(Decrease)in System Costs with Offshore Wind
Annual Change in Cost by Line Item Net Difference In Total System Cost
51,800 56,0I
s1,600 $7,000
$1,400 $6,000
s1,z00 $5,000
$1,000 s4,00
0
$soo
$600 s3,01 '
$400 $2,000
$200 $1,000
$0 — ---
(sz0o) —
($400) ($
1,000)
�y (OV nry 0(V0 Qr� O '+ N Q O n W 01 VOy << VNy Oy VQV Oy.O o0 Q O ti N Q �O op O. O OO N CC OO '�' 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 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 N N N
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs
■Emissions ■Net Market Transactions■Transmission —Net CoW(Benefit) ---Cuandative PVRWd)
Additional Sensitivity Analysis
Note—Sensitivity cases, which are not eligible for selection as the preferred portfolio, are
under development and will be evaluated and included in the March 31, 2025 filing of the
2025 IRP. The list of planned sensitivities is described below.
In addition to the resource portfolios developed and studied as part of the portfolio-development
process that supports selection of the preferred portfolio, sensitivity cases were developed to better
understand how certain modeling assumptions influence the resource mix and timing of future
resource additions. These sensitivity cases are also useful as "bookend" analysis to aid in
understanding how PaciflCorp's resource plan would be affected by changes to uncertain planning
assumptions and to address how alternative resources and planning paradigms affect system costs
and risks.
Table S.l lists additional sensitivity studies to be performed for the 2025 IRP. To isolate the impact
of a given planning assumption, all sensitivity cases will be evaluated with the preferred portfolio.
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PACIFICORP—2023 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table S.1— Summary of Additional Sensitivity Cases
Sensitivity efinitio
High Load Growth Base load forecast replaced by a high load version
Low Load Growth Base load forecast replaced by a low load version
1-20 Peak Load Base load forecast replaced by a high load version using historical 20 year
highest load
High Private Generation Assumes lower load due to high private generation adoption
Low Private Generation Assumes higher load due to low private generation adoption
Large Metered Load Growth Assumes significant large metered customer load growth
Low Cost Renewables Assumes high adoption of IRA/IIJA benefits leads to large cost declines
Low PTC/ITC eligibility Assumes changes to IRA/IIJA leading to shorter PTC/ITC eligibility window
All CCS Allows CCS to be selected at any coal site
Jim Bridger Long Term Fuel Adjusts the long term fuel plan at Jim Bridger to assess impacts of change
B2H Delayed to 2030 In the Large Metered Load Growth scenario,B2H is not eligible until 2030
Business as Usual Portfolio if no state requirements existed
Business Plan9 First 3 years are aligned with the current business plan
Washington Scenariol,
Note—Scenarios required by Washington rule, which are not eligible for selection as the
preferred portfolio, are under development and will be evaluated and included in the March
31, 2025 filing of the 2025 IRP. The list of planned sensitivities is described below.
As described in Chapter 8, in addition to the information provided throughout the 2025 IRP,
Washington's CETA legislation indicates three key studies and sensitivities be analyzed, in
addition to the least-cost, least-risk portfolio developed to meet CETA clean energy standards:10
• Alternative Lowest Reasonable Cost
• Maximum Customer Benefit
WAC 480-100-620(l 1)(a) specifically requires the utility to demonstrate how the long-range
integrated resource plan expects to achieve clean energy transformation standards(WAC 480-100-
610 (1) through (3)), and 0), to incorporate the social cost of greenhouse gas emissions as a cost
adder as specific in RCW 19.280.030(3). The integrated preferred portfolio includes all resource
selections for Washington customers as optimized and determined under the SCGHG price policy
that are necessary to achieve a path to CETA compliance.
Additional discussion on how the preferred portfolio meets the requirements set out by CETA
statute and puts the company on a path towards greenhouse gas neutrality as depicted by the long-
term clean energy interim targets is included in Volume 11, Appendix O — Washington Clean
Energy Action Plan.
9 In the 2025 IRP,the business plan sensitivity is aligned with the integrated preferred portfolio due to the base
assumptions being aligned.For this reason,no additional sensitivity is needed.
io The Washington requirement for a climate change sensitivity which includes climate changes impacts is met by
the incorporation of climate change into all 2025 IRP studies.
255

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
256

PACIFICORP-2025 IRP CHAPTER 10—DRAFT ACTION PLAN
CHAPTER 10 - DRAFT ACTION PLAN
CHAPTER HIGHLIGHTS
• The 2025 Integrated Resource Plan (IRP) action plan identifies steps that PacifiCorp will take
over the next two-to-four years to deliver resources in the preferred portfolio'. In its draft form,
the action plan is subject to change driven by stakeholder feedback, ongoing review and
validation, and changes in the planning environment.
• PacifiCorp's 2025 IRP draft action plan includes action items for existing resources, new
resources, transmission, demand-side management (DSM) resources, short-term firm market
purchases, and the purchase and sale of renewable energy credits (RECs).2
• PacifiCorp further discusses how it can mitigate procurement delay risk, summarizes planned
procurement activities tied to the action plan, assesses trade-offs between owning or purchasing
third-parry power, discusses its hedging practices, and identifies the types of risks borne by
customers and the types of risks borne by shareholders.
PacifiCorp's 2025 IRP action plan identifies the steps the company will take over the next two-to-
four years to deliver a least-cost, least-risk portfolio for customers, based on the resources and
requirements identified in its preferred portfolio,with a focus on the front five years of the planning
horizon.
The 2025 IRP action plan is based on the latest and most accurate information available at the time
portfolios are being developed and analyzed on cost and risk metrics. PacifiCorp recognizes that
the preferred portfolio, upon which the action plan is based, is developed in an uncertain and
evolving planning environment and that resource acquisition strategies need to be regularly
evaluated as planning assumptions change.
Resource information used in the 2025 IRP, such as capital and operating costs, are based upon
recent projections of cost-and-performance data. However, it is important to recognize that
resources identified in the plan include proxy resources, which act as a guide for resource
procurement and not as a commitment. Resources evaluated as part of procurement initiatives may
vary from the proxy resources identified in the plan with respect to resource type, timing, size,
cost, and location.
PacifiCorp recognizes the need to support and justify resource acquisitions consistent with then-
current laws, regulatory rules and requirements, and commission orders.
In addition to presenting the 2025 IRP action plan, reporting on progress in delivering the prior
action plan, and presenting the 2025 IRP acquisition path analysis, this chapter also includes
discussion of the following resource procurement topics:
1 The draft preferred portfolio is subject to change driven by stakeholder feedback,ongoing review and validation,
and changes in the planning environment.
a Changes in procurement planning and Federal legislative drivers for change were discussed in the 2025 IRP public
input meeting series. See Appendix M,stakeholder feedback form#11 (Utah Environmental Caucus). See also
Appendix M,stakeholder feedback form#13 (Joan Entwistle).
257

PACIFICORP-2025 IRP CHAPTER 10-DRAFT ACTION PLAN
• Procurement delays;
• IRP action plan linkage to the business plan;
• Resource procurement strategy;
• Assessment of owning assets vs. purchasing power;
• Managing carbon risk for existing plants;
• Purpose of hedging; and
• Treatment of customer and investor risks.
the 2025 IRP Action P
The 2025 IRP action plan identifies specific actions PacifiCorp will take over roughly the next
two-to-four years to deliver its preferred portfolio. Action items are based on the size, type and
timing of resources in the preferred portfolio, findings from analysis completed over the course of
portfolio modeling, and feedback received by stakeholders in the 2025 IRP public-input process.
Table 10.1 details specific 2021 IRP action items by resource category.
258

PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Table 10.4 —2025 IRP Action Plan
Action
Item 1. Existing Resource Actions
Colstrip Units 3 and 4:
la • PacifiCorp will continue to work with co-owners to develop the most cost-effective path toward an exit from the Colstrip
project in Montana by 2030.
Craig Unit 1:
lb PacifiCorp will continue to work closely with co-owners to seek the most cost-effective path forward toward the 2025 IRP
preferred portfolio target exit date of December 31, 2025.
Naughton Units 1 and 2:
• PacifiCorp will continue the process of converting Naughton Units 1 and 2 to natural gas as initiated in Q2 2023, including
lc obtaining all required regulatory notices and filings.Natural gas operations are anticipated to commence spring of 2026.
• PacifiCorp will initiate the closure of the Naughton 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 pond closure extension submission.
Carbon Capture and Storage/Low Carbon Portfolio Standard:
ld • PacifiCorp will continue to evaluate the economic and technical feasibility of carbon capture technology on Jim Bridger
Units 3 and 4 to comply with Wyoming's low carbon portfolio standard.
Regional Haze Compliance:
• Following the resolution of first planning period regional haze compliance disputes, and the EPA's determination of the states'
le second planning period regional haze state implementation plans, PacifiCorp will evaluate and model any emission control
retrofits, emission limitations, or utilization reductions that are required for coal units.
• PacifiCorp will continue to engage with the EPA, state agencies, and stakeholders to achieve second planning period regional
haze compliance outcomes that improve Class I visibility, provide environmental benefits, and are cost effective.
NatriumTM Demonstration Proiect:
• By the end of 2025, PacifiCorp expects to finalize a commercial off-take agreement for the NatriumTM project. PacifiCorp will
if continue to monitor key TerraPower development milestones 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.
259

PACIFICORP-2025 IRP CHAPTER 10 ACTION PLAN
Ozone Transport Rule Compliance:
• EPA finalized its approval of Wyoming's cross-state ozone state plan on December 19, 2023. This approval means
PacifiCorp facilities in Wyoming are not subject to the federal ozone plan requirements.
Ig • The Tenth Circuit granted a motion to stay EPA's disapproval of Utah's state ozone plan. Utah is not subject to federal
ozone requirements while the stay is in place. The Utah ozone case was transferred to the D.C. Circuit in February of 2024,
for adjudication of the merits, leaving the stay in place. PacifiCorp will continue to monitor developments in the Utah ozone
case and adjust its plans accordingly in response to developments.
Natural Gas Emissions Compliance Strategies
• The 2025 IRP indicates that changes in accounting and/or dispatch of existing natural gas resources may be a beneficial element
1h of Oregon's HB 2021 compliance strategy and to align with evolving state policies.A range of implementation strategies exist,
with intertwined implications on resource allocation,market participation, and compliance requirements. PacifiCorp will meet
with impacted parties, program administrators, and regulators to enable a refined analysis of the available options to prepare
for implementation no later than the start of 2030.
260

PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Action
2. New Resource Actions
Item
Customer Preference Request for Proposals:
• PacifiCorp is continuously receiving and evaluating requests for voluntary customer programs in Utah and Oregon.
PacifiCorp may use the marginal resources from future request for proposals to fulfill customer need. In some cases,
2a customer preference may necessitate issuance of a request for proposals to procure resources within the action plan window.
• Consistent with Utah Community Renewable Energy Act, PacifiCorp will continue to work with eligible communities to
develop program to achieve goal of being net 100 percent renewable by 2030; PacifiCorp filed an application for approval of
a resource solicitation process for the program with the Utah Public Service Commission in November 2024. PacifiCorp
plans to file an application for the remainder of the program during Q 12025.
2025 All-Source Request for Proposals:
• PacifiCorp will issue as appropriate by jurisdiction need, one or more all-source Request for Proposals (RFP) to procure
2b resources aligned with the 2025 IRP preferred portfolio that can achieve commercial operations by the end of December 2029.3
• In light of the differentiated resource needs by jurisdiction identified in the 2025 IRP, scope and targeted resource needs may
vary by jurisdiction.
Action
Item 3. Transmission Action Items
-AM 0
Local Reinforcement Proiects
3a Initiate Local Reinforcement Projects as identified with the addition of new resources per the preferred portfolio, and follow-on
requests for proposal successful bids.
Gateway West Support
Continue permitting support for Gateway West segments D.3 and E. Initiate preliminary permitting and development activities
3b for future transmission investments not currently included in the preferred portfolio. These 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
PacifiCorp to prepare for potential growth in new large loads seeking new service over the next decade.
3 Procurement strategy was a frequent topic during the 2025 IRP public input meeting process and stakeholder feedback. See Appendix M,stakeholder feedback form
#17(Oregon Public Utilities Commission)
261

PACIFICORP-2025 IRP CHAPTER 10 ACTION PLAN
Action
Item 4. Demand-Side Management(DSM) Actions
Energy Efficiency Targets:
• PacifiCorp will acquire cost-effective energy efficiency resources targeting annual system energy and capacity selections
from the preferred portfolio. PacifiCorp's state-specific processes for planning for DSM acquisitions is provided in
4a Appendix D in Volume II of the 2025 IRP.
• PacifiCorp will pursue cost-effective energy efficiency resources.
• PacifiCorp will pursue cost-effective demand response resources targeting annual system capacity selections from the
preferred portfolio. Capacity impacts for demand response include both summer and winter impacts within a year.
Action
ItemM 0
5. Market Purchases
Market Purchases:
• PacifiCorp will acquire short-term firm market purchases for on-peak delivery from 2025-2027 consistent with the Risk
Management Policy and Energy Supply Management Front Office Procedures and Practices. These short-term firm market
5a purchases will be acquired through multiple means:
o Balance of month and day-ahead brokered transactions in which the broker provides a competitive price.
o Balance of month, day-ahead, and hour-ahead transactions executed through an exchange, such as the
Intercontinental Exchange, in which the exchange provides a competitive price.
o Prompt-month,balance-of-month, day-ahead, and hour-ahead non-brokered bi-lateral transactions.
Action
Item 6. Renewable Energy Credit (REC) Actions
Renewable Portfolio Standards (RPS):
• PacifiCorp will pursue unbundled REC RFPs and purchases to meet its state RPS compliance requirements.
6a • PacifiCorp will issue RFPs seeking unbundled RECs that will qualify in meeting California RPS targets through 2026 and
future compliance periods, as needed.
262

PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Renewable Energy Credit Sales:
6b • Maximize the sale of RECs that are not required to meet state RPS compliance obligations.
Progress on 2023 Action Pla
This section describes progress that has been made on previous action plan items documented in the 2023 IRP filed with state commissions
on May 30, 2023. Many of these action items have been superseded in some form by items identified in the 2025 IRP action plan. The status
for all action items from the 2025 IRP is summarized in Table 10.2.
Table 10.2 —2023 IRP Action Plan Status Update
Action 1. Existing Resource Actions Status
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.
Craig 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 regulatory
• PacifiCorp will initiate the process of converting notices and filings to process the conversion of
Naughton Units 1 and 2 to natural gas beginning Q2 Naughton Units 1 and 2 from coal to natural gas.
2023, including obtaining all required regulatory • Coal supply agreements for Naughton Units 1 and 2
notices and filings. Natural gas operations are will not be extended beyond the end of December
lc anticipated to commence spring of 2026. 2025.
• PacifiCorp will initiate the closure of the Naughton
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 pond
closure extension submission.
263

PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Jim Bridger Units 1 and 2 Gas Conversion: • PacifiCorp received an approval order on December 7,
• PacifiCorp has initiated the process of ending coal- 2023 from the Wyoming Public Service Commission
fueled operations. The Wyoming Air Quality Division for the conversion of Jim Bridger Units 1 and 2 from
issued an air permit on December 28, 2022, for the coal to natural gas.
natural gas conversion. All required regulatory notices • PacifiCorp ceased coal-fueled operations at Jim
ld and filings will be completed by end of 2023. Bridger Units 1 and 2 on December 31, 2023.
• By the end of Q4 2023, PacifiCorp will administer • Removal of coal handling equipment and installation
termination, amendment, or close-out of existing of natural gas components began on January 1, 2024.
permits, contracts, and other agreements. Conversions were completed 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 in
• PacifiCorp will complete an evaluation of the August of 2023.
information received as part of the CCUS RFP and RFI • PacifiCorp filed its final plan with the Wyoming Public
le processes by the end of Q3 2023. Service Commission on March 29, 2024, as required
• PacifiCorp will submit, for Wyoming Public Service 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 disputes
determination of the states' second planning period have been resolved. The Tenth Circuit found EPA's
regional haze state implementation plans, PacifiCorp disapproval of Wyoming's plan for Wyodak unlawful
will evaluate and model any emission control retrofits, and remanded the plan to EPA for further review in
emission limitations, or utilization reductions that are accordance with the requirements of the Clean Air Act.
if required for coal units. No proposed rule has been issued to date.
• PacifiCorp will continue to engage with the EPA, state • Wyoming submitted its state-approved revised regional
agencies, and stakeholders to achieve second planning haze plan requiring the natural gas conversion of Jim
period regional haze compliance outcomes that improve Bridger Units 1 and 2 to EPA for approval. EPA is
Class I visibility,provide environmental benefits, and reviewing the state plan. PacifiCorp continues to
are cost effective. comply with the state-approved plan and operating
permits.
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• PacifiCorp continues to engage with the EPA, state
agencies, and stakeholders relating to second planning
period regional haze compliance. No second planning
period requirements have been finalized by EPA to
date.
NatriumTM Demonstration Proiect: • PacifiCorp continues to work with TerraPower on
• PacifiCorp will continue to monitor and report key commercial arrangements for offtake from the
TerraPower milestones for development and will make NatriumTM project and expects to finalize these
regulatory filings, as applicable. arrangements by the end of 2025.
• 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 community
1g 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 the means PacifiCorp facilities in Wyoming are not subject
assumptions contained in the 2023 IRP. to the federal ozone plan requirements.
1h • PacifiCorp will continue to engage with the EPA, state • The Tenth Circuit granted a motion to stay EPA's
agencies, and stakeholders to achieve Ozone Transport disapproval of Utah's state ozone plan. Utah is not
Rule compliance outcomes that provide environmental subject to federal ozone requirements while the stay is
benefits, support reliable energy delivery and are cost in place. The Utah ozone case was transferred to the
effective. D.C. Circuit in February of 2024, for adjudication of the
merits, leaving the stay in place.
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• Based on the Ozone Transport Rule trading program
and the associated benefits for reducing NOx emissions,
PacifiCorp will install selective non-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 tatu
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 applied for
Oregon.PacifiCorp may use the marginal resources from approval of a resource solicitation process with the Utah
ongoing 2022AS RFP and future request for proposals to Public Service Commission in November 2024.
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 the 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.
2025 All-Source Request for Proposals: The 2025 IRP includes an action item to procure
2b • PacifiCorp will issue an all-source Request for Proposals incremental resources as needed to serve customers over the
(RFP) to procure resources aligned with the 2025 IRP long term.
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preferred portfolio that can achieve commercial
operations by the end of December 2030.
• In Q4 2023, PacifiCorp will notify the Public Utility
Commission of Oregon, the Public Service Commission
of Utah,and the Washington Utilities and Transportation
Commission, of PacifiCorp's need for an independent
evaluator.
• In Q 1 2024, 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 RFP 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 Q 1 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 in
for Proposals to procure resources that can achieve the planning environment might influence long-term
commercial operations by the end of December 2027. resource procurement activities.
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• In Q2 2023,PacifiCorp will identify a final shortlist from • EPA's approval of Wyoming's cross-state ozone
the all-source RFP, and file for approval of the final transport rule plan and the Tenth Circuit Court's stay of
shortlist in Oregon. Similarly, PacifiCorp will make a Utah's ozone plan have materially impacted the need for
filing in Utah for any applicable significant energy the type and volume of resources identified in the 2023
resources on final shortlist. PacifiCorp will file IRP preferred portfolio, which considered resource
certificate of public convenience and necessity (CPCN) procurement needs coming out of the 2022 All-Source
applications, as applicable, and Request for Proposals.
• By Q4 2023 PacifiCorp will execute definitive • PacifiCorp contracted on a bi-lateral basis for battery
agreements with winning bids from the all-source RFP. energy storage resources with commercial operation
• Winning bids from the 2022 all-source REP are expected dates prior to summer 2026 and terminated the 2022 All
to achieve commercial operation by December 31,2027, Source Request for Proposals.
or earlier.
Action
Item 3. Transmission Action ItemsM I M
Status
Energy Gateway South Segment F (Aeolus-Clover 500 The Energy Gateway South transmission project is in-
kV transmission line): service.
3a
• In Q4 2024, construction of Energy Gateway South is
expected to be completed and placed in service.
Energy Gateway West, Segment D.1 (Windstar-Shirley The Energy Gateway West Sub-Segment D1 transmission
Basin 230 kV transmission line): project is in-service.
3b • In Q4 2024, construction of Energy Gateway West
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 of negotiations, planning and permitting of the Boardman-to-
the Boardman-to-Hemingway Transmission Project Hemingway 3c Hemin 500 kilovolt transmission line which is
(132H) Joint Permit Funding Agreement. targeted for a 2027 in-service date.
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• 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 the Reinforcements have been identified. A final assessment of
3d addition of new resources per the preferred portfolio, and upgrades is pending signed agreements.
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 development D.3 and E, maintaining the record of decision on each
activities for future transmission investments not currently segment.
included in the preferred portfolio. These future transmission
projects can include development of additional Energy
3e 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 PacifiCorp to prepare for
potential growth in new large loads seeking new service over
the next decade.
Action
Item 4. Demand-Side Management(DSM)Actions Status
Energy Efficiency Targets: • PacifiCorp achieved the Action Plan target of 543 GWh
PacifiCorp will acquire cost-effective energy efficiency in 2023 and is on track to achieve its 2024 Class 2 DSM
4a resources targeting annual system energy and capacity target.
selections from the preferred portfolio as summarized
below. PacifiCorp's state-specific processes for PacifiCorp has launched a number of new demand response
programs in 2022 and 2023. Additionally, the company is
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
planning for DSM acquisitions is provided in Appendix currently expanding its existing programs. PacifiCorp
D in Volume II of the 2023 IRP. continues to pursue the incremental capacity additions but
did not achieve the 2023 incremental capacity, due to the
later than anticipated timing of program effective dates for
newly launched demand response programs.
Action
JEEL5.ItemMarket Purchases StatusI=
Market Purchases: Since the publication of the 2023 IRP action plan,
• Acquire short-term firm market purchases for on-peak PacifiCorp has continued to transact consistent with its risk
delivery from 2023-2025 consistent with the Risk management and energy supply procedures to reliably cost-
Management Policy and Energy Supply Management effectively serve customer requirements. Such transactions
Front Office Procedures and Practices. These short-term include seeking competitive pricing to acquire short-term
firm market purchases will be acquired through firm purchases, execute balance of month, day-ahead and
multiple means: Balance of month and day-ahead hour-ahead transactions through exchanges, and engage in
5a brokered transactions in which the broker provides a prompt-month, balance-of-month, day-ahead and hour-
competitive price. ahead non-brokered bi-lateral transactions.
• Balance of month, day-ahead, and hour-ahead
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.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Action
Item 6. Renewable Energy Credit (REC)Actions Status
Renewable Portfolio Standards (RPS): PacifiCorp will continue to evaluate the need for unbundled
• PacifiCorp will pursue unbundled REC RFPs and RECs and issue RFPs to meet its state RPS compliance
purchases to meet its state RPS compliance requirements as needed.
6a requirements.
• 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 maximize
6b • Maximize the sale of RECs that are not required to meet the sale of RECs that are not required to meet state RPS
state RPS compliance obligations. compliance obligations
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PACIFICORP—2025 IRP CHAPTER 10—ACTION PLAN
Acquisition Path Analysis
Resource and Compliance Strategies
PacifiCorp worked with stakeholders to define its portfolio development process and cost and risk
analysis in the 2025 IRP. This analysis reflects a combination of specific planning assumptions
related to key uncertainties addressed in the acquisition path analysis including load, private
generation, changes in available resources, and emissions polices. PacifiCorp will further analyze
sensitivity cases on planning assumptions related primarily to the load forecasts and private
generation penetration levels. The array of planning assumptions that define the studies used to
develop resource portfolios provides the framework for a resource acquisition path analysis by
evaluating how resource selections are impacted by changes to planning assumptions.
Given current load expectations, portfolio modeling performed for the 2025 IRP shows the
resource acquisition path in the preferred portfolio is robust among a wide range of policy and
market conditions, particularly in the near-term, when cost-effective renewable resources
qualifying for federal income tax credits, market purchases, and energy efficiency and demand
response resources are consistently selected, in conjunction with new storage and continued
thermal unit operations to mitigate volatility. With regard to renewable resource acquisition, the
portfolio development modeling performed in the 2025 IRP shows that new renewable resource
needs are driven primarily by economics and reliability. Beyond load, CO2 policy also influences
resource selections in the 2025 IRP. For these reasons, the acquisition path analysis focuses on
economic, load, reliability, and environmental policy trigger events that would require alternative
resource acquisition strategies. For each trigger event, PacifiCorp identifies the planning scenario
assumption affecting both short-term(2025-2034) and long-term(2035-2045)resource strategies.
Acquisition Path Decision Mechanism
Note—Acquisition path analysis is heavily dependent upon sensitivity studies which have
are not included in the December 31, 2024 Draft 2025 IRP distribution. The purpose and
scope of acquisition path analysis is described below, with final sensitivity studies to be
provided by March 31, 2025.
The Public Service Commission of Utah requires that PacifiCorp provide "[a] plan of different
resource acquisition paths with a decision mechanism to select among and modify as the future
unfolds."4 PacifiCorp's decision mechanism is centered on the IRP process and ongoing updates
to the IRP modeling tools between IRP cycles. The same modeling tools used in the IRP are also
used to evaluate and inform the procurement of resources. The IRP models are used on a macro-
level to evaluate alternative portfolios and futures as part of the IRP process, and then on a micro-
level to evaluate the economics and system benefits of individual resources as part of the supply-
side resource procurement and demand-side management target-setting/valuation processes.
PacifiCorp uses the IRP development process and the IRP modeling tools to serve as decision
support tools to guide prudent resource acquisition paths that maintain system reliability and
flexibility at a reasonable cost.
4 Public Service Commission of Utah,In the Matter of Analysis of an Integrated Resource Plan for PacifiCorp,
Report and Order,Docket No. 90-2035-01,June 1992,p.28.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
PacifiCorp's 2025 IRP acquisition path analysis provides insight on how changes in the planning
environment might influence future resource procurement activities. Changes in procurement
activities driven by changes in the planning environment will ultimately be reflected in future IRPs
and resource procurement decisions.
Procurement Delays
The main procurement risk, where a procurement need is indicated, is an inability to procure
resources in the required timeframe to maintain reliable and resilient grid operations. There are
various reasons why a particular proxy resource cannot be procured in the timeframe identified in
a given action plan period. There may not be any cost-effective opportunities available through an
RFP, the successful RFP bidder may experience delays in permitting and/or default on their
obligations, or there might be a material and sudden change in the market for fuel and materials.
Moreover,there is always the risk of unforeseen environmental or other electric utility regulations
that may influence the PacifiCorp's entire resource procurement strategy.
Possible paths PacifiCorp could take in the event of a procurement delay or sudden change in
procurement need can include combinations of the following:
• In circumstances where PacifiCorp is engaged in an active RFP where a specific bidder is
unable to perform, alternative bids can be pursued.
• PacifiCorp can issue an emergency RFP for a specific resource and with specified
availability.
• PacifiCorp can seek to negotiate an accelerated delivery date of a potential resource with
the supplier/developer.
• PacifiCorp can seek to procure near-term purchased power and transmission until a
longer-term alternative is identified, acquired through customized market RFPs,
exchange transactions, brokered transactions or bi-lateral, sole source procurement.
• Accelerate acquisition timelines for direct load control programs.
• Procure and install temporary generators to address some or all of the capacity needs.
• Temporarily drop below its planning reserve margin.
• Implement load control initiatives, including calls for load curtailment via existing load
curtailment contracts.
MAction P to Busine
Consistent with the Utah commission's order in Docket No. 15-035-04, the IRP is directed to
include a business plan sensitivity. In the 2025 IRP, a distinct sensitivity would be redundant
because the integrated preferred portfolio's base assumptions are aligned with the business plan as
set forth the following parameters:
• Over the first three years, resources align with those assumed in PacifiCorp's current
Business Plan.
• Beyond the first three years of the study period, unit retirement assumptions are aligned
with the preferred portfolio.
• All other resources are optimized.
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PACIFICORP—2025 IRP CHAPTER 10—ACTION PLAN
Resource Procurement Strategy
To acquire resources outlined in the 2023 IRP action plan, PacifiCorp intends to continue using
competitive solicitation processes in accordance with applicable laws, rules, and/or guidelines in
each of the states in which PacifiCorp operates. PacifiCorp will also continue to pursue
opportunistic acquisitions identified outside of a competitive procurement process that provide
benefits to customers. Regardless of the method for acquiring resources, PacifiCorp will support
its resource procurement activities with the appropriate financial analysis using then-current
assumptions for inputs such as load forecasts, commodity prices, resource costs, and policy
developments. Any such financial analysis will account for any applicable long-term system
benefits with least-cost, least-risk planning principles in mind. The sections below profile the
general procurement approaches for the key resource categories covered in the 2023 IRP action
plan.
Renewable Resources, Storage Resources, and Dispatchable Resources
PacifiCorp will use a competitive RFPs to procure supply-side resources consistent applicable
laws, rules, and/or guidelines in each of the states in which PacifiCorp operates. In Oregon and
Utah, these state requirements involve the oversight of an independent evaluator. In Washington,
an independent evaluator may be used if benchmark resources (PacifiCorp built and owned
resources) are being considered after consultation with Washington staff and stakeholders. The
all-source RFPs outline the types of resources being pursued,defines specific information required
of potential bidders and details both price and non-price scoring metrics that will be used to
evaluate proposals.
Renewable Energy Credits
PacifiCorp uses shelf RFPs as the primary mechanism under which REC RFPs and reverse REC
RFPs will be issued to the market. The shelf RFPs are updated to define the product definition,
timing, and volume and further provide schedule and other applicable criteria to bidders.
Demand-Side Managements
PacifiCorp offers a robust portfolio of demand response and energy efficiency programs and
initiatives, most of which are offered in multiple states, depending on size of the opportunity and
the need. Programs are reassessed on a regular basis. PacifiCorp provides Class 4 DSM offerings,
and has continued wattsmart outreach and communications.Educating customers regarding energy
efficiency and load management opportunities is an important component of PacifiCorp's long-
term resource acquisition plan. PacifiCorp will continue to evaluate how to best incorporate
potential DSM programs into the broader all-source RFP process discussed above or whether
separate RFPs focused on these resources are warranted based on state-specific requirements and
program needs.
5 Class 1 DSM is most commonly referred to as"demand response"in the 2023 IRP;Class 2 DSM is most
commonly referred to as"energy efficiency". Class 4 DSM describes energy efficiency measures achieved through
public outreach and education.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Small Scale Renewable Energy Supply
In order to fulfil Oregon regulatory requirements for small-scale renewable resources, PacifiCorp
plans to issue a small-scale renewable energy RFP in 2025 to solicit resources within its territory
which are 20 MW or smaller and can be commercially operational by 2029. Currently, Oregon's
new HB 2021 legislation and associated Clean Energy Plan is driving a specific evaluation of
small-scale renewables that may help to identify the costs and benefits of smaller(20 MW or less
installed capacity) community-oriented renewables projects across PacifiCorp's service territory.
This study is addressed in PacifiCorp's 2023 Oregon Clean Energy Plan.
Essessment of Owning Assets versus Purchasing Power
As PacifiCorp acquires new resources, it will need to determine whether it is better to own a
resource or purchase power from another parry. While the ultimate decision will be made at the
time resources are acquired, and will primarily be based on cost,there are other considerations that
may be relevant.
With owned resources, PacifiCorp is in a better position to control costs, make life extension
improvements (as was implemented with the wind repower project), use the site for additional
resources in the future,change fueling strategies or sources (as was implemented for the Naughton
Unit 3 gas conversion and as planned for Jim Bridger Units I and 2), efficiently address plant
modifications that may be required as a result of changes in environmental or other laws and
regulations, and use the plant at embedded cost as long as it remains economic. In addition, by
owning a plant, PacifiCorp can hedge itself against the uncertainty of third-party performance
consistent with the terms and conditions outlined in a power-purchase agreement over time.
Because of recent downgrades by credit rating agencies,the increase in debt associated with owned
resources could negatively impact PacifiCorp's credit ratios and credit rating.
Alternately and depending on contractual terms, purchasing power from a third party in a long-
term contract may help mitigate and may avoid liabilities associated with closure of a plant. A
long-term power-purchase agreement relinquishes control of construction cost, schedule, ongoing
costs and environmental and regulatory compliance. Power-purchase agreements can also protect
and cap the buyer's exposure to events that may not cover actual seller financial impacts.However,
credit rating agencies can impute debt associated with long-term resource contracts that may result
from a competitive procurement process. While the level of imputation associated with long-term
contracts is expected to be lower than the debt associated with owned resources, it still may affect
PacifiCorp's credit ratios and credit rating.
Managing Carbon Risk for Existing Plants
CO2 reduction regulations at the federal, regional, or state levels could prompt PacifiCorp to
continue to look for measures to lower CO2 emissions of fossil-fired power plants through cost-
effective means. The cost, timing, and compliance flexibility afforded by CO2 reduction rules will
impact what types of measures might be cost effective and practical from operational and
regulatory perspectives.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Compliance strategies will be affected by how and whether states or the federal government choose
to implement further policies related to greenhouse gases and nitrogen oxide. State or federal
frameworks could impute a carbon tax or implement a cap-and-trade framework.Under a cap-and-
trade policy framework, examples of factors affecting carbon compliance strategies include the
allocation of emission allowances, the cost of allowances in the market, and any flexible
compliance mechanisms such as opportunities to use carbon offsets, allowance/offset banking and
borrowing, and safety valve mechanisms. Under a CO2 tax framework, the tax level and details
around how the tax might be assessed would affect compliance strategies.
To lower the emission levels for existing fossil-fired power plants,options include changes in plant
dispatch, unit retirements, changing the fuel type, deployment of plant efficiency improvement
projects, and adoption of new technologies such as CO2 capture with sequestration. As mentioned
above,plant CO2 emission risk may also be addressed by acquiring offsets or other environmental
attributes that could become available in the market under certain regulatory frameworks.
PacifiCorp's compliance strategies will evolve and continue to be reassessed in future IRP cycles
as market forces and regulatory outcomes evolve.
Purpose of Hedging
While PacifiCorp focuses every day on minimizing net power costs for customers, the company
also focuses every day on mitigating price risk to customers, which is done through hedging
consistent with a robust risk management policy. For years PacifiCorp has followed a consistent
hedging program that limits risk to customers, has tracked risk metrics assiduously and has
diligently documented hedging activities. PacifiCorp's risk management policy and hedging
program exists to achieve the following goals: (1) ensure reliable sources of electric power are
available to meet PacifiCorp's customers' needs; and (2) reduce volatility of net power costs for
PacifiCorp's customers. PacifiCorp does not engage in a material amount of proprietary trading
activities. Hedging modifies the potential losses and gains in net power costs associated with
wholesale market price changes. The purpose of hedging is not to reduce or minimize net power
costs. PacifiCorp cannot predict the direction or sustainability of changes in forward prices.
Therefore, PacifiCorp hedges, in the forward market, to reduce the volatility of net power costs
consistent with good industry practice as documented in the company's risk management policy.
Risk Management Policy and Hedging Program
PacifiCorp's risk management policy and hedging program were designed to follow electric
industry best practices and are reviewed at least annually by the company's risk oversight
committee.The risk oversight committee includes PacifiCorp representatives from the front office,
finance, risk management, treasury, and legal department. The risk oversight committee makes
recommendations to the chief executive officer of PacifiCorp, who ultimately must approve any
change to the risk management policy.
The main components of PacifiCorp's risk management policy and hedging program are natural
gas percent hedged volume limits and power volume hedge limits. These limits force PacifiCorp
to monitor the open positions it holds in power and natural gas on behalf of its customers on a
daily basis and limit the size of short positions by prescribed time frames in order to reduce
customer exposure to price concentration and price volatility. The hedge program requires
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
purchases of natural gas and power at fixed prices in gradual stages in advance of when it is
required to reduce the size of short positions and associated customer risk.
Dollar cost averaging is the term used to describe gradually hedging over a period of time rather
than all at once. This method of hedging, which is widely used by many utilities, captures
time diversification and eliminates speculative bursts of market timing activity. Its use means that
at times PacifiCorp buys at relatively higher prices and at other times relatively lower prices,
essentially capturing an array of prices at many levels. While doing so, PacifiCorp steadily and
adaptively meets its hedge goals through the use of this technique while staying within power
volume hedge limits and natural gas percent hedge volume limits.
Cost Minimization
While hedging does not minimize net power costs, PacifiCorp takes many actions to minimize net
power costs for customers. First, the company is engaged in integrated resource planning to plan
resource acquisitions that are anticipated to provide the lowest cost resources to our customers in
the long run. PacifiCorp then issues competitive requests for proposals to assure that the resources
we acquire are the lowest cost resources available on a risk-adjusted basis. In operations,
PacifiCorp optimizes its portfolio of resources on behalf of customers by maintaining and
operating a portfolio of assets that diversifies customer exposure to fuel, power market and
emissions risk and utilize an extensive transmission network that provides access to markets across
the western United States. Independent of any natural gas and electric price hedging activity, to
provide reliable supply and minimize net power costs for customers, PacifiCorp commits
generation units daily, dispatches in real time all economic generation resources and all must-
take contract resources, serves retail load, and then sells any excess generation to generate
wholesale revenue to reduce net power costs for customers.PacifiCorp also purchases power when
it is less expensive to purchase power than to generate power from our owned and contracted
resources.
Hedging cannot be used to minimize net power costs. Hedging does not produce a different
expected outcome than not hedging and therefore cannot be considered a cost minimization tool.
Hedging is solely a tool to mitigate customer exposure to net power cost volatility and the risk of
adverse price movement. However, PacifiCorp does minimize the cost of hedging by transacting
in liquid markets and utilizing robust protections to mitigate the risk of counterparty default.
Portfolio
PacifiCorp has a short position in natural gas because of its ownership of gas-fired electric
generation that requires it to purchase large quantities of natural gas to generate electricity to serve
its customers. PacifiCorp may have short or long positions in power depending on the shortfall or
excess of the company's total generation capacity relative to customer load requirements at a given
point in time.
Instruments
PacifiCorp's hedging program allows the use of several instruments including financial swaps,
fixed price physical and options for these products. PacifiCorp chooses instruments that generally
have greater liquidity and lower transaction costs.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Treatment of Customer and Investor Risks
The IRP standards and guidelines in Utah require that PacifiCorp "identify which risks will be
borne by ratepayers and which will be borne by shareholders." This section addresses this
requirement. Three types of risk are covered: stochastic risk, capital cost risk, and scenario risk.
Stochastic Risk Assessment
Several of the uncertain variables that pose cost risks to different IRP resource portfolios are
quantified in the IRP production cost model using historic years to represent uncertainty. The
variables addressed with such tools include retail loads, natural gas prices, wholesale electricity
prices, hydroelectric generation, and thermal unit availability. Changes in these variables that
occur over the long-term are typically reflected in normalized revenue requirements and are thus
borne by customers. Unexpected variations in these elements are normally not reflected in rates,
and are therefore borne by investors unless specific regulatory mechanisms provide otherwise.
Consequently, over time, these risks are shared between customers and investors. Between rate
cases, investors bear these risks. Over a period of years, changes in prudently incurred costs will
be reflected in rates and customers will bear the risk.
Capital Cost Risks
The actual cost of a generating or transmission asset is expected to vary from the cost assumed in
the IRP. State commissions may determine that a portion of the cost of an asset was imprudent and
therefore should not be included in the determination of rates. The risk of such a determination is
borne by investors. To the extent that capital costs vary from those assumed in this IRP for reasons
that do not reflect imprudence by PacifiCorp, the risks are borne by customers.
Scenario Risk Assessment
Scenario risk assessment pertains to abrupt or fundamental changes to variables that are
appropriately handled by scenario analysis as opposed to representation by a statistical process or
expected-value forecast. The single most important scenario risks of this type facing PacifiCorp
continue to be government actions related to emissions and changes in load and transmission
infrastructure. These scenario risks relate to the uncertainty in predicting the scope, timing, and
cost impact of emission and policies and renewable standard compliance rules.
To address these risks,PacifiCorp evaluates resources in the IRP and for competitive procurements
using a range of CO2 policy assumptions consistent with the scenario analysis methodology
adopted for PacifiCorp's 2025 IRP portfolio development and evaluation process. The company's
use of IRP sensitivity analysis covering different resource policy and cost assumptions also
addresses the need for consideration of scenario risks for long-term resource planning. The extent
to which future regulatory policy shifts do not align with PacifiCorp's resource investments
determined to be prudent by state commissions is a risk borne by customers.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
280

- Wind
20 5
Integrated Resource Plan
(D raft)
; i Volume 11 - December 31 , 2024
te a—
`,
AM
PACIFICORR

This 2025 Draft Integrated Resource Plan is based upon the best available information at the
time of preparation. The 2025 Integrated Resource Plan is anticipated to be distributed March
31, 2025.
For more information, contact:
PacifiCorp Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
[e-mail]
www.pacificorp.com

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF CONTENTS - VOLUME II
TABLE OF CONTENTS...............................................................................1
TABLEOF TABLES...................................................................................v
TABLE OF FIGURES ...............................................................................vii
APPENDIX A - LOAD FORECAST
MAINTAINING CUSTOMER FOCUS.............................................................................................................1
ROADMAP..................................................................................................................................................................I
CHANGES TO OUR PORTFOLIO...................................................................................................................................2
PACIFICORP'S INTEGRATED RESOURCE PLAN APPROACH................................................................2
PREFERRED PORTFOLIO HIGHLIGHTS....................................................................................................4
NEWSOLAR RESOURCES...........................................................................................................................................6
NEWWIND RESOURCES.............................................................................................................................................7
NEWSTORAGE RESOURCES.......................................................................................................................................7
NEWNUCLEAR RESOURCES......................................................................................................................................7
DEMAND-SIDE MANAGEMENT..................................................................................................................................8
COAL AND GAS EXITS,RETIREMENTS,AND GAS CONVERSIONS...............................................................................8
ACTIONPLAN...............................................................................................................................................11
APPENDIX B - REGULATORY COMPLIANCE
INTRODUCTION.................................................................................................................................................is
GENERAL COMPLIANCE.....................................................................................................................................is
CALIFORNIA................................................................................................................................................................16
IDAHO.......................................................................................................................................................................17
OREGON....................................................................................................................................................................17
UTAH........................................................................................................................................................................18
WASHINGTON.............................................................................................................................................................18
WYOMING .................................................................................................................................................................18
APPENDIX C - PUBLIC INPUT
PARTICIPANTLIST.............................................................................................................................................29
COMMISSIONS............................................................................................................................................................29
STAKEHOLDERS AND INDUSTRY EXPERTS...........................................................................................................................30
GENERAL MEETINGS AND AGENDAS..................................................................................................................31
GENERALMEETINGS.....................................................................................................................................................31
STAKEHOLDER COMMENTS...............................................................................................................................32
CONTACTINFORMATION..................................................................................................................................33
1

PACIFICORP—2025 IRP TABLE OF CONTENTS
APPENDIX D - DEMAND-SIDE MANAGEMENT
INTRODUCTION.................................................................................................................................................35
CONSERVATION POTENTIAL ASSESSMENT(CPA)FOR 2025-2044.......................................................................35
CURRENT DSM PROGRAM OFFERINGS BY STATE...............................................................................................36
STATE-SPECIFIC DSM PLANNING PROCESSES.....................................................................................................38
UTAH,WYOMING AND IDAHO........................................................................................................................................38
WASH I N GTO N.............................................................................................................................................................38
CALIFORNIA................................................................................................................................................................39
OREGON....................................................................................................................................................................39
PREFERRED PORTFOLIO DSM RESOURCE SELECTIONS........................................................................................39
APPENDIX E - GRID ENHANCEMENT
INTRODUCTION...........................................................................................................................................41
REGIONALENERGY MARKETS.................................................................................................................................41
Western Energy Imbalance Market....................................................................................................................41
ExtendedDay Ahead Market.............................................................................................................................42
TRANSMISSION NETWORK AND OPERATION ENHANCEMENTS.................................................................................42
AdvancedProtective Relays...............................................................................................................................42
DynamicLine Rating.........................................................................................................................................42
Digital Fault Recorders/Phasor Measurement Unit Deployment....................................................................43
Radio Frequency Line Sensors...........................................................................................................................44
TransmissionCFCLs..........................................................................................................................................44
DISTRIBUTION AUTOMATION AND RELIABILITY......................................................................................................45
Distribution Automation/Fault Location,Isolation and Service Restoration..................................................45
DistributionCFCLs............................................................................................................................................45
Distribution Substation Metering.......................................................................................................................46
DISTRIBUTED ENERGY RESOURCES.........................................................................................................................47
EnergyStorage Systems.....................................................................................................................................47
DemandResponse..............................................................................................................................................48
Dispatchable Customer Storage Resources.......................................................................................................48
TRANSPORTATION ELECTRIFICATION......................................................................................................................49
ADVANCED METERING INFRASTRUCTURE...............................................................................................................50
OUTAGE MANAGEMENT IMPROVEMENTS................................................................................................................51
FUTURE GRID ENHANCEMENTS..............................................................................................................52
APPENDIX F - FLEXIBLE RESERVE STUDY
INTRODUCTION...........................................................................................................................................53
OVERVIEW...............................................................................................................................................................54
FLEXIBLE RESOURCE REQUIREMENTS.................................................................................................55
11

PACIFICORP—2025 IRP TABLE OF CONTENTS
CONTINGENCYRESERVE.........................................................................................................................................56
REGULATIONRESERVE............................................................................................................................................56
FREQUENCY RESPONSE RESERVE............................................................................................................................57
BLACK START REQUIREMENTS................................................................................................................................58
ANCILLARY SERVICES OPERATIONAL DISTINCTIONS..............................................................................................58
REGULATION RESERVE DATA INPUTS...................................................................................................59
OVERVIEW...............................................................................................................................................................59
LOADDATA.............................................................................................................................................................60
WINDAND SOLAR DATA.........................................................................................................................................60
NON-VER DATA.....................................................................................................................................................61
REGULATION RESERVE DATA ANALYSIS AND ADJUSTMENT...........................................................61
OVERVIEW...............................................................................................................................................................61
BASE SCHEDULE RAMPING ADJUSTMENT................................................................................................................61
DATACORRECTIONS...............................................................................................................................................62
REGULATION RESERVE REQUIREMENT METHODOLOGY................................................................63
OVERVIEW...............................................................................................................................................................63
COMPONENTS OF OPERATING RESERVE METHODOLOGY........................................................................................64
Operating Reserve:Reserve Categories............................................................................................................64
Planning Reliability Target:Loss of Load Probability......................................................................................65
Balancing Authority ACE Limit:Allowed Deviations........................................................................................66
Regulation Reserve Forecast:Amount Held......................................................................................................67
REGULATION RESERVE FORECAST..........................................................................................................................68
Overview............................................................................................................................................................68
PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS...................................................................73
PORTFOLIO DIVERSITY BENEFIT..............................................................................................................................73
EIMDIVERSITY BENEFIT........................................................................................................................................74
FAST-RAMPING RESERVE REQUIREMENTS..........................................................................................76
PORTFOLIO REGULATION RESERVE REQUIREMENTS.......................................................................77
REGULATIONRESERVE COST..................................................................................................................................79
FLEXIBLE RESOURCE NEEDS ASSESSMENT..........................................................................................81
OVERVIEW...............................................................................................................................................................81
FORECASTED RESERVE REQUIREMENTS..................................................................................................................81
FLEXIBLE RESOURCE SUPPLY FORECAST................................................................................................................82
FLEXIBLE RESOURCE SUPPLY PLANNING................................................................................................................83
APPENDIX G- PLANT WATER CONSUMPTION
STUDYDATA.................................................................................................................................................87
APPENDIX I - CAPACITY EXPANSION RESULTS
2025 IRP PORTFOLIO SUMMARIES.....................................................................................................................93
PREFERREDPORTFOLIO.................................................................................................................................................93
................................................................................................................................................................................93
OREGON FULL JURISDICTIONAL PORTFOLIO.......................................................................................................................94
WASHINGTON FULL JURISDICTIONAL PORTFOLIO................................................................................................................95
UTAH,IDAHO,WYOMING,CALIFORNIA(UIWC)FULL JURISDICTIONAL PORTFOLIO..................................................................96
NoCCS.....................................................................................................................................................................97
iii

PACIFICORP—2025 IRP TABLE OF CONTENTS
NONUCLEAR..............................................................................................................................................................98
NoCOAL 2032...........................................................................................................................................................99
OFFSHOREWIND.......................................................................................................................................................100
LN..........................................................................................................................................................................101
MR.........................................................................................................................................................................102
HH.........................................................................................................................................................................103
SC..........................................................................................................................................................................104
APPENDIX L - DISTRIBUTED GENERATION STUDY
DISTRIBUTED GENERATION BEHIND-THE-METER RESOURCE ASSESSMENT.......................................................107
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
INTRODUCTION.........................................................................................................................................189
STAKEHOLDER FEEDBACK FORM SUMMARY....................................................................................189
REQUESTED ADDITIONAL STUDIES......................................................................................................191
PUBLISHED STAKEHOLDER FEEDBACK FORMS................................................................................192
APPENDIX O - WASHINGTON CLEAN ENERGY ACTION PLAN
INTRODUCTION...................................................................................................................................................313
PORTFOLIO DEVELOPMENT...........................................................................................................................314
RESOURCE PORTFOLIO DEVELOPMENT..................................................................................................................315
ResourceAdequacy..........................................................................................................................................315
Development of a Washington-compliant portfolio.........................................................................................315
INTERIM TARGETS.............................................................................................................................................317
SPECIFIC ACTIONS.............................................................................................................................................319
CUSTOMER BENEFIT INDICATORS...............................................................................................................319
APPENDIX P - ACRONYMS
iv

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF TABLES - VOLUME II
APPENDIX A - LOAD FORECAST
TABLE A.1-FORECASTED ANNUAL LOAD,2025 THROUGH 2034(MEGAWATT-HOURS),AT GENERATION,PRE-DSM .........................3
TABLE A.2-FORECASTED ANNUAL COINCIDENT PEAK LOAD(MEGAWATTS)AT GENERATION,PRE-DSM...........................................4
TABLE A.3-ANNUAL LOAD CHANGE:MAY 2024 FORECAST LESS MAY 2022 FORECAST(MEGAWATT-HOURS)AT GENERATION,PRE-
DSM......................................................................................................................................................................4
TABLE A.4-ANNUAL COINCIDENT PEAK CHANGE:MAY 2024 FORECAST LESS MAY 2022 FORECAST(MEGAWATTS)AT GENERATION,
PRE-DSM................................................................................................................................................................4
TABLE A.5-PROJECTED RANGE OF TEMPERATURE CHANGE IN THE 2020S AND 2050S RELATIVE TO THE 19905.................................7
TABLE A.6-WEATHER NORMALIZED JURISDICTIONAL RETAIL SALES 2000 THROUGH 2021..........................................................10
TABLE A.7-NON-COINCIDENT JURISDICTIONAL PEAK 2000 THROUGH 2O23.............................................................................10
TABLE A.8-JURISDICTIONAL CONTRIBUTION TO COINCIDENT PEAK 2000 THROUGH 2O23...........................................................10
TABLE A.9-SYSTEM ANNUAL RETAIL SALES FORECAST 2025 THROUGH 2034,POST-DSM..........................................................13
TABLE A.10-FORECASTED RETAIL SALES GROWTH IN OREGON,POST-DSM..............................................................................13
TABLE A.11-FORECASTED RETAIL SALES GROWTH IN WASHINGTON,POST-DSM.......................................................................14
TABLE A.12-FORECASTED RETAIL SALES GROWTH IN CALIFORNIA,POST-DSM...........................................................................14
TABLE A.13-FORECASTED RETAIL SALES GROWTH IN UTAH,POST-DSM ..................................................................................14
TABLE A.14-FORECASTED RETAIL SALES GROWTH IN IDAHO,POST-DSM..................................................................................14
TABLE A.15-FORECASTED RETAIL SALES GROWTH IN WYOMING,POST-DSM ...........................................................................14
APPENDIX B - REGULATORY COMPLIANCE
TABLE B.1-INTEGRATED RESOURCE PLANNING STANDARDS AND GUIDELINES SUMMARY BY STATE................................................19
APPENDIX C - PUBLIC INPUT
APPENDIX D - DEMAND-SIDE MANAGEMENT
TABLE D.1-CURRENT DEMAND RESPONSE AND ENERGY EFFICIENCY PROGRAM SERVICES AND OFFERINGS BY SECTOR AND STATE........36
TABLE D.2-CURRENT WATTSMART OUTREACH AND COMMUNICATIONS ACTIVITIES....................................................................38
TABLE D.3-CUMULATIVE DEMAND RESPONSE RESOURCE SELECTIONS(2025 IRP PREFERRED PORTFOLIO).....................................40
TABLE DA-CUMULATIVE ENERGY EFFICIENCY RESOURCE SELECTIONS(2025 IRP PREFERRED PORTFOLIO).....................................40
APPENDIX E - GRID ENHANCEMENT
APPENDIX F - FLEXIBLE RESERVE STUDY
TABLE F.1 -PORTFOLIO REGULATION RESERVE REQUIREMENTS ................................................................................55
TABLE F.2-20252023 FLEXIBLE RESOURCE COSTS AS COMPARED TO 2023 COSTS,$/MWH.....................................55
TABLE F.3-SUMMARY OF STAND-ALONE REGULATION RESERVE REQUIREMENTS....................................................73
TABLE FA-EIM DIVERSITY BENEFIT APPLICATION EXAMPLE..................................................................................75
TABLE F.5-2018-2019 RESULTS WITH PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS.................................75
V

PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX G- PLANT WATER CONSUMPTION
TABLE G.1-PLANT WATER CONSUMPTION WITH ACRE-FEET*PER YEAR.................................................................87
TABLE G.2-PLANT WATER CONSUMPTION BY STATE ACRE-FEET)...........................................................................89
TABLE G.3-PLANT WATER CONSUMPTION BY FUEL TYPE ACRE-FEET)....................................................................89
TABLE GA-PLANT WATER CONSUMPTION FOR PLANTS LOCATED IN THE UPPER COLORADO RIVER BASIN(ACRE-
FEET)...................................................................................................................................................................89
APPENDIX I - CAPACITY EXPANSION RESULTS
TABLE I.1-PRICE-POLICY SCENARIO PORTFOLIOS.....................................................................................................91
TABLE I.2-VARIANT PORTFOLIOS..............................................................................................................................91
APPENDIX L - DISTRIBUTED GENERATION STUDY
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
APPENDIX O - WASHINGTON CLEAN ENERGY ACTION PLAN
APPENDIX P - ACRONYMS
vi

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF FIGURES - VOLUME II
APPENDIX A - LOAD FORECAST
FIGURE A.1-PACIFICORP SYSTEM ENERGY LOAD FORECAST CHANGE,AT GENERATION,PRE-DSM ..................................................2
FIGURE A.2-PACIFICORP ANNUAL RETAIL SALES 2000 THROUGH 2O21 AND WESTERN REGION EMPLOYMENT.................................5
FIGURE A.3-PACIFICORP ANNUAL RESIDENTIAL USE PER CUSTOMER 2001 THROUGH 2O21..........................................................6
FIGURE A.4-COMPARISON OF UTAH 5,10,AND 20-YEAR AVERAGE PEAK PRODUCING TEMPERATURES...........................................9
FIGURE A.5-LOAD FORECAST SCENARIOS,PRE-DSM ............................................................................................................15
APPENDIX B - REGULATORY COMPLIANCE
APPENDIX C - PUBLIC INPUT
APPENDIX D - DEMAND-SIDE MANAGEMENT
APPENDIX E - GRID ENHANCEMENT
APPENDIX F - FLEXIBLE RESERVE STUDY
FIGURE F.1 -BASE SCHEDULE RAMPING ADJUSTMENT................................................................................................62
FIGURE F.2-PROBABILITY OF EXCEEDING ALLOWED DEVIATION...............................................................................67
FIGURE F.3-WIND REGULATION RESERVE REQUIREMENTS BY FORECAST-PACE....................................................69
FIGURE F.4-WIND REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACW....................69
FIGURE F.5-SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACE....................70
FIGURE F.6-SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACW..................70
FIGURE F.7-NONNER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR-PACE...............................71
FIGURE F.8-NONNER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR-PACW.............................71
FIGURE F.9-STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS-PACE..................................................72
FIGURE F.10-STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS-PACW...............................................72
FIGURE F.11-INCREMENTAL WIND AND SOLAR REGULATION RESERVE COSTS.........................................................81
FIGURE F.12-COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES,EAST BALANCING AUTHORITY AREA
(MW)..................................................................................................................................................................83
FIGURE F.13-COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES,WEST BALANCING AUTHORITY AREA
(MW)..................................................................................................................................................................83
APPENDIX G - PLANT WATER CONSUMPTION
Vii

PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX I - CAPACITY EXPANSION RESULTS
APPENDIX L - DISTRIBUTED GENERATION STUDY
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
APPENDIX O -WASHINGTON CLEAN ENERGY ACTION PLAN
APPENDIX P - ACRONYMS
v>;i

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
APPENDIX A - LOAD FORECAST
Introduction
This appendix reviews the load forecast used in the modeling and analysis of the 2025 Integrated
Resource Plan ("IRP"), including scenario development for case sensitivities. The load forecast
used in the IRP is an estimate of the energy sales and peak demand over a 20-year period. The 20-
year horizon is important to anticipate electricity demand to develop a timely response of
resources.
In the development of its load forecast PacifiCorp employs econometric models that use historical
data and inputs such as regional and national economic growth, weather, seasonality, and other
customer usage and behavior changes. The forecast is divided into classes that use energy for
similar purposes and at comparable retail rates. These separate customer classes include
residential, commercial, industrial, irrigation, and lighting customer classes. The classes are
modeled separately using variables specific to their usage patterns. For residential customers,
typical energy uses include space heating, air conditioning, water heating, lighting, cooking,
refrigeration, dish washing, laundry washing, televisions, and various other end-use appliances.
Commercial and industrial customers use energy for production and manufacturing processes,
space heating, air conditioning, lighting, computers, and other office equipment.
Jurisdictional peak load forecasts are developed using econometric equations that relate observed
monthly peak loads, peak producing weather and the weather-sensitive loads for all classes. The
system coincident peak forecast, which is used in portfolio development, is the maximum load
required on the system in any hourly period and is extracted from the hourly forecast model.
Summary Load Forecast
PacifiCorp updated its load forecast in May 2024. The compound annual load growth rate for the
10-year period (2025 through 2034) is 2.44 percent. Relative to the load forecast prepared for the
2023 IRP,PacifiCorp's 2034 forecast load requirement decreased in Oregon,California,Wyoming
and Idaho,resulting in PacifiCorp system load requirement to decline 3.01 percent in 2034. Figure
A.1 provides a comparison of the 2025 IRP and the 2023 IRP load forecasts.
1

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Figure A.1 —PacifiCorp System Energy Load Forecast Change, at Generation, re-DSM
Forecasted Annual System
Load (GWh)
2023 IRP --M-2025 IRP
120,000
100,000
80,000
0
x 60,000
40,000
on
U 20,000
Vl l- 00 C� O N M 't W) "0 r­ 00 01 O M 't
N N N N N M M M M M M M M M M I �t �
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
Table A.l and Table A.2 show the annual load and coincident peak load forecast when not
reducing load projections to account for new energy efficiency measures.' 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.
Table A.1 —Forecasted Annual Load, 2025 through 2034 (Megawatt-hours), at Generation,
re-DSM
Year otal RMO— NMI L, mdu WY
2025 65,060,422 16,427,112 4,545,410 844,170 29,729,280 9,662,750 3,851,700
2026 65,709,687 16,686,547 4,573,810 844,790 30,092,110 9,640,700 3,871,730
2027 68,479,409 16,981,229 4,761,850 84 ,,380 32,331,920 9,666,940 3,893,090
2028 71,791,117 17,211,827 4,957,640 845,780 35,172,110 9,684,200 3,919,560
2029 73,628,022 17,382,202 4,967,740 842,310 36,817,630 9,686,200 3,931,940
2030 75,117,094 17,597,704 4,993,880 841,360 38,053,630 9,681,100 3,949,420
2031 76,867,685 17,819,165 5,018,660 840,620 39,526,380 9,696,570 3,966,290
2032 78,480,937 18,085,127 5,055,940 842,410 40,802,960 9,704,760 3,989,740
2033 79,769,335 18,298,195 5,071,770 839,820 41,856,710 9,700,290 4,002,550
2034 80,843,645 18,574,275 5,100,920 839,770 42,614,010 9,691,460 4,023,210
ompound Annual Growth Rate
2025-34 2.44% 1.37% 1.29% -0.06% 4.08% 0.03% 0.49%
'Energy efficiency load reductions are included as resources in the Plexos model.
2

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Table A.2-Forecasted Annual Coincident Peak Load(Me awatts) at Generation, re-DSM
Year Total OR WA CA UT WY ID
2025 11,374 2,758 830 146 5,647 1,233 760
2026 11,410 2,779 841 147 5,675 1,211 756
2027 11,708 2,808 880 147 5,909 1,211 753
2028 12,085 2,825 886 148 6,275 1,213 739
2029 12,303 2,848 891 148 6,462 1,214 739
2030 12,501 2,879 895 148 6,622 1,218 740
2031 12,824 2,959 898 148 6,830 1,220 769
2032 12,961 2,931 901 148 6,998 1,218 765
2033 13,156 2,978 904 148 7,157 1,218 751
2034 13,358 3,073 941 152 7,210 1,210 773
o npound Annual Growth Rate
2025-34 1.80% 1.21% 1.40% 0.44% 2.75°/u -0.21% 0.18%
Table A.3 - Annual Load Change: May 2024 Forecast less May 2022 Forecast (Megawatt-
hours) at Generation, re-DSM
Year Total OR WA CA UT ID
2025 (4,744,638) (3,303,208) (155,350) (11,050) (631,940) (412,110) (230,980)
2026 (4,228,733) (3,771,103) (147,950) (8,180) 404,630 (472,540) (233,590)
2027 (4,170,361) (4,780,061) 5,020 (8,800) 1,297,500 (450,000) (234,020)
2028 (4,890,003) (6,234,133) 146,440 (10,700) 1,988,370 (544,910) (235,070)
2029 (4,291,258) (6,570,578) 126,430 (12,850) 2,956,270 (553,770) (236,760)
2030 (3,694,746) (6,468,356) 108,530 (14,430) 3,569,730 (651,450) (238,770)
2031 (3,513,005) (7,002,525) 87,960 (15,980) 4,326,490 (667,550) (241,400)
2032 (2,840,843) (7,075,753) 65,540 (17,550) 5,202,610 (771,970) (243,720)
2033 (2,452,895) (7,121,585) 45,520 (18,880) 5,694,760 (807,980) (244,730)
2034 (2,507,895) (7,167,315) 23,940 (20,350) 5,768,680 (868,020) (244,830)
Table A.4 - Annual Coincident Peak Change: May 2024 Forecast less May 2022 Forecast
(Megawatts) at Generation, pre-DSM
Year Total OR W CA UT
2025 (373) (253) (26) (1) 19 (68) (43)
2026 (349) (275) (30) (1) 103 (94) (52)
2027 (343) (380) (7) (2) 202 (95) (60)
2028 (400) (499) (19) (4) 282 (105) (55)
2029 (380) (639) (36) (9) 439 (77) (59)
2030 (314) (628) (51) (10) 521 (83) (63)
2031 (298) (672) (68) (12) 616 (91) (72)
2032 (248) (701) (84) (13) 729 (97) (82)
2033 (191) (693) (102) (14) 800 (104) (79)
2034 (155) (638) (85) (11) 762 (121) (62)
3

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Load Forecast Assumptions
Regional Economy by Jurisdiction
The PacifiCorp electric service territory is comprised of six states and within these states the
Company serves customers in a total of 90 counties. The level of retail sales for each state and
county is correlated with economic conditions and population statistics in each state. PacifiCorp
uses both economic data, such as employment, and population data, to forecast its retail sales.
Looking at historical sales and employment data for PacifiCorp's service territory, 2000 through
2023, in Figure A.2, it is apparent that PacifiCorp's retail sales are correlated to economic
conditions in its service territory, and most recently the economic downturn and rebound from the
COVID-19 pandemic.
Figure A.2 — PacifiCorp Annual Retail Sales 2000 through 2021 and Western Region
Employment
Retail Sales and Service Territory Employment
58,000 System Annual Sales —Western Region Employment 39.0
56,000
37.0 �
c
54,000
35.0
52,000 E
s 33.0 c
3 50,000 E
31.0 0
48,000 a
46,000 29.0 LU
44,000 27.0
42,000 1 25.0
T)OO -'001����0o��ooA�oos�oo6��������9"a� �0�1�01�101��o1p�o1S1oJ6�oz��o���of9�o� 1o�r
The 2025 IRP forecast utilizes the February 2024 release of S&P Global Market Intelligence
(formerly known as IHS Markit) economic driver forecast, whereas the 2023 IRP relied on the
March 2022 release from S&P Global Market Intelligence. Figure A.3 shows the weather
normalized average system residential use per customer.
4

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
Figure A.3—PacifiCorp Annual Residential Use per Customer 2001 through 2021
System Residential Use per Customer
E 11,000
0
4�
� r
m
10,500
c
a
10,000
.•
L
a 9,500 -
9,000
f0
L
a 8,500
8,000
�'0 � 1�s c�`, �00� �Oj j �0f� �OVS �0j, �019 �0��
E(eath
PacifiCorp's load forecast is based on historical actual weather adjusted for expectations and
impacts from climate change. The historical weather is defined by the 20-year period of 2004
through 2023. The climate change weather uses the data from the historical period and adjusts the
percentile of the data to achieve the expected target average annual temperature and calculate the
HDD and CDD impacts and peak producing weather impacts within the energy forecast and peak
forecast, respectively.
The climate change weather target temperature relies on actual 1990 average temperatures and
projected temperature increases over 1990 average temperatures as determined by the United
States Bureau of Reclamation (Reclamation) in the West-Wide Climate Risk Assessments:
Hydroclimate Projections Study (Study).2 PacifiCorp determined daily average temperatures and
peak producing temperatures that correspond to the midpoint of the projected temperature increase
between the Representative Concentration Pathway(RCP)4.5 and RCP 8.5 ranges in the Study.
2 United States Bureau of Reclamation,March 2021,Managing Water in the West,Technical Memorandum No.
ENV-2021-001,West-Wide Climate Risk Assessments:Hydroclimate Projections.
https://www.usbr.gov/climate/secure/docs/2021 secure/westwidesecurereport 1-2.pdf
5

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
Table A.5 —Projected Range of Temperature Change in the 2020s and 2050s relative to the
1990s,
PacifiCorp Projected Range of Temperature Change
:ureau of Reclamation Site Jurisdiction (OF)*
Assumption a A
02 OS
Klamath River near Klamath California 1.7 to 2.6 3.6 to 5.2
Snake River Near Heise Idaho 1.6 to 3.0 4.1 to 5.9
Klamath River near Seiad Valley Oregon 1.8 to 2.7 3.7 to 5.3
Green River near Greendale Utah 1.8 to 3.3 4.2 to 6.3
Yakima River at Parker Washington 1.8 to 2.8 3.6 to 5.6
Green River near Greendale Wyoming 1.8 to 3.3 4.2 to 6.3
*Lower bound of temperature projections based on RCP 4.5,while upper bound based on RCP 8.5
In addition to climate change weather discussed above, PacifiCorp has reviewed the
appropriateness of using the average weather from a shorter time period as its "normal" peak
weather. Figure A.4 indicates that peak producing weather does not change significantly when
comparing five, 10, or 20-year average weather.
PacifiCorp also updated its temperature spline models to the five-year time period of October 2018
— September 2023. PacifiCorp's spline models are used to model the commercial, residential and
irrigation class temperature sensitivity at varying temperatures.
3 Ibid.
6

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
Figure A.4-Comparison of Utah 5, 10, and 20-Year Average Peak Producing
Tem eratures
Utah Average Peak Producing Weather
(Average Dry Bulb Temperature on Peak Day (Deg
F.))
20 Year Average --C-10 Year Average 5 Year Average
100
90
80
70
60
50
Ar
A 40
30
20
10
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Statistically Adjusted End-Use ("SAE")
PacifiCorp models sales per customer for the residential class using the SAE model, which
combines the end-use modeling concepts with traditional regression analysis techniques. Major
drivers of the SAE-based residential model are heating and cooling related variables, equipment
shares, saturation levels and efficiency trends, and economic drivers such as household size,
income, and energy price. PacifiCorp uses ITRON for its load forecasting software and services,
as well as the SAE. To predict future changes in the efficiency of the various end uses for the
residential class, an Excel spreadsheet model obtained from ITRON was utilized; the model
includes appliance efficiency trends based on appliance life as well as past and future efficiency
standards. The model embeds all currently applicable laws and regulations regarding appliance
efficiency, along with life cycle models of each appliance. The life cycle models, based on the
decay and replacement rate are necessary to estimate how fast the existing stock of any given
appliance turns over,i.e.,newer more efficient equipment replacing older less efficient equipment.
The underlying efficiency data is based on estimates of energy efficiency from the US Department
of Energy's Energy Information Administration (EIA). The EIA estimates the efficiency of
appliance stocks and the saturation of appliances at the national level and for individual Census
Regions.
Individual Customer Forecast
PacifiCorp updated its load forecast for a select group of large industrial customers,self-generation
facilities of large industrial customers,and data center forecasts within the respective jurisdictions.
7

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Changes to PacifiCorp's load forecast are driven by lower projected demand from new large
customers, who are expected to provide or pay for their necessary resources and transmission.
Customer forecasts are provided by the customer to PacifiCorp through a regional business
manager("RBM").
Actual Load Data
Note— Certain load forecast tables indicated in the following pages are not included in the
2025 Draft IRP, and are anticipated to be provided in the March 31, 2025 final filing.
With the exception to the industrial and the street lighting classes,PacifiCorp uses actual load data
from January 2006 through February 2024.The historical data period used to develop the industrial
monthly sales forecast is from January 2006 through February 2024 in California, Idaho, Utah,
Washington and Wyoming. January 2008 through February 2024 is used in Oregon. The historical
data period used to develop the street light monthly sales forecast for Oregon is from April 2006
through February 2024 and for Utah it is January 2007 through February 2024.
Table A.6—Weather Normalized Jurisdictional Retail Sales 2000 through 2021
To be included within final 2025 IRP submittal.
Table A.7—Non-Coincident Jurisdictional Peak 2000 through 2023
To be included within final 2025 IRP submittal.
Table A.8—Jurisdictional Contribution to Coincident Peak 2000 through 2023
To be included within final 2025 IRP submittal.
System Losses
Line loss factors are derived using the five-year average of the percent difference between the
annual system load by jurisdiction and the retail sales by jurisdiction. System line losses were
updated to reflect actual losses for the five-year period ending December 31, 2023.
Forecast Methodology Overview
Demand-side Management Resources in the Load Forecast
PacifiCorp modeled as a resource option to be selected as part of a cost-effective portfolio resource
mix using the Plexos capacity expansion optimization model. The load forecast used for IRP
portfolio development excluded forecasted load reductions from energy efficiency; Plexos then
determines the amount of energy efficiency—expressed as supply curves that relate incremental
DSM quantities with their costs—given the other resource options and inputs included in the
model. The use of energy efficiency supply curves, along with the economic screening provided
by Plexos, determines the cost-effective mix of energy efficiency for a given scenario.
8

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Modeling overview
The load forecast is developed by forecasting the monthly sales by customer class for each
jurisdiction. The residential sales forecast is developed as a use-per-customer forecast multiplied
by the forecasted number of customers.
The customer forecasts are based on a combination of regression analysis and exponential
smoothing techniques using historical data from January 2006 to February 2024.For the residential
class, PacifiCorp forecasts the number of customers using S&P Global Market Intelligence
forecast of each state's population or number of households as the major driver.
PacifiCorp uses a differenced model approach in the development of the residential customer
forecast. Rather than directly forecasting the number of customers, the differenced model predicts
the monthly change in number of customers.
PacifiCorp models sales per customer for the residential class using the SAE model discussed
above, which combines the end-use modeling concepts with traditional regression analysis
techniques.
For the commercial class, PacifiCorp forecasts sales using regression analysis techniques with
non-manufacturing employment and non-farm employment designated as the major economic
drivers, in addition to weather-related variables. Monthly sales for the commercial class are
forecast directly from historical sales volumes,not as a product of the use per customer and number
of customers. The development of the forecast of monthly commercial sales involves an additional
step; to reflect the addition of a large "lumpy" change in sales such as a new data center, monthly
commercial sales are increased based on input from PacifiCorp's RBM's. The treatment of large
commercial additions is similar to the methodology for large industrial customer sales, which is
discussed below.
Monthly sales for irrigation and street lighting are forecast directly from historical sales volumes,
not as a product of the use per customer and number of customers.
The majority of industrial sales are modeled using regression analysis with trend and economic
variables. Manufacturing employment is used as the major economic driver in all states with
exception of Utah and West Wyoming, in which an Industrial Production Index and mining
employment, respectively, is used. For a small number of the very largest industrial customers,
PacifiCorp prepares individual forecasts based on input from the customer and information
provided by the RBM's.
After PacifiCorp develops the forecasts of monthly energy sales by customer class, a forecast of
hourly loads is developed in two steps. First, monthly peak forecasts are developed for each state.
The monthly peak model uses historical peak-producing weather for each state and incorporates
the impact of weather on load above baseload through several weather variables that drive heating
and cooling usage. The weather variables include the average temperature on the peak day and
lagged average temperatures from up to two days before the day of the forecast. The peak forecast
is based on the climate change peak-producing weather discussed above.
Second, PacifiCorp develops hourly load forecasts for each state using hourly load models that
include state-specific hourly load data, daily weather variables, the 20-year average temperatures
9

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
for the 20-year period 2004 through 2023, a typical annual weather pattern, and day-type variables
such as weekends and holidays as inputs to the model. The hourly loads are adjusted to match the
monthly peaks from the first step above. Hourly loads are then adjusted so the monthly sum of
hourly loads equals monthly sales plus line losses.
After the hourly load forecasts are developed for each state, hourly loads are aggregated to the
total system level. The system coincident peaks can then be identified, as well as the contribution
of each jurisdiction to those monthly peaks.
Electrification Adjustments
The load forecast used for 2025 IRP portfolio development includes PacifiCorp's expectations for
transportation electrification based on current and expected electric-vehicle (EV) adoption trends.
These projections were incorporated as a post-model adjustment to the residential and commercial
sales forecasts.
Electric vehicle adoption and load impacts vary by state depending on a variety of socioeconomic
factors and policies particular to each state. To develop a prospective forecast of EV adoption,
PacifiCorp developed a model to assess trends for light-duty EVs and medium-duty EVs. To
develop a future EV adoption curve, PacifiCorp reviewed three national EV forecasts, each
representing varying degrees of aggressiveness. While these forecasts represent national trends,
the adoption curves themselves can be applied and adapted to state-specific parameters to reflect
current market conditions in the state. PacifiCorp calibrates each adoption curve source to base
inputs from EIA's Annual Energy Outlook (AEO) projections and estimated historical vehicle
actuals. The AEO inputs include estimated shares of battery electric vehicles and plug-in hybrid
electric vehicles as well as light-duty vehicles and light-duty trucks. Each of the national adoption
curve sources is discussed below to help contextualize the various sources reviewed for this plan's
EV adoption forecast.4
2025 IRP is based on a specific EV shape for EV loads. Historically, EV loads were added to
jurisdictional loads and shaped based on jurisdictional load shape. While electric vehicle loads
were small, this approach generated satisfactory results, but with growth drivers such as state and
federal mandates and the Inflation Reduction Act of 2022, EV loads have an increasing potential
impact on loads and peaks. It is important that this growing impact on loads be modeled correctly
both so that PacifiCorp can plan for the load effectively and so that programs to mitigate for this
growth, such as time-of-use (TOU)rates can be introduced and their benefits correctly quantified.
The load forecast also incorporates PacifiCorp's expectations for building electrification
initiatives.In the near-term,building electrification is relatively minor share of load but is expected
to grow over time as state and national policies encouraging fuel substitution and electrification
become more prevalent. PacifiCorp's building electrification forecast is based on expected fuel
shares for space heating and water heating equipment at the end of its useful life and future new
construction shares of electric fuel for these end-uses over time. Adoption curves are calibrated to
expected equipment turnover and new construction rates in alignment with assumptions used in
the Conservation Potential Assessment. Adoption curves and timing of building electrification is
4 Transportation electrification impacts for Oregon and Washington may differ slightly from estimated impacts
provided in transportation electrification plans as result of the vintage associated with data inputs.
10

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
estimated based on the state specific policies or known market trends supporting advancement of
building electrification.
PacifiCorp continually assesses both transportation and building electrification market trends,
policies, and adoptions levels in each state. As these markets evolve, PacifiCorp will continue to
update forecasts to reflect new trends as they occur.
Private Generation
The 2025 IRP load forecast relies on private generation adoption expectations as determined by
third-party vendor, DNV. The Distributed Generation Forecast Behind-the-Meter Resource
Assessment was developed by DNV for Utah, Oregon, Idaho, Wyoming, California, and
Washington. The study evaluated the expected adoption of behind-the-meter(BTM)technologies
including photovoltaic solar, photovoltaic solar coupled with battery storage, small scale wind,
small scale hydro, reciprocating engines, and microturbines for a 20-year forecast horizon. The
study provided projections for three cases, which includes the base, high, and low adoption
projections.
Please refer to Appendix L — Distributed Generation Study for additional information regarding
the methodology and assumptions used to develop the Distributed Generation Forecast Behind-
the-Meter Resource Assessment.
ales Forecast at the Customer Meter
This section provides total system and state-level forecasted retail sales summaries measured at
the customer meter by customer class including load reduction projections from new energy
efficiency measures from the Preferred Portfolio.
To be included within final 2025 IRP submittal.
Table A.9—System Annual Retail Sales Forecast 2025 through 2034, post-DSM
To be included within final 2025 IRP submittal.
State Summaries
Oregon
Table A.10 summarizes Oregon state forecasted retail sales growth by customer class.
Table A.10—Forecasted Retail Sales Growth in Oregon, post-DSM
To be included within final 2025 IRP submittal.
Washington
Table A.I I summarizes Washington state forecasted retail sales growth by customer class.
11

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Table A.11 —Forecasted Retail Sales Growth in Washington,post-DSM
To be included within final 2025 IRP submittal.
California
Table A.12 summarizes California state forecasted sales growth by customer class.
Table A.12 -Forecasted Retail Sales Growth in California, post-DSM
To be included within final 2025 IRP submittal.
Utah
Table A.13 summarizes Utah state forecasted sales growth by customer class.
Table A.13 —Forecasted Retail Sales Growth in Utah,post-DSM
To be included within final 2025 IRP submittal.
Idaho
Table A.14 summarizes Idaho state forecasted sales growth by customer class.
Table A.14 -Forecasted Retail Sales Growth in Idaho,post-DSM
To be included within final 2025 IRP submittal.
WyomingError! Reference source not found. summarizes Wyoming state forecasted sales g
rowth by customer class.
Table A.15—Forecasted Retail Sales Growth in Wyoming, post-DSM
To be included within final 2025 IRP submittal.
Alternative Load Forecast Scenarios
The purpose of providing alternative load forecast cases is to determine the resource type and
timing impacts resulting from a change in the economy or system peaks as a result of varying
temperatures and economic conditions.
High and Low Private Generation Scenarios
As noted above, DNV's Distributed Generation Forecast Behind-the-Meter Resource Assessment
included results for three private generation scenarios, which includes the base, high, and low
adoption projections. The high and low private generation load forecast scenarios rely on the high
and low private generation adoption scenarios produced by DNV. Please refer to Appendix L —
Distributed Generation Study for additional information regarding the methodology and
assumptions used in the study.
12

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Optimistic and Pessimistic Scenarios
The May 2024 forecast is the baseline scenario. For the high and low load growth scenarios,
optimistic and pessimistic economic driver assumptions from S&P Global Market Intelligence
were applied to the economic drivers in PacifiCorp's load forecasting models. These growth
assumptions were extended for the entire forecast horizon. Further, the high and low load growth
scenarios also incorporate the standard error bands for the energy and the peak forecast to
determine a 95%prediction interval around the base IRP forecast. The high scenario incorporates
PacifiCorp's low private generation forecast, while the low scenario incorporates the high private
generation forecast. Lastly, the high scenario incorporates high climate change temperatures,
which are based on RCP 8.5 and the low scenario incorporate low climate change temperatures,
which are based on RCP 4.5 (see Table A.5).
The 95% prediction interval is calculated at the system level and then allocated to each state and
class based on their contribution to the variability of the system level forecast. The standard error
bands for the jurisdictional peak forecasts were calculated in a similar manner. The final high load
growth scenario includes the optimistic economic forecast and low private generation forecast plus
the monthly energy adder and the monthly peak forecast with the peak adder. The final low load
growth scenario includes the pessimistic economic forecast and high private generation forecast
minus the monthly energy adder and monthly peak forecast minus the peak adder.
1-in-20 Year Scenario
For the 1-in-20 year (5 percent probability) extreme weather scenario, PacifiCorp used 1-in-20
year peak weather for summer (July) months for each state. The 1-in-20 year peak weather is
defined as the year for which the peak has the chance of occurring once in 20 years.
High Data Center Scenario
The 2025 IRP incorporates a high data center scenario given that center load potential is emerging
as a key driver to incremental resource and transmission needs across the industry. The high data
center scenario accounts for all active data center requests from prospective data center customers
assuming the demand as requested by the customer.
Figure A.5 show the comparison of the above scenarios relative to the Base Case scenario.
Figure A.5—Load Forecast Scenarios,pre-DSM
To be included within final 2025 IRP submittal.
13

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
14

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
APPENDIX B - REGULATORY COMPLIANCE
This appendix describes general state requirements for PacifiCorp's 2025 Integrated Resource Plan
(IRP). Line-item details for each states' compliance, which is dependent on information that is not
included in this draft, will be provided in the March 31, 2025 filing.
General Complian
PacifiCorp prepares the IRP on a biennial basis and files the IRP with state commissions. The
preparation of the IRP is done in an open public process with consultation from all interested parties,
including commissioners and commission staff,customers,and other stakeholders. This open process
provides parties with a substantial opportunity to contribute information and ideas in the planning
process and serves to inform all parties on the planning issues and approach. The public input process
for this IRP is described in Volume I, Chapter 2 (Introduction), as well as Volume II, Appendix C
(Public).
The IRP provides a framework and plan for future actions to ensure PacifiCorp continues to provide
reliable and least-cost electric service to its customers. The IRP evaluates, over a twenty-year
planning period,the future load of PacifiCorp customers and the resources required to meet this load.
To fill any gap between changes in loads and existing resources, while taking into consideration
potential early retirement of existing coal units as an alternative to investments that achieve
compliance with environmental regulations, the IRP evaluates a broad range of available resource
options, as required by state commission rules. These resource options include supply-side, demand-
side, and transmission alternatives. The evaluation of the alternatives in the IRP, as detailed in
Volume I, Chapter 8 (Modeling and Portfolio Evaluation) and Chapter 9 (Modeling and Portfolio
Selection Results)meets this requirement and includes the impact to system costs, system operations,
supply and transmission reliability, and the impacts of various risks, uncertainties and externality
costs that could occur.
To perform the analysis and evaluation, PacifiCorp employs a suite of models that simulate the
complex operation of the PacifiCorp system and its integration within the Western interconnection.
The models allow for a rigorous testing of a broad range of commercially feasible resource alternatives
available to PacifiCorp on a consistent and comparable basis. The analytical process, including the
risk and uncertainty analysis, fully complies with IRP standards and guidelines, and is described in
detail in Volume I, Chapter 8.
The IRP analysis is designed to define a resource plan that is least-cost,after consideration of risks
and uncertainties. To evaluate resource alternatives and identify a least-cost, risk adjusted plan,
portfolio resource options were developed and tested against each other. This testing included
examination of various tradeoffs among the portfolios, such as average cost versus risk,reliability,
customer rate impacts,and average annual carbon dioxide(CO2)emissions. This draft portfolio
analysis and the results and conclusions drawn from the analysis are described in Volume I, Chapter
9.
15

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Consistent with the IRP standards and guidelines of Oregon, Utah, and Washington, this draft
includes an Action Plan in Volume I, Chapter 10 (Action Plan). The Action Plan details near-term
actions that are necessary to ensure PacifiCorp continues to provide reliable and least-cost electric
service after considering risk and uncertainty. The Action Plan also provides a progress report on
action items contained in the 2023 IRP.
The 2025 IRP and related Action Plan are filed with each commission with a request for
acknowledgment or acceptance, as applicable. Acknowledgment or acceptance means that a
commission recognizes the IRP as meeting all regulatory requirements at the time of
acknowledgment.In a case where a commission acknowledges the IRP in part or not at all,PacifiCorp
may modify and seek to re-file an IRP that meets their acknowledgment standards or address any
deficiencies in the next plan.
State commission acknowledgment orders or letters typically stress that an acknowledgment does not
indicate approval or endorsement of IRP conclusions or analysis results. Similarly, an
acknowledgment does not imply that favorable ratemaking treatment for resources proposed in the IRP
will be given.
California
Public Utilities Code Section 454.52, mandates that the California Public Utilities Commission
(CPUC) adopt a process for load serving entities to file an IRP beginning in 2017. In February 2016,
the CPUC opened a rulemaking to adopt an IRP process and address the scope of the IRP to be filed
with the CPUC (Docket R.16-02-007).
Decision (D.) 18-02-018 instructed PacifiCorp to file an alternative IRP consisting of any IRP
submitted to another public regulatory entity within the previous calendar year (Alternative Type 2
Load Serving Entity Plan). D.18-02-018 also instructed PacifiCorp to provide an adequate description
of treatment of disadvantaged communities, as well as a description of how planned future
procurement is consistent with the 2030 Greenhouse Gas Benchmark.
PacifiCorp also provides its IRP and an IRP Supplement in lieu of providing a Renewables Portfolio
Standard Procurement Plan, as authorized by Public Utilities Code Section 399.17(d). Requirements
for PacifiCorp's IRP Supplement are outlined in an annual Assigned Commissioner's Ruling from
the CPUC' and D.22-12-030 issued on December 19, 2022, approving the company's 2021 IRP
Supplement(2022 Off-Year Supplement to its 2021 IRP).
On October 18, 2019, PacifiCorp submitted its 2019 IRP in compliance with D.18-02-018.
On April 6, 2020, the CPUC issued D.20-03-028, which reiterated PacifiCorp's ability to file an
alternative IRP.
I The most recent Assigned Commissioner's Ruling is the Assigned Commissioner and Assigned Administrative Law
Judge's Ruling Identifying issues and Schedules of Review for 2022 Renewables Portfolio Standard Procurement Plans
and Denying Joint IOU's Motion to File Advice Letters for Market Offer Process, Rulemaking 18-07-003 (April 11,
2022).
16

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
On September 1, 2021, PacifiCorp filed its 2021 IRP in Docket R.18-07-003 in compliance with
D.08-05-029.
On November 1, 2022, PacifiCorp filed its 2021 IRP in Docket R.20-05-003 in compliance with
D.18-02-018, D.20-03-028, and D.22-02-004.
On January 18, 2023, PacifiCorp filed its 2021 IRP Supplement (2022 Off-Year Supplement to its
2021 IRP) in Docket R.18-07-003 in compliance with D.08-05-029 and D.22-12-030.
California Public Utilities Code Section 454.5 allows utility with less than 500,000 customers in the
state to request an exemption from filing an IRP. However, PacifiCorp files its IRP and IRP
supplements with the California Public Utilities Commission to address the company plan for
compliance with the California RPS requirements.
Idaho
The Idaho Public Utilities Commission's (Idaho PUC) Order No. 22299, issued in January 1989,
specifies integrated resource planning requirements. This order mandates that PacifiCorp submit a
Resource Management Report (RMR) on a biennial basis. The intent of the RMR is to describe the
status of IRP efforts in a concise format, and cover the following areas:
Each utility's RMR should discuss any flexibilities and analyses considered during
comprehensive resource planning, such as: (1) examination of load forecast uncertainties;
(2) effects of known or potential changes to existing resources; (3) consideration of demand
and supply side resource options; and (4) contingencies for upgrading, optioning and
acquiring resources at optimum times (considering cost, availability, lead time, reliability,
risk, etc) as future events unfold.
This IRP is submitted to the Idaho PUC as the Resource Management Report for 2023, and fully
addresses the above report components.
Oregon
This IRP is submitted to the Oregon Public Utility Commission (OPUC) in compliance with its
planning guidelines issued in January 2007 (Order No. 07-002). The Oregon PUC's IRP guidelines
consist of substantive requirements (Guideline 1),procedural requirements (Guideline 2),plan filing,
review, and updates (Guideline 3), plan components (Guideline 4), transmission (Guideline 5),
conservation(Guideline 6), demand response (Guideline 7), environmental costs(Guideline 8, Order
No. 08-339), direct access loads (Guideline 9), multi-state utilities (Guideline 10), reliability
(Guideline 11), distributed generation (Guideline 12), resource acquisition (Guideline 13), and
flexible resource capacity(Order No. 12-013). Consistent with the earlier guidelines(Order 89-5072),
the Oregon PUC notes that acknowledgment does not guarantee favorable ratemaking treatment,only
that the plan seems reasonable at the time acknowledgment is given. Table B provides detail on how
this plan addresses each of the requirements.3
z Public Utility Commission of Oregon,Order No. 12-013,Docket No. 1461,January 19,2012.
s During the 2025 IRP public input meeting series,an inquiry was made regarding the requirement to provide an IRP
Update in between major IRP filings. See Appendix M,stakeholder feedback form#8(Western Resource Advocates)
for discussion of this requirement.
17

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
Utah
This IRP is submitted to the Public Service Commission of Utah in compliance with its 1992 Order on
Standards and Guidelines for Integrated Resource Planning (Docket No. 90-2035-01, "Report and
Order on Standards and Guidelines").Table B documents how PacifiCorp complies with each of these
standards.
Washington
This IRP is submitted to the Washington Utilities and Transportation Commission (WUTC) in
compliance with its rule requiring a two-year progress report of the previously filed plan, which was
the Company's 2021 IRP (Washington Administrative Code 480-100-625) (effective, December
2020).
In its report, the rule requires PacifiCorp to include an update of its load forecast; demand-side
resource assessment, including new conservation potential assessment; resource costs; and the
portfolio analysis and preferred portfolio. The report must also include other updates that are
necessary due to changing state or federal requirements,or significant changes to economic or market
forces;and an update for any elements found in the Company's current Clean Energy Implementation
Plan (CEIP). Please refer to Appendix O (Washington Two-year Progress Report Additional
Elements) for additional detail regarding updates to elements of the Company's CEIP.
Wyoming
Wyoming Public Service Commission issued new rules that replaced the previous set of rules on
March 21,2016. Chapter 3, Section 33 outlines the requirements on filing IRPs for any utility serving
Wyoming customers. The rule, shown below, went into effect in March 2016.
Section 33. Integrated Resource Plan (IRP). Each utility serving in Wyoming that files an
IRP in another jurisdiction shall file that IRP with the Commission. The Commission may
require any utility to file an IRP.
18

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Table B.1 —Integrated Resource Planning Standards and Guidelines Summary by State
Topic Oregon Utah Washingto Idaho Wyol
Source Order No.07-002, Docket 90-2035-01 WAC 480-100-251 Least Order 22299 Wyoming Electric,Gas
Investigation Into Standards and Guidelines cost planning,May 19, Electric Utility and Water Utilities,
Integrated Resource for Integrated Resource 1987,and as amended Conservation Standards Chapter 3,Section 33,
Planning,January 8, Planning June 18, 1992. from WAC 480-100-238 and Practices March 21,2016.
2007,as amended by Least Cost Planning January 1989.
Order No.07-047. Rulemaking, January 9,
2006(Docket#UE-
Guideline 2c: The 030311).
utility must provide
a draft IRP for WAC 480-100-625(3)
public review and Draft IRP.
comment prior to
filing a final plan Commission General
with the Order R-601 further
Commission. adopted IRP rules
compliant with CETA.
Order No.08-339,
Investigation into the
Treatment of CO2 Risk in
the Integrated Resource
Planning Process,June
30,2008
Order No.09-041,New
Rule OAR 860-027-
0400,
implementing Guideline
3,"Plan Filing,Review,
and Updates".
Order No. 12-013,
"Investigation of Matters
related to Electric
Vehicle Charging",
January 19,2012
19

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Filing Least-cost plans must be An IRP is to be submitted Submit a least cost plan to Submit Resource Each utility serving in
Requirements filed with the Oregon to commission. the WUTC.Plan to be Management Report on Wyoming that files and
PUC. developed with planning status.Also,file IRP in another
consultation of WUTC progress reports on jurisdiction,shall file the
staff,and with public conservation,low-income IRP with the commission.
involvement. programs,lost
opportunities and
capability building.
Frequency Plans filed biennially, File biennially. Unless otherwise ordered RMR to be filed at least The commission may
within two years of its by the commission,each biennially.Conservation require any utility to file
previous IRP electric utility must file an reports to be filed an IRP.
acknowledgment order. integrated resource plan annually.Low-income
An annual update to the (IRP)with the reports to be filed at least
most recently commission by January 1, annually.Lost
acknowledged IRP is 2021,and every four Opportunities reports to
required to be filed on or years thereafter. be filed at least annually.
before the one-year Capability building
anniversary of the At least every two years reports to be filed at least
acknowledgment order after the utility files its annually.
date.While informational IRP,beginning January 1,
only,utilities may request 2023,the utility must file
acknowledgment of a two-year progress
proposed changes to the report.
action plan.
Commission Least-cost plan(LCP) IRP acknowledged if The plan will be Report does not constitute Commission advisory
Response acknowledged if found to found to comply with considered,with other pre-approval of proposed staff reviews the IRP as
comply with standards standards and guidelines. available information, resource acquisitions. directed by the
and guidelines.A decision Prudence reviews of new when evaluating the Commission and drafts a
made in the LCP process resource acquisitions will performance of the utility Idaho sends a short letter memo to report its
does not guarantee occur during rate making in rate proceedings. stating that they accept findings to the
favorable rate-making proceedings. the filing and commission in an open
treatment.The OPUC WUTC sends a letter acknowledge the report as meeting or technical
may direct the utility to discussing the report, satisfying commission conference.
revise the IRP or conduct making suggestions and requirements.
additional analysis before requirements and
an acknowledgment order acknowledges the report.
is issued.
20

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Filing Least-cost plans must be An IRP is to be submitted Submit a least cost plan to Submit Resource Each utility serving in
Requirements filed with the Oregon to commission. the WUTC.Plan to be Management Report on Wyoming that files and
PUC. developed with planning status.Also,file IRP in another
consultation of WUTC progress reports on jurisdiction,shall file the
staff,and with public conservation,low-income IRP with the commission.
involvement. programs,lost
opportunities and
capability building.
Note,however,that Rate
Plan legislation allows
pre-approval of near-term
resource investments.
Process The public and other Planning process open to In consultation with Utilities to work with The review may be
utilities are allowed the public at all stages. WUTC staff,develop and commission staff when conducted in accordance
significant involvement in IRP developed in implement a public reviewing and updating with guidelines set from
the preparation of the consultation with the involvement plan. RMRs.Regular public time to time as conditions
plan,with opportunities to commission,its staff,with Involvement by the public workshops should be part warrant.
contribute and receive ample opportunity for in development of the of process.
information. Order 07- public input. plan is required. The Public Service
002 requires that the PacifiCorp is required to Commission of Wyoming,
utility present IRP results submit a work plan for in its Letter Order on
to the Oregon PUC at a informal commission PacifiCorp's 2008 IRP
public meeting prior to review not later than 15 (Docket No.2000-346-
the deadline for written months prior to the due EA-09)adopted
public comments. date of the plan.The work commission Staff s
Commission staff and plan is to lay out the recommendation to
parties should complete contents of the IRP, expand the review process
their comments and resource assessment to include a technical
recommendations within method,and timing and conference,an expanded
six months after IRP extent of public public comment period,
filing. participation. and filing of reply
Competitive secrets must comments.
be protected. Draft IRP.No later than
four months prior to the
due date of the final IRP,
the utility must file its
draft IRP with the
commission.At
minimum,the draft IRP
21

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
must include the preferred
portfolio,CEAP,and
supporting analysis,and
to the extent practicable
all scenarios,sensitivities,
appendices,and
attachments.
(a)The commission will
hear public comment on
the draft IRP at an open
meeting scheduled after
the utility files its draft
IRP.The commission will
accept public comments
electronically and in any
other available formats,as
outlined in the
commission's notice for
the open public meeting
and opportunity to
comment.
(b)The utility must file
with the commission
completed presentation
materials concerning the
draft IRP at least five
business days prior to the
open meeting.
22

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Focus 20-year plan,with end- 20-year plan,with short- 20-year plan,with short- 20-year plan to meet load Identification of least-
effects,and a short-term term(four-year)action term(two-year)action obligations at least-cost, cost/least-risk resources
(two-year)action plan. plan. Specific actions for plan. with equal consideration and discussion of
The IRP process should the first two years and The plan describes mix of to demand side resources. deviations from least-cost
result in the selection of anticipated actions in the resources sufficient to Plan to address risks and resources or resource
that mix of options which second two years to be meet current and future uncertainties.Emphasis combinations.
yields,for society over detailed. The IRP process loads at"lowest on clarity,
the long run,the best should result in the reasonable"cost to utility understandability,
combination of expected selection of the optimal and ratepayers.Resource resource capabilities and
costs and variance of set of resources given the cost,market volatility planning flexibility.
costs. expected combination of risks,demand-side
costs,risk,and resource uncertainty,
uncertainty. resource dispatchability,
ratepayer risks,policy
impacts,environmental
risks,and equitable
distribution of benefits
must be considered.
23

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
As part of the IRP,
utilities must develop a
ten-year clean energy
action plan for
implementing RCW
19.405.030 through
19.405.050.
Elements Basic elements include: IRP will include: The plan shall include: Discuss analyses Proposed Commission
• All resources evaluated • Range of forecasts of • A range of forecasts of considered including: Staff guidelines issued
on a consistent and future load growth future demand using • Load forecast July 2016 cover:
comparable basis. • Evaluation of all methods that examine uncertainties; • Sufficiency of the
• Risk and uncertainty present and future the effect of economic • Known or potential public comment process
forces on the changes to existing • Utility strategic goals,
must be considered. resources,including consumption of resources; resource planning goals
• The primary goal must demand side,supply electricity and that . Equal consideration of and preferred resource
be least cost,consistent side and market,on a
with the long-run consistent and address changes in the demand and supply portfolio public interest. comparable basis. number,type,and side resource options; • Resource need over the
efficiency of electrical • Contingencies for near-term and long-
• The plan must be • Analysis of the role of end-uses. upgrading,optioning, term planning horizons
consistent with Oregon competitive bidding • An assessment of and acquiring resources • Types of resources
and federal energy • A plan for adapting to commercially available at optimum times. considered
policy. different paths as the conservation,including • Report on existing • Changes in expected
• External costs must be future unfolds. load management,as resource stack,load resource acquisitions
considered,and • A cost effectiveness well as an assessment of forecast and additional and load growth from
quantified where methodology. currently employed and resource menu. the previous IRP
new policies and • Environmental impacts
possible.OPUC . An evaluation of the programs needed to considered
specifies financial,competitive, obtain the conservation • Market purchase
environmental adders reliabilityand p
improvements.
(Order No. 93-695, evaluationoperational risks • Assessment of a wide • Reserve mar in
Docket UM 424). associated with g
range of conventional analysis
• Multi-state utilities resource options,and and commercially • Demand-side
should plan their how the action plan available management and
generation and addresses these risks. nonconventional
transmissions stems conservation options
y Definition of how risks generating technologies
on an integrated- are allocated between • An assessment of
system basis. ratepayers and transmission system
• Construction of shareholders capability and
resource portfolios reliability.
over the range of
24

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
identified risks and • A comparative
uncertainties. evaluation of energy
• Portfolio analysis shall supply resources
include fuel (including transmission
transportation and and distribution)and
transmission improvements in
requirements. conservation using
"lowest reasonable
• Plan includes cost"criteria.
conservation potential • An assessment and
study,demand determination of
response resources,
environmental costs, resource adequacy
metrics.
and distributed
• An assessment of
generation energy and nonenergy
technologies. benefits and reductions
• Avoided cost filing of burdens to vulnerable
required within 30 populations and highly
days of impacted communities;
acknowledgment. long-term and short-
term public health and
environmental benefits,
costs,and risks;and
energy security risk
• Integration of the
demand forecasts and
resource evaluations
into a long-range(at
least 10 years)plan.
• All plans shall also
include a progress
report that relates the
new plan to the
previously filed plan.
• Must develop a ten-year
clean energy action plan
for implementing RCW
19.405.030 through
19.405.050.
25

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
• The IRP must include a
summary of substantive
changes to modeling
methodologies or inputs
that result in changes to
the utility's resource
need,as compared to
the utility's previous
IRP.
• The IRP must include
an analysis and
summary of the avoided
cost estimate for
energy,capacity,
transmission,
distribution,and
greenhouse gas
emissions costs.The
utility must list
nonenergy costs and
benefits addressed in
the IRP and should
specify if they accrue to
the utility,customers,
participants,vulnerable
populations,highly
impacted communities,
or the general public.
• The utility must provide
a summary of public
comments received
during the development
of its IRP and the
utility's responses,
including whether
issues raised in the
comments were
addressed and
incorporated into the
final IRP as well as
26

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
documentation of the
reasons for rejecting any
public input.
27

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
28

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
APPENDIX C - PUBLIC INPUT PROCESS
A critical element of this Integrated Resource Plan (IRP) is the public input process. PacifiCorp
has pursued an open and collaborative approach involving the commissions, customers, and other
stakeholders in PacifiCorp's IRP prior to making resource planning decisions. Since these
decisions can have significant economic and environmental consequences, conducting the IRP
with transparency and full participation from interested and affected parties is essential to achieve
long-term planning objectives.
Stakeholders have been involved in the development of the 2025 IRP from the beginning. The
public input meetings held beginning in January 2024 were the cornerstone of the direct public-
input process, and 10 public input meetings are included as part of the 2025 IRP development
cycle. In addition to the 2025 IRP public input meeting series,the IRP continues to be represented
as appropriate in advisory group meetings and in communications with regulators in all
jurisdictions.
PacifiCorp's integrated resource plan website houses feedback forms included in this filing. This
standardized form allows stakeholders to provide comments, questions, and suggestions.
PacifiCorp also posts its responses to the feedback forms at the same location. Feedback forms
and PacifiCorp's responses can be found via the following link:
https://www.pacificop2.com/energ /integrated-resource-plan/comments.html
PacifiCorp's 2025 IRP continues to be a robust process involving input from many parties.
Participants included commissions, stakeholders, and industry experts. Among the organizations
that have been represented and actively involved in this collaborative effort are:
Commissions
• California Public Utilities Commission
• Idaho Public Utilities Commission
• Oregon Public Utility Commission
• Public Service Commission of Utah
• Washington Utilities and Transportation Commission
• Wyoming Public Service Commission
29

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
PacifiCorp extends its gratitude for participants'continued time and energy devoted to the IRP
process. Their participation has contributed significantly to the quality of this plan.
Stakeholders and Industry Experts
AES Corporation Powder River Basin Conservation League
Ameresco Powder River Basin Resource Council
Anchor Blue Renewable Energy Coalition
Apex Clean Energy Renewable Northwest
Applied Energy Group RMI
Birch Creek rPlus Energies
Cascade Natural Gas Salt Lake City
City of Kemmerer Wyoming Sierra Club
City of SLC SLC Corp
Cottonwood Heights, UT Southwest Energy Efficiency Project
DNV State of Wyoming
Energy Strategies University of Wyoming
Energy Trust of Oregon Utah Citizens Advocating Renewable
ENYO Energy Energy(UCARE)
ESS, INC Utah Clean Energy
Fervo Energy Utah Department of Agriculture and Food
First Principles Utah Department of Environmental Quality
Green Energy International Utah Division of Public Utilities
Grid United Utah Needs Clean Energy
Holland&Hart Utah OCS (Utah Office of Consumer
Idaho Power Services)
Idaho Public Utilities Commission Utah Public Service Commission
Intermountain Wind-Colorado Utah Valley University
Interwest Energy Alliance Vote Solar
James Dodge Russell& Stephens, P.C. Washington Public Service Commission
Key Capture Energy Washington Utilities and Transportation
Mitsubishi Heavy Industries Commission
Northwest Energy Coalition Western Electricity Coordinating Council
Northwest Power Council Western Energy Storage Task Force
NP Energy Western Resource Advocates
NWEC Wyoming Business Council
Oregon Citizen Utility Board Wyoming Coalition of Local Governments
Oregon League of Women Voters Wyoming Energy Consumers
Oregon Public Utility Commission Wyoming Office of Consumer Advocates
Orsted Wyoming Public Service Commission
Portland General Electric
30

PACIFICORP—2025 IRP APPENDIX C—PUBLIC INPUT PROCESS
General Meetings and Agendas
During the 2025 IRP public input process presentations and discussions have covered various
issues regarding inputs, assumptions, risks, modeling techniques, planned studies and analytical
results.' Below are the agendas from the public input meetings; the presentations and recordings
of the meetings are available at:
https://www.pacificorp.com/enerjz/integrated-resource-planzpublic-input-process.html
General Meetings
January 25, 2024
• 2025 IRP Public Meeting Kick-off
• 2023 IRP Filing Update
• 2025 IRP Overview
• 2023 IRP Status and Update
• 2025 IRP
o Conservation Potential Assessment Planning
o Supply-Side Resource development
March 14,2024
• Planning Environment Updates
• Input Data Development
• Optimization Modeling Overview
• PLEXOS Modeling
• 2023 IRP Update Drafting
May 2, 2024
• Conservation Potential Update
• Distributed Generation Study Overview
• Transmission Modeling Strategy
• March price curve update
• 2023 IRP Update Outcomes
June 26-27, 2024
• Federal Policy Updates
• Draft Load Forecast Update
• Hydro Forecast Under Climate Change
• Distributed Generation Update
• Reliability and Resource Adequacy
• Supply Side Resources—Alternative Fuels
• Qualifying Facility Renewals
• Transmission Interconnection Options
' The 2025 IRP public process included discussions of inputs and planned studies throughout,as noted in Appendix
M,stakeholder feedback form#3 (Oregon Public Utilities Commission)
31

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
July 17-18,2024
• 2023 IRP Filing Update
• Distribution System Planning Update
• Renewable Portfolio Standards
• Price-Policy Scenarios
• Market Reliance
• Volatility and Stochastics
• Preview 2025 IRP Studies
• Supply Side Resources Update—Assumptions and Attributes
• Emissions Modeling
• DSM Bundling Portfolio Methodology
August 14-15, 2024
• Generation Transition, Equity and Justice
• Regional Haze Update
• Emissions Reporting Update
• State Updates
• 2025 IRP Studies Update
• Existing Thermal Resource Options
• Daily Shapes
• 2023 IRP Update Progress
• Transmission Option Dependencies
• Customer Preference
• Supply Side Resource Table
September 25-26, 2024
• 2025 IRP Progress Report
• Supply-side Resources
• Data Center Load Studies
• State and Federal Updates
• Stakeholder Feedback Summary
In addition to the topics listed above, each public input meeting incorporated a concluding
discussion of stakeholder feedback forms received and next steps.
Two additional public input meetings are scheduled in the 2025 IRP public input meeting series to
be held subsequent to the December 31, 2024, distribution of the 2025 Draft IRP:
• January 22-23, 2025
• February 26-27, 2025
Stakeholder Comments
In the 2025 IRP cycle, in recognition of the importance of stakeholder feedback, PacifiCorp
provided a form which gave participants a direct opportunity to provide comments, questions, and
suggestions in addition to the opportunities for discussion at public input meetings. Please refer to
32

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
Appendix M (Stakeholder Feedback) to view submitted Stakeholder Feedback Forms, including
responses, for the 2025 IRP. These completed forms, and also a blank for new submissions, are
also located on the PacifiCorp website at the IRP comments webpage:
www.pacificop2.com/energ. /y integrated-resource-plan/comments.html.
PacifiCorp's IRP website: www.pacificorp.com/energy/integrated-resource-plan.html.
Stakeholders and members of the public can also send comments, questions and requests to the
following email address:
IR kPacifiCorp.com
33

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
34

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
APPENDIX D - DEMAND-SIDE MANAGEMENT
kntroduction
This appendix reviews the studies and reports used to support the demand-side management
(DSM) resource information used in the modeling and analysis of the 2025 Integrated Resource
Plan(IRP). In addition,it provides information on the economic DSM selections in the 2025 IRP's
Preferred Portfolio, a summary of existing DSM program services and offerings, and an overview
of the DSM planning process in each of PacifiCorp's service areas.
Conservation Potential Assessment (CPA) for 2025-2044
Since 1989, PacifiCorp has developed biennial IRPs to identify an optimal mix of resources that
balance considerations of cost, risk, uncertainty, supply reliability/deliverability, and long-run
public policy goals. The optimization process accounts for capital, energy, and ongoing operation
costs as well as the risk profiles of various resource alternatives, including traditional generation
and market purchases, renewable generation, and DSM resources such as energy efficiency, and
demand response or capacity-focused resources. Since the 2008 IRP, DSM resources have
competed directly against supply-side options, allowing the IRP model to guide decisions
regarding resource mixes, based on cost and risk.
The Conservation Potential Assessment (CPA) for 2025-2044,I conducted by Applied Energy
Group (AEG) on behalf of PacifiCorp, primarily seeks to develop reliable estimates of the
magnitude, timing, and costs of DSM resources likely available to PacifiCorp over the IRP's 20-
year planning horizon. The study focuses on resources realistically achievable during the planning
horizon, given normal market dynamics that may hinder or advance resource acquisition. Study
results were incorporated into PacifiCorp's 2025 IRP and will be used to inform subsequent DSM
planning and program design efforts. This study serves as an update of similar studies completed
since 2007.
For resource planning purposes, PacifiCorp classifies DSM resources into four categories or
"classes," differentiated by two primary characteristics: reliability and customer choice. These
resource classifications can be defined as: Class 1 is demand response (e.g., a firm, capacity
focused resource such as direct load control), Class 2 is energy efficiency (e.g., a firm energy
intensity resource such as conservation), Class 3 is demand side rates (DSR) (e.g., a non-firm,
capacity focused resource such as time of use rates), and Class 4 is non-incented behavioral-based
response (e.g., customer energy management actions through education and information).
From a system-planning perspective, demand response resources can be considered the most
reliable, as they can be dispatched by the utility. In contrast, behavioral-based resources are the
least reliable due to the resource's dependence on voluntary behavioral changes. With respect to
customer choice, demand response and energy efficiency resources should be considered
involuntary in that, once equipment and systems have been put in place, savings can be expected
to occur over a certain period. DSR and non-incented behavioral-based activities involve greater
'PacifiCorp's Demand-Side Resource Potential Assessment for 2025-2044,completed by AEG,can be found at:
www.pacificorp.com/energy/integrated-resource-plan/support.html.
35

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
customer choice and control. This assessment estimates potential from demand response, energy
efficiency, and DSR.
The CPA excludes an assessment of Oregon's energy efficiency resource potential, as this work is
performed by Energy Trust of Oregon, which provides energy efficiency potential in Oregon to
PacifiCorp for resource planning purposes.
Current DSM Program Offerings by Stat
Currently, PacifiCorp offers a robust portfolio of DSM programs and initiatives, most of
which are offered in multiple states, depending on size of the opportunity and the need.
Programs are reassessed on a regular basis. PacifiCorp has the most up-to-date programs
on its website.2 Demand response and energy efficiency program services and offerings are
available by state and sector. Energy efficiency services listed for Oregon, except for low-
income weatherization services,are provided in collaboration with Energy Trust of Oregon 3
Table D.1 provides an overview of the breadth of demand response and energy efficiency program
services and offerings available by Sector and State.
PacifiCorp has numerous DSR offerings currently available. They include metered time-of-day
and time-of-use pricing plans (in all states, availability varies by customer class), and residential
seasonal rates(Idaho and Utah). System-wide, approximately 14,467 customers were participating
in metered time-of-day and time-of-use programs as of 2023.
Savings associated with rate design are captured within the company's load forecast and are thus
captured in the integrated resource planning framework. PacifiCorp continues to evaluate DSR
programs for applicability to long-term resource planning.
PacifiCorp provides behavioral based offerings as well. Educating customers regarding energy
efficiency and load management opportunities is an important component of PacifiCorp's long-
term resource acquisition plan. A variety of channels are used to educate customers including
television, radio, newspapers, bill inserts and messages, newsletters, school education programs,
and personal contact. Load reductions due to behavioral activity will show up in demand response
and energy efficiency program results and non-program reductions in the load forecast over time.
Table D.1—Current Demand Response and Energy Efficiency Program Services and
Offerings by Sector and State
Program Services&Offerings California Oregon Washington
by Sector and State —Ent-
Residential Sector
Air Conditioner Direct Load
Control
Lighting Incentives
New Appliance Incentives
z Programs for Rocky Mountain Power can be found at www.rockymountainpower.net/savings-energy-choices.html
and programs for Pacific Power can be found at www.pacificpower.net/savings-energy-choices.html.
I Funds for low-income weatherization services are forwarded to Oregon Housing and Community Services.
36

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
Program Services&Offerings California 1 � i i Idaho i
i - - -
Heating And Cooling Incentives
Weatherization Incentives-
Windows,Insulation,Duct
Sealing,etc.
New Homes
Low-Income Weatherization
Home Energy Reports
School Curriculum
Financing Options With On-Bill
Payments
Trade Ally Outreach
Electric Vehicle Load Control
Battery Load Control
Program Services&Offerings California 1 � i i Idaho i
b - - -
Non-Residential Sector
Irrigation Load Control
Commercial and Industrial
Demand Response
Standard Incentives
Energy Engineering Services
Billing Credit Incentive(offset
to DSM charge)
Energy Management
Energy Profiler Online
Business Solutions Toolkit
Trade Ally Outreach
Small Business Lighting
Lighting Instant Incentives
Small to Mid-Sized Business
Facilitation
DSM Project Managers Partner
With Customer Account
Managers
Error! Not a valid bookmark self-reference. provides an overview of DSM related Wattsmart
Outreach and Communication activities (Class 4 DSM activities)by state.
37

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
Table D.2 — Current Wattsmart Outreach and Communications Activities
Wattsmart Outreach& I
Communications(incremental California Oregon Washington Idaho Utah Wyoming
to program
Advertising
Sponsorships
Social Media
Public Relations
Business Advocacy(awards at
customer meetings,
sponsorships,chamber
partnership,university
partnership)
Wattsmart Workshops and
Community Outreach
BE Wattsmart,Begin at Home-
in school energy education
tate-S ecific DSM Planning Processe
A summary of the DSM planning process in each state is provided below.
Utah, Wyoming and Idaho
The company's biennial IRP and associated action plan provides the foundation for DSM
acquisition targets in each state. Where appropriate, the company maintains and uses external
stakeholder groups and vendors to advise on a range of issues including annual goals for
conservation programs,development of conservation potential assessments,development of multi-
year DSM plans, program marketing, incentive levels, budgets, adaptive management, and the
development of new and pilot programs.
Washington
The company is one of three investor-owned utilities required to comply with Washington's
Energy Independence Act(also referred to as I-937)approved in November 2006.The Act requires
utilities to pursue all conservation that is cost-effective, reliable, and feasible. Every two years,
each utility must identify its 10-year conservation potential and two-year acquisition target based
on its IRP and using methodologies that are consistent with those used by the Northwest Power
and Conservation Council.Each utility must maintain and use an external conservation stakeholder
group that advises on a wide range of issues including conservation programs, development of
conservation potential assessments, program marketing, incentive levels, budgets, adaptive
management, and the development of new and pilot programs. PacifiCorp works with the
conservation stakeholder group annually on its energy efficiency program design and planning.
In 2019, Washington passed the Clean Energy Transformation Act (CETA), which requires
utilities to meet three primary clean energy standards: remove coal-fueled generation from
Washington's allocation of electricity by 2025, serve Washington customers with greenhouse gas
neutral electricity by 2030, and to serve customers in Washington with 100%renewable and non-
38

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
emitting electricity by 2045. The conservation stakeholder group and the demand-side
management advisory group inform the CETA planning process as documented in the Company's
Clean Energy Implementation Plan (CEIP).4
California
On October 9, 2024, PacifiCorp submitted to the Commission the Company's Biennial Budget
Advice Letter(BBAL)Filing 747-E to administering its energy efficiency programs through 2026.
The BBAL was submitted PacifiCorp submitted in accordance with Ordering Paragraph 4 of
Decision (D.) 21-12-034 an application for the continuation of energy efficiency programs for
program years 2022-2026 on December 31, 2020.
Oregon
Energy efficiency programs for Oregon customers are planned for and delivered by Energy Trust
of Oregon in collaboration with PacifiCorp. Energy Trust's planning process is comparable to
PacifiCorp's other states, including establishing resource acquisition targets based on resource
assessment and integrated resource planning, developing programs based on local market
conditions,and coordinating with stakeholders and regulators to ensure efficient and cost-effective
delivery of energy efficiency resources.
Preferred Portfolio DSM Resource Selections
The following tables show the economic DSM resource selections by state and year in the 2025
IRP preferred portfolio.'
a The Company's 2021 CEIP can be found online at
https://www.pacificorp.com/content/dam/pcorp/documents/en/paci ficorp/energy/ceip/PAC-CEIP-12-30-
21_with Appx.pdf
s Following DSM resource selection methodologies described in Chapter 7 of the IRP.
39

PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
Table D.3 -Cumulative Demand Response Resource Selections (2025 IRP Preferred
Portfolio)
Resource 2025 27 2028 __N2Mr 2030 2031
DRSummer-CA 0 0 0 3 4 5 5 5 5 5 5
DR Winter-CA 0 0 0 0 0 0 0 0 0 0 0
DR Summer-ID 0 0 0 13 14 15 15 15 15 26 30
DR Winter-ID 0 0 0 0 0 0 0 0 0 0 0
DRSummer-OR 21 7 7 37 37 371 37 37 37 37 37
DR Winter-OR 0 19 26 35 40 101 108 1111 114 1171 118
DR Summer-UT 2 2 2 57 73 89 89 117 117 148 161
DR Winter-UT 0 0 0 0 0 0 0 0 0 0 0
DR Summer-WA 2 6 10 18 19 19 25 26 26 27 27
DRWinter-WA 0 11 111 11 111 11 11 11 11 11 11
DRSummer-WY 121 121 391 471 511 51 52 52 53 57
DRWinter-WY 0 0 0 0 0 0 0 0 0 0 0
sourc =1 2037 2038 ME2039 2040 2M]NE 2042 2043 2045
DRSummer-CA 6 6 6 6 6 7 10 10 11 11
DR Winter-CA 0 0 0 0 0 0 0 0 0 0
DRSummer-ID 30 31 31 56 56 57 62 63 63 76
DR Winter-ID 0 0 0 0 0 0 0 0 0 0
DR Summer-OR 37 90 141 144 1651 195 1981 200 238 245
DR Winter-OR 118 118 118 118 118 118 118 118 118 118
DR Summer-UT 173 186 199 212 229 244 260 327 347 470
DR Winter-UT 0 0 01 0 0 0 0 01 0 0
DRSummer-WA 27 27 39 39 51 52 52 53 56 57
DR Winter-WA 11 11 11 11 11 11 11 11 11 11
DRSummer-WY 58 58 58 581 581 581 63 63 64 64
DRWinter-WY 0 0 0 0 0 0 0 0 0 0
Table DA-Cumulative Energy Efficiency Resource Selections (2025 IRP Preferred
Portfolio)'
Curnutative Energy Efficiency Energy(MWh)Setected by State and Year
State 2025 2026 2027 2028 2029 2030 2031 2032 2033 MR6AMLL
CA 3,308 7,186 13,832 20,186 26,823 33,469 39,967 46,864 53,356 59,296 64,727
ID 17,544 42,512 63,201 85,809 109,760 134,567 155,257 185,725 216,663 246,826 274,451
OR 191,834 360,054 544,971 732,678 926,395 1,120,867 1,304,185 1,502,299 1,698,056 1,866,326 2,035,086
UT 272,934 573,161 973,115 1,465,931 1,942,259 2,401,553 2,811,536 3,374,021 3,939,353 4,456,818 4,945,653
WA 46,965 80,143 119,026 163,691 208,892 257,563 310,527 365,528 421,560 474,884 526,589
WY 41,384 a3,765 158,486 241,607 322,779 405,630 475,624 570,993 668,426 760,809 845,821
Total System 1 573,969 1 1,146,820 1 1,872,632 1 2,709,903 1 3,536,908 1 4,353,650 1 5,097,096 1 6,045,431 1 6,997,414 1 7,864,959 8,692,326
CurnuLative Energy Efficiency Energy(MWh)Setected byState and Year
State 2036 2037 2038 2039 2040 2041 2042 2043 2044
CA 70,047 73,914 77,871 81,595 84,558 87,533 89,500 92,087 94,082 95,444
ID 300,295 314,332 338,172 361,106 379,984 399,350 399,519 417,792 434,116 443,344
OR 2,183,430 2,306,242 2,453,148 2,592,107 2,736,233 2,867,688 2,959,241 2,777,170 2,893,594 3,028,081
UT 5,204,249 5,562,189 5,964,200 6,351,161 6,691,431 7,035,184 6,929,216 7,234,120 7,480,153 7,696,114
WA 572,972 617,392 656,778 693,586 724,169 755,016 779,461 807,176 830,083 848,578
917,119 958,608 1,018,963 1,075,940 1,124,893 1,177,655 1,196,770 1,244,308 1,283,918 1,322,306
9,248,1111 9,832,678 1 10,509,132 1 11,155,495 1 11,741,267 1 12,322,426 1 12,353,707 1 12,572,655 1 13,015,947 13,433,866
For the 20-year assumed nameplate capacity contributions (MW impacts) by state and year
associated with the energy efficiency resource selections above, see Volume I, Chapter 9
(Modeling and Portfolio Selection).
6 First Year energy may differ somewhat from incremental values,i.e.,subtracting cumulative energy from the prior year,due to hourly shapes of
energy efficiency changing from year to year.
40

PACIFICORP-2025 I" APPENDIX E-GRID ENHANCEMENT
APPENDIX E - GRID ENHANCEMENT
Introduction
"Smart" grid enhancement is the application of advanced communications and controls applied to
every aspect of the electric power system from regional real-time energy markets to distribution
automation. The wide array of applications discussed in this appendix can be considered under the
grid enhancement umbrella. PacifiCorp has identified specific areas for research and
implementation that include practices such as joining the western day-ahead market and
technologies such as dynamic line rating, phasor measurement units, distribution automation,
advanced metering infrastructure (AMI), automated demand response and others.
PacifiCorp has reviewed relevant grid enhancement technologies for transmission and distribution
systems that provide local and system benefits. When considering these technologies, advanced
controls and communications often the most critical infrastructure decision. The company network
must have relevant speed, reliability and security to support applications such as the current real-
time Western Energy Imbalance Market (WEIM), which optimizes the energy imbalances
throughout the West by transferring energy between participants in 15-minute and five-minute
intervals throughout the day.
Finally,PacifiCorp has focused on those technologies that present a positive benefit for customers,
seeking to optimize the electrical grid when and where it is economically feasible, operationally
beneficial and in the best interest of customers. PacifiCorp is committed to consistently evaluating
emerging technologies for integration—when they are found to be appropriate investments. The
company is working with state commissions to improve reliability, energy efficiency, customer
service and integration of renewable resources by analyzing the total cost of ownership,performing
thorough cost-benefit analyses and reaching out to customers concerning grid enhancement
applications. As industry advances and development continue, PacifiCorp can improve cost
estimates and benefits of grid enhancement technologies that will assist in identifying the best-
suited opportunities and applications for implementation.
Regional Energy Markets
Western Energy Imbalance Market
The company and the California Independent System Operator (CAISO) launched the Western
Energy Imbalance Market (WEIM) on November 1, 2014. The WEIM is a voluntary market and
the first western energy market outside of California. It includes companies from a Canadian
province and 10 states in the western United States — British Columbia, Arizona, California,
Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming leveraging
the California ISO advanced market systems to dispatch the least-cost resources every five
minutes. The company continues to work with CAISO, existing and prospective WEIM entities
and stakeholders to enhance market functionality and support market growth. The expansive
footprint now represents 79% of load in the Western Interconnection. The WEIM has produced
significant monetary benefits for its participant members($5.5 billion total footprint-wide benefits
as of March 31, 2024, accumulated since November 2014), quantified in the following categories:
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• More efficient dispatch, both inter- and intraregional, by optimizing dispatch every 15-
minute and every five-minute interval within and across the WEIM footprint
• Reduced renewable energy curtailment by allowing balancing authority areas to export
renewable generation that would otherwise need to be curtailed; renewable resource
curtailment has been reduced by 2.2 million MWh since 2015
Extended Day Ahead Market
PacifiCorp has planned to build on the success of real-time energy market innovation by joining
the new, voluntary, Western day-ahead market, (EDAM), developed by CAISO. The EDAM
builds on the existing structure and proven success of the WEIM. Participation in the day-ahead
market is designed to deliver significant reliability, economic and environmental benefits. The
EDAM optimizes resources and transmission offered to the market and commits resources
efficiently while conducting energy transfers to meet forecasted demand across the EDAM
footprint. WEIM participants can extend their participation to incorporate EDAM but must notify
CAISO of their participation and sign on for EDAM implementation.
Throughout 2022, PacifiCorp participated in a robust stakeholder process hosted by CAISO to
provide input on market design.As a result,the EDAM design incorporated a resource sufficiency
evaluation (RSE) and demonstration of transmission to ensure confidence in market transfers.
EDAM participation is defined by a participant's ability to pass the EDAM RSE, which prevents
leaning on other market participants through a standardized criterion. The EDAM requires a
transmission offering to support the EDAM participants' RSE showing in addition to facilitating
transfers across the EDAM footprint in the day-ahead timeframe.EDAM participants will continue
to plan to meet projected load as done today and will retain the responsibilities of balancing and
ensuring reliability within the WEIM. PacifiCorp along with three other large utilities have
informed CAISO of their interest in joining the EDAM.
Transmission Network and Operation Enhancements
Advanced Protective Relays
The company is expanding its use and understanding of advanced protective relays. These devices
are designed to remotely identify and report the distance and directionality of faults. PacifiCorp
has come to recognize that these sensors can provide significantly more information beyond fault
distance and directionality. For example, advanced protective relays provide near-real-time data
on proper breaker functionality as well as oscillographic operation data that is especially valuable
in managing inverter-based resources, like customer solar and wind farms. To ensure the company
implements monitoring equipment with minimum potential disruption to customers, adoption is
iterative: the company simulates data and events in a test environment to check settings and logic
before implementation.
Dynamic Line Rating
Dynamic line rating (DLR) is the application of sensors to transmission lines to indicate the real-
time, current-carrying capacity of the lines in relation to thermal restrictions. Transmission line
ratings are typically based on line-loading calculations given a set of worst-case weather
assumptions, such as high ambient temperatures and low wind speeds. DLR allows an increase in
current-carrying capacity of transmission lines, when more favorable weather conditions are
present, without compromising safety. DLR has become increasingly relevant with higher shares
of variable renewable energy (VRE) in the power system. By increasing the ampacity of
transmission lines, DLR provides economic and technical benefits to all involved. FERC NOPR
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(RM21-17-000)is calling to fully consider DLR and advanced power now control devices in local
and regional transmission planning processes.
PacifiCorp has been using DLR since 2014. The Standpipe—Platte project was implemented in
2014 and has delivered positive results as windy days are linked to increased wind power
generation and increased transmission ratings. A DLR system determines the resulting cooling
effect of the wind on the line. The current carrying capacity is then updated to a new weather-
dependent line rating. The Standpipe—Platte 230 kilovolt (kV) transmission line is one of three
lines in the Aeolus West transmission corridor and had been one of the lines that limits the corridor
power transfer during high wind conditions.As a result of this project,nonsimultaneous path rating
for the Western Electricity Coordinating Council (WECC)-defined Aeolus West path was
increased. The DLR system on the Standpipe—Platte 230 kV line has been updated with a
transmission line monitoring (TLM) system manufactured by Lindsey Systems.
Additionally, a new DLR system is being implemented on the existing Dave Johnston—Amasa—
Heward—Shirley Basin 230 kV line as well as the Windstar—Shirley Basin 230 kV line as part of
the Gateway West Segment D.1 Project. The Dave Johnston—Amasa—Heward—Shirley Basin 230
kV line connects two areas ((northeast and southeast Wyoming) with a high penetration of wind
generation resources. Implementation of the DLR system will improve the link between those two
areas to reduce the need for operational curtailments when wind patterns result in a variation in
generation between the two areas, such as high winds in the northeast Wyoming area and moderate
to low winds in the southeast Wyoming area. The DLR system will increase the transmission line
steady-state rating under increased wind conditions and reduce instances and duration of
associated generation curtailments while increasing power transfers between the two areas.
DLR and/or other grid-enhancing technologies (GET)will be evaluated for all future transmission
needs as a means for increasing capacity in relation to traditional construction methods. DLR is
only applicable for thermal constraints and only provides additional site-dependent capacity during
finite time periods. It may or may not align with expected transmission needs of future projects.
PacifiCorp will continue to look for opportunities to cost-effectively employ DLR systems similar
to the one deployed on the Standpipe—Platte 230 kV, Dave Johnston—Amasa—Heward—Shirley
Basin 230 kV line, and the Windstar—Shirley Basin 230 kV transmission lines.
Digital Fault Recorders/Phasor Measurement Unit Deployment
Phasor management units(PMU)provide sub-second data for voltage and current phasors. Digital
fault recorders (DFR)have a shorter recording time with higher sampling rate to validate dynamic
disturbance modeling. DFR/PMUs deliver dynamic PMU data to a centralized phasor data
concentrator (PDC) storage server where offline analysis can be performed by transmission
operators,planners, and protection&control engineers to validate system models. The PMU sub-
second data can be used for North American Electric Reliability Corporation(NERC) MOD-033-
I standard event analysis and model verification. DFRs data can be used to validate dynamic
disturbance modeling per NERC standard PRC-002-2. To comply with the MOD-033-1 and PRC-
002-2,PacifiCorp has installed over 100 multifunctional DFRs,which include PMU functionality.
The installations are at key transmission and generation facilities throughout the six-state service
territory, generally placed on WECC-identified critical paths.
Transmission planners, in coordination with other Western Power Pool member utilities, use the
phasor data quantities from actual system events to benchmark performance of steady-state and
transient stability models of the interconnected transmission system and generating facilities.
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Using a combination of phasor data from the PMUs and analog quantities currently available
through Supervisory Control and Data Acquisition System (SCADA), transmission planners can
set up the system models to accurately depict the transmission system before,during and following
an event. Differences in simulated versus actual system performance are then evaluated to allow
for enhancements and corrections to the system model.
DFR/PMU grid enhancement technology is being evaluated on several levels. Model validation
procedures are being evaluated in conjunction with data and equipment availability to fulfill MOD-
033-1. The process of validating the system model against a historical system outage event that
includes the comparison of a planning power flow model to actual system behavior and the
comparison of the planning dynamic model to actual system response is ongoing. PacifiCorp also
continues to evaluate potential benefits of PMU installation and intelligent monitoring as the
industry considers PMU in special protection,remedial action scheme and other roles that support
transmission grid operators. PacifiCorp will continue to work with the CAISO Reliability
Coordinator West to share data as appropriate. Finally, the technology is being evaluated in light
of recently upgraded the PMU firmware,which has improved the data reliability and the extent of
the data. The company is now engaging in preliminary evaluations on its potential use by grid
operations and dispatch.
Radio Frequency Line Sensors
Similar to communicating faulted circuit indicators (CFCI) discussed later in this appendix, radio
frequency (RF) line sensors are located along circuits (not in substations). Unlike CFCIs, RF line
sensors are installed not on but adjacent to lines-2-4 feet from a conductor, outside the minimum
approach distance. Where CFCIs evaluate magnetic fields to identify faults in amperage, RF line
sensors monitor high-frequency radio waves that can be caused by physical damage to a line, for
example a nicked conductor or failing insulator. While the physical damage may not be visible to
the naked eye, the use of multiple RF line sensors with GPS clocks installed allows the devices to
provide location information within 100 feet. The use of partial discharge cameras with arrays of
high-frequency microphones further refines the problem and location. Smart technology that can
detect physical degradation before it is obvious is a practical choice for strategically mitigating
damage to aging infrastructure; the company is pursuing a pilot RF line sensor project on one
transmission line in Oregon and California, involving 20 sensors. The equipment installation is
substantially complete. (The final sensor will be installed in early 2025 once weather permits.)
The company has begun collecting and evaluating the data and its potential uses. The data
collection and analysis phase are currently planned for several years. If results are promising,
PacifiCorp might expand beyond the pilot project sooner.
Transmission CFCIs
CFCIs, for both transmission and distribution, are grid enhancement devices installed directly on
conductors; these devices use magnetic field measurements to provide fault indication. They offer
real-time visibility and are increasingly valuable for ensuring system reliability, resiliency, and
flexibility. CFCIs provide multiple grid management enhancements:
• Leverage real-time line information to augment predictive capability of existing OMS and
reducing the time spent to locate, isolate and restore power
• Help determine safe switching procedures and support cost-effective capital improvement and
maintenance plans
• Improve optimization opportunities for capital costs and system losses by providing
measurements of per-phase vector quantities for voltage and current
• Identify service quality issues early and allow timely development and implementation of cost-
effective mitigation
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PacifiCorp has adopted and is continuing to broadly deploy distribution level CFCIs. The
Company is also beginning its adoption of CFCIs for use at the transmission level.
The steps necessary for a transmission level CFCI pilot have begun. PacifiCorp has completed a
transmission CFCI request for proposals (RFP) and selected two vendors. The company plans to
move forward with both vendors—given supply and development the company views this as a
prudent choice.
Distribution Automation and Reliability
Distribution Automation/Fault Location, Isolation and Service Restoration
Distribution automation (DA) uses multiple technologies including sensors, switches, controllers,
and communications networks that can work together to improve distribution system reliability.
Fault location, isolation and service restoration(FLISR) software can be used to control reclosers to
automatically restore customers located downstream from trouble.
DA's ability to provide improved outage management with decreased restoration times after failure,
operational efficiency, and peak load management using distributed resources and predictive
equipment failure analysis based on complex data algorithms has been a company focus. PacifiCorp
continues to evaluate different DA strategies to help determine which method is the best fit for a
typical distribution system based on cost, cybersecurity and scope of the DA effort.
In Oregon, PacifiCorp identified and performed cost-benefit analyses on 40 circuits. From this
analysis two circuits in Lincoln City, Oregon, were selected to have a fault location, isolation and
service restoration(FLISR)system installed. The project was installed in 2019 and commissioning
of the automation scheme conducted through 2020 in the distribution loop out of Devil's Lake
substation in Lincoln City, Oregon. The company also moved its predeployment DA testing
equipment to its Tech Ops center in Portland, Oregon,to expand open discussion between internal
end users including operations, service crews and field technicians. Throughout the
implementation of the Devil's Lake DA scheme, the company faced persistent challenges with
communication over its existing AMI network. The company found the communication capability
of AMI was not well-suited for a FLISR scheme and evaluated alternative solutions. The solution
now uses fiber optic communication, which the company installed in a loop configuration to
increase resiliency of the FLISR scheme's communication path. Despite communication issues in
the early stages of its implementation, PacifiCorp can now remotely monitor and control these
devices. The company has fault location and remote-control at Devil's Lake, and the FLISR
scheme was implemented summer 2022.
Two additional FLISR schemes Portland and Medford are slated for completion early 2025. The
vendor that programmed/developed the logic for all three projects has moved on to other work,
creating code maintenance challenges. PacifiCorp is collaborating with the vendor in its long-term
development of the next generation of this technology. Early evaluation shows the new FLISR
graphical user interface is more elegant and the system overall easier to maintain.
Distribution CFCIs
CFCI technology was described in greater detail earlier in this appendix. To briefly restate: CFCI
devices are installed on distribution lines. They measure the magnetic field and provide fault
indication. Their positive impacts are multiple and varied. In brief, CFCIs substantially improve
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real-time information exchange and reduce the time spent to locate, isolate, and restore power.
PacifiCorp expects CFCIs to contribute towards SAIDI reductions as well as reduced carbon
emissions due to decreased need for line patrols.
CFCI installation began as a conversation at PacifiCorp in 2017,became a pilot in 2019-2020, and
entered broad deployment in 2021. There are now approximately 4,000 CFCIs on the company
distribution network, mainly in high fire risk areas. Roughly 3,500 more are planned for
installation before the end of 2025.
Since broad deployment, company field staff have come to increasingly rely on CFCIs. The
effectiveness of these devices for field operations and dispatch has become clear relatively quickly.
For field operations, CFCIs to locate the fault more quickly, improving situational awareness,
fault location and restoration. For dispatch, CFCIs have enabled faster information transfer to the
field—data is coming through the OMS/EMS systems more quickly.
Distribution Substation Metering
Substation monitoring and measurement of various electrical attributes were identified as a
necessity due to the increasing complexity of distribution planning driven by growing levels of
primarily solar generation as distributed energy resources. Enhanced measurements improve
visibility into loading levels and generation hosting capacity as well as load shapes,customer usage
patterns, and information about reliability and power quality events.
In 2017, an advanced substation metering project was initiated to provide an affordable option for
gathering required substation and circuit data at locations where SCADA is unavailable and/or
uneconomical. SCADA has been the preferred form of gathering load profile data from distribution
circuits, however SCADA systems can be expensive to install, and additional equipment is
required to provide the data needed to perform distribution system and power quality analysis.
When system data rather than data and control is important, SCADA is no longer the best option.
Engineers require data to perform analysis of system loading and diagnose waveform and
harmonics issues;the lack of data can inhibit accurate system evaluations. The substation metering
project recognizes that system data has value independent of control and current system status.
The advanced substation metering pilot is intended to provide an affordable option for gathering
required distribution system data.
The advanced substation metering project was intended to provide an affordable option for
gathering required distribution system data. The company's work plan included:
• Finalize installation of advanced substation meters at distribution substations and
document installations
• Ensure all substation meters installed as part of this program are enabled with remote
communication capabilities
• Refine a data management system (PQView) to automatically download, analyze and
interpret data downloaded from all installed substation meters
The power quality monitoring project initiated in Utah in 2019 expanded in 2023 to include 340
data sources across the company's six-state service territory that feed data to PQView, including
reprogrammed revenue meters across the company's six-state territory.The data is used to monitor
voltage harmonics,voltage balance, steady-state voltage levels, and to log voltage sag events. The
company also deployed PQView software, a data analytics tool that provides users with a refined
view of power quality information gathered from substation meters.
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Distributed Energy Resources
Energy Storage Systems
CES includes large, centralized storage resources, such as electrochemical batteries, pumped
hydroelectric energy storage, compressed air energy storage (CAES), gravity energy storage
systems (such as weights moved by cranes, elevators or on rails), thermal energy storage, and
electromechanical batteries (i.e., flywheels). One smart grid benefit is the ability to integrate
renewable energy sources into an electricity delivery system. In contrast to dispatchable resources
that are available on demand (but not above nameplate capacity), such as most fossil fuel
generation, some renewable energy resources have intermittent generation output associated with
environmental conditions, such as the presence of wind or sun. The generation output of these
resources cannot be increased on demand or above the nameplate capacity and may have high
opportunity costs when generation is decreased unexpectedly.Providing service to the electric grid
may become progressively more challenging as the amount of the grid's energy requirements are
increasingly served from these intermittent generation resources, particularly in the absence of
incremental transmission construction. Two methods to fill this generation gap without the use of
dispatchable resources are energy storage and DR programs, whether local or centralized.
PacifiCorp,through its 2023 IRP Renewables Report,compared,on a preliminary, screening-level,
technical capabilities, capital costs and operations and maintenance costs of the following energy
storage and combined renewable resource/energy storage technologies: Li-Ion and flow batteries;
gravity energy storage systems (other than pumped hydro); CAES; solar, wind+ energy storage;
nuclear+ thermal energy storage. Each technology of interest to the Company shall be evaluated
by additional detailed studies to further investigate its direct application within long-term plans.
In addition to the evaluative efforts discussed above, in 2017, PacifiCorp filed the Energy Storage
Potential Evaluation and Energy Storage Project proposal with the Oregon Public Utilities
Commission (OPUC). This filing aligned with PacifiCorp's strategy and vision regarding the
expansion and integration of renewable technologies. The company proposed a utility-owned,
targeted energy storage system(ESS)pilot project. In 2019 PacifiCorp began project development
and is progressing to build an ESS on a Hillview substation distribution circuit in Corvallis,
Oregon. Due to issues finding a suitable location in Corvallis the company located a different
location. The new location for the ESS is the Lakeport substation in Klamath Falls. The intent of
this project is to integrate the ESS into the existing distribution system with the capability and
flexibility to potentially advance to a future microgrid system.
Phase I of the project involves/involved installation of a single, utility-owned energy storage
device to address historic outage characterization on a specific feeder, validate modeling through
field test data, create a research platform and optimize energy storage controls and integration on
the company network. The company contracted an owner's engineer to aid in project development
and is progressing on the Phase I project to build an ESS at the Oregon Institute of Technology
(OIT) on circuit SL49, fed from the Lakeport substation. The company contracted Powin Energy
to provide the ESS. The intent of this project is to integrate the ESS into the existing distribution
system with the capability and flexibility to potentially provide renewables integration support
with OIT's solar generation. The project is scheduled to be constructed and placed into service in
mid-2025. The minimum system size is:
• Energy requirement of 6 MWh
• Power requirement of 2 MW
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Phase II of the project involves/involved the addition of an additional energy storage device to
pilot distributed storage, optimize use cases per Phase I results, explore tariff structure and
ownership models and continue research.
In 2020, PacifiCorp developed Community Resiliency programs in Oregon and California to
expand customer and utility understanding of how the use of ESS equipment might increase the
resilience of critical facilities. The initial pilot programs provided technical support and evaluation
of potential options as well as grant funding for on-site battery storage systems. Over a dozen
feasibility studies were delivered across the Company's service area in the two states. Two ESS
systems have been installed in California with a third approved; one ESS is in the final stages of
commissioning in Oregon. As part of more recent efforts related to PacifiCorp's Oregon Clean
Energy Plan (CEP), the Company received approval to provide pathways of support for
communities working to enhance resilience at critical facilities. This includes feasibility
assessments, grant match funding and ongoing project support for renewable energy and BESS
systems. This Pilot program will operate through 2027.
The PacifiCorp filing with FERC covering optional generation interconnection study assumptions
for stand-alone electric storage resources was approved on February 28, 2023 (section 38.1 of the
Open Access Transmission Tariff). The use of real-world operating assumptions for electric
storage resources should lead to a more efficient interconnection process.
Demand Response
PacifiCorp has operated demand response programs since the 1980's and has been expanding its
offerings in the decades since. As demand response has been selected as a cost-effective demand-
side management resource in the past several IRPs,including in PacifiCorp's western state service
areas,the Company has rolled out demand response programs to a wide array of customers and to
address multiple grid needs. Today, PacifiCorp has five demand response program categories
(Cool Keeper, Wattsmart Batteries, Wattsmart Drive, Wattsmart Business Demand Response, and
Irrigation Load Control)currently approved in multiple states. These programs reach all customer
classes --residential, commercial, industrial, and irrigation-- and are operating at different stages
of deployment, from emerging, small-scale innovative pilots to large-scale mature programs, and
in between. The Cool Keeper program alone, for example, provides more than 270 MWs of
operating reserves to the system through the control of more than 118,000 air conditioning units.
The Company has goals to grow and increase participation in each of these programs and will use
the program for various use cases such as frequency response, contingency and peak load
management.
For further discussion of PacifiCorp's demand response offerings, please reference Chapter 6,
Chapter 7, and Appendix D.
Dispatchable Customer Storage Resources
Based on the learnings from PacifiCorp's partnership with Soleil Lofts and Sonnen in 2018, the
company developed the Wattsmart Battery Program,which was approved in Utah in October 2020
and in Idaho in April 2022.This innovative demand response program allows the company to
manage behind-the-meter customer batteries for daily load cycling, backup power real-time grid
needs such as peak load management, contingency reserves and frequency response. Customer-
controlled batteries allow the company to maximize renewable energy when it is needed to support
the electrical grid. The program has experienced exponential growth in its first four years of
operation and has over 5,300 participating residential batteries as of Q4 2024 and has also been
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adding 8-12 large commercial batteries each year. PacifiCorp is exploring expanding the program
into its service areas in Oregon and Washington starting in 2025.
Transportation Electrification
Electric vehicle infrastructure programming has begun expanding across much the company's six-
state service territory, touching Utah, California, Oregon and Washington.
Following 2020 Utah legislation, in 2021 the Utah Public Service Commission approved the
company's EV Infrastructure Program(EVIP). The program,which went into effect on January 1,
2022, is expected to last 10 years. The EVIP has five main elements: company-owned chargers,
make-ready investments, innovative projects and partnerships, incentives, and outreach and
education.
Multiple state of California government and utility commission efforts have required the company
to address multiple efforts, including the 2022 adoption of California Rule 24, which requires
utilities to provide line extensions to nonresidential EV charging stations at no cost to the applicant
performing all civil and electrical work. On November 17, 2022, the California Public Utilities
Commission issued D.22-11-040 , which adopted a long-term TE policy framework that includes
a third-party administered, statewide TE infrastructure program. PacifiCorp is participating by
funding this statewide initiative and providing dedicated technical assistance services to
commercial customers as they move to adopt EV infrastructure.
Oregon, over the last three years, has adopted numerous policies that are quickening the pace
toward an electric transportation future. Oregon Senate Bill 1044, passed in 2019, established
statewide zero-emission vehicle (ZEV) goals in five-year increments, reaching 90% of new sales
by 2035, which equates to 2.5 million electric vehicles (EV) on the road. Advanced Clean Cars II
rule, passed in December of 2022, requires 100% of new light-duty vehicles (LDV) be ZEVs or
plug-in hybrid EVs by 2035, ramping up from an initial requirement that 35% of new LDVs be
ZEVs in 2026. $101 million in National Electric Vehicle Infrastructure (NEVI) funding and
additional state funding over seven years is being used to invest in electric vehicle supply
equipment (EVSE) installation along major corridors and other roads, including a focus on rural
areas,underserved communities,and multifamily housing locations. House Bill 2165 requires that
all electricity companies(with>25,000 retail customers)recover the cost of prudent infrastructure
investments in TE. The Oregon Department of Environmental Quality adopted the Advanced
Clean Truck Rules 2021 in November 2021. In doing so, Oregon adopted California's emission
standards for medium-duty vehicles(MDV)and heavy-duty vehicles(HDV), collectively referred
to as MHDVs. This creates the ability to pursue the incentives to support the transition to zero
emissions for medium- and heavy-duty sectors, and the target of 100% of new sales of MHDV
being ZEV by 2050.
PacifiCorp proposed a portfolio of programs and pilots offering a range of support to different
sectors working toward TE in its 2023 Transportation Electrification Plan (TEP). This included
support for residential, commercial and multifamily customers as well as customers pursuing
electrification of fleets and MHDVs. The TE programs and pilots include:
• EVSE Rebate Pilot Program: Launched June of 2022, this program delivers rebates to
residential, income-eligible, commercial and multifamily customers to install Level 2
chargers.
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• Outreach and Education Pilot Program: Provides future EV drivers with greater awareness
and understanding of the benefits of electric transportation through outreach and educational
platforms, self-service tools,ride-and-drive events and more.This program was also launched
in June of 2022.
• Grant Programs: Since 2019, PacifiCorp has facilitated grants that support projects that
advance electric transportation in underserved communitiesa combination of competitive
grants, matching grants and grant writing funded through Oregon Clean Fuels Program.
• Fleet Make Ready Pilot Program: This program, expected to launch in 2024, offers a behind-
the-meter custom incentives to fleet customers that will support all make-ready infrastructure
focused on commercial customers and inclusive of all vehicle class types.
• Public Utility-Owned Infrastructure Pilot Program: Launched in the third quarter of 2023,
PacifiCorp will deploy utility-owned, publicly available charging infrastructure in
underserved communities.
• Residential Managed Charging Pilot Program: This pilot, planned to launch later in 2024,
actively manages EV loads through vehicle-and charger-enable protocols to shift charging
load to off-peak times.
• To deliver the programs and pilots contained in this portfolio, PacifiCorp proposed a three-
year budget totaling approximately $30 million, with each year containing increased annual
spending. The TEP was approved in July 2023.
In Washington, Governor Jay Inslee signed House Bill 1091, low carbon fuel standard legislation,
which limits the aggregate overall greenhouse gas emissions per unit of transportation fuel energy
to 20% below 2017 levels by 2038. Electric utilities can opt into the program as credit generators
and be assigned credits from residential EV charging,which the company has opted into. Revenue
earned by selling these credits must be used for TE projects while compliance can be achieved
through reducing the carbon intensity of fuel or buying credits. In addition,Washington Executive
Order 21-04 sets targets for 100% of all state fleet light-duty vehicles to be electric by 2035 and
medium-and heavy-duty vehicles to be electric by 2040. The Advanced Clean Cars II rule, passed
in December 2022 also requires 100% of new LDVs be ZEVs or plug-in hybrid EVs by 2035. To
support TE in its service area, Pacific Power received approval in October 2022 of its Washington
Transportation Electrification Plan. As a follow-up the company filed applications for new grant
programs, outreach and education programs and a managed charging program. The new
communities grant program plans to be launched in mid-2024, while outreach and education and
managed charging are finalizing vendor contracting and moving toward kickoff activities.
Advanced Metering Infrastructure
Advanced metering infrastructure (AMI) is an integrated system of smart meters, communications
networks, and data management systems that provide interval data available daily. This
infrastructure can also provide advanced functionalities including remote connect/disconnect,
outage detection and restoration signals, and support DA schemes. In 2016, PacifiCorp identified
economical AMI solutions for California and Oregon that delivered tangible benefits to customers
while minimizing the impact on consumer rates.
In 2019, PacifiCorp completed installation of the Itron Gen5 AMI system across the company's
Oregon and California service territories. The AMI system consists of head-end software, FANS
and approximately 680,000 meters. Interval energy usage data is provided to customers via the
company's public websites and mobile apps. The project was completed on schedule and on
budget.
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In 2018, PacifiCorp awarded a contract to Itron for their OpenWay Riva AMI system in the states
of Idaho and Utah. In early 2020,Itron proposed a change for the information technology(IT) and
network systems,using their Gen5 system rather than the OpenWay system, while still deploying
the more advanced Riva meter technology. Itron's Gen5 system has the same IT and network used
in PacifiCorp's Oregon and California service territories. This solution aligns with Itron's future
road map and provides PacifiCorp with a single operational system that will reduce cybersecurity
issues and operating costs associated with maintaining separate systems. This solution provides a
stronger, more flexible network coupled with a high-end metering solution.
The Utah/Idaho project involved upgrading the head-end software and installation of the Field
Area Network (FAN) and approximately 325,000 new Itron Riva AMI meters for most customer
classification and 1,700 FAN devices. This solution uses over 80% of the existing AMR meters in
Utah to provide hourly interval data for residential customers as well as outage detection and
restoration messaging. The project replaced all current meters in Idaho with new Itron Riva AMI
meters as AMR was not fully deployed there. Furthermore,the project will leverage the customer
communication tools developed for the Oregon and California AMI projects. The project was
completed in 2023.
Financial analyses to extend AMI solutions to Washington and Wyoming were performed in 2019,
2020, 2023, and 2024, respectively. The analyses determined that moving these states to an AMI
solution is not cost effective at this time.
Outage Management Improvements
PacifiCorp advanced a new module in its outage management systems (OMS) that allows field
responders to update outage data as they complete their work, using Mobile Workforce
Management tools. This functionality is restricted to service transformer and customer meter
devices, which comprise approximately half of the outages to which the company responds. This
ensures more rapid, accurate and efficient updates to outage data, but still maintains the OMS
topology as the method to manage line worker safety by having real-time access to elements that
are energized and those that may be in an abnormal state.
Meter pinging and last-gasp outage management functionalities were put in place for the AMI
system in Oregon and California and is now being used in Utah and Idaho. The company's system
operations organization use meter ping functionality and last-gasp messages to augment customer
calls and create outage tickets in the company's OMS.The company implemented business process
changes to facilitate outage management functionality for single-service as well as large-scale
outages. These changes have provided system operations with more flexibility to identify and
respond to outages.
Intelligent line sensors will be installed on distribution circuits to provide service to critical
facilities. For this project, critical facilities have been defined as major emergency facility centers
such as hospitals, trauma centers, police, fire dispatch centers, etc. The information provided by
the line sensors will allow control center operators to target restoration at critical facilities during
major outages sooner than is currently possible. Full implementation of the project was completed
in December 2021, concurrent with the completion of the AMI project.
51

PACIFICORP-2025 IRP APPENDIX E-GRID ENHANCEMENT
The company continues to develop a strategy to attain long-term goals for grid modernization and
grid enhancement-related activities to continually improve system efficiency, reliability and
safety, while providing a cost-effective service to our customers. The company will continue to
monitor grid enhancement technologies and determine viability and applicability of
implementation to the system. As tipping points to broader implementation occur, PacifiCorp will
communicate with customers and stakeholders through a variety of methods, including this IRP as
well as other regulatory mechanisms relevant to each state.
52

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
APPENDIX F - FLEXIBLE RESERVE STUDY
Introduction
For the 2025 IRP, PacifiCorp is continuing to use the methodology developed in its 2021 Flexible
Reserve Study(FRS), which relied upon historical data from 2018-2019, as discussed below.I
The 2021 Flexible Reserve Study (FRS) estimated the regulation reserve required to maintain
PacifiCorp's system reliability and comply with North American Electric Reliability Corporation
(NERC)reliability standards. Because the FRS methodology accounts for changes in PacifiCorp's
resource mix,both the quantity and cost of reserves has been updated for the 2025 IRP, as reported
herein.
PacifiCorp operates two balancing authority areas(BAAs)in the Western Electricity Coordinating
Council (WECC) NERC region--PacifiCorp East (PACE) and PacifiCorp West (PACW). The
PACE and PACW BAAs are interconnected by a limited amount of transmission across a third-
party transmission system and the two BAAs are each required to comply with NERC standards.
PacifiCorp must provide sufficient regulation reserve to remain within NERC's balancing
authority area control error(ACE) limit in compliance with BAL-001-2,2 as well as the amount of
contingency reserve required to comply with NERC standard BAL-002-WECC-2.' BAL-001-2 is
a regulation reserve standard that became effective July 1, 2016, and BAL-002-WECC-3 is a
contingency reserve standard that became effective June 28, 2021. Regulation reserve and
contingency reserve are components of operating reserve,which NERC defines as"that capability
above firm system demand required to provide for regulation, load forecasting error, equipment
forced and scheduled outages and local area protection."4
Apart from disturbance events that are addressed through contingency reserve, regulation reserve
is necessary to compensate for changes in load demand and generation output to maintain ACE
within mandatory parameters established by the BAL-001-2 standard. The FRS estimates the
amount of regulation reserve required to manage variations in load, variable energy resources
(VERB), and resources that are not VERB ("Non-VERB") in each of PacifiCorp's BAAS. Load,
wind, solar, and Non-VERs were each studied because PacifiCorp's data indicates that these
' 2021 IRP Volume II,Appendix F(Flexible Reserve Study):
hgps://www.12acificorp.com/content/dam/pcorp/documents/en/pacificop2/energy /y integrated-resource-plan/2021-
irpNolume%20II%20-%209.15.2021%20Final.pdf
2 NERC Standard BAL-001-2, https://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-001-2.pdf, which
became effective July 1,2016.ACE is the difference between a BAA's scheduled and actual interchange and reflects
the difference between electrical generation and Load within that BAA.
3 NERC Standard BAL-002-WECC-3,hllps://www.nerc.com/pa/Stand/Reliability%20Standards/BAL-002-WECC-
3.ndf,which became effective June 28,2021.BAL-002-WECC-3 removed the requirement that at least 50%of
contingency reserves be held as"spinning"resources,as this was deemed redundant with frequency response
requirements under BAL-003-2.
4 Glossary of Terms Used in NERC Reliability Standards:
https://www.nerc.com/pa/Stand/Glossary%20of%2OTcrms/Glossary of Terms.pdf,updated March 8,2023.
5 VERs are resources that resources that: (1)are renewable;(2)cannot be stored by the facility owner or operator;
and(3)have variability that is beyond the control of the facility owner or operator.Integration of Variable Energy
Resources,Order No. 764, 139 FERC¶61,246 at P 281 (2012)("Order No. 764");order on reh g,Order No.764-
A, 141 FERC¶61,232(2012)("Order No. 764-A");order on reh'g and clarification,Order No. 764-B, 144 FERC
¶61,222 at P 210(2013)("Order No. 764-B").
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
components or customer classes place different regulation reserve burdens on PacifiCorp's system
due to differences in the magnitude, frequency, and timing of their variations from forecasted
levels.
The FRS is based on PacifiCorp operational data recorded from January 2018 through December
2019 for load, wind, solar, and Non-VERB. PacifiCorp's primary analysis focuses on the actual
variability of load, wind, solar, and Non-VERB during 2018-2019. A supplemental analysis
discusses how the total variability of the PacifiCorp system changes with varying levels of wind
and solar capacity. The estimated regulation reserve amounts determined in this study represent
the incremental capacity needed to ensure compliance with BAL-001-2 for a particular operating
hour. The regulation reserve requirement covers variations in load, wind, solar, and Non-VERB,
while implicitly accounting for the diversity between the different classes. An explicit adjustment
is also made to account for diversity benefits realized because of PacifiCorp's participation in the
Western Energy Imbalance Market(EIM)operated by the California Independent System Operator
Corporation(CAISO).6
The methodology in the FRS is like that previously employed in PacifiCorp's 2019 IRP but was
enhanced in two areas.'First,the historical period evaluated in the study was expanded to include
two years, rather than one, to capture a larger sample of system conditions. Second, the
methodology for extrapolating results for higher renewable resource penetration levels was
modified to better capture the diversity between growing wind and solar portfolios.
The FRS results produce an hourly forecast of the regulation reserve requirements for each of
PacifiCorp's BAAS that is sufficient to ensure the reliability of the transmission system and
compliance with NERC and WECC standards. This regulation reserve forecast covers the
combined deviations of the load,wind, solar and Non-VERs on PacifiCorp's system and varies as
a function of the wind and solar capacity on PacifiCorp's system, as well as forecasted levels of
wind, solar and load.
The regulation reserve requirement methodologies produced by the FRS are applied in production
cost modeling to determine the cost of the reserve requirements associated with incremental wind
and solar capacity. After a portfolio is selected,the regulation reserve requirements specific to that
portfolio can be calculated and included in the study inputs, such that the production cost impact
of the requirements is incorporated in the reported results. As a result, this production cost impact
is dependent on the wind and solar resources in the portfolio as well as the characteristics of the
dispatchable resources in the portfolio that are available to provide regulation reserves.
Overview
The primary analysis in the FRS is to estimate the regulation reserve necessary to maintain
compliance with NERC Standard BAL-001-2 given a specified portfolio of wind and solar
resources. The FRS next calculates the cost of holding regulation reserve for incremental wind and
solar resources. Finally, the FRS compares PacifiCorp's overall operating reserve requirements
6 Western Energy Imbalance Market. www.westemeim.com
2019 IRP Volume II,Appendix F(Flexible Reserve Study):
https://www.pacificorp.com/content/dam/pcorp/documents/enZpacificorp/energy/grated-resource-
plan/2019_IRP_Volume_II_Appendices A-L.pdf
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
over the IRP study period,including both regulation reserve and contingency reserve,to its flexible
resource supply.
The FRS estimates regulation reserve based on the specific requirements of NERC Standard BAL-
001-2. It also incorporates the current timeline for EIM market processes, as well as EIM resource
deviations and diversity benefits based on actual results. The FRS also includes adjustments to
regulation reserve requirements to account for the changing portfolio of solar and wind resources
on PacifiCorp's system and accounts for the diversity of using a single portfolio of regulation
reserve resources to cover variations in load, wind, solar, and Non-VERB. A comparison of the
results of the current analysis and that from previous IRPs is shown in Table F.1 and Table F.2.
Flexible resource costs are portfolio dependent and vary over time. For more details, please refer
to Figure F.11 —Incremental Wind and Solar Regulation Reserve Costs.
Table FA - Portfolio Regulation Reserve Requirements
Wind Solar Stand-alone Portfolio Regulation
Capacity Capacity Regulation Diversity Requirement
Requirement Credit with Diversity
[Case AILM (MW) MW (MW) (%) IL (MW)
CY2017(2019 FRS) 2,750 1,021 994 47% 531
2018-2019(2021 FRS) 2,745 1,080 1,057 49% 540
Table F.2 - 20252023 Flexible Resource Costs as Compared to 2023 Costs, $/MWh
Note— Table F.2 will be updated for the March 31, 2025 IRP filing based on final
preferred portfolio results.
Flexible Resource Requirements
PacifiCorp's flexible resource needs are the same as its operating reserve requirements over the
planning horizon for maintaining reliability and compliance with NERC regional reliability
standards. Operating reserve generally consists of three categories: (1) contingency reserve (i.e.,
spinning, and supplemental reserve), (2) regulation reserve, and (3) frequency response reserve.
Contingency reserve is capacity that PacifiCorp holds available to ensure compliance with the
NERC regional reliability standard BAL-002-WECC-3.8 Regulation reserve is capacity that
PacifiCorp holds available to ensure compliance with the NERC Control Performance Criteria in
BAL-001-2.9 Frequency response reserve is capacity that PacifiCorp holds available to ensure
compliance with NERC standard BAL-003-2.10 Each type of operating reserve is further defined
below.
8 NERC Standard BAL-002-WECC-3—Contingency Reserve:
https://www.nerc.com/pa/Stand/Reliabiliiy%2oStandards/BAL-002-WECC-3.pdf
9 NERC Standard BAL-001-2—Real Power Balancing Control Performance:
https://www.nerc.com/pa/Stand/Reliabiliiy%20Standards/BAL-001-2.pdf
10 NERC Standard BAL-003-2—Frequency Response and Frequency Bias Setting:
https://www.nerc.com/pa/Stand/Reliabiliiy%20Standards/BAL-003-2.pdf
55

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Contingency Reserve
Purpose: Contingency reserve may be deployed when unexpected outages of a generator or a
transmission line occur. Contingency reserve may not be deployed to manage other system
fluctuations such as changes in load or wind generation output.
Volume: NERC regional reliability standard BAL-002-WECC-3 specifies that each BAA must
hold as contingency reserve an amount of capacity equal to three percent of load and three percent
of generation in that BAA.
Duration: Except within 60 minutes of a qualifying contingency event, a BAA must maintain the
required level of contingency reserve at all times. Generally, this means that up to 60 minutes of
generation are required to provide contingency reserve, though successive outage events may
result in contingency reserves being deployed for longer periods. To restore contingency reserves,
other resources must be deployed to replace any generating resources that experienced outages,
typically either market purchases or generation from resources with slower ramp rates.
Ramp Rate: Only up capacity available within ten minutes can be counted as contingency reserve.
This can include "spinning" resources that are online and immediately responsive to system
frequency deviations to maintain compliance with frequency response obligations under BAL-
003-1.1, as well as from "non-spinning" resources that do not respond immediately, though they
must still be fully deployed in ten minutes.I I
Regulation Reserve
Purpose: NERC standard BAL-001-2, which became effective July 1, 2016, does not specify a
regulation reserve requirement based on a simple formula, but instead requires utilities to hold
sufficient reserve to meet specified control performance standards. The primary requirement
relates to area control error ("ACE"), which is the difference between a BAA'S scheduled and
actual interchange and reflects the difference between electrical generation and load within that
BAA. Requirement 2 of BAL-001-2 defines the compliance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL)for more than 30 consecutive clock-minutes...
In addition, Requirement 1 of BAL-001-2 specifies that PacifiCorp's Control Performance
Standard 1 ("CPS 1") score must be greater than equal to 100 percent for each preceding 12
consecutive calendar month period, evaluated monthly. The CPS 1 score compares PacifiCorp's
ACE with interconnection frequency during each clock minute. A higher score indicates
PacifiCorp's ACE is helping interconnection frequency,while a lower score indicates it is hurting
interconnection frequency. Because CPS 1 is averaged and evaluated monthly, it does not require
a response to every ACE event, but rather requires that PacifiCorp meet a minimum aggregate
level of performance in each month. Regulation reserve is thus the capacity that PacifiCorp holds
I' While the minimum spinning reserve obligation previously contained within BAL-002-WECC-2a was retired due
to redundancy with frequency response obligations under BAL-003-2, PacifiCorp's 2023 IRP does not explicitly
model the frequency response obligation and retains the spinning obligation to ensure a supply of rapidly responding
resources is maintained.
56

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
available to respond to changes in generation and load to manage ACE within the limits specified
in BAL-001-2.
Volume: NERC standard BAL-001-2 does not specify a regulation reserve requirement based on
a simple formula, but instead requires utilities to hold sufficient reserve to meet performance
standards as discussed above. The FRS estimates the regulation reserve necessary to meet
Requirement 2 by compensating for the combined deviations of the load, wind, solar and Non-
VERs on PacifiCorp's system. These regulation reserve requirements are discussed in more detail
later in the study.
Ramp Rate: Because Requirement 2 includes a 30-minute time limit for compliance, ramping
capability that can be deployed within 30 minutes contributes to meeting PacifiCorp's regulation
reserve requirements. The reserve for CPS 1 is not expected to be incremental to the need for
compliance with Requirement 2 but may require that a subset of resources held for Requirement 2
be able to make frequent rapid changes to manage ACE relative to interconnection frequency.
Duration: PacifiCorp is required to submit balanced load and resource schedules as part of its
participation in EIM. PacifiCorp is also required to submit resources with up flexibility and down
flexibility to cover uncertainty and expected ramps across the next hour. Because forecasts are
submitted prior to the start of an hour, deviations can begin before an hour starts. As a result, a
flexible resource might be called upon for the entire hour. To continue providing flexible capacity
in the following hour, energy must be available in storage for that hour as well. The likelihood of
deploying for two hours or more for reliability compliance (as opposed to economics) is expected
to be small.
Frequency Response Reserve
Purpose: NERC standard BAL-003-2 specifies that each BAA must arrest frequency deviations
and support the interconnection when frequency drops below the scheduled level. When a
frequency drop occurs because of an event, PacifiCorp will deploy resources that increase the net
interchange of its BAAS and the flow of generation to the rest of the interconnection.
Volume: When a frequency drop occurs, each BAA is expected to deploy resources that are at
least equal to its frequency response obligation. The incremental requirement is based on the size
of the frequency drop and the BAA'S frequency response obligation, expressed in megawatt
(MW)/O.1 Herts (Hz). To comply with the standard, a BAA'S median measured frequency
response during a sampling of under-frequency events must be equal to or greater than its
frequency response obligation. PacifiCorp's 2024 frequency response obligation was 21.7
MW/O.1Hz for PACW, and 62.9 MW/O.1Hz for PACE.12 PacifiCorp's combined obligation
amounts to 84.6 MW for a frequency drop of 0.1 Hz, or 253.8 MW for a frequency drop of 0.3 Hz.
12 NERC.BAL-003-2 Frequency Response Obligation Allocation and Minimum Frequency Bias Settings for
Operating Year 2022.
https://www.nerc.com/comm/OC/RS%20Landin %g 20Page%20DL/Frequency%20Response%20Standard%20Reso
urcesBA FRO Allocations_for OY2024.pdf
57

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
The performance measurement for contingency reserve under the Disturbance Control Standard
(BAL-002-3)13, allows for recovery to the lesser of zero or the ACE value prior to the contingency
event, so increasing ACE above zero during a frequency event reduces the additional deployment
needed if a contingency event occurs. Because contingency, regulation, and frequency events are
all relatively infrequent,they are unlikely to occur simultaneously.Because the frequency response
standard is based on median performance during a year, overlapping requirements that reduced
PacifiCorp's response during a limited number of frequency events would not impact compliance.
As a result, any available capacity not being used for generation is expected to contribute to
meeting PacifiCorp's frequency response obligation, up to the technical capability of each unit,
including that designated as contingency or regulation reserves. Frequency response must occur
very rapidly, and a generating unit's capability is limited based on the unit's size, governor
controls, and available capacity, as well as the size of the frequency drop. As a result, while a few
resources could hold a large amount of contingency or regulation reserve,frequency response may
need to be spread over a larger number of resources. Additionally, only resources that have active
and tuned governor controls as well as outer loop control logic will respond properly to frequency
events.
Ramp Rate: Frequency response performance is measured over a period of seconds, amounting
to under a minute. Compliance is based on the average response over the course of an event. As a
result, a resource that immediately provides its full frequency response capability will provide the
greatest contribution. That same resource will contribute a smaller amount if it instead ramps up
to its full frequency response capability over the course of a minute or responds after a lag.
Duration: Frequency response events are less than one minute in duration.
Black Start Requirements
Black start service is the ability of a generating unit to start without an outside electrical supply
and is necessary to help ensure the reliable restoration of the grid following a blackout. At this
time, PACW grid restoration would occur in coordination with Bonneville Power Administration
black start resources. The Gadsby combustion turbine resources can support grid restoration in
PACE. PacifiCorp has not identified any incremental needs for black start service during the IRP
study period.
Ancillary Services Operational Distinctions
In actual operations, PacifiCorp identifies two types of flexible capacity as part of its participation
in the EIM. The contingency reserve held on each resource is specifically identified and is not
available for economic dispatch within the EIM. Any remaining flexible capacity on participating
resources that is not designated as contingency reserve can be economically dispatched in EIM
based on its operating cost (i.e. bid) and system requirements and can contribute to meeting
regulation reserve obligations. Because of this distinction, resources must either be designated as
contingency reserve or as regulation reserve. Contingency events are relatively rare while
opportunities to deploy additional regulation reserve in EIM occur frequently. As a result,
PacifiCorp typically schedules its lowest-cost flexible resources to serve its load and blocks off
"NERC Standard BAL-002-3—Disturbance Control Standard—Contingency Reserve for Recovery from a
Balancing Contingency Event:https://www.nerc.comipa/Stand/Reliability Standards/BAL-002-3.pdf
58

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
capacity on its highest-cost flexible resources to meet its contingency obligations, subject to any
ramping limitations at each resource. This leaves resources with moderate costs available for
dispatch up by EIM, while lower-cost flexible resources remain available to be dispatched down
by EIM.
Overview
This section describes the data used to determine PacifiCorp's regulation reserve requirements. To
estimate PacifiCorp's required regulation reserve amount, PacifiCorp must determine the
difference between the expected load and resources and actual load and resources. The difference
between load and resources is calculated every four seconds and is represented by the ACE. ACE
must be maintained within the limits established by BAL-001-2, so PacifiCorp must estimate the
amount of regulation reserve that is necessary to maintain ACE within these limits.
To estimate the amount of regulation reserve that will be required in the future,the FRS identifies
the scheduled use of the system as compared to the actual use of the system during the study term.
For the baseline determination of scheduled use for load and resources, the FRS used hourly base
schedules.Hourly base schedules are the power production forecasts used for imbalance settlement
in the EIM and represent the best information available concerning the upcoming hour.14
The deviation from scheduled use was derived from data provided through participation in the
EIM. The deviations of generation resources in EIM were measured on a five-minute basis, so
five-minute intervals are used throughout the regulation reserve analysis.
EIM base schedule and deviation data for each wind, solar and Non-VER transaction point were
downloaded using the SettleCore application, which is populated with data provided by the
CAISO. Since PacifiCorp's implementation of EIM on November 1, 2014, PacifiCorp requires
certain operational forecast data from all its transmission customers pursuant to the provisions of
Attachment T to PacifiCorp's Federal Energy Regulatory Commission (FERC) approved Open
Access Transmission Tariff(GATT). This includes EIM base schedule data(or forecasts)from all
resources included in the EIM network model at transaction points. EIM base schedules are
submitted by transmission customers with hourly granularity, and are settled using hourly data for
load, and fifteen-minute and five-minute data for resources. A primary function of the EIM is to
measure load and resource imbalance (or deviations) as the difference between the hourly base
schedule and the actual metered values.
14 The CAISO,as the market operator for the EIM,requests base schedules at 75 minutes(T-75)prior to the hour of
delivery.PacifiCorp's transmission customers are required to submit base schedules by 77 minutes(T-77)prior to
the hour of delivery—two minutes in advance of the EIM Entity deadline. This allows all transmission customer
base schedules enough time to be submitted into the EIM systems before the overall deadline of T-75 for the entirety
of PacifiCorp's two BAAs.The base schedules are due again to CAISO at 55 minutes(T-55)prior to the delivery
hour and can be adjusted up until that time by the EIM Entity(i.e.,PacifiCorp Grid Operations).PacifiCorp's
transmission customers are required to submit updated,final base schedules no later than 57 minutes(T-57)prior to
the delivery hour.Again,this allows all transmission customer base schedules enough time to be submitted into the
EIM systems before the overall deadline of T-55 for the entirety of PacifiCorp's two BAAs.Base schedules may be
finally adjusted again,by the EIM Entity only,at 40 minutes(T-40)prior to the delivery hour in response to CAISO
sufficiency tests.T-40 is the base schedule time point used throughout this study.
59

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
A summary of the data gathered for this analysis is listed below, and a more detailed description
of each type of source data is contained in the following subsections.
Source data:
- Load data
o Five-minute interval actual load
o Hourly base schedules
- VER data
o Five-minute interval actual generation
o Hourly base schedules
- Non-VER data
o Five-minute interval actual generation
o Hourly base schedules
Load Data
The load class represents the aggregate firm demand of end users of power from the electric
system. While the requirements of individual users vary,there are diurnal and seasonal patterns in
aggregated demand. The load class can generally be described to include three components: (1)
average load,which is the base load during a particular scheduling period; (2)the trend,or"ramp,"
during the hour and from hour-to-hour; and (3) the rapid fluctuations in load that depart from the
underlying trend. The need for a system response to the second and third components is the
function of regulation reserve in order to ensure reliability of the system.
The PACE BAA includes several large industrial loads with unique patterns of demand. Each of
these loads is either interruptible at short notice or includes behind the meter generation. Due to
their large size, abrupt changes in their demand are magnified for these customers in a manner
which is not representative of the aggregated demand of the large number of small customers
which make up most PacifiCorp's loads.
In addition, interruptible loads can be curtailed if their deviations are contributing to a resource
shortfall. Because of these unique characteristics, these loads are excluded from the FRS. This
treatment is consistent with that used in the CAISO load forecast methodology (used for PACE
and PACW operations),which also nets these interruptible customer loads out of the PACE BAA.
Actual average load data was collected separately for the PACE and PACW BAAS for each five-
minute interval. Load data has not been adjusted for transmission and distribution losses.
Wind and Solar Data
The wind and solar classes include resources that: (1) are renewable; (2) cannot be stored by the
facility owner or operator; and(3) have variability that is beyond the control of the facility owner
or operator." Wind and solar, in comparison to load, often have larger upward and downward
fluctuations in output that impose significant and sometimes unforeseen challenges when
attempting to maintain reliability. For example, as recognized by FERC in Order No. 764,
15 Order No. 764 at P 281;Order No. 764-B at P 210.
60

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
"Increasing the relative amount of[VERB] on a system can increase operational uncertainty that
the system operator must manage through operating criteria, practices, and procedures, including
the commitment of adequate reserves."16 The data included in the FRS for the wind and solar
classes include all wind and solar resources in PacifiCorp's BAAS,which includes: (1)third-party
resources (OATT or legacy contract transmission customers); (2) PacifiCorp-owned resources;
and (3) other PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and
exchanges. In total, the FRS study period includes an average of 2,745 megawatts of wind and
1,080 megawatts of solar.
Non-VER Data
The Non-VER class is a mix of thermal and hydroelectric resources and includes all resources
which are not VERB, and which do not provide either contingency or regulation reserve. Non-
VERs, in contrast to VERB, are often more stable and predictable. Non-VERB are thus easier to
plan for and maintain within a reliable operating state. For example, in Order No. 764, FERC
suggested that many of its rules were developed with Non-VERB in mind and that such generation
"could be scheduled with relative precision."I'The output of these resources is largely in the
control of the resource operator, particularly when considered within the hourly timeframe of the
FRS. The deviations by resources in the Non-VER class are thus significantly lower than the
deviations by resources in the wind class. The Non-VER class includes third-party resources
(GATT or legacy transmission customers); many PacifiCorp-owned resources; and other
PacifiCorp-contracted resources, such as qualifying facilities,power purchases, and exchanges. In
total, the FRS includes 2,202 megawatts of Non-VERB.
In the FRS, resources that provide contingency or regulation reserve are considered a separate,
dispatchable resource class. The dispatchable resource class compensates for deviations resulting
from other users of the transmission system in all hours. While non-dispatchable resources may
offset deviations in loads and other resources in some hours, they are not in the control of the
system operator and contribute to the overall requirement in other hours. Because the dispatchable
resource class is a net provider rather than a user of regulation reserve service, its stand-alone
regulation reserve requirement is zero (or negative), and its share of the system regulation reserve
requirement is also zero. The allocation of regulation reserve requirements and diversity benefits
is discussed in more detail later in the study.
on Reserve Data Analysis and Adjustment
Overview
This section provides details on adjustments made to the data to align the ACE calculation with
actual operations, and address data issues.
Base Schedule Ramping Adjustment
In actual operations, PacifiCorp's ACE calculation includes a linear ramp from the base schedule
in one hour to the base schedule in the next hour, starting ten-minutes before the hour and
continuing until ten-minutes past the hour. The hourly base schedules used in the study are adjusted
16 Order No. 764 at P 20(emphasis added).
"Id. at P 92.
61

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
to reflect this transition from one hour to the next. This adjustment step is important because, to
the extent actual load or generation is transitioning to the levels expected in the next hour, the
adjusted base schedules will result in reduced deviations during these intervals, potentially
reducing the regulation reserve requirement. Figure F.1 below illustrates the hourly base schedule
and the ramping adjustment. The same calculation applies to all base schedules: Load,Wind,Non-
VERs, and the combined portfolio.
Figure F.1 -Base Schedule Ramping Adjustment
3100
3000
2900
2800
a�
2700
U
U)
LJ
2600
CO
2500
2400
Base Schedule —Adjusted Base Schedule
2300
A A � Ln Ln Ln Ln Ln Ln Ln Ln Ln Ln Ln Ln 01 61 61 61 61 M M M M M M M --1 --1 --1 -_l
A LP LP O O I- F­ N N W W A A Ln Ln O O F, F, N N W W A A LP LP O O h, F­
Ln O Ln O In O Ln O In O Ln O Ln O Ln O Ln O Ln O Ln O Ln O Ln O Ln O In O In
Time
Data Corrections
The data extracted from PacifiCorp's systems for, wind, solar and Non-VERs was sourced from
CAISO settlement quality data. This data has already been verified for inconsistencies as part of
the settlement process and needs minimal cleaning as described below. Regarding five-minute
interval load data from the PI Ranger system, intervals were excluded from the FRS results if any
five-minute interval suffered from at least one of the data anomalies that are described further
below:
Load:
• Telemetry spike/poor connection to meter
• Missing meter data
• Missing base schedules
62

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
VERs:
• Curtailment events
Load in PacifiCorp's BAAS changes continuously. While a BAA could potentially maintain the
exact same load levels in two five-minute intervals in a row, it is extremely unlikely for the exact
same load level to persist over longer time frames.When PacifiCorp's energy management system
(EMS) load telemetry fails, updated load values may not be logged, and the last available load
measurement for the BAA will continue to be reported.
Rapid spikes in load telemetry either up or down are unlikely to be the result of conditions which
require deployment of regulation reserve, particularly when they are transient. Such events could
be a result of a transmission or distribution outage, which would allow for the deployment of
contingency reserve, and would not require deployment of regulation reserve. Such events are also
likely to be a result of a single bad load measurement. Load telemetry spike irregularities were
identified by examining the intervals with the largest changes from one interval to the next, either
up or down. Intervals with inexplicably large and rapid changes in load, particularly where the
load reverts within a short period,were assumed to have been covered through contingency reserve
deployment or to reflect inaccurate load measurements. Because they do not reflect periods that
require regulation reserve deployment, such intervals are excluded from the analysis. During the
study period, in PACW 15 minutes' worth of telemetry spikes were excluded while no telemetry
spikes were observed in PACE. There were also 10 minutes' worth of missing load meter data,
and 82 hours of missing load base schedules.
The available VER data includes wind curtailment events which affect metered output.When these
curtailments occur, the CAISO sends data, by generator, indicating the magnitude of the
curtailment. This data is layered on top of the actual meter data to develop a proxy for what the
metered output would have been if the generator were not curtailed. Regulation reserve
requirements are calculated based on the shortfall in actual output relative to base schedules. By
adding back curtailed volumes to the actual metered output,the shortfall relative to base schedules
is reduced, as is the regulation reserve requirement. This is reasonable since the curtailment is
directed by the CAISO or the transmission system operator to help maintain reliable operation, so
it should not exacerbate the calculated need for regulation reserves.
After review of the data for each of the above anomaly types, and out of 210,216 five-minute
intervals evaluated, approximately 1,000 five-minute intervals, or 0.5% of the data, was removed
due to data errors. While cleaning up or replacing anomalous hours could yield a more complete
data set, determining the appropriate conditions in those hours would be difficult and subjective.
By removing anomalies, the FRS sample is smaller but remains reflective of the range of
conditions PacifiCorp experiences, including the impact on regulation reserve requirements of
weather events experienced during the study period.
Regulation Reserve Requirement Methodology
Overview
This section presents the methodology used to determine the initial regulation reserve needed to
manage the load and resource balance within PacifiCorp's BAAS. The five-minute interval load
63

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
and resource deviation data described above informs a regulation reserve forecast methodology
that achieves the following goals:
- Complies with NERC standard BAL-001-2;
- Minimizes regulation reserve held; and
- Uses data available at time of EIM base schedule submission at T-40.18
The components of the methodology are described below, and include:
- Operating Reserve: Reserve Categories;
- Calculation of Regulation Reserve Need;
- Balancing Authority ACE Limit: Allowed Deviations;
- Planning Reliability Target: Loss of Load Probability("LOLP"); and
- Regulation Reserve Forecast: Amount Held.
Following the explanation below of the components of the methodology, the next section details
the forecasted amount of regulation reserve for:
- Wind;
- Solar;
- Non-VERs; and
- Load.
Components of Operating Reserve Methodology
Operating Reserve: Reserve Categories
Operating reserve consists of three categories: (1) contingency reserve, (2)regulation reserve, and
(3) frequency response reserve. These requirements must be met by resources that are incremental
to those needed to meet firm system demand. The purpose of the FRS is to determine the regulation
reserve requirement. The contingency reserve and frequency response requirements are defined
formulaically by their respective reliability standards.
Of the three categories of reserve referenced above, the FRS is primarily focused on the
requirements associated with regulation reserve. Contingency reserve may not be deployed to
manage other system fluctuations such as changes in load or wind generation output. Because
deviations caused by contingency events are covered by contingency reserve rather than regulation
reserve,they are excluded from the determination of the regulation reserve requirements. Because
frequency response reserve can overlap with that held for contingency and regulation reserve
requirements it is similarly excluded from the determination of regulation reserve requirements.
The types of operating reserve and relationship between them are further defined in in the Flexible
Resource Requirements section above.
Regulation reserve is capacity that PacifiCorp holds available to ensure compliance with the NERC
Control Performance Criteria in BAL-001-2, which requires a BAA to carry regulation reserve
incremental to contingency reserve to maintain reliability.19 The regulation reserve requirement is
not defined by a simple formula, but instead is the amount of reserve required by each BAA to
18 See footnote 12 above for explanation of PacifiCorp's use of the T-40 base schedule time point in the FRS.
19 NERC Standard BAL-001-2,https://www.nerc.comipa/Stand/Reliability%20Standards/BAL-001-2.pdf
64

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
meet specified control performance standards. Requirement two of BAL-001-2 defines the
compliance standard as follows:
Each Balancing Authority shall operate such that its clock-minute average of
Reporting ACE does not exceed its clock-minute Balancing Authority ACE Limit
(BAAL)for more than 30 consecutive clock-minutes...
PacifiCorp has been operating under BAL-001-2 since March 1, 2010, as part of a NERC
Reliability-Based Control field trial in the Western Interconnection, so PacifiCorp had experience
operating under the standard, even before it became effective on July 1, 2016.
The three key elements in BAL-001-2 are: (1) the length of time (or "interval") used to measure
compliance; (2)the percentage of intervals that a BAA must be within the limits set in the standard;
and (3) the bandwidth of acceptable deviation used under each standard to determine whether an
interval is considered out of compliance. These changes are discussed in further detail below.
The first element is the length of time used to measure compliance. Compliance under BAL-001-
2 is measured over rolling thirty-minute intervals, with 60 overlapping periods per hour, some of
which include parts of two clock-hours. In effect, this means that every minute of every hour is
the beginning of a new, thirty-minute compliance interval under the new BAL-001-2 standard. If
ACE is within the allowed limits at least once in a thirty-minute interval, that interval is in
compliance, so only the minimum deviation in each rolling thirty-minute interval is considered in
determining compliance. As a result, PacifiCorp does not need to hold regulation reserve for
deviations with duration less than 30 minutes.
The second element is the number of intervals where deviations are allowed to be outside the limits
set in the standard. BAL-001-2 requires 100 percent compliance, so deviations must be maintained
within the requirement set by the standard for all rolling thirty-minute intervals.
The third element is the bandwidth of acceptable deviation before an interval is considered out of
compliance. Under BAL-001-2, the acceptable deviation for each BAA is dynamic, varying as a
function of the frequency deviation for the entire interconnect. When interconnection frequency
exceeds 60 Hz, the dynamic calculation does not require regulation resources to be deployed
regardless of a BAA'S ACE. As interconnection frequency drops further below 60 Hz, a BAA'S
permissible ACE shortfall is increasingly restrictive.
Planning Reliability Target: Loss of Load Probability
When conducting resource planning, it is common to use a reliability target that assumes a
specified loss of load probability (LOLP). In effect, this is a plan to curtail firm load in rare
circumstances,rather than acquiring resources for extremely unlikely events. The reliability target
balances the cost of additional capacity against the benefit of incrementally more reliable
operation. By planning to curtail firm load in the rare event of a regulation reserve shortage,
PacifiCorp can maintain the required 100 percent compliance with the BAL-001-2 standard and
the Balancing Authority ACE Limit.This balances the cost of holding additional regulation reserve
against the likelihood of regulation reserve shortage events.
The FRS assumes that a regulation reserve forecasting methodology that results in 0.50 loss of
load hours per year due to regulation reserve shortages is appropriate for planning and ratemaking
65

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
purposes. This is in addition to any loss of load resulting from transmission or distribution outages,
resource adequacy, or other causes. The FRS applies this reliability target as follows:
• If the regulation reserve available is greater than the regulation reserve need for an hour,
the LOLP is zero for that hour.
• If the regulation reserve held is less than the amount needed,the LOLP is derived from the
Balancing Authority ACE Limit probability distribution as illustrated below.
Balancing Authority ACE Limit: Allowed Deviations
Even if insufficient regulation reserve capability is available to compensate for a thirty-minute
sustained deviation,a violation of BAL-001-2 does not occur unless the deviation also exceeds the
Balancing Authority ACE Limit.
The Balancing Authority ACE Limit is specific to each BAA and is dynamic,varying as a function
of interconnection frequency. When WECC frequency is close to 60 Hz, the Balancing Authority
ACE Limit is large and large deviations in ACE are allowed. As WECC frequency drops further
and further below 60 Hz,ACE deviations are increasingly restricted for BAAS that are contributing
to the shortfall, i.e. those BAAS with higher loads than resources. A BAA commits a BAL-001-2
reliability violation if in any thirty-minute interval it does not have at least one minute when its
ACE is within its Balancing Authority ACE Limit.
While the specific Balancing Authority ACE Limit for a given interval cannot be known in
advance,the historical probability distribution of Balancing Authority ACE Limit values is known.
Figure F.2 below shows the probability of exceeding the allowed deviation during a five-minute
interval for a given level of ACE shortfall. For instance, an 82 MW ACE shortfall in PACW has a
one percent chance of exceeding the Balancing Authority ACE Limit. WECC-wide frequency can
change rapidly and without notice, and this causes large changes in the Balancing Authority ACE
Limit over short time frames. Maintaining ACE within the Balancing Authority ACE Limit under
those circumstances can require rapid deployment of large amounts of operating reserve. To limit
the size and speed of resource deployment necessitated by variation in the Balancing Authority
ACE Limit, PacifrCorp's operating practice caps permissible ACE at the lesser of the Balancing
Authority ACE Limit or four times Lio. This also limits the occurrence of transmission flows that
exceed path ratings as result of large variations in ACE.20,2I This cap is reflected in Figure F.2.
20"Regional Industry Initiatives Assessment."NWPP MC Phase 3 Operations Integration Work Group.Dec. 31,
2014.Pg. 14.Available at:www.nwpp.org/documents/MC-Public/NWPP-MC-Phase-3-Regional-Industry-
Initiatives-Assessment 12-31-2014.pdf
21 "NERC Reliability-Based Control Field Trial Draft Report."Western Electricity Coordinating Council.Mar.25,
2015.Available at:www.wecc.biz/Reliability/RBC%20Field%2OTria1%2OReport%2OApproved%203-25-2015.pdf
66

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.2 -Probability of Exceeding Allowed Deviation
100%
90% -
0 80%
70%
0
3 60%
0
Q
tin 50%
c
i6
40%
x
w
0 30%
20%
0
10%
0%
0 25 50 75 100 125 150 175 200 225
ACE Shortfall (MW)
Exceedance Probability (PACW) —Exceedance Probability (PACE)
In 2018-2019, PacifiCorp's deviations and Balancing Authority ACE Limits were uncorrelated,
which indicates that PacifiCorp's contribution to WECC-wide frequency is small. PacifiCorp's
deviations and Balancing Authority ACE Limits were also uncorrelated when periods with large
deviations were examined in isolation. If PacifiCorp's large deviations made distinguishable
contributions to the Balancing Authority ACE Limit, ACE shortfalls would be more likely to
exceed the Balancing Authority ACE Limit during large deviations. Since this is not the case, the
probability of exceeding the Balancing Authority ACE Limit is lower, and less regulation reserve
is necessary to comply with the BAL-001-2 standard.
Regulation Reserve Forecast: Amount Held
To calculate the amount of regulation reserve required to be held while being compliant with BAL-
001-2—using a LOLP of 0.5 hours per year or less—a quantile regression methodology was used.
Quantile regression is a type of regression analysis. Whereas the typical method of ordinary least
squares results in estimates of the conditional mean(50th percentile)of the response variable given
certain values of the predictor variables, quantile regression aims at estimating other specified
percentiles of the response variable. Eight regressions were prepared, one for each class
(load/wind/solar/non-VER) and area (PACE/PACW). Each regression uses the following
variables:
• Response Variable: the error in each interval, in megawatts;
• Predictor Variable: the forecasted generation or load in each interval, expressed as a
percentage of area capacity;
67

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
The forecasted generation or load in each interval used as the predictor variable contributes to the
regression as a combination of linear, square, and higher order exponential effects. Specifically,
the regression identifies coefficients that correspond to the following functions for each class:
Load Error: Load Forecast'+ Constant
Wind Error: Wind Forecast2+Wind Forecast'
Solar Error: Solar Forecast4+ Solar Forecast3 + Solar Forecast2 + Solar Forecast'
Non-VER Error: Non-VER Forecast2+Non-VER Forecast'
The instances requiring the largest amounts of regulation reserve occur infrequently, and many
hours have very low requirements. If periods when requirements are likely to be low can be
distinguished from periods when requirements are likely to be high, less regulation reserve is
necessary to achieve a given reliability target. The regulation reserve forecast is not intended to
compensate for every potential deviation. Instead,when a shortfall occurs,the size of that shortfall
determines the probability of exceeding the Balancing Authority ACE Limit and a reliability
violation occurring. The forecast is adjusted to achieve a cumulative LOLP that corresponds to the
annual reliability target.
Regulation Reserve Forecast
Overview
The following forecasts are polynomial functions that cover a targeted percentile of all historical
deviations. These forecasts are stand-alone forecasts, based on the difference between hour-ahead
base schedules and actual meter data, expressing the errors as a function of the level of forecast.
The stand-alone reserve requirement shown achieves the annual reliability target of 0.5 hours per
year, after accounting for the dynamic Balancing Authority ACE Limit. The combined diversity
error system requirements are discussed later in the study. Figure F.3- Figure F.8 illustrate the
relationship between the regulation reserve requirements during 2018-2019 and the forecasted
level of output, for each resource class and control area. Both the regulation reserve requirements
and the forecasted level of output are expressed as a percentage of resource nameplate (i.e., as a
capacity factor). Figure F.9 and Figure F.10 illustrate the same relationship between the regulation
reserve requirements during 2018-2019 and the forecasted load for each control area. Both the
regulation reserve requirements and the forecasted load are expressed as a percentage of the annual
peak load(i.e., as a load factor).
68

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.3 -Wind Regulation Reserve Requirements by Forecast - PACE
PACE Wind - Relationship between Forecast and Error
45%
40%
35%
a 30%
t0
O
m _
°l 2Ou'O siS.,••T•jh.L��-..j:�,7'!•'�.� 6.J�.•:, .C:�
10%
50/0
0% �} _
0% 10% 20% 30% 40% SO% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure F.4 -Wind Regulation Reserve Requirements by Forecast Capacity Factor- PACW
PACW Wind - Relationship between Forecast and Error
45%
40%
35%
yam'. it'
m 30% •_3•:
o ' 'r•'':r � •�s,i�r ii'.:. :.
CL
t .a'
10%
i
5°/O
O%
0% 10% 201. 3030 40°io 50% 6040 70°0 800/. 900/.
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
69

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.5 - Solar Regulation Reserve Requirements by Forecast Capacity Factor- PACE
PACE Solar- Relationship between Forecast and Error
55%
50%
45%
Al-
30% "'' t?��rU' !�.x>x•-•c'e...,•'iL~�%'3•�t':•i
2511.
K.
1S% '*
10%
5%
0%
0% 10% 20% 30% 40% 504b 601�0 70°1, 80116 9030
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure F.6 - Solar Regulation Reserve Requirements by Forecast Capacity Factor - PACW
PACW Solar- Relationship between Forecast and Error
55%
50%
45%
T
a 40% -
m
0 3S% ' •! •.
711
1S%
10%
5%
O%
0% 10% 209/o 3000 40% 50% 60% 70% 80°i 9090
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
70

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.7—Non-VER Regulation Reserve Requirements by Capacity Factor- PACE
PACE Non-VER- Relationship between Forecast and Error
24% •i
22% r
20%
} f .
a 18%
16% •r'
a 14%
V12% ,lt.
16
.'7.y x �x. g y, .j�♦
41/'. �L.• =.tom' •R •X�. •i
U°° lr
20% 30% 40% SO% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure F.8—Non-VER Regulation Reserve Requirements by Capacity Factor- PACW
PACW Non-VER- Relationship between Forecast and Error
24%
22%
20%
z 18%
V •
16%
°+ 14%
�.•
f... -
8°hLu
2% a, y
O%
20% 30% 40% 50,46 60% 70°ro 801/. 90".
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
71

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.9—Stand-alone Load Regulation Reserve Requirements - PACE
PACE Load- Relationship between Forecast and Error
7.0%
6.5%
6.0%
5.5%
5.0%
o -
m 4.5%
a
0 4.O% �.
rn c
ra 2.5% .• :- '.• .a .r'Tas „a. `.•'.• }::,,.ir ., .c
1.0%
0.5%
O.O%
30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Peak Load
Reserves
■ Reserve Requirement
Figure F.10—Stand-alone Load Regulation Reserve Requirements - PACW
PACW Load-Relationship between Forecast and Error
7.0% _ - -
6.5%
6.0%
5.5%
o e
6 4.09/. i
ra 2.5/o r-
°
w 2.0/o
1.0%
0.5%
O.O% i t.
300/c 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Peak Load
Reserves
M Reserve Requirement
72

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
The results of the analysis are shown in Table F.3 below.
Table F.3— Summar of Stand-alone Regulation Reserve Re uirements
Stand-alone Regulation Capacity Stand-alone Regulation
Scenario Forecast(aMW) (MW Forecast
Non-VER 106 1,304 8.2%
Load 334 10,094 3.3%
VER-Wind 457 2,745 16.7%
VER- Solar 159 1,080 14.8%
Total 1,057
ortfolio Diversity and EIM Diversity Benefit
The EIM is a voluntary energy imbalance market service through the CAISO where market
systems automatically balance supply and demand for electricity every fifteen and five minutes,
dispatching least-cost resources every five minutes.
PacifiCorp and CAISO began full EIM operation on November 1, 2014. Many additional
participants have since joined the EIM, such that it now includes nearly 80%of electricity demand
in the Western interconnection, and more participants are scheduled to join in the next several
years. PacifiCorp's participation in the EIM results in improved power production forecasting and
optimized intra-hour resource dispatch. This brings important benefits including reduced energy
dispatch costs through automatic dispatch, enhanced reliability with improved situational
awareness,better integration of renewable energy resources,and reduced curtailment of renewable
energy resources.
The EIM also has direct effects related to regulation reserve requirements. First, because of EIM
participation, PacifiCorp has improved data used in the analysis contained in this FRS. The data
and control provided by the EIM allow PacifiCorp to achieve the portfolio diversity benefits
described in the first part of this section. Second, the EIM's intra-hour capabilities across the
broader EIM footprint provide the opportunity to reduce the amount of regulation reserve
necessary for PacifiCorp to hold, as further explained in the second part of this section.
Portfolio Diversity Benefit
The regulation reserve forecasts described above independently ensure that the probability of a
reliability violation for each class remains within the reliability target; however, the largest
deviations in each class tend not to occur simultaneously, and in some cases, deviations will occur
in offsetting directions. Because the deviations are not occurring at the same time, the regulation
reserve held can cover the expected deviations for multiple classes at once and a reduced total
quantity of reserve is sufficient to maintain the desired level of reliability. This reduction in the
reserve requirement is the diversity benefit from holding a single pool of reserve to cover
deviations in Solar, Wind, Non-VERs, and Load. As a result, the regulation reserve forecast for
the portfolio can be reduced while still meeting the reliability target. In the historical period,
73

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
portfolio diversity from the interactions between the various classes results in a regulation reserve
requirement that is 36%lower than the sum of the stand-alone requirements,or approximately 679
MW.
EIM Diversity Benefit
In addition to the direct benefits from EIM's increased system visibility and improved intra-hour
operational performance described above, the participation of other entities in the broader EIM
footprint provides the opportunity to further reduce the amount of regulation reserve PacifiCorp
must hold.
By pooling variability in load and resource output, EIM entities reduce the quantity of reserve
required to meet flexibility needs. The EIM also facilitates procurement of flexible ramping
capacity in the fifteen-minute market to address variability that may occur in the five-minute
market. Because variability across different BAAS may happen in opposite directions,the flexible
ramping requirement for the entire EIM footprint can be less than the sum of individual BAA
requirements. This difference is known as the"diversity benefit"in the EIM. This diversity benefit
reflects offsetting variability and lower combined uncertainty. This flexibility reserve(uncertainty
requirement) is in addition to the spinning and supplemental reserve carried against generation or
transmission system contingencies under the NERC standards.
The CAISO calculates the EIM diversity benefit by first calculating an uncertainty requirement
for each individual EIM BAA and then by comparing the sum of those requirements to the
uncertainty requirement for the entire EIM area. The latter amount is expected to be less than the
sum of the uncertainty requirements from the individual BAAS due to the portfolio diversification
effect of forecasting a larger pool of load and resources using intra-hour scheduling and increased
system visibility in the hypothetical, single-BAA EIM. Each EIM BAA is then credited with a
share of the diversity benefit calculated by CAISO based on its share of the stand-alone
requirement relative to the total stand-alone requirement.
The EIM does not relieve participants of their reliability responsibilities. EIM entities are required
to have sufficient resources to serve their load on a standalone basis each hour before participating
in the EIM. Thus, each EIM participant remains responsible for all reliability obligations. Despite
these limitations,EIM imports from other participating BAAS can help balance PacifiCorp's loads
and resources within an hour, reducing the size of reserve shortfalls and the likelihood of a
Balancing Authority ACE Limit violation.While substantial EIM imports do occur in some hours,
it is only appropriate to rely on PacifiCorp's diversity benefit associated with EIM participation,
as these are derived from the structure of the EIM rather than resources contributed by other
participants.
Table F.4 below provides a numeric example of uncertainty requirements and application of the
calculated diversity benefit.
74

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Table FA—EIM Dive sity Benefit Application Example
a b c d e f g h i j
=a+b+c+ =e-f =g/e =c*h =c-i
d
CAISO NEVP PACE PACW Total Total PACE
req't. req't. req't. req't. req't. req't. Total Diversity PACE req't.
diversity benefit
before before before before before after benefit ratio benefit after
benefit benefit benefit benefit benefit benefit benefit
Hour (MW) (MW) (MW) (MW) I (MW) (MW) (MW) (MW) (MW) (MW)
1 550 110 165 100 925 583 342 37.00% 61 104
2 600 110 165 100 975 636 339 34.80% 57 108
3 650 110 165 110 1,035 689 346 33.40% 55 110
4 667 120 180 113 1,080 742 338 31.30% 56 124
While the diversity benefit is uncertain, that uncertainty is not significantly different from the
uncertainty in the Balancing Authority ACE Limit previously described. In the FRS, PacifiCorp
has credited the regulation reserve forecast based on a historical distribution of calculated EIM
diversity benefits. While this FRS considers regulation reserve requirements in 2018-2019, the
CAISO identified an error in their calculation of uncertainty requirements in early 2018. CAISO's
published uncertainty requirements and associated diversity benefits are now only valid for March
2018 forward. To capture these additional benefits for this analysis, PacifiCorp has applied the
historical distribution of EIM diversity benefits from the 12 months beginning March 2018. In the
historical study period, EIM diversity benefits used in the FRS would have reduced regulation
reserve requirements by approximately 140 MW.
The inclusion of EIM diversity benefits in the FRS reduces the magnitude, and thus probability,
of reserve shortfalls and, in doing so, reduces the overall regulation reserve requirement. This
allows PacifiCorp's forecasted requirements to be reduced. As shown in Table F.5 below, the
resulting regulation reserve requirement is 540 MW, which is a 49 percent reduction (including
the portfolio diversity benefit) compared to the stand-alone requirement for each class. This
portfolio regulation forecast is expected to achieve an LOLP of 0.5 hours per year.
Table F.5 —2018-2019 Results with Portfolio Diversity and EIM Diversity Benefits
Stand-alone Portfolio
Regulation Stand-alone Regulation Portfolio
Forecast Rate Forecast w/EIM Rate Capacity Rate
Scenario (aMW) (%) (aMW) (%) (MW) Determinant
Non-VER 106 8.2% 55 4.2% 1,304 Nameplate
Load 334 3.3% 172 1.7% 10,094 12 CP
VER-Wind 457 16.7% 237 8.6% 2,745 Nameplate
VER-Solar 159 14.8% 76 7.1% 1,080 Nameplate
Total 1,057 540
75

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
Fast-Ramping Reserve Requirements
As previously discussed, Requirement 1 of BAL-001-2 specifies that PacifiCorp's CPS1 score
must be greater than equal to 100 percent for each preceding 12 consecutive calendar month period,
evaluated monthly. The CPS 1 score compares PacifiCorp's ACE with interconnection frequency
during each clock minute. A higher score indicates PacifiCorp's ACE is helping interconnection
frequency, while a lower score indicates it is hurting interconnection frequency. Because CPS 1 is
averaged and evaluated on a monthly basis, it does not require a response to each and every ACE
event,but rather requires that PacifiCorp meet a minimum aggregate level of performance in each
month.
The Regulation Reserve Forecast described above is evaluating requirements for extreme
deviations that are at least 30 minutes in duration, for compliance with Requirement 2 of BAL-
001-2. In contrast, compliance with CPS1 requires reserve capability to compensate for most
conditions over a minute-to-minute basis. These fast-ramping resources would be deployed
frequently and would also contribute to compliance with Requirement 2 of BAL-001-2, so they
are a subset of the Regulation Reserve Forecast described above.
To evaluate CPS1 requirements, PacifiCorp compared the net load change for each five-minute
interval in the study period to the corresponding value for Requirement 2 compliance in that hour
from the Regulation Reserve Forecast, after accounting for diversity (resulting in a 540 MW
average requirement).Resources may deploy for Requirement 2 compliance over up to 30 minutes,
so the average requirement of 540 MW would require ramping capability of at least 18.0 MW per
minute (540 MW/ 30 minutes).
Because CPS 1 is averaged and evaluated monthly, it does not require a response to each and every
ACE event,but rather requires that PacifiCorp meet a minimum aggregate level of performance in
each month. Resources capable of ensuring compliance in 95 percent of intervals are expected to
be sufficient to meet CPS 1 and given that ACE may deviate in either a positive or negative
direction, the 97.5th percentile of incremental requirements versus Requirement 2 in that interval
was evaluated. At the 97.5th percentile, fast ramping requirements for PACE and PACW are 1.7
MW/minute and 0.8 MW/minute higher than the Requirement 2 ramp rate,respectively; however,
if dynamic transfers between the BAAS are available, the 97.5th percentile for system is 0.6 MW/
minute lower than the Requirement 2 value. When viewed on a system basis, this means that 30-
minute ramping capability held for Requirement 2 would be sufficient to cover an adequate portion
of the fast-ramping events to ensure CPS 1 compliance.
Note that resources must respond immediately to ensure compliance with Requirement 1, as
performance is measured on a minute-to-minute basis. As a result, resources that respond after a
delay, such as quick-start gas plants or certain interruptible loads, would not be suitable for
Requirement 1 compliance, so these resources cannot be allocated the entire regulation reserve
requirement.However,because Requirement 1 compliance is a small portion of the total regulation
reserve requirement,these restrictions on resource type are unlikely to be a meaningful constraint.
In addition, CPS 1 compliance is weighted toward performance during conditions when
interconnection frequency deviations are large. The largest frequency deviations would also result
in deployment of frequency response reserves, which are somewhat larger in magnitude, though
76

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
they have a less stringent performance metric under BAL-003-2,based on median response during
the largest events.
In light of the overlaps with BAL-001-2 Requirement 2 and BAL-003-2 described above, CPS1
compliance is not expected to result in an additional requirement beyond what is necessary to
comply with those standards.
Portfolio Regulation Reserve Requirements
The IRP portfolio optimization process contemplates the addition of new wind and solar capacity
as part of its selection of future resources, as well as changes in peak load due to load growth and
energy efficiency measure selection. These load and resource changes are expected to drive
changes in PacifiCorp's regulation reserve requirements that will vary from portfolio to portfolio.
The locations that have been identified as likely sites for future wind and solar additions are in
relatively close proximity to existing wind and solar resources, and PacifiCorp's portfolio of
resources is already relatively diverse with significant wind in Wyoming, along the Columbia
River gorge, and in eastern Idaho/western Wyoming and significant solar in southern Utah and
southern Oregon. Because future resources are likely to be added in relatively close proximity to
these existing resources, they are not likely to change the diversity for that class of resources as a
whole. Given the sizeable sample of existing wind and solar resources in PACE and PACW,
maintaining the existing level of diversity as a class of resources doubles or quadruples is a more
likely outcome than the continuing improvements previously assumed in the 2019 FRS. With that
in mind, the incremental regulation reserve analysis for the 2021 FRS methodology assumes that
wind, solar, and load deviations scale linearly with capacity increases from the actual data in the
2018-2019 historical period.
While diversity within each class is not expected to change significantly, there is the opportunity
for greater diversity among the wind,solar,and load requirements.These portfolio-related benefits
are inherently tied to the portfolio, so it is appropriate that they vary with the portfolio. To that
end,the 2021 FRS methodology calculates the portfolio diversity benefits specific to a wide variety
of wind and solar capacity combinations,rather than relying upon the historical portfolio diversity
value.
As part of the portfolio diversity calculation, the analysis assumes that minimum EIM flexible
reserve requirements and EIM diversity benefits scale with changes in portfolio capacity. EIM
minimum flexible reserve requirements are tied to the uncertainty in PacifiCorp's requirements,
which grow with changes portfolio capacity, so it would be impacted directly. EIM diversity
benefits reflect PacifiCorp's share of stand-alone requirements relative to those of the rest of the
BAA's participating in EIM. All else being equal, increases in PacifiCorp's portfolio capacity
would result in a greater proportion of the EIM diversity benefits being allocated to PacifiCorp.
Portfolio diversity is driven by interplay among the deviations by wind, solar, and load, so it is not
a single number, but rather is dependent on the specific conditions. The 2021 FRS methodology
incorporates two mechanisms to better account for these interactions. First, a portfolio diversity
value is calculated specific to each hour of the day in each season. Second,rather than applying an
equal percentage reduction to all hours, diversity benefits are assumed to be highest when stand-
77

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
alone requirements are highest. For example,there is more opportunity for offsetting requirements
when load, wind, and solar all have significant stand-alone requirements. With that in mind,
diversity is applied as an exponent to the incremental requirement more than the EIM minimum
requirement. The result of this calculation is a diversity benefit which is highest for large reserve
requirements, and which approaches zero as the requirement approaches the EIM minimum, as
illustrated in Table F.6.
Table F.6-Portfolio Diversity Exponent Example
Incremental Requirement w/
Diversity(NM Portfolio Diversity(%)
By Diversity Ex onent By Diversity Exponent
Stand-alone EIM Stand-alone
Reserve Floor Incremental d= e= f= g=1 - h=1 i=1- -
Req.(MW) (MW) Req.(MW) c ^ 75% c ^85% c^ 95% (b+d)/a (b+e)/a (b+f)/a
a b c=a-b 75% 85% 95% 75% 85% 95%
200 200 0 0 0 0 0% 0% 0%
250 200 50 19 28 41 12% 9% 4%
300 200 100 32 50 79 23% 17% 1 7%
350 200 150 43 71 117 31% 23% 9%
400 200 200 53 90 153 37% 27% 12%
450 200 250 63 109 190 42% 31% 13%
500 200 300 72 128 226 46% 34% 15%
For each combination of wind and solar capacity,the hourly portfolio diversity exponents for each
season are increased in a stepwise fashion until the risk of regulation reserve shortfalls during an
interval is sufficiently low and the overall risk of regulation reserve shortfalls achieves the target
of 0.5 hours per year. The resulting portfolio diversity is maximized for a combination of wind
and solar as summarized in Table F.77 and Table F.8 for PacifiCorp East and PacifiCorp West,
respectively.
Table F.7-PacifiCorp East Diversity by Portfolio Composition
MW % % Reduction vs. Stand-alone Requirements)
8,224 548% 17.2% 18.8% 20.6
v 7,184 472% 19.2% 21.5% 23.09%. 25.5% 26.5%
6,144 395% 22.9% 24.1% 25.6% 27.9% 28.5% 29.0%
U 5,104 319% 26.0% 27.3% 29.2% 30.7% 30.7% 30.59%. 29.5%
4,064 242% 30.4% 31.6% 32.9% 33.89%. 32.7% 32.8% 32.8%
3,024 166% 35.0% 36.2% 38.5% 37.1% 37.6% 36.2% 33.9% 31.9%
1,575 100% 48.0% 45.8% 43.1% 39.5% 35.8% 32.2% 29.4%
W
788 50% 1 46.4% 40.3% 36.4% 33.0% 30.0% 27.3%
50% 100% 166% 329% 493% 656% 820% 983% %
428 855 1,462 2,502 3,542 4,582 5,622 6,662 MW
East Solar Capacity
2018-2019 Actual Wind and Solar Capacity
78

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
Table F.8-PacifiCorp West Diversity by Portfolio Composition
MW % % Reduction vs. Stand-alone Requirements)
4,389 548% KR.1% 22.4% 22.9%
3,669 472% 23.4% 24.8% 25.4%141M. 33.0%
2,949 395% 26.2% 26.7% 27.6% 32.1% 34.8% 38.1%
.� 2,229 319% 29.6% 30.6% 31.4% 36.2% 39.5% 42.7% 42.7%
1,509 242% 33.8% 34.5% 36.3% 40.8% 45.2% 46.2% 43.9%
789 166% 38.8% 41.6% 43.1% 47.6% 48.4% 47.7% 45.0% 44.3%
y 726 100% 42.4% 42.9% 48.6% 49.3% 47.7% 46.2% 44.4%
363 50% 41.7% 47.1% 49.8% 47.4% 45.0% 43.2%
50% 100% 166% 329% 493% 656% 820% 983% %
111 221 321 1,041 1,761 2,481 3,201 3,921 MW
West Solar Capacity
2018-2019 Actual Wind and Solar Capacity
After portfolio selection is complete, regulation reserve requirements are calculated specific to a
portfolio's load,wind, and solar resources in each year. The hourly regulation reserve requirement
varies as a function of annual peak load net of energy efficiency selections as well as total wind
and solar capacity. The regulation reserve requirement also varies based on the hourly load net of
energy efficiency and hourly wind and solar generation values. Diversity exponents specific to the
wind and solar capacity in each year are applied by hour and season, by interpolating among the
scenarios illustrated in Figure F.7 and Figure F.8. For example, the diversity exponent for hour
five in the spring for a PACW study with 1,000 MW of wind and 1,000 MW of solar would reflect
a weighting of diversity exponents in hour five in the spring from four scenarios. The highest
weighting would apply to the 789 MW wind/1,041 MW solar scenario, and successively lower
weightings would apply to 1,509 MW wind/1,041 MW solar, 789 MW wind/321 MW solar, and
1,509 MW wind/321 MW solar, with the total weighting for all four scenarios summing to 100%.
Finally, an adjustment is made to account for the ability of resources that are combined with
storage to offset their own generation shortfalls beyond what is already captured by the model.
For example, combined solar and storage resources can offset their own generation shortfalls, up
to their interconnection limit. In actual operation, a reduction in solar generation would enable
additional storage discharge. However, within the PLEXOS model, there are no intra-hour
variations in load or renewable resource output and thus no potential increase in storage discharge.
Note that combined storage can only be discharged when there is a generation shortfall at the
adjacent resource, so it cannot cover all shortfalls across the system. For example, many solar
resources do not have co-located storage, and their errors would continue to need to be met with
incremental reserves. Nonetheless, combined solar and storage can cover a portion of their own
shortfalls, and that portion increases as more combined storage resources are added to the system.
This adjustment reduces the hourly regulation reserve requirement that is entered in the model.
Regulation Reserve Cost
The PLEXOS model reports marginal reserve prices on an hourly basis. So long as the change in
reserve obligations or capability from what was input for a study is relatively small, this reserve
79

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
price can provide a reasonable estimate of the impact of changes in reserves, without requiring
additional model runs.
To estimate wind and solar integration costs for the 2025 IRP, PacifiCorp prepared a PLEXOS
scenario that reflected the final regulation reserve requirements, consistent with the Company's
existing wind and resources plus selections in the preferred portfolio. Hourly regulation reserve
prices were reported from this study.
Note—Incremental regulation reserve requirements discussed below will be updated for the
March 31, 2025 IRP filing based on final preferred portfolio results.
Wind Integration
The wind reserve case uses the 2021 FRS methodology to recalculate the wind reserve
requirement for a portfolio with 5 MW more wind resources starting in the first year proxy
resources are generally available and extending to the end of the IRP study horizon(2028-
2045). The change in resources is applied equally between PACE and PACW, and is
allocated pro-rata among all wind resources in the area, such that the aggregate hourly
capacity factor is not impacted by the change in capacity. The change in wind capacity
results in incremental regulation reserve requirements that average approximately XX% of
the nameplate capacity of the wind. Wind integration costs are calculated by multiplying
the hourly change in reserve requirements (in MW) by the hourly regulation reserve price
in each hour of the year, and then dividing that total by the incremental wind generation
over the year.
Solar Integration
The solar reserve case uses the 2021 FRS methodology to recalculate the solar reserve
requirement for a portfolio with 5 MW more solar resources starting in the first year proxy
resources are generally available and extending to the end of the IRP study horizon(2028-
2045). The reduction in resources is applied equally between PACE and PACW, and is
allocated pro-rata among all solar resources in the area, such that the aggregate hourly
capacity factor is not impacted by the change in capacity. The change in solar capacity
results in incremental regulation reserve requirements that average approximately XX% of
the nameplate capacity of the solar. Solar integration costs are calculated by multiplying
the hourly change in reserve requirements (in MW) by the hourly regulation reserve price
in each hour of the year, and then dividing that total by the incremental solar generation
over the year.
The incremental regulation reserve cost results for wind and solar are shown in Figure F.11. The
comparable regulation reserve costs from the 2021 FRS are also shown. Integration costs are high
in the near term, as market prices are currently high and flexible capacity is somewhat limited.
Integration costs fall as energy storage resources are added to the portfolio, as they can provide
free operating reserves while charging and in any hour in which they are not discharging and not
fully depleted, which for a four-hour energy storage resource is most of the day.
80

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
Figure F.11 —Incremental Wind and Solar Regulation Reserve Costs
Note—Figure F.11 will be updated for the March 31, 2025 IRP filing based on final
preferred portfolio results.
Flexible Resource Needs Assessment
Overview
In its Order No. 12-013 issued on January 19, 2012, in Docket No. UM 1461 on"Investigation of
matters related to Electric Vehicle Charging", the Oregon Public Utility Commission (OPUC)
adopted the OPUC staff s proposed IRP guideline:
1. Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the
balancing reserves needed at different time intervals (e.g. ramping needed within 5
minutes)to respond to variation in load and intermittent renewable generation over the 20-
year planning period;
2. Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing
reserves available at different time intervals(e.g.ramping available within 5 minutes)from
existing generating resources over the 20-year planning period; and
3. Evaluate Flexible Resources on a Consistent and Comparable Basis: In planning to fill any
gap between the demand and supply of flexible capacity,the electric utilities shall evaluate
all resource options including the use of electric vehicles (EVs), on a consistent and
comparable basis.
In this section, PacifiCorp first identifies its flexible resource needs for the IRP study period of
2025 through 2045, and the calculation method used to estimate those requirements. PacifiCorp
then identifies its supply of flexible capacity from its generation resources, in accordance with the
Western Electricity Coordinating Council (WECC) operating reserve guidelines, demonstrating
that PacifiCorp has sufficient flexible resources to meet its requirements.
Forecasted Reserve Requirements
Since contingency reserve and regulation reserve are separate and distinct components,PacifiCorp
estimates the forward requirements for each separately. The contingency reserve requirements are
derived from the PLEXOS model. The regulating reserve requirements are part of the inputs to the
PLEXOS model and are calculated by applying the methods developed in the Portfolio Regulation
Reserve Requirements section. The contingency and regulation reserve requirements are two
distinct components that are modeled separately in the 2025 IRP: 10-minute contingency reserve
requirements and 30-minute regulation reserve requirements. The average reserve requirements
for PacifiCorp's two balancing authority areas are shown in Table F.9 below.
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PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
Table F.9 -Reserve Requirements (Average MV)
Note— Table F.9 will be updated for the March 31, 2025 IRP filing based on the final
preferred portfolio results.
Flexible Resource Supply Forecast
Requirements by NERC and the WECC dictate the types of resources that can be used to serve the
reserve requirements.
• 10-minute spinning reserve can only be provided by resources currently online and
synchronized to the transmission grid;
• 10-minute non-spinning reserve may be served by fast-start resources that are capable of
being online and synchronized to the transmission grid within ten minutes. Interruptible
load can only provide non-spinning reserve. Non-spinning reserve may be provided by
resources that are capable of providing spinning reserve.
• 30-minute regulation reserve can be provided by unused spinning or non-spinning
reserve. Incremental 30-minute ramping capability beyond the 10-minute capability
captured in the categories above also counts toward this requirement.
The resources that PacifiCorp employs to serve its reserve requirements include owned hydro
resources that have storage, owned thermal resources, and purchased power contracts that provide
reserve capability.
Hydro resources are generally deployed first to meet the spinning reserve requirements because of
their flexibility and their ability to respond quickly. The amount of reserve that these resources can
provide depends upon the difference between their expected capacities and their generation level
at the time. The hydro resources that PacifiCorp may use to cover reserve requirements in the
PacifiCorp West balancing authority area include its facilities on the Lewis River and the Klamath
River as well as its share of generation and capacity from the Mid-Columbia projects. In the
PacifiCorp East balancing authority area, PacifiCorp may use facilities on the Bear River to
provide spinning reserve.
Thermal resources are also used to meet the spinning reserve requirements when they are online.
The amount of reserve provided by these resources is determined by their ability to ramp up within
a 10-minute interval. For natural gas-fired combustion turbines,the amount of reserve can be close
to the differences between their nameplate capacities and their minimum generation levels. In
contrast, both coal and gas-converted steam turbines have slower ramp rates, and may ramp from
minimum to maximum over an hour or more. In the current IRP, PacifiCorp's reserve needs are
increasingly met by energy storage resources, including contracted resources and proxy resource
selections in the preferred portfolio.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Table F.10 lists the annual reserve capability from resources in PacifiCorp's East and West
balancing authority areas.22 The changes in the flexible resource supply reflect retirement of
existing resources, addition of new preferred portfolio resources, and variation in hydro capability
due to forecasted streamflow conditions, and expiration of contracts from the Mid-Columbia
projects that are reflected in the preferred portfolio.
Table F.10 -Flexible Resource Supply Forecast (Average MW)
Note— Table F.10 will be updated for the March 31, 2025 IRP filing based on the
final preferred portfolio results.
Figure F.12 and Figure F.13 graphically display the balances of reserve requirements and
capability of spinning reserve resources in PacifiCorp's East and West balancing authority areas
respectively. The graphs demonstrate that PacifiCorp's system has sufficient resources to serve its
reserve requirements throughout the IRP planning period. Note that keeping minimum amounts
in energy storage or bringing thermal plants online and/or reducing their generation while online
could increase the available response beyond that shown in the figures. In addition, PacifiCorp
currently can transfer a portion of the operating reserves held in either of its balancing authority
areas to help meet the requirements of its other balancing authority area,based on the reserve need
and relative economics of the available supply.
Figure F.12 - Comparison of Reserve Requirements and Resources, East Balancing
Authority Area (MW)
Note—Figure F.12 will be updated for the March 31, 2025 IRP filing based on the
final preferred portfolio results.
Figure F.13 - Comparison of Reserve Requirements and Resources, West Balancing
Authority Area (MW)
Note—Figure F.13 will be updated for the March 31, 2025 IRP filing based on the
final preferred portfolio results.
Flexible Resource Supply Planning
In actual operations, PacifiCorp has been able to serve its reserve requirements and has not
experienced any incidents where it was short of reserve. PacifiCorp manages its resources to meet
its reserve obligation in the same manner as meeting its load obligation — through long term
22 Frequency response capability is a subset of the 10-minute capability shown. Battery resources are capable of
responding with their maximum output during a frequency event and can provide an even greater response if they
were charging at the start of an event.PacifiCorp has sufficient frequency response capability at present and by 2025
the battery capacity currently contracted or added in the preferred portfolio will exceed PacifiCorp's current 266.4
MW frequency response obligation for a 0.3 Hz event.As a result,compliance with the frequency response obligation
is not anticipated to require incremental supply.
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PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
planning,market transactions,utilization of the transmission capability between the two balancing
authority areas, and operational activities that are performed on an economic basis.
PacifiCorp and the California Independent System Operator Corporation implemented the energy
imbalance market (EIM) on November 1, 2014, and participation by other utilities has expanded
significantly with more participants scheduled for entry through 2026. By pooling variability in
load and resource output, EIM entities reduce the quantity of reserve required to meet flexibility
needs. Because variability across different BAAS may happen in opposite directions, the
uncertainty requirement for the entire EIM footprint can be less than the sum of individual BAAS'
requirements. This difference is known as the"diversity benefit"in the EIM. This diversity benefit
reflects offsetting variability and lower combined uncertainty. PacifiCorp's regulation reserve
forecast includes a credit to account for the diversity benefits associated with its participation in
EIM.
As indicated in OPUC order 12-013, electric vehicle technologies may be able to meet flexible
resource needs. Since the 2023 IRP, electric vehicle load control has been one of the demand
response options available for selection. While operating reserve supply is projected to be well in
excess of operating reserve requirements, the rising supply of zero-cost renewable resources
increases the value associated with shifting load within the day and seasonally, rather than just
within the hour as contemplated in this appendix.
84

PACIFICORP—2025 IRP APPENDIX G—PLANT WATER CONSUMPTION STUDY
APPENDIX G - PLANT WATER CONSUMPTION STUDY
The information provided in this appendix is for PacifiCorp owned plants. Total water
consumption and generation includes all owners for jointly owned facilities.
Water intake for each facility is determined by using data acquired from water contracts, water
shares and private water rights for each individual facility. Total consumption is the difference
between raw water intake and the total water discharged at each respective location. Plant specific
water consumption rates are calculated using consumption divided by plant Net MWh production.'
For the purposes of water consumption estimates,PacifiCorp is using a four-year average historical
model to estimate future water usage. Past water consumption rates have suggested that baseline
water usage for thermal generation is consistent year over year with only minor variations in water
consumption per Net MWh. 2020-2023 data remained consistent with this model predicting
consistent baseline water data. 2023 saw approximately a 25% decrease in Net MWh production
while water consumption decreased by around 10% which led to a higher rate of water
consumption per MWh produced. The four-year average will remain viable as a predictive model
if thermal generation data continues to fall within the range seen in the past four years. If thermal
generation decreases significantly,the actual rates will likely be higher than the four-year average,
similar to 2023.
' Updated water usage was a topic included in stakeholder feedback during the public input meeting series. See
Appendix M,stakeholder feedback form#11 (Utah Environmental Caucus).
85

PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
86

PACIFICORP-2025 IRP APPENDLY G-PLANT WATER CONSUMPTION
Study Data
Table G.1 -Plant Water Consumption with Acre-Feet* per Year
Acre-Feet Per Year \et%Iwhs Per fear 4-•ear Average
Zero Cooling 4-year Gals/ GP1%11
Plant Name Discharge Media 2020 2021 2022 2023 Avenge 2020 2021 2022 2023 MWH 11iW
Chehalis Air 66 71 4- 44 57 2.407.519 2.248?37 2.172.465 2.239346 8 0.1
Currant Creek Yes Air 95 113 85 133 106 2335.426 2:746:290 2:805:979 2:879:943 13 0.2
Dave Johnston Water 7,856 6,571 5,901 12.770 8,275 4,325,604 3:601:242 32581,919 3,537,695 717 11.9
Gadsby Water 409 339 454 184 346 133,410 83,008 118,821 236,930 789 13.2
Hunter Yes Water 15,103 16,326 13,426 8,788 13,411 7,988,203 9,248,963 7,381,184 3,410,309 624 10.4
Huntington Yes Water 7,929 12,019 11,717 7,427 9,773 4,515,305 6,263,658 5,673,115 3,400,758 642 10.7
Jim Bridger Yes Water 18,184 19,103 19,076 15,054 17,854 10,458,575 10,342,840 10,662,019 6,075,458 620 10.3
Lakeside Water 4,075 4,421 4,591 4,435 4,380 5,560,112 6,389,355 6578,673 6,456,506 229 3.8
Naughton Yes Water 7.622 7,236 6.929 7.570 7,339 2.659,033 2.596.446 2,456,201 2.766.289 913 15.2
XN7,odak Yes Air 336 333 324 283 319 1.732.784 1_717528 1,779,843 1.282117 64 1.1
TOTAL 61,675 66,532 62,55 56,6N 42,115,971 45,237,567 43,210,219 32,285,351 472 7.9
*One acre-foot of water is equivalent to 325,851 Gallons or 43,560 Cubic Feet.
Gadsby includes a mix of both Rankine steam units and Brayton peaking gas turbines.
87

PACIEICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
88

PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
Table G.2-Plant Water Consumption by State (acre-feet)
LTAH PUNTS �
Plant Name 2017 2018 2019 2020 2021 2022 2023
Currant Creek 116 110 101 95 113 85 133
Gadsby 100 205 281 409 339 454 184
Hunter 15,383 14,751 15,808 15,103 16.326 13,426 8,788
Huntington 9,653 9,804 9,028 7,929 12,019 11,717 7,427
Lakeside 2,698 3,648 1894 4,075 4,421 4,591 4435
TOTAL JK 1 2' 28,513 29,1121 27,611 1111111F30,273 20,966
Percent of total water consumption= 44A0 o
WYOMING P
Plant Name 2017 2018 2019 2020 212022 2023
Dave Johnston 8:231 8,325 8,485 7:856 6,571 5:901 12:770
Jim Bridger 19,047 20,067 19,893 18,184 19,103 19,076 15,054
Naughton 6,927 9:916 10,195 7,622 7,236 6,929 7,570
Wvodak 332 319 292 336 333 324 283
TOTAL 33,627 38,365 33,998 33-243M 32,230 35,678
Percent of total water consumption= ^5 60 0
Table G.3 -Plant Water Consumption by Fuel Type (acre-feet)
COAL FIRED PLANTS
Plant Name 2023
Dave Johnston 8,231 8,325 8,485 7,856 6,571 5,901 12770
Hunter 15,383 14,751 15;808 15,103 16,326 13,426 8,788
Huntington 9.653 9,804 9,028 7,929 12.019 11,717 7,427
Jim er 19.047 20,067 19,893 18,184 19.103 19,076 15,054
Naughton 6.927 9.916 10,195 7.622 7.236 6.929 7.570
Wyodak 332 "1 292 336 333 324 283
'TOTAL 59,573 63,182 63,701 57,030 61,588 57j73 51,393
Percent of total water consumption= 93.10o
NATURAL GAS FIRED PLANTS
Plant Name 2017 2018 2019 2020 2021 2022 2023
Currant Creek 116 110 101 95 lll, SS 133
Chehalis 54 33 63 66 71 47 45
Gadsby 100 205 281 409 339 454 184
Lakeside 2 69S 3.648 3.894 4.075 4,421 4,591 4,435
TOTAL 2,%8 3,9% 4,339 MIA,57 4.796
Percent of total water consumption= 6.90 o
Table GA-Plant Water Consumption for Plants Located in the Upper Colorado River Basin
(acre-feet)
Plant NameAJOR17 2018 2019 2020 1 2021 2022 02023
Hunter 15,383 14,751 15,808 15,103 16,326 13,426 8,788
Huntington 9,653 9,804 9.028 7,929 12,019 11,717 7,427
Naughton 6.927 9,916 10,195 7,622 7,236 6,929 7,570
Jun Bridger 19047 20067 19893 1 S,1 S4 19103 190-6 15:054
TOTAL 51,0101 54,5381 54,9241 48,838 54,684 1 51,148 38,839
Percent of total seater consumption= -9-60 o
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PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
90

APPENDIX I - CAPACITY EXPANSION RESULTS
The tables below provide the full portfolio expansion results for each case with a distinct portfolio in the 2025 IRP.See the below tables
for a list of cases presented here.
Table I.1 —Price-Policy Scenario Portfolios
1
� - i
i
MN Optimized Optimized End of Life All allowed
MR Optimized Optimized End of Life All allowed
LN Optimized Optimized End of Life All allowed
HH Optimized Optimized End of Life All allowed
SC Optimized Optimized End of Life All allowed
Table L2—Variant Portfolios
No CCS No coal units are able to select CCS technology -
No Nuclear No nuclear resources are eligible for selection -
No No
2032 All coal must retire or gas convert by January 1, -
2032
Offshore Wind Counterfactual to the Preferred Portfolio selection -
All Coal End of Life Continue 2025 coal technology See the No CCS variant
No New Gas No new gas resources allowed See the Preferred Portfolio
Force All Gas Force all coal-to-gas options See the No Coal 2032
Conversions variant
No Forward Technology No nuclear,hydro, storage or biodiesel peaking See the No Nuclear variant
91

92

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
2025 IRP Portfo
Preferred Portfolio
LT 25I.LP.iLT.21.Inte rated.EP.2409MN.Base IntTrans 106955 d78.1
Summary Portfolio Capacity by Resource Type and Year,Installed MW 0
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 2032 2033 2034 1 2035 1 2036 2037 2038 2039 2040 2041 2042 2043 1 2044 1 2045 Tot
E anion O tions
Gas-CCCT - - - - - - - - - - - - - - - - - - - - -
Gas-Pealing - - - - - - - - - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking - - - - - - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency 89 89 238 262 270 285 342 329 308 282 265 255 250 233 220 208 201 232 283 269 239 5,149
DSM-Demand Response 18 40 11 144 33 81 13 36 2 46 24 12 66 76 42 51 46 33 71 63 144 1,052
Renewable-Wind - 486 804 - - 451 - - 3 2,327 - - - - - - - - - 4,071
Renewable-Small Scale Wind - - 380 505 4 85 - 246 4 37 9 - 236 802 2,308
Renewable-Utility Solar 245 182 - 848 896 805 49 5 2,221 4 237 - - 5,492
Renewable-Small Scale Solar -
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery 520 1,297 116 39 - 416 3 317 176 11 253 10 81 105 488 257 279 15 4,383
Renewable-Battery(Long Duration) I - 1 26 62 655 166 22 93 88 67 326 466 312 325 - 264 1 332 80 3,285
Other Renewable
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal (357) - (205) (700) (1,262)
Coal-CCS - - -
Coal-Gas Conversions - 357 - - 205 - - - - - - - - - - - - - - - - 562
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal (3) (32) (35)
Retire-Wind - -
Retire-Solar - - - - - - - - - - - - - - - - - - - - - -
Expire-Wind PPA (64) (99) (200) (333) - (696)
Expire-Solar PPA - (2) - (9) (100) (65) (230) (407)
Expire-QE (47) (3JE(20)
(2) (52)
Expire-Other (20)
Total 107 1 502 1 1,792 1 961 1 1,426 1 1,966 1 1,212 1 2,144 1 455 1 735 1 535 1 5,061 1 235 1 893 1 747 1 652 1 516 1 989 1 1,630 1 710 456
93

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Oregon Full Jurisdictional Portfolio
Summary Portfolio Capacity by Resource Type and Year,Insuffed MW
lastalled C ac)1 111W
Resource 2025 2026 2027 2028 2029 2030 2031 2032 2033 2031 2035 2036 1 2037 2038 2039 1 2040 1 2041 1 2042 204-1 '_011 2015 Total
E ausion does
Gas-CCCI' - - - - - - - - - - -
Gas-Pealdn
- - - - - - - - - - - - - - -
Nuclear 500 500
- - - - - - - - - - - - - - - - -
Renmable Peal
DSNI-Ever Efficiency 89 89 233 253 261 275 325 322 302 277 260 248 250 233 219 208 201 232 283 269 235 5,064
DSD1-Demand Response 18 25 7 38 86 60 7 4 2 3 1 255 85 47 46 46 27 79 61 43 940
ReneNsable-Wind 222 166 594 3 31E1�46
1:272
- - - - - - - - - - - - - - -
ReneNsable-Small Scale Rind 380 505 4 85 246 4 9 1:270
Renesable-Utility Solar 109 165 848 102 807 45 4 2 2.221 4 4,307
Renewable-Small Scale Solar
- - - - - - - - - - - - -Renewable-Geodrrmal - - -Renewable-Battery 520 1,091 10 19 5 3 25 3 4 6 7 16 504 67 6 6 2,438
Renewable-Battery(Long Duration 1 26 62 1 655 166 1 22 93 88 67 130 174 634 1 381 97 1 277 332 80 3,285
Other Perrwable
- - - - - - - - - - - - - - -
Stora -Other
Iiistin2 Unit Cha es
Coal Plant Retirements-MinorityOvned 82' 33 123 148 386
- - - - - - - - - - - - - - - - -
Coal Plaru Retirements (2 20 220
- - - - - - - - - - - - - - - - -
Coal Plant Ceases as Coal 357 205 700 1.262
- - - - - - - - - - - - - -
Coal-CCS - 526 526
- - - - - - - - - - - - - -
Coal-Gas Comersions 357 20 5 562
- - - - - - - - - - - - - - - - -
Gas Plaru Retirements
Retire-Hydro
- - - - - - - - - - - - - -
Retire-Non-Mrnnal 3 32 35
- - - - - - - - - - - - - - - - -
Retire-Rind
- - - - - - - - - - - - - - - - - -
Retire-Solar
- - - - - - - - - - - - - - - - -Expire-Wind PPA (64 (99 200 333 696
- - - - - - - - - - - - - - -
Ex're-Solar PPA (100) 230 40
Expire-QF 4 3 50
Expire-Other 20 20
Total 1 107 1 487 1 1,663 1 403 1 666 1 3,0315 1 400 1 1 143 1 467 1 372 1 337 1 2715 1 444 1 955 1 455 1 995 1 246 1 960 1 659 1 435 344
94

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
Washington Full Jurisdictional Portfolio
lustalledCa acit .MA
Resotwce 2025 1 2026 1 2027 1 2028 1 2029 1 2030 2031 1 2032 1 20i3 1 2034 2034; 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2012 1 2043 1 2044 2045 Tod
1xpausion Opnow
Gas-CCCT - - - - "1 179 400
Gas-Pe
\udear `00 500
Rerrtcable Peald
DSM-EriergyEfficiewy 89 89 214 236 243 252 326 322 300 283 265 258 260 243 229 217 210 230 285 271 236 5.058
DSM-DernwAResponse 18 17 4 8 37 - 185 35 - 54 57 - 26 44 42 52 24 45 30 78 40 796
Renenable-Rlnd 1.008 594 17 3 1990 130 3742
- - - - - - - - - - - - - - -
Rewsable-Small Scale Rlnd - - - - 121 157 - 194 660 1,132
- - - - - - - - - - - -
Rewsable-U htv Solar 136 17 791 630 4 1 406 - - 237 - - 2.225
Rewsable-Small Scale Solar
- - - - - - - - - - - - - - - - - -
RewAable-Geodrriral
- - - - - - - - - - - - - - - - - -
Renessable-Battery 520 490 6 747 296 196 269 28 471 177 152 347 285 15 4,004
Renessable-Battery Duration 25 132 121 139 224 92 395 107 108 1343
Oder ReneNxable
- - - - - - - - - - - - - - -
Storage-Odff
Unit Clmmges
Coal Pl=Feurenrm-.\finoitvO%Nwd (82' (33) (1`3) (148 86
- - - - - - - - - - - - - -
Coal P1 art Retirerrrrus (?'0) 20
- - - - - - - - - - - - - - -
Coal Plait Ceases as Coal (357) (265) (1,030) (1,592)
Coal-CCS 526 526
- - - - - - - - - - - - - - - -
Coal-Gas Comersions 357 205 330 892
Gas PlantRedmrents
- - - - - - - - - - - - - - - -
Re6re-Hydro
Refire-Nor-Toerrral (3) 32 35
Refire-Rlnd
- - - - - - - - - - - - - - -
Re6re-Solar -
Expire-Wind PPA 64 (99 2100 33 696
- - - - - - - - - - - - - -
Expire-Solar PPA 9 (100 65 30 40
re QF 1 1 (47) (3) (50)
lExpire-Odrr 0 20
Total 1 1071 4791 1,852 1 121 972 1 3311 1,1011 1,7761 304 1 6311 653 2-141 316 1 1,051 1 559 1 1,L1 1 5211 822 7-121 703 931
95

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
Utah, Idaho, Wyoming, California (UIWC) Full Jurisdictional Portfolio
Summary Portfbfio Capacity by Resource Tv
pe and Year,Installed NIW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 2029 2030 2031 1 2032 2033 1 2034 2035 1 2036 1 2037 2038 2039 2040 1 2041 1 2042 1 2043 1 2044 2045 Total
Expansion Options
Gas-CCCT - - - - - - - - - - - -
Gas-Pealin_e - - - -
Ntrlear 500 - 500
- - - - - - - - - - - - - - - - - - -
Renewable Pealing
DSJI-Energylifficiency 89 89 203 247 256 271 331 319 298 273 255 259 250 233 220 209 207 232 283 271 239 5,033
DSJI-DemandResponse 18 1 157 40 33 46 36 29 27 17 17 47 47 46 33 74 61 144 923
Renewable-Wind 486 211 1.045 340 2,082
- - - - - - - - - - - - - - - - -
Renewable-Small Scale Wind - - - 143 390 802 1-335
- - - - - - - - - - - - - - -
Renewable-UtilitvSolar 11675 4 670 4 2-353
Renewable-Small Scale Solar
Renewable-G eotherm al
Renewable-Battery 4 444 355 134 389 4 11 6 6 14 462 65 6 6 2,658
Renewable-Battery(Long Dtration 130 8 368 383 359 466 312 325 51 332 70 2,974
Other Renewable -
- - - - - - -
- - - - - - - - - - - - - -
Storage-Other - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-MinorityOnned (82) (33) (123) (148) (386)
Coal Plant Retirements (220) (220)
- - - - - - - - - - - - - - - - - -
CoalPlantCeasesasCoal (357) (205) (700) (1-262)
- - - - - - - - - - - - - -
Coal-CCS 526 526
- - - - - - - - - - - - - - -
Coal-Gas Con%ttsions 357 205 - - 562
Gas Plait Retifemergs - - - - -
Retire-Hydro - - - - - -
Retire-Nort_Thefmal - - - - (3) - (+_', (35)
Retire-Wind - - - - - - -
Retire-Solar - -
Expire-WindPPA (64) (99) (200) (333) (696)
- - - - - - - - - - - - - - -
Expire-SolarPPA (2) (9) (100) (65) (230) (407)
- - - - - - - - - - - - - - - -
Expire-QF (47) (3) (50)
Expire-Other (20) (20)
Total 1 107 1 463 1 207 1 1,079 1 739 1 647 1 122 1 3,474 1 298 1 692 1 366 1 1,664 1 565 1 583 1 739 1 567 1 337 1 1,117 1 1r28 1 437 439
96

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
No CCS
LT 25LLP.iLT.21.Inteoratcd.EP.2409MN.No CCS IntTrans 107094 v78.5
�olnmary Portfolio Capacity by Resource Type and Year,installed MW
Installed Capacity,MW
sonrre 2025 2026 2027 2023 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 1 2043 1 2044 1 2045 7tnsion
Option.,Gas-CCC7Gas-Peaking _ _ 40 Nuclear 300
Renewable Peaking
DSM-Energy Efficiency 89 89 238 262 270 285 343 329 308 282 270 253 250 234 220 208 202 232 287 272 239 5.164
DSM-Demand Response 18 40 11. 139 38 81 13 36 2 46 24 12 66 76 45 48 60 68 23 153 53 1,052
Renewable-Wind 439 - 970 602 273 2,634 4,918
Renewable-Small Scale Wind _ _ 380 505 4 1 85 1 11 246 4 37 1 9 176 660 2.106
Renewable-Utility Solar 245 182 848 896 805 567 5 4.291 2 237 8,078
Renewable-Small Scale Solar
_ _ _ _
Renewable-Geothermal
Renewable-Battery 520 1,297 16 43 19 4 464 14 242 389 438 417 65 488 214 2l4 355 592 15 5,806
Renewable-Batt (Long Duration) I 26 62 653 166 22 93 88 67 130 174 634 381 97 277 332 So 3.285
Other Renewable
Storage-Oil=
t.
Exhtlag Una CYaagea
Coal Plant Retuemettts w Minority Owned (82) (33) (123) (148) (386)
Coal Plan Retirements (220) (220)
Coal Plant Ceases as Coal (357) (205) (562)
Coal-CCS
Coal-Gas Conversions 357 205 562
Gas Plan Retirements
Retire-Hydro
Retire-Noa-Thermal (3) (32) (35)
Retire-Wind
Retire-Solar
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ *(3) (2)
_
Expire-Wind PPA (64) (99) (200) (333) (696)
Expire-Solar PPA (2) (9) (100) (65) (407)
Expire-QP E(47) (52)
Expire-Other (20)
Total f 107 502 1 2,2311 1,540 1 1,272 2,646 1 1,2171 1,7411 994 "0 1 1,023 7,438 1 "0 1 862 1 553 611 1 995 1 1,292 1,025
97

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
No Nuclear
LT 25I.LP.iLT.21.Inte rated.EP.240911IN.No Nuclear IntTrans 106164 v76
Summaji.Poilfolio Capacity by Resource Type and Year,Installed NINI.
Installed Capacity,MW
Resource 202.5 2026 2027 2028 2029 1 2030 2031 2032 1 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2043 1
Rapau on Options
as G -CCC1 _ _ _ .. _
Gas-Peaking
Nuclear -
Rmewable Peaking
D -EactsyEfficiency 89 89 238 262 275 289 345 331 308 283 265 252 250 233 227 214 207 235 286 275 239 59192
DSM-Demand Response 18 40 19 126 53 94 23 21 18 39 16 1 136 28 42 77 23 29 72 62 144 1.081
Renewable-Wind 422 834 412 199 1,374 616 3.857
Renewable-Small Scale Wind 246 7 21 207 111 17 9 105 211 934
Renewable-Utility Solar 290 237 44 181 451 521 2 2.079 2.103 4 51912
Renewable-Small Scale Solar 591 1 26 17 635
Renewable-Geotherotsl
Renewable-Battery 520 734 124 318 879 110 317 15 309 148 314 14 861 174 95 108 43 96 5,179
Renewable-Battery(Long Duration) 251 109 123 2,49 97 258 126 36 152 120 277 229 246 140 104 33 2,570
Other Renewable
_ _
Storeae-Other
Unit Charges
Coal Plant Retiremws-.Minority Owned (82) (33) (123) (149) (396)
Coal plant Retirements (-0) (220)
Coal Plant Ceases as Coal (357) (205) (700) (1,262)
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Coal-CCS
Coal-Gas Cmversioos 357 205 562
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Gas Plant Retirements
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Hydro
Retire-Non-Thermal (3) (32) (35)
Retire-Wind
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Sol.
Expire-Wind PPA E'64) (99) 200 (333) (696)
Expire-Solar PPA (2) (9) (100) (65) (230) (407)
ire- F (47) 3) (2 (52)
Expire-Other (20) (20)
Total 1 107 502 1,532 1,023 1,397 1,319 706 1,630 886 1 903 J 2.04 1 3937 1 1,053 712 412 1,429 2J5 603 379 336 701
98

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
No Coal 2032
LT 25I.LP.iLT.2 Llnte rated.EP.2409Wi Ao Coal 2032 IntTrans 107095 v78.5
Surnmary Portfolio Capacity by Resource Type and Year,installed NM
IostaOed Ca adty.MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 2033 2034 2035 2036 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 2045_M Total
Expaoslon Option _ _ _
Gas-CCC'I 199 298 497
Gas-Peaking
Nuclear _ _500 _ 500
Renewable Peaking
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
DSM-Energy Efficiency 89 89 238 259 266 _ 281 336 329 303 282 265 248 250 234 220 208 201 232 283 269 240 5,122
DSM-Demand Response 18 40 11 141 32 60 47 27 2 46 16 12 66 84 42 48 48 34 71 62 43 950
Renewable-Wind I.077 594 153 78 350 2 3.13Z 178 5.564
Renewable-Small Scale Wind 380 505 4 85 146 _ 4 37 9 176 660 2,106
Renewable-Utility Solar 245 182 948 896 805 87 5 480 4,291 4 237 87080
Reoewable-Small Scale Solar -
Renewable-Geothermal
Renewable-Battery 520 1,297 116 19 4 639 12 71 365 56 602 220 422 128 227 242 411 17 5,369
Renewable-Battery(Long Duration) 1 26 62 655 166 22 93 88 67 130 174 634 381 97 277 332 80 3,235
Older Renewable
Storage-Other -
KIdgelft IIMb
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) (386)
Coal Plant Retirements (220) (268) (488)
Coal Plant Ceases as Coal (357) (205) (3,097) (3,659)
Coal-CCS
Coal-Gas Conversions 357 205 3,097 3,659
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Gas Plant Retirements
Retire-Hydro
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Non-Thermal (3) (32) (35)
Retire-Wind
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Solar
Expire-Wind PPA (64) (99) (200) (333) (696)
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Expire-Solar PPA (2) (9) (IOO) (65) (230) (407)
Expire-QF (47) 3) (2) (52)
Expire-Od— (20) (20)
Total 1 107 $02 1 1,792 1 1546 1,4101 2,774 1 1,3221 2,287 1 497 1 499 1 1,195 1 7,9291 458 1 1.0551 665 1 1,3121 15971 590 1 8261 1,017 I,018
99

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Offshore Wind
LT 25I.LP.iLT.21.Integrated.EP.2409MN.OSWind IntTrans 106388 v76.6
'Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 2029 1 2030 2031 2032 1 2033 1 2034 1 2035 1 2036 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 1 2045
Expansion Options
Gas-CCCT - - - - - - - - - - - - - - - - - - - - -
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear - - - - - 500 - - - - - - - - - - - - - - - 500
Renewable Peaking -- - - -
- - - - - - - - - - - - - - - - -
DSM-Energy Efficiency 89 89 238 259 270 285 338 329 308 283 265 252 250 233 219 208 207 232 283 271 236 5,144
DSM-Demand Response 18 40 23 135 38 49 7 37 18 30 24 1 136 47 42 72 24 28 79 61 1 43 952
Renewable-Wind - - - 452 792 - 200 - 41 - 270 864 1,126 - - - - - - - - 3,745
Renewable-Small Scale Wind - - - - - 0558
- - - - - - - - - - - 79 1 - - 193
Renewable-Utility Solar - - 297 101 - 411 634 521 4 405 4 - - 670 - - 393 - - 3,825
Renewable-Small Scale Solar - - - - - 55 72 - - 3 165 54 8 9 - - - - - 244 1,341
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery - 520 1,360 328 220 140 69 122 118 47 - - 127 10 1,067 322 405 313 244 15 5,985
Renewable-Battery(Long Duration) - - 45 15 79 - 31 - 339 178 - - 382 675 305 206 274 327 362 122 3,506
Other Renewable - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned - (82) - (33) (123) (148) - - - - - - - - - - - - - - - (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal - (357) - - (205) (700) - - - - - - - - - - - - - - - (1,262)
Coal-CCUS - - - - 526 - - - - - - - - - - - - - 526
Coal-Gas Conversions - 357 - - 205 - - - - - - - - - - - - - - - - 562
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (33) - - - - - - - (35)
Retire-Wind - - - - - - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - - - - - - - - - - -
Expire-Wind PPA - (64) - - - (99) (200) - - - - - - - - - (333) - - - - (696)
Expire-Solar PPA - - - (2) (9 - - - (100) - - - (65) - (230) (407)
Expire-QE - - - - - - - - - - - - - - - - - - (47) (3) (2) (52)
Expire-Other - - - - - - - - - - - - - - - - - - - - (20) (20)
Total 107 502 1,963 1,035 1,276 2,366 942 1,172 1,010 771 787 1,687 1,470 1 765 1 955 2,322 361 1,018 1 1,349 74) 638
100

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
LN
LT 25I.LP.iLT.2LIntegrated.EP.2409LN.Base IntTrans 109399 v79.5
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 2030 2031 2032 2033 2034 1 2035 1 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Expansion Options
Gas-CCCT - - - - 410 424 - - - - - - - - 319 - 212 410 - - - 1,774
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear - - - - - 500 - - - - - - - - - - - - - - - 500
Renewable Peaking - - - - - - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency 89 89 237 257 265 280 334 328 307 281 264 254 249 232 218 206 199 225 276 266 227 5,083
DSM-Demand Response 18 40 25 138 53 34 13 36 18 31 16 21 85 76 43 50 46 33 72 118 88 1,054
Renewable-Wind 594 - - 3 3,015 - - - - 3,612
Renewable-Small Scale Wind - - 500 349 034 26 - 29 29 29 41 33 9 109 194 660 2,042
Renewable-Utility Solar - - 136 317 49 683 452 522 300 105 1 4 6 - 231 - 3,791
Renewable-Small Scale Solar - - - - - - - - - -
Renewable-Geothermal - - - - - -Renewable-Battery - 520 I,235 160 3 - 401 6 242 546 156 368 245 412 863 211 456 380 851 9 7,064
Renewable-Battery(Long Duration) - - 93 - 2 803 66 102 58 - - - 58 94 554 89 109 257 345 23 2,804
Other Renewable - - - - - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (I48) - - - - - - - - - - - - - (386)
Coal Plant Retirements (220) - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal - (357) - - (205) (1,030) - - - - - - - - - - - - - - - (1,592)
Coal-CCS - - - - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions - 357 - - 205 330 - - - - - - - - - - - - - - - 892
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (32) - - - - - - - (35)
Retire-Wind - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - -
Expire-Wind PPA - (64) - - - (99) (200) - - - - - - - - (333) (696)
Expire-Solar PPA - - - (2) - (9) - - - - - (100) - - (65) (230) (407)
Expire-QP - - - - - - - - - - - - - - - - - - (47) (3) (2) (52)
Expire-Other - - - - - - - - - - - - - - - - - - - - (20) (20)
Total 1 107 502 1,726 617 1,753 2,126 1 1,308 1,309 955 938 963 3,476 647 618 1,094 1,782 1 590 1,233 938 1,541 985
101

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
MR
LT 25I.LP.iLT.2LIntegrated.EP.2409MR.Base IntTrans 107932 v78.7
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 2044 2045
Expansion Options
Gas-CCCT - - - - - - - - - - - - - - - - - - - - - -
Gas-Peaking - - - - - - - 479 - - - - - - - - - - - - - 479
Nuclear - - - - - 500 - - - - - - - - - - - - - - - 500
Renewable Peaking - - - - - - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency 89 89 238 259 266 285 338 329 308 282 265 249 250 239 227 214 210 235 286 271 239 5,168
DSM-Demand Response 18 40 11 126 43 76 12 39 2 46 16 12 80 80 42 48 48 34 71 43 62 949
Renewable-Wind 1,417 594 - 451 - 3 2,954 187 - - - - 5,606
Renewable-Small Scale Wind - - - 745 60 52 - - 300 98 9 9 - 552 28 414 40 2,307
Renewable-Utility Solar - - 136 107 - 505 794 1,081 522 1 - 2,736 2 406 - - 237 - 6,527
Renewable-Small Scale Solar - - - 61 - 110 27 - - - - - - - - - 198
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery - 520 1,135 26 ISl 390 108 537 37 197 277 - 176 341 73 81 79 651 589 639 15 6M( 2
Renewable-Battery(Long Duration) - - - - - 378 - - - - - - - 60 167 496 261 50 108 71
Other Renewable - - - - - - - - - - - - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (I48) - - - - - - - - - - - (386)
Coal Plant Retirements (220) - (268) - - - - - - - - - - - - (488)
Coal Plant Ceases as Coal - (357) - - (205) (3,097) - - - - - - - - - - - - - - - (3,659)
Coal-CCS - - - - - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions - 357 - - 205 2,397 - - - - - - - - - - - - - - - 2,959
Gas Plant Retirements - - - - - - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (32) - - - - - - - (35)
Retire-Wind - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - -
Expire-Wind PPA - (64) - - - (99) (200) - - - - - - - - (333) (696)
Expire-Solar PPA - - - (2) - (9) - - - - - (100) - - (65) (230) (407)
Expire-QP - - - - - - - - - - - - - - - - - - (47) (3) (2) (52)
Expire-Other - - - - - - - - - - - - - - - - - - - - (20) (20)
Total 1 107 1 502 1 1,520 1 1,7411 961 2,042 1 1,043 1 2,735 1 921 1 523 1 561 1 6,251 1 693 1 1,103 1 518 1 839 1 437 1 1,522 1 1,035 1,205 334
102

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
HH
LT 251.LPJLT.21.Integrated.EP.2409HH.Base IntTrans 109124 v79.2
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 2030 2031 2032 2033 2034 1 2035 2036 2037 2038 2039 1 2040 1 2041 1 2042 1 2043 1 2044 1 2045 Total
Expansion Options
Gas-CCCT - - - - - - - - - - - - - - - - - - - - -
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear - - 500 - - - - - - - - - - - - P2,654
Renewable Peaking - - - - - - - - - - - - - - - - - - - - -DSM-Energy Efficiency 89 89 244 268 276 291 347 333 312 286 268 268 261 243 229 217 210 235 286 272 240 DSM-Demand Response 18 40 23 134 45 34 13 36 2 50 16 12 105 25 39 104 50 19 81 28 65Renewable-Wind - - 1,187 721 975 233 - 451 - - 3 2,492 - - - - - - - - -Renewable-Small Scale Wind - - - - 133 876 89 - - - 14 172 76 49 - 402 486 120 125 37 Renewable-Utility Solar - - 419 41I 546 2,865 452 4 1 2,648 800 406 - 237 - - ,
Renewable-Small Scale Solar - - - - - - - - - - - - - - - - - - - - 1,121 1,121
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery - 520 1,133 66 108 347 141 452 141 12 200 - 74 50 12 193 136 505 399 276 34 4,799
Renewable-Battery(Long Duration) - - - - - 243 - - - 86 131 - 274 375 106 555 - - 135 346 90 2,341
Other Renewable - - - - - - - - - - - - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned - (82) - (33) (123) (148) - - - - - - - - - - - - - - - (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal - (357) (205) (1,030) - - - - - - - - - - (1,592)
Coal-CCUS - - - - - 526 - - - - - - - - - - - - - - - 526
Coal-Gas Conversions - 357 - - 205 330 - - - - - - - - - - - - - - - 892
Gas Plant Retirements - - - - - - - - -
Retire-Hydro - - - - - - - -
- - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (32) - - - - - - - (35)
Retire-Wind - - - - - - - - - - - -
Retire-Solar - - - - - - - - - -
Expire-Wind PPA - (64) - E(2)
- (99) (200) - - - - - - - - - (333) - - - - (696)
Expire-Solar PPA - - (9) - - - - (100) - - (65) (230) (407)
Expire-QP - - - - - - - - - - - (47) (3) (2) (52)
Expire-Other - - - - - - - - - - - - - - - - - - - (20) (20)
Total 107 1 502 1 3,006 1 1,345 1 1,414 1 2,649 1 3,246 1 1,724 1 459 1 432 1 632 1 5,592 1 1,490 1 1,142 1 435 1 1,069 1 637 1 1,245 1 974 1 814 1,565
103

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
SC
LT 25I.LP.iLT.21.Integrated.EP.2409SC.Base IntTrans 109123 v79.2
,Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 2033 2034 1 2035 1 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 12044 2045 Total
Expansion Options
Gas-CCCT - - - - 199 - - 199 - - - - - - - - - - - - - 398
Gas-Peaking - - - - - - - - - - - - - - - - - - - - - -
Nuclear - - - - - 500 - - - - - - - - - - - - - - - 500
Renewable Peaking - - - - - - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency 89 89 244 265 272 286 347 333 310 283 265 258 252 240 227 209 210 234 286 271 235 5,205
DSM-Demand Response 18 40 13 27 115 21 82 26 2 46 16 1 32 91 94 30 67 27 77 27 40 892
Renewable-Wind - - 1,417 594 451 297 3,236 152 - 6,147
Renewable-Small Scale Wind - - 20 302 616 35 89 1 8 215 32 103 119 875 92 - 454 2,961
Renewable-Utility Solar - - 336 500 281 1,156 415 55 1 66 3,363 1,584 564 139 237 793 - 9,490
Renewable-Small Scale Solar - - - - - - - - - - - - - - - - - - - - 156 156
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery - 520 1,011 98 - 708 2 592 91 14 181 - 13 313 307 94 393 41 370 695 139 5,582
Renewable-Battery(Long Duration) - - - - - 197 - - - 103 78 - 24 - 14 399 130 469 373 108 - 1,895
Other Renewable - - - - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned - (82) - (33) (123) (148) - - - - - - - - - - - - - - - (386)
Coal Plant Retirements - - - (220) - - - - - - - - - - - - - - - - - (220)
Coal Plant Ceases as Coal - (357) - - (205) (1,030) - - - - - - - - - - - - - - - (1,592)
Coal-CCUS - - 526 - - - - - - - - - - - - - - 526
Coal-Gas Conversions - 357 - 205 330 - - - - - - - - - - - - - 892
Gas Plant Retirements - - - - - - - - - - - - - - - - -
Retire-Hydro - - - - - - - - - - - - - - - - -
Retire-Non-Thermal - - - - - - - - - (3) - - - (32) - - - - - - - (35)
Retire-Wind - - - - - - - - - - - - - - - - - - - - - -
Retire-Solar - - - - - - - - - - - - - - - - - - - - - -
Expire-Wind PPA - (64) - - - (99) (200) - - - - - - - - - (333) - - - - (696)
Expire-Solar PPA - - - (2) (9) - - - - - (I 00) - - (65) (230) (407)
Expire-QF - - - - - - - - - - (47) (3) (2) (52)
Expire-Other - - - - - - - - - - (20) (20)
Total 107 1 502 1 3,0411 635 1 1,359 1 2,188 1 1,413 1 2,105 1 459 1 444 1 9111 7,073 1 1,989 1 1,279 1 900 1 732 1 639 1 2,439 1 1,1511 868 1,002
104

PACIFICORP—2025 IRP APPENDIX L—DISTRIBUTED GENERATION STUDY
APPENDIX L - DISTRIBUTED GENERATION STUDY
Introduction
DNV prepared the Distributed Generation Study for PacifiCorp.I A key objective of this research
is to assist PacifiCorp in developing penetration forecasts of non-utility owned distributed
generation resources to support its 2025 Integrated Resource Plan. The purpose of this study is to
project the level of distributed generation resources PacifiCorp's customers might install over the
next twenty years under low, base, and high penetration scenarios.
'Note that in the 2023 IRP,this study was referred to as the"Private Generation"assessment.
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PACIFICORP-2025 IRP APPENDIX L-PRIVATE GENERATION STUDY
106

DNV
DISTRIBUTED GENERATION FORECAST
Behind-The-Meter Resource
Assessment
PacifiCorp
Date: November 25, 2024
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Table of contents
1 EXECUTIVE SUMMARY..........................................................................................................................................1
1.1 Study methodologies and approaches.....................................................................................................................2
1.1.1 State-level forecast approach.............................................................................................................................2
1.2 Distributed generation forecast................................................................................................................................3
2 BACKGROUND .......................................................................................................................................................6
3 APPROACH AND METHODS..................................................................................................................................8
3.1 Technology attributes...............................................................................................................................................8
3.1.1 Solar PV.............................................................................................................................................................8
3.1.2 Small-scale wind...............................................................................................................................................15
3.1.3 Small-scale hydropower...................................................................................................................................16
3.1.4 Reciprocating engines......................................................................................................................................17
3.1.5 Microturbines....................................................................................................................................................18
3.1.6 Incentives overview..........................................................................................................................................18
3.2 Current distributed generation market....................................................................................................................22
3.3 Forecast methodology............................................................................................................................................23
3.3.1 Economic analysis............................................................................................................................................24
3.3.2 Technical feasibility..........................................................................................................................................25
3.3.3 Market adoption................................................................................................................................................26
4 RESULTS...............................................................................................................................................................30
4.1 Generation capacity results by state......................................................................................................................33
4.1.1 California..........................................................................................................................................................34
4.1.2 Idaho................................................................................................................................................................38
4.1.3 Oregon .............................................................................................................................................................42
4.1.4 Utah..................................................................................................................................................................46
4.1.5 Washington.......................................................................................................................................................50
4.1.6 Wyoming ..........................................................................................................................................................54
5 APPENDIX.............................................................................................................................................................58
5.1 Technology assumptions and segment-level inputs...............................................................................................58
5.2 Detailed results......................................................................................................................................................58
5.3 Behind-the-meter battery storage forecast.............................................................................................................59
5.3.1 Study methodologies and approaches .............................................................................................................59
5.3.2 Battery dispatch modelling ...............................................................................................................................60
5.3.3 Results .............................................................................................................................................................60
5.3.4 Storage capacity results by state......................................................................................................................61
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List of figures
Figure 1-1. Historic cumulative installed distributed generation capacity, PacifiCorp, 2014-2024.............................................1
Figure 1-2. Methodology to determine market potential of distributed generation adoption......................................................3
Figure 1-3. Cumulative historical and new capacity installed by scenario(MW-AC), 2024-2043..............................................4
Figure 1-4. Cumulative new capacity installed by state(MW-AC), 2024-2043, base case.......................................................5
Figure 1-5. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case..............................................5
Figure 2-1. PacifiCorp service territory......................................................................................................................................6
Figure 3-1. Example residential summer load shape compared to PV Only and PV+ battery generation profiles...................9
Figure 3-2. Cost of residential PV standalone, battery storage retrofit to existing PV, and PV+ battery systems from DNV
bottom-up Cap-Ex Model, Utah' .............................................................................................................................................12
Figure 3-3. Cost of commercial PV standalone, battery storage retrofit to existing PV, and PV+ battery systems from DNV
bottom-up Cap-Ex Model, Utah' .............................................................................................................................................13
Figure 3-4.Average residential solar PV system costs, 2022-2043........................................................................................14
Figure 3-5.Average non-residential solar PV system costs, 2023-2043.................................................................................14
Figure 3-6.Average residential battery energy storage system (AC-coupled)costs, 2024-2043............................................15
Figure 3-7.Average non-residential battery energy storage system (AC-coupled)costs, 2024-2043 ....................................15
Figure 3-8. Cumulative installed distributed generation capacity by state, by technology, as of March 31, 2024...................22
Figure 3-9. Methodology to determine market potential of distributed generation adoption....................................................24
Figure 3-10. Bass diffusion curve illustration...........................................................................................................................27
Figure 3-11.Willingness to adopt based on technology payback...........................................................................................28
Figure 3-12.Willingness to adopt based on technology payback, by sector and scenario .....................................................28
Figure 4-1. Cumulative new distributed generation capacity installed by scenario(MW-AC), 2018-2043 ..............................30
Figure 4-2. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case............................................31
Figure 4-3. Cumulative new capacity installed by technology(MW-AC), 2024-2043, low case..............................................31
Figure 4-4. Cumulative new capacity installed by technology(MW-AC), 2024-2043, high case.............................................32
Figure 4-5. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case(Excluding PV& PV+
Battery)...................................................................................................................................................................................32
Figure 4-6. Cumulative new capacity installed by technology(MW-AC), 2024-2043, low case(Excluding PV& PV+ Battery)
................................................................................................................................................................................................33
Figure 4-7. Cumulative new capacity installed by technology(MW-AC), 2024-2043, high case(Excluding PV&PV+ Battery)
................................................................................................................................................................................................33
Figure 4-8. Cumulative new capacity installations by state(MW-AC), 2024-2043, base case................................................34
Figure 4-9. Cumulative new distributed generation capacity installations by scenario(MW-AC), California, 2018-2043........35
Figure 4-10. Cumulative new capacity installations by technology(MW-AC), California base case, 2024-2043....................35
Figure 4-11. Cumulative new capacity installations by technology(MW-AC), California low case, 2024-2043.......................36
Figure 4-12. Cumulative new capacity installed by technology(MW-AC), California high case, 2024-2043...........................36
Figure 4-13. Cumulative new PV capacity installed by sector across all scenarios, California, 2024-2043............................37
Figure 4-14. Cumulative new distributed generation capacity installed by scenario(MW-AC), Idaho, 2018-2043..................38
Figure 4-15. Cumulative new capacity installations by technology(MW-AC), Idaho base case, 2024-2043..........................39
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Figure 4-16. Cumulative new capacity installations by technology(MW-AC), Idaho low case, 2024-2043.............................39
Figure 4-17. Cumulative new capacity installations by technology(MW-AC), Idaho high case, 2024-2043...........................40
Figure 4-18. Cumulative new PV capacity installed by sector across all scenarios, Idaho, 2024-2043 ..................................41
Figure 4-19. Cumulative new distributed generation capacity installed by scenario(MW-AC), Oregon, 2018-2043...............42
Figure 4-20. Cumulative new capacity installations by technology(MW-AC), Oregon base case, 2024-2043.......................43
Figure 4-21. Cumulative new capacity installations by technology(MW-AC), Oregon low case, 2024-2043..........................43
Figure 4-22. Cumulative new capacity installations by technology(MW-AC), Oregon high case, 2024-2043........................44
Figure 4-23. Cumulative new PV capacity installed by sector across all scenarios, Oregon, 2024-2043................................45
Figure 4-24. Cumulative new distributed generation capacity installed by scenario(MW-AC), Utah, 2023-2043...................46
Figure 4-25. Cumulative new capacity installations by technology(MW-AC), Utah base case, 2024-2043............................47
Figure 4-26. Cumulative new capacity installations by technology(MW-AC), Utah low case, 2024-2043..............................47
Figure 4-27. Cumulative new capacity installations by technology(MW-AC), Utah high case, 2024-2043.............................48
Figure 4-28. Cumulative new PV capacity installed by sector across all scenarios, Utah, 2024-2043....................................49
Figure 4-29. Cumulative new distributed generation capacity installed by scenario(MW-AC), Washington, 2018-2043........50
Figure 4-30. Cumulative new capacity installations by technology(MW-AC), Washington base case, 2024-2043 ................51
Figure 4-31. Cumulative new capacity installations by technology(MW-AC), Washington low case, 2024-2043...................51
Figure 4-32. Cumulative new capacity installations by technology(MW-AC), Washington high case, 2024-2043 .................52
Figure 4-33. Cumulative new PV capacity installed by sector across all scenarios, Washington, 2024-2043.........................53
Figure 4-34. Cumulative new distributed generation capacity installed by scenario(MW-AC), Wyoming, 2018-2043............54
Figure 4-35. Cumulative new capacity installations by technology(MW-AC), Wyoming base case, 2024-2043....................55
Figure 4-36. Cumulative new capacity installations by technology(MW-AC), Wyoming low case, 2024-2043.......................55
Figure 4-37. Cumulative new capacity installations by technology(MW-AC), Wyoming high case, 2024-2043 .....................56
Figure 4-38. Cumulative New PV capacity installed by sector across all scenarios,Wyoming, 2024-2043............................57
Figure 5-1. Historic cumulative installed behind-the-meter battery storage capacity, PacifiCorp, 2014-2024.........................59
Figure 5-2. Cumulative new battery storage capacity installed by scenario(MW), 2023-2042...............................................61
Figure 5-3. Cumulative new battery storage capacity installed by state(MW), 2024-2043, base case...................................62
Figure 5-4. Cumulative new battery storage capacity installed by state(MW), 2024-2043, low case.....................................62
Figure 5-5. Cumulative new battery storage capacity installed by state(MW), 2024-2043, high case....................................63
Figure 5-6. Cumulative new battery storage capacity installed by scenario(MW), California, 2028-2043..............................63
Figure 5-7. Cumulative new battery storage capacity installed by technology across all scenarios (MW), California, 2023-
2042........................................................................................................................................................................................64
Figure 5-8. Cumulative new battery storage capacity installed by scenario(MW), Idaho, 2018-2043....................................65
Figure 5-9. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Idaho, 2023-2042 66
Figure 5-10. Cumulative new battery storage capacity installed by scenario(MW), Oregon, 2018-2043...............................67
Figure 5-11. Cumulative new battery storage capacity installed by technology across all scenarios(MW), Oregon, 2023-2042
................................................................................................................................................................................................68
Figure 5-12. Cumulative new battery storage capacity installed by scenario(MW), Utah, 2018-2043....................................69
Figure 5-13. Cumulative new battery storage capacity installed by technology across all scenarios(MW), Utah, 2023-204270
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Figure 5-14. Cumulative new battery storage capacity installed by scenario (MW), Washington, 2018-2043........................71
Figure 5-15. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Washington, 2023-
2042........................................................................................................................................................................................72
Figure 5-16. Cumulative new battery storage capacity installed by scenario (MW),Wyoming, 2018-2043............................73
Figure 5-17. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Wyoming, 2023-
2042........................................................................................................................................................................................74
List of tables
Table 3-1. Residential PV Only representative system assumptions........................................................................................9
Table 3-2. Non-residential PV Only representative system assumptions................................................................................10
Table 3-3. Residential PV+ battery representative system assumptions ...............................................................................11
Table3-4. Small wind assumptions ........................................................................................................................................16
Table3-5. Small hydro assumptions.......................................................................................................................................16
Table 3-6. Reciprocating engine assumptions........................................................................................................................17
Table 3-7. Microturbine assumptions......................................................................................................................................18
Table 3-8. Federal investment tax credits for DERs................................................................................................................20
Table 3-9. State Incentives for DERs......................................................................................................................................21
Table 3-10. Distributed generation forecast economic analysis inputs' ..................................................................................25
Table 3-11. Solar willingness-to-adopt curve used by state and sector..................................................................................27
Table 4-1. Cumulative adopted distributed generation capacity by 2043, by scenario............................................................30
Table 5-1. Cumulative adopted battery storage capacity by 2043, by scenario......................................................................60
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Customer's organization.
For disclosure only to individuals directly concerned with the
❑ Private and Confidential subject matter of the document within the Customer's
organization.
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Distribution for information only at the discretion of the
❑X Customer's Discretion Customer(subject to the above Important Notice and
Disclaimer and the terms of DNV's written agreement with
the Customer).
El Published Available for information only to the general public(subject to
the above Important Notice and Disclaimer).
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1 EXECUTIVE SUMMARY
This report presents DNV's Long-Term Distributed Generation Resource Assessment for PacifiCorp(the Company)covering
service territories in Utah, Oregon, Idaho,Wyoming, California, and Washington to support PacifiCorp's 2025 Integrated
Resource Plan (IRP). This assessment evaluated the expected adoption of behind-the-meter(BTM)distributed energy
resources(DERs) including photovoltaic solar(PV only), photovoltaic solar coupled with battery storage (PV+ Battery),
small wind, small hydro, reciprocating engines, and microturbines over a 20-year forecast horizon (2024-2043)for all
customer sectors(residential, commercial, industrial, and agricultural). The adoption model DNV developed for this study is
calibrated to the currently' installed and interconnected capacity of these technologies, shown in Figure 1-1.
Figure 1-1. Historic cumulative installed distributed generation capacity, PacifiCorp, 2014-2024
Cumulative installed PG capacity by state Cumulative installed PG capacity by technology
1,200
■CA ID ■OR ■UT WA ■WY Small Hydro Wind
0
1.000 0.115% ° PV+Battery
Micro 7.60%
Turbine
800 0.11%
> Reciprocating
600 Engine
0.00%
U 400
PV Only
200 / 92.05%
0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
To date and consistent with the 2023 report, the majority of PG-installed capacity and annual capacity growth has been in
Utah,which represents the largest portion of PacifiCorp's customer population—about 50%of all PacifiCorp customers are
in the Company's Utah service territory. Roughly 99%of existing distributed generation capacity installed in PacifiCorp's
service territory is PV or PV+ Battery.To inform the adoption forecast process, DNV conducted an in-depth review of the
other technologies and did not find any literature to suggest that they would take on a larger share of the distributed
generation market in the Company's service territory in the future years of this study.
DNV developed its assumptions, inputs, methodologies, and forecasts independently from prior distributed generation
assessments performed for PacifiCorp. Further, DNV developed three adoption scenarios for each technology and sector: a
base case, a high case, and a low case. The base case is considered the most likely projection as it is based on current
market trends and expected changes in technology costs and retail electricity rates;the high and low cases are used as
sensitivities to test how changes in costs and retail rates impact customer adoption of these technologies.Additional factors
considered in the scenarios include export rate factors, value of backup power, incentive levels, and non-monetary market
barriers.
'PacifiCorp Distributed Generation interconnection data as of end of quarter 1 2024.
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DNV
All scenarios use technology cost and performance assumptions specific to each state in PacifiCorp's service territory in the
base year(2023)of the assessment. The base case uses the 2023 federal income tax credit schedules and state incentives,
retail electricity rate escalation from the Annual Energy Outlook(AEO)2 reference case, and a blended version of the
National Renewable Energy Laboratory(NREL)Annual Technology Baseline' moderate and conservative technology cost
forecasts as inputs to the modelling process. In the high case, retail electricity rates increase more rapidly, and technology
costs decline at a faster rate compared to the base case. The high case also considers NREL's value of backup power in the
customer's benefit-cost calculation and a reduction in non-monetary market barriers resulting from the federal efforts to
promote distributed generation through the Inflation Reduction Act(IRA)of 2022,further increasing the adoption rates. For
the low case, retail electricity rates increase at a slower rate than the base case and technology costs decrease at a slower
rate than the base case.
1.1 Study methodologies and approaches
The forecasting methodologies and techniques DNV applied in this analysis are commonly used in small-scale, BTM energy
resource and energy efficiency forecasting. The methods used to develop the state and sector-level results are described in
more detail below.
1 .1 .1 State-level forecast approach
DNV developed a BTM net economic framework that defines costs as the acquisition and installation expenses for each
technology, adjusted for available incentives. Benefits are defined as the customer's economic gains from ownership,
including energy and demand savings, as well as export credits. We assumed that the current net metering or net billing
policies and tariff structures in each state remained the same throughout the assessment.This resulted in the model
incorporating benefits associated with net metering in Oregon, Washington, and Wyoming and net billing in Utah and
California. We assumed customers in Idaho would accrue benefits based on Utah's net billing policy.
This analysis incorporated the current rate structures and tariffs offered to customers in PacifiCorp's service territories. Time-
of-use rates,tiered tariffs, and retail tariffs that include high demand charges increased the value of PV+ Battery
configurations compared to PV-Only configurations while other factors such as load profiles and DER compensation
mechanisms minimized the impact of such tariffs on the customer economics of PV+ Battery systems.The DER
compensation mechanism in Oregon, Washington, and Wyoming—traditional net metering—does not incentivize PV+
Battery storage co-adoption. In net metering DER compensation schemes, customers receive export credits for excess PV
generation at the same dollar-per-kWh rate that they would have otherwise paid to purchase electricity from the grid. Net
billing—the mechanism modelled in California, Idaho, and Utah—does incentivize PV+ Battery storage co-adoption, as
customers can lower their electricity bills by charging their batteries with excess PV generation and dispatching their
batteries to meet on-site load during times of day when retail energy prices are high. From the perspective of utility bill
savings alone, PV+ battery systems are often not the most cost-effective option for most customers. Customers who seek
the reassurance and reliability of backup power show more of a willingness to pay for this product, especially if they reside in
areas prone to outages and severe weather events.
The economic analysis calculated payback by year for each technology by sector and state.A corresponding technical
feasibility analysis determined the maximum,feasible adoption for each technology by sector given system size limits,
2 U.S.Energy Information Administration,Annual Energy Outlook 2023(AE02023),(Washington,DC,March 2023).
'NREL.2023 Annual Technology Baseline.Golden,CO:National Renewable Energy Laboratory.
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customer usage profiles, and physical conditions.The results of the technical feasibility assessment and economic analysis
were then used to inform the market adoption analysis to derive market potential.The methodology and major inputs to the
analysis are shown in Figure 1-2. Changes to technology costs, retail electricity rates, and federal tax credits used in the
high and low cases impact the economic portion of the analysis.
Figure 1-2. Methodology to determine market potential of distributed generation adoption
LocalInstallation and O&M costs
• federal
Energy
l •
J •
f t
Net • • • export credits
Market
Customer •.• shapesperformance
System size limitsJconstraints
Non-shaded rooftop space Land-use feasibility
Access to unprotected streams and requirements
dams, • resource
DNV used technology and sector-specific Bass diffusion curves to model market adoption and derive total market potential.
Bass diffusion curves are widely used for forecasting technology adoption. Diffusion curves typically take the form of an S-
curve with an initial period of slow early adoption that increases as the technology becomes more mainstream and
eventually tapers off amongst late adopters. The upper limit of the curve is set to maximum market potential, or the
maximum share of the market that will adopt the technology regardless of the interventions applied to influence adoption. In
this analysis,the long-term maximum level of market adoption was based on payback.As payback was calculated by year in
the economic analysis to capture the changing effects of market interventions over time, the maximum level of market
adoption in the diffusion curves varied by year in the study.
The Bass diffusion curves used in the market potential analysis are characterized by three parameters—an innovation
coefficient, an imitation coefficient, and the ultimate market potential. Together,these three parameters also determine the
time to reach maximum adoption and the overall shape of the curve. The innovation and imitation parameters were
calibrated for each technology and sector, based on current market penetration and when PacifiCorp started to see the
technology being adopted in each of its service territories. Updated diffusion parameters used the most recent installation
data provided by PacifiCorp(through Q1 2024).
1.2 Distributed generation forecast
In the base case scenario, DNV estimates 4,182 MW of new distributed generation capacity will be installed in PacifiCorp's
service territory over the next twenty years(2024-2043). Figure 1-3 shows historical distributed generation capacity and
forecast base, low and high case scenarios compared to the previous(2022)study's total base case forecast. The 2022
study base case scenario estimated 3,874 MW of new capacity over the 20-year forecast.The 2024 study low case scenario
estimates 3,129 MW of new capacity over the 20-year forecast while the high case estimates 4,871 MW of new distributed
generation capacity installed by 2043.
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Figure 1-3. Cumulative historical and new capacity installed by scenario(MW-AC),2024-2043
5,000
4,500
4,000
3,500 sop 00
♦
Q 3,000
♦
2,500
> 2,000
iu
1,500
v' 1,000
500
0
O(b OHO Oho O�� O��OHO O�'� 00� OHO 00'� O�� O`1O 000 00� 00�000 O�� Oo� 000 00� 00� 000 OHO O�� O��OHO
T V rp T ti ti V rp ti T T T V T ti r ' ti ti � �
— — 2022 Study —Historical —Low —Base —High
The sensitivity analysis showed a greater margin of uncertainty on the low side than on the high side. The IRA extends tax
credits for distributed generation that create favorable economics for adoption, and those are embedded in the base case.
We therefore limited our upper bound forecast to lower technology costs and higher retail electricity rates, and these
produced only a small boost to adoption for technologies that were already cost-effective under the IRA. In contrast,when
we modelled our lower bound,we found that the decreases in cost-effectiveness were enough to tamp down adoption by a
wider margin.The low case assumed higher technology costs and lower increases in retail electricity rates than the other
cases, reducing the economic appeal of distributed generation despite incentives being unchanged. The low-case forecast is
26% less than the base case,while the high-case cumulative installed capacity forecasted over the 20-year period is 15%
greater than the base case.
Figure 1-4 shows the base case forecast by state, compared to the previous (2022)assessment's total base case forecast.
This figure indicates that Utah and Oregon will drive most PG installations over the next two decades,which is to be
expected given these two states represent the largest share of PacifiCorp's customers and sales. Utah continues to
dominate near-and long-term adoption (customer base and current adoption levels). Oregon adoption increases
significantly in the near-to medium-term due to various factors, and Idaho and Washington experience moderate to high
adoption levels over time.The base scenario estimates approximately 1,740 MW of new capacity will be installed over the
next 10 years in PacifiCorp's territory-62%of which is in Utah, 36% in Oregon, 8% in Washington, and 5% in Idaho. Given
recent adoption trends, projected PV capacity is expected to grow at a faster rate in the early years and at a slower rate
towards the end of the forecast period. The key drivers of these differences include larger average PV system sizes, a
steeper decline in PV+ Battery costs at the start of the forecast period, and the maturity of rooftop PV technology.
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Figure 1-4. Cumulative new capacity installed by state(MW-AC),2024-2043, base case
6,000
5,000
U
Q
4,000
3,000 -
E 2,000 --
U
1,000
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
CA �!� ID OR �UT WA WY --- 2022
In Figure 1-5 below, the base case forecast is presented by technology for all states in PacifiCorp's service territory. First-
year PV Only is estimated to grow by 10 MW and PV+ Battery by 3 MW. These two technologies make up 99%of new
installed distributed generation capacity forecasted. The results section of the report contains results by technology for the
high, base, and low sectors.Additionally,the total PV capacity forecasted is presented by sector in that section.
Figure 1-5. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case
4,500
4,000
U 3,500
3,000 f
r
2,500
2,000
� r
E 1,500
D
U 1,000
500
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV + Battery Wind
Small Hydro Reciprocating Engine Micro Turbine
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2 BACKGROUND
DNV prepared this distributed generation Long-term Resource Assessment on behalf of PacifiCorp. The assessment
represents their service territory in six states: California, Idaho, Oregon, Utah, Washington, and Wyoming, as shown in
Figure 2-1. In this assessment, distributed generation technologies provide BTM energy generation at the customer site and
are designed to offset customer load and/or peak demand.This assessment supports PacifiCorp's 2025 IRP forecasting the
level of distributed generation resources PacifiCorp's customers may install over the next two decades under base, low, and
high adoption scenarios. In addition to distributed generation, DNV also considered the cost-effective potential for high-
efficiency cogeneration in Washington, consistent with the 480-109-060(13)and 480-109-100 (6)of the Washington
Administrative Code(WAC).
Figure 2-1. PacifiCorp service territory
�R"�DERkE _ WASHINGTON
AREA
- w w�.
_ O_w ._. 0 ....0
o
...__..o o.......
0.
U ..ono
_ a IDAHO
.� OREGON _oo —o
VKW M1N G o _
_
V WASATCH ...p o
FRONT o
c ... SEMICE ..-.o�° o` o...,_
CALIFORNIA AREA V \ oa. .-
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Pacific Power
-r.-0 r....._.
UTAH
Rocky Mountain Power
There have been seven previous assessments involving distributed generation. DNV developed its assumptions, inputs,
methodologies, and forecasts for years 2022 and 2024 independently from the prior seven assessments. The forecasting
methodologies and techniques DNV applied in this analysis are commonly used in small-scale, BTM energy resource and
energy efficiency forecasting. This study evaluated the expected adoption of BTM technologies over the next 20 years,
including:
1. Photovoltaic(Solar PV)Systems
2. Solar PV paired with battery storage
3. Small scale wind
4. Small scale hydro
5. Reciprocating engines
6. Microturbines
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Project sizes were determined based on average customer load across the commercial, irrigation, industrial, and residential
customer classes for each state. The project sizes were then limited by each state's respective system size limits.
Distributed generation adoption for each technology was estimated by sector in each state in PacifiCorp's service territory.
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3 APPROACH AND METHODS
DNV used applicability,technical feasibility, customer perspectives toward distributed generation, and project economics to
forecast the expected market adoption of each distributed generation technology.
3.1 Technology attributes
The technology attributes define the reference systems and their key attributes such as capacity factors, derate factors, and
costs which are used in the payback and adoption analyses.A full list of detailed technology attributes and assumptions by
state and sector is provided in section 5. The following information provides a high-level summary of the key elements of the
technologies assessed in this analysis.
3.1 .1 Solar PV
Solar photovoltaic(PV)systems convert sunlight into electrical energy. DNV modeled representative PV system energy
output for residential and non-residential systems in each state to estimate first-year production.To model hourly production,
DNV leveraged its SolarFarmer and Solar Resource Compass APIs. DNV's Solar Resource Compass API accesses and
compares irradiance data from multiple data providers in each region. Solar Resource Compass also generates monthly
soiling loss estimates for dust soiling and snow soiling, as well as a monthly albedo profile. By incorporating industry
standard models and DNV analytics, precipitation, and snowfall data are automatically accessed and used to estimate the
impact on energy generation.
Total PV capacity is forecasted by two different technology configurations: PV Only and PV+ Battery.The PV technology in
the PV+ Battery systems was modeled using the same specifications as the PV Only technology except for nameplate
capacity. DNV determined that average system sizes for PV+ Battery configurations are, on average, larger than PV Only
systems.
DNV further segmented the PV+ Battery technology into two categories: new PV+ Battery systems installed together and a
Battery Retrofit case,where a battery is added to an existing PV system. The PV Only forecast presented in the results
section of this report is the net of customers who later adopt an add-on battery system (Battery Retrofit), and therefore
become a part of the PV+ Battery forecast. DNV assumes that customers in the Battery Retrofit case do not represent new
incremental PV MW-AC capacity; however,the generation profile of the customer changes from PV Only to PV+ Battery.
An example residential customer load profile for two summer days is presented in Figure 3-1 to illustrate the difference
between the generation profiles of PV Only and PV+ Battery systems. This example represents peak PV production, and it
should be noted that systems located in PacifiCorp territory have different load curves for the winter and rainy seasons.
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Figure 3-1. Example residential summer load shape compared to PV Only and PV+ battery generation profiles
6.00
5.00
4.00
3.00
0
IL
2.00
1.00
0.00 - -
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Hour of Day(Hour Ending MT)
Customer Load (Gross) PV Only Generation (Gross) PV+ Battery Generation (Net Effective)
3.1.1.1 PV Only
Table 3-1 provides the representative system specifications used to model residential standalone PV adoption. DC/AC ratio
assumptions are derived from DNV's experience in the residential PV industry.
Table 3-1. Residential PV Only representative system assumptions
pSystem
erformance �Mmmmmm
Nameplate
capacity kW-DC 6.5 7.3 7.1 6.2 10.0 7.2
Module type n/a c-Si c-si c-si c-Si c-si c-si
PV inverter n/a Microinverter
Installation Fixed-tilt roof-mounted
requirements n/a
kWh
Capacity factor (kW-DC x
8760 hrs./yr) 13% 15% 16% 15% 13% 16%
DC/AC derate
factor n/a 1.118 1.123 1.121 1.129 1.132 1.118
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Table 3-2 provides the representative system specification used to model non-residential standalone PV adoption. DC/AC
ratio assumptions are derived from Wood Mackenzie's H1 2022 US solar PV system pricing report.The nameplate capacity
of the system depends on the average customer size for each non-residential sector and state.
Table 3-2. Non-residential PV Only representative system assumptions
System
performance
Nameplate
capacity kW-DC 25-129 26-123 25-253 52-138 17-98 15-25
Module type
n/a c-Si c-Si c-Si c-Si c-Si c-Si
PV inverter n/a Three-phase string inverter
Installation Flat roof-mounted
requirements n/a
kWh
Capacity factor (kW-DC x
8760 hrs./yr) 14% 13% 12% 14% 12% 12%
DC/AC derate
factor n/a 1.30 1.30 1.30 1.30 1.30 1.30
The full list of nameplate capacity assumptions by sector and state can be found in section 5. For all PV systems, DNV
assumed a linear degradation rate of 0.5%across the expected useful life of the system.
3.1.1.2 PV + battery
Technology attributes consist of a representative system, operational data, cost assumptions, and capital costs which are
used in conjunction to develop a total installed cost in dollars per kW. DNV reviewed PacifiCorp's history of interconnected
projects to develop its customer-level assumptions for a number of batteries, usable energy capacity, and rated power at the
state level.The resulting representative composite system is used for operational parameters and costs to be used for long-
term adoption and forecasting purposes.
DNV assumes a fully integrated battery energy storage system (BESS)product for the residential sector, which will include a
battery pack and a bi-directional inverter based on leading residential battery energy storage manufacturers such as Tesla,
Enphase, and Sonnen providing fully integrated BESS solutions. Table 3-3 presents the representative residential PV+
Battery system assumptions used in this analysis. The system specifications for the commercial, industrial, and irrigation
sectors are listed in Appendix A, section 5.1.
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Table 3-3. Residential PV+battery representative system assumptions
System performance MMMMMM
PV Nameplate capacity kW-DC 8.5 8.9 8.7 7.7 12.0 8.2
Total usable energy
capacity kWh 12.5 12.5 12.5 10.0 14.0 10.0
Total power kW 5.0 5.0 7.0 5.0 7.0 5.0
Battery duration Hrs 2.5 2.5 2.0 2.5 2.0 2.0
Roundtrip efficiency % 89%
BESS Battery pack chemistry n/a Lithium-ion nickel, manganese, cobalt(NMC)
Residential and non-residential BESS can be installed as a standalone system, added to an existing PV system (i.e., battery
retrofit), or the system can be installed with a new PV system. DNV assumed all battery installations would be co-located
with a PV system in an AC-coupled configuration, as standalone BESS systems are ineligible for the federal IT, as explained
in section 3.1.6.
Battery adoption was forecasted separately for PV+ Battery systems installed together, and the Battery Retrofit case,where
a battery is added to an existing PV system. The basis of the Battery Retrofit forecast is the existing PV capacity in
PacifiCorp's service territories and the PV Only capacity forecasted in this analysis. For forecasting distributed generation
capacity, the Battery Retrofit forecast is presented in the results section as a part of the PV+ Battery capacity forecast. In
the BTM battery storage capacity forecast, presented in Appendix 5.3,the Battery Retrofit case is split out in the
presentation of the results.
Battery degradation was modeled using DNV's Battery Al, a data-driven battery analytics tool that predicts short-term and
long-term useable energy capacity degradation under different usage conditions. It combines laboratory cell testing data with
artificial intelligence(AI)technologies to provide an estimation for battery energy capacity degradation over time. In this
analysis, Battery Al used several current-generation, commercially available NMC cells to predict the expected degradation
performance of"generic"cells.These cells were tested in the lab over six to twelve months at multiple temperatures, C-
rates, SOC ranges, and cycling/resting conditions. Predictions are generally constrained within the bounds of the testing
data. DNV has not explicitly modeled battery end-of-life(EOL), due to a lack of testing data in this region of operation.
Earlier than 20 years or 60%capacity retention is generally considered to represent EOL.
Both cycling and calendar effects were considered in the degradation assessment. It is also assumed the battery cell
temperature will be controlled to be around 25°C for the majority of the time with proper thermal management(e.g.,
ventilation, HVAC). DNV notes that temperature plays a key role in battery degradation. Continuous operation under
extremely low or high temperatures will accelerate degradation in the battery's state of health.
Cost assumptions
Cost assumptions are used in conjunction with representative system parameters to develop system costs. The costs are
developed for each state and sector, including hardware, labor, permitting, interconnection fees, and provisions for sales
and marketing, overhead, and profit. For labor costs,we used state-level data from the U.S. Bureau of Labor Statistics(BLS)
for electricians, laborers (construction), and electrical engineers.
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Total installed costs(or capital expenditures)are based on cost assumptions developed on a bottom-up basis—including
hardware, installation/interconnection, as well as a provision for sales, general, and administrative costs, and overhead.
Capital expenditures(Cap-Ex)are expenditures required to achieve commercial operation in a given year. Pricing indicates
a cash sale, not a lease or Power Purchase Agreement(PPA), and it does not account for Investment Tax Credit(ITC)or
local rebates. Examples of total installed costs by category for residential and commercial customers in Utah are shown in
Figure 3-2 and Figure 3-3, respectively.The full set of cost and incentive assumptions used in the analysis can be found in
Appendix A, section 5.1.
Figure 3-2. Cost of residential PV standalone, battery storage retrofit to existing PV,and PV+battery systems from
DNV bottom-up Cap-Ex Model, Utah'
$40.000
$35,000 ■Overhead&Profit
$30,000
•Customer Acquisition
■Sales Tax
$25.000 ■Supply Chain&Logistics
to ■Permitting&Interconnection
:D $20.000
`t CV ■Design&Engineering
O
N $15,000 ■Installation Labor
Balance of System
$10.000 ■Battery Inverter
■Battery Pack
$5,000
PV Inverter
$0 isPV Module
PV Only(8 kW) Battery Retrofit PV(8 kW)+Battery(5
(5 kW/12.5 kWh) kW/12.5 kWh)
Costs are presented as all-in costs before tax credits.
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Figure 3-3. Cost of commercial PV standalone, battery storage retrofit to existing PV,and PV+battery systems
from DNV bottom-up Cap-Ex Model, Utah'
$400,000
$350,000
■Overhead&Profit
$300,000
■Customer Acquisition
■Sales Tax
$250,000 ■Supply Chain&Logistics
■Permitting&Interconnection
It $200,000
cV ■Design&Engineering
0
$150,000 ■Installation Labor
Balance of System
$100,000 ■Battery Inverter
■Battery Pack
$50,000 PV Inverter
■PV Module
$0
PV Only(150 kW) Battery Retrofit PV(150 kW)+Battery(35
(35 kW/140 kWh) kW/140 kWh)
Costs are presented as all-in costs before tax credits.
DNV has estimated all CapEx categories for the projects based on Wood Mackenzie's US 2022 H1 cost model,which is
reasonable relative to the actual CapEx that DNV has observed on past projects. DNV estimated the benchmark CapEx
values based on the project capacity, location, and technology assumptions for each state and sector.When technology
assumptions were unavailable, DNV made reasonable assumptions. Combined PV+ Battery systems were assumed to
have cost efficiencies in certain categories that would reduce the total cost of the system when installed at the same time.
Cap-Ex categories assumed to have cost efficiencies for combined systems include electrical and structural balance of
system, installation labor, design &engineering, permitting, interconnection&inspection costs, customer acquisition costs,
supply chain&logistics, and overhead &profit costs.
DNV used a blended version of the NREL Annual Technology Baseline4 moderate and conservative solar PV and battery
energy storage system technology cost forecasts in the base case of this distributed generation forecast. The average
residential and non-residential PV system cost forecasts are presented in Figure 3-4 and Figure 3-5, and the average
residential and non-residential battery cost forecasts are shown in Figure 3-6 and Figure 3-7.
4NREL(National Renewable Energy Laboratory).2023.2023 Annual Technology Baseline.Golden,CO:National Renewable Energy Laboratory.
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DNV reviewed the costs presented in the NREL dataset and found that the moderate cost decline forecast for solar PV was
much more aggressive than what DNV's national cost models are predicting and what has been seen in the market
historically.The technology cost forecast used in the base case has a 37% price decrease in the first 10 years, as opposed
to the 50%decrease forecasted in the NREL moderate case. Base year costs were developed for each state, and then the
forecasts were applied to each base year cost(by state,technology, and scenario)to get future year costs.
Figure 3-4.Average residential solar PV system costs,2022-2043
4000
3500
3000
U
0 2500
Y 2000
v>
0 1500
N
1000
500
0
2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042
High Base Low --Historic
Figure 3-5.Average non-residential solar PV system costs, 2023-2043
$2.500
$2.000
U
$1,500 _
N $1.000
0
N
$500
$0
2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042
Historic High Base —Low
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Figure 3-6.Average residential battery energy storage system (AC-coupled)costs, 2024-2043
$5,000
$4,500
$4,000
U $3,500
$3,000
$2,500
iy $2,000
O
$1,500
$1,000
$500
$0
2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042
Historic High Base ----Low
Figure 3-7.Average non-residential battery energy storage system (AC-coupled) costs, 2024-2043
$3,500
$3,000
U $2,500
0
$2.000
$1,500
N
O
$1,000
$500
$0 -
2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042
Historic High Base -_- -Low
3.1 .2 Small-scale wind
Distributed wind technology is a relatively mature DER. Small-scale wind systems typically serve rural homes,farms, and
manufacturing facilities due to their size and land requirements.Wind turbines generate electricity by converting the kinetic
energy in the wind into rotating shaft power that spins an AC generator.
Assumptions on system capacity sizes in each state and sector are detailed in Appendix A, section 5.1.Table 3-4 provides
the cost and performance assumptions used in the small-scale wind forecast and the source for each.
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Table 3-4. Small wind assumptions
Cost& Residential Midsize
performance (20 kW or Commercial ...
metric less) ii
NREL,2022. Distributed Wind Energy
Futures Study.
Installed cost 2024$/kW $7,054 $3,917 $2,931 https://www.nrel.gov/docs/fv22osti/82519.pdf
Annual NREL.2021."2021 Annual Technology
installed cost Baseline."Golden,CO: National Renewable
change %, 2024-2043 -1.9% Energy Laboratory. https://atb.nrel.gov/
NREL,2022. Distributed Wind Energy
Futures Study.
Fixed O&M 2024$/kW-yr $38 $38 $38 https://www.nrel.qov/docs/fv22osti/82519.pdf
Annual fixed NREL.2023."2023 Annual Technology
O&M cost Baseline."Golden, CO: National Renewable
change %, 2024-2043 -3.5% -1.9% -1.9% Energy Laboratory. https://atb.nrel.ggv/
Capacity
Factor System Advisor Model Version 2023.12.17.
(dependent 15.2%- National Renewable Energy Laboratory.
on state) % 7.7-10.8% 15.1%-18.5% 18.4% Golden, CO. https://sam.nrel.gov
3.1 .3 Small-scale hydropower
Hydroelectric power is an established, mature technology, but small-scale systems are a newer permutation of the
technology and are still quite costly compared to other distributed generation technologies. Small hydro systems generate
electricity by transforming potential energy from a water source into kinetic energy that rotates the shaft of an AC generator.
Assumptions on system capacity sizes in each state and sector are detailed in Appendix A, section 5.1.Table 3-5 provides
the cost and performance assumptions used in the small hydro forecast and the source for each.
Table 3-5. Small hydro assumptions
Micro- Mini-
Cost& hydro hydro
performance 0i i0
metric Im or less) MW)
International Renewable Energy Agency(IRENA).2012.
Installed cost 2024$/kW $5,190 $3,892 "Renewable Energy Cost Analysis: Hydropower"
NREL.2021. "2021 Annual Technology Baseline."
Annual installed Golden, CO: National Renewable Energy Laboratory.
cost change %, 2024-2043 -0.2% https://atb.nrel.gov/
International Renewable Energy Agency(IRENA).2012.
Fixed O&M 2024$/kW-yr $208 $156 "Renewable Energy Cost Analysis: Hydropower"
NREL.2023. "2023 Annual Technology Baseline."
Annual fixed O&M Golden, CO: National Renewable Energy Laboratory.
cost change %, 2024-2043 -1.9% https://atb.nrel.gov/
International Renewable Energy Agency(IRENA).2012.
Capacity factor % 45% 45% "Renewable Energy Cost Analysis: Hydropower"
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3.1 .4 Reciprocating engines
Combined heat and power(CHIP), or cogeneration, is a mature technology that has been used in the power sector and as a
distributed generation resource for decades. The two most common CHIP technologies for commercial and small-to
medium-industrial applications are reciprocating engines and microturbines, used to produce both onsite power and thermal
energy.
Reciprocating engines are a mature, reliable technology that performs well at part-load operation in both baseload and load-
following applications. Reciprocating engines can be operated with a wide variety of fuels; however, this analysis assumes
natural gas is used to generate electricity as it is the most commonly used fuel in CHIP applications.A reciprocating engine
uses a cylindrical combustion chamber with a close-fitting piston that travels the length of the cylinder. The piston connects
to a crankshaft that converts the linear motion of the piston into a rotating motion. Reciprocating engines start quickly and
operate on normal natural gas delivery pressures without additional gas compression. The thermal energy output from
system operation can be used to produce hot water, low-pressure steam, or chilled water with the addition of an absorption
chiller.Typical CHP applications for reciprocating engine systems in the Pacific Northwest include universities, hospitals,
wastewater treatment facilities, agricultural applications, commercial buildings, and small-to medium-sized industrial
facilities.5
Assumptions on system capacity sizes in each state and sector are detailed in Appendix A, section 5.1.Two representative
reciprocating engine sizes were used in this analysis based on the ability to meet the average customer's minimum electric
load, ranging from less than 100 kW to 1 MW. Table 3-6 provides the cost and performance assumptions used in the
reciprocating engine forecast and the source for each.
Table 3-6. Reciprocating engine assumptions
Cost& Small Med�u
VTJ�t t0
metric or less) MW)
"A Comprehensive Assessment of Small Combined
Installed cost Heat and Power Technical and Market Potential in
2024$/kW $4,189 $3,125 California."2019.California Energy Commission.
Annual installed NREL.2023. "2023 Annual Technology Baseline."
cost change o o Golden, CO: National Renewable Energy Laboratory.
2024-2043 -0.5/o https://atb.nrel.gov/
"A Comprehensive Assessment of Small Combined
Variable O&M Heat and Power Technical and Market Potential in
2024$/MWh $28 $20 California."2019.California Energy Commission.
Annual variable NREL.2023. "2023 Annual Technology Baseline."
O&M cost change o o Golden,CO: National Renewable Energy Laboratory.
/o, 2024-2043 -1.9/o https://atb.nrel.gov/
Electric heat rate "A Comprehensive Assessment of Small Combined
(HHV) Heat and Power Technical and Market Potential in
Btu/kWh 11,765 9,721 California."2019.California Energy Commission.
5 U.S.Department of Energy Combined Heat and Power and Microgrid Installation Databases(2024).Available at:https://doe.icfwebservices.com/chl).
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3.1 .5 Microturbines
Microturbines are another CHP application commonly used in smaller commercial and industrial applications. They are
smaller combustion turbines that can be stacked in parallel to serve larger loads and provide flexibility in deployment and
interconnection at customer sites. Microturbines can use gaseous or liquid fuels, but for CHP applications natural gas is the
most common fuel. Therefore,for this analysis, DNV assumed microturbines would use natural gas to generate electricity
and thermal energy at customer sites. Microturbines operate on the Brayton thermodynamic cycle where atmospheric air is
compressed, heated by burning fuel, and then used to drive a turbine that in turn drives an AC generator. A microturbine can
have exhaust temperatures in the range of 500 to 600°F, which can be used to produce steam, hot water, or chilled water
with the addition of an absorption chiller in CHP applications. Microturbine efficiency declines significantly as load
decreases;therefore the technology is best suited to operate in base load applications operating at or near full system load.
Common microturbine CHP installations in the Pacific Northwest include small universities, commercial buildings, small
manufacturing operations, hotels, and wastewater treatment facilities.'
Assumptions on system capacity sizes in each state and sector are detailed in Appendix A, section 5.1.This analysis used
two representative microturbine sizes based on the ability to meet the average customer's minimum electric load, ranging
from less than 100 kW to 1 MW. Table 3-7 provides the cost and performance assumptions used in the microturbines
forecast and the source for each.
Table 3-7. Microturbine assumptions
Cost& Small performance (less than
i;
metric ii
"A Comprehensive Assessment of Small Combined
Heat and Power Technical and Market Potential in
Installed cost 2024$/kW $3,742 $3,134 California."2019.California Energy Commission.
NREL.2023. "2023 Annual Technology Baseline."
Annual installed Golden,CO: National Renewable Energy Laboratory.
cost change %, 2024-2043 -0.6% https://atb.nrel.gov/
"A Comprehensive Assessment of Small Combined
Heat and Power Technical and Market Potential in
Variable O&M 2024$/MWh $19 $15 California."2019.California Energy Commission.
NREL.2023. "2023 Annual Technology Baseline."
Annual variable Golden, CO: National Renewable Energy Laboratory.
O&M cost change %, 2024-2043 -1.9% https://atb.nrel.gov/
"A Comprehensive Assessment of Small Combined
Electric heat rate Heat and Power Technical and Market Potential in
(HHV) Btu/kWh 13,648 11,566 California."2019.California Energy Commission.
3.1 .6 Incentives overview
Since the passing of the IRA,the ITC has been extended 10 years past its original expiration date. For facilities beginning
construction before January 1, 2025,the IRA extends the ITC for up to 30%of the cost of installed equipment through 2032
and is assumed to 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
'Ibid
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facilities,the updated ITC includes credits for standalone energy storage with a capacity of at least 3 kWh for residential
customers and 5 kWh for non-residential customers. Energy storage installations that begin construction after Dec. 31,
2024,will be entitled to credits under the technology-neutral ITC under new Section 48E.The base ITC rate for energy
storage projects is 6%and the bonus rate is 30%.The IRA also includes a 5-year MACRS depreciation schedule for non-
residential (i.e., Solar Photovoltaics,Wind (All),Wind (Small), and Microturbines. The federal tax credits in Table 3-8 were
included in the economic analysis of all distributed generation forecast scenarios. Since there are complexities related to the
ability to apply and receive tax credits for larger DG systems,future modeling assumptions could take into account historical
data to apply factors that align with the tax credit percentage granted.
The U.S. EPA Solar for All program issued a$7 billion Notice of Funding Opportunity in 2023. This opportunity provides
funding for 60 grants to states,territories, Tribal governments, municipalities, and nonprofits to create and expand programs
that provide financing and technical assistance to bring residential solar to low-income and disadvantaged communities. The
funding availability assumptions incorporated into state-level incentives for solar PV aligned with residential LMI segments.
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Table 3-8. Federal investment tax credits for DERs
Cells in green represent the transition to a technology-neutral ITC for clean energy technologies with 0 gCO2e emissions per kWh, under section 48D.
TechnologySystem
size
Incentive (M) ffi
- i i i -
< 1,000 PV 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
Residential
/Business < 1,000 Energy Storage 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
ITC
< 1,000 Small Wind 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
< 1,000 Microturbines 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
Reciprocating
< 1,000 Engines 30% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
Small Hydro
Business (hydropower
ITC < 150 dams) 30% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Small Hydro
(Hydrokinetic
pressurized
<25 conduits) 30% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
< 1,000 Small Hydro 0% 30% 30% 30% 30% 30% 30% 30% 30% 26% 22% 0%
A summary of the state incentives included in the economic analysis is provided below in Table 3-9.
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Table 3-9. State Incentives for DERs
Residential Non-residential
PV-Only: Battery Storage:
Oregon' PV-Only:
$450/home, $3,000 $250/kWh, $3,000
max/home max/home $0.15/W(up to 480 kW)
Utah$ PV-Only: Non-PV:
None(expired in 25%of eligible system cost Up to 10%of the eligible system cost
2023) (up to$2,000) or up to$50,000*
Idaho' Annual maximum of$5,000, and$20,000 over four
years** None
California
None None
WA provides a sales tax exception for
PV purchases>100-500 kW
Washington installations.These are split between
Category 1 (>500 kW)and Category 2
None (100-500 kW)
Wyoming None None
* Solar PV,wind,geothermal,hydro,biomass,or certain renewable thermal technologies
**Mechanism or series of mechanisms using solar radiation,wind,or geothermal resource
***Note that incentives from Rocky Mountain Power's Wattsmart battery program were also included in the modeling process
'Incentives are provided through the Energy Trust of Oregon(Solar for Your Home,Solar Within Reach,and Solar for Your Business)and the Oregon Department of
Energy(Solar+Storage Rebate Program for Low-Moderate Income and Non-Income Restricted Homeowners).https://energVtrust.org/programs/solar/;
https://www.oregon.gov/energy/Incentives/Pages/Solar-Storage-Rebate-Program.aspx Funding for the Oregon Solar+Storage Rebate Program is fully reserved as
of May 2024,and ODOE is no longer accepting applications.
8 Incentives are provided through the Utah Office of Energy Development Renewable Energy Systems Tax Credit.https://energy.utah.goy/tax-credits/renewable-energy-
systems-tax-credit/
9 Incentives are provided through the State of Idaho Renewable Alternative Tax Deduction.https://legislature.idaho.gov/statutesruies/idstaVtitle63/t63ch30/sect63-3022c/
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3.2 Current distributed generation market
To date, about 99%of the existing distributed generation capacity installed in PacifiCorp's service territory is PV or PV+
Battery.10 To inform the adoption forecast process, DNV conducted an in-depth review of the other technologies and did not
find any literature to suggest that they would take on a larger share of the distributed generation market in the Company's
service territory in the future years of this assessment. Figure 3-8 shows the current share of distributed generation capacity
by technology in each of PacifiCorp's six-state service territories.
Figure 3-8. Cumulative installed distributed generation capacity by state, by technology, as of March 31, 2024
CA ID
Small Small Hydro Wind
Hydro Wind PV+ 0.00% 0.07% PV+
0.000% 0.02% Battery Battery
Micro 3.16% Micro 12.93%
Turbine
Turbine 0.00%
0.00%
Reciprocating Reciprocating
Engine
Engine 0.00% IP
0.00%
PV Only PV Only
96.81/0 87.00%
PG capacity installed: 15.8 MW-AC PG capacity installed: 23.6 MW-AC
OR UT
Small Small
Hydro
0.000% Wind PV+ Hydro Wind PV +
0.04% Battery MICfO 0.003% 0.02% Battery
/
Micro 3.10/o 9.48%
Turbine Turbine
0.46% 0.00%
Reciprocating
Reciprocating Engine
Engine 0.00%
0.00%
PV Only PV Only:
96.40% 90.50%
PG capacity installed: 190.1 MW-AC PG capacity installed: 593.5 MW-AC
10 PacifiCorp distributed generation interconnection data as of April 2024.
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WA WY
Small
Small
Wind PV+ Hydro Wind PV+
Micro Hydro o Battery0.000% 0•49% Battery
0.08/0 1.62 Micro 0
0.000/0 11.55/o
Turbine Turbine
0.00% 0.00%
Reciprocating Reciprocating
Engine Engine
0.00% 0.00%
PV Only PV Only
98.30% 87.96%
PG Capacity Installed: 38.9 MW-AC PG Capacity Installed: 6.5 MW-AC
Section 3.3.3 details how the historic distributed generation adoption data is used in the distributed generation forecast
modelling process.
3.3 Forecast methodology
DNV combined technical feasibility characteristics of the identified distributed generation technologies and potential
customers with an economic analysis to calculate cost-effectiveness metrics for each technology,within each state that
PacifiCorp serves, over the analysis timeframe. DNV then used a Bass diffusion model to estimate customer adoption based
on technical and economic feasibility and incorporated existing adoption of each technology by state and customer segment
as input to the adoption model.
Technical feasibility characteristics were used to identify the potential customer base that could technically support the
installation of a specific distributed generation technology, or the maximum,feasible, adoption for each technology by sector.
These factors included overall distributed generation metrics such as average customer load shapes and system size limits
by state, and specific technology factors such as estimated rooftop space and resource access based on location (for hydro
and wind resource applicability). Simple payback was used in the customer adoption portion of the model as an input
parameter to Bass diffusion curves that determined the future penetration of all technologies. Figure 3-9 provides a visual
representation of how different inputs were used in different portions of the model.Additional details on the economic and
adoption approaches used in this analysis are provided in the subsequent sections.
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Figure 3-9. Methodology to determine market potential of distributed generation adoption
Installation • O&M costs
costsLocal and
-.- incentives
• •
Energy savings Benefits of analysis
• . • - •• -•
ownership Market
Customer load shapes System potential
performance
Land-useSystem size limits constraints
Non-shaded rooftop space
dams,Access to unprotected streams and requirements
• resource
3.3.1 Economic analysis
The economic analysis portion of overall customer adoption was used as a key factor in the Bass diffusion model that
calculated future distributed generation adoption. DNV used simple payback as the preferred method of estimating
economic viability based on customer perspectives given its widespread use in similar adoption analyses, ability to reflect
customer decision-making in forecasting efforts, and ease of estimation.
DNV developed a behind-the-meter net economic perspective that includes, as costs, the acquisition and installation costs
for each technology less the impact of available incentives and, as benefits, the customer's economic benefits of ownership
such as energy and demand savings and export credits. For this assessment,we assumed that the current net metering or
net billing policies and tariff structures in each state continued throughout the study horizon. This resulted in the model
incorporating benefits associated with net metering in Oregon,Washington, and Wyoming and net billing in Utah and
California. We assumed customers in Idaho would accrue benefits based on the net billing policy in Utah throughout the
study.
A detailed breakdown of the simple payback calculation and different elements is shown below.
Cumulative Net Costs
Simple Payback=
Cumulative Net Benefits
Cumulative Net Costs= (Upfront System Cost—Year One Incentives)+NPV(Annual 0&M Costs+Annual Fuel Costs)
Cumulative Net Benefits=NPV(MACRS Savings+ Self Consumption Savings+Export Credits+Peak Demand Savings)
DNV also used an annual hourly profile analysis to estimate electric bill savings and excess generation for each distributed
generation technology by customer segment.This analysis used hourly generation and customer load profiles, and tiered,
time-of-use(TOU), and peak demand rates for each customer segment and technology permutation. DNV integrated the
energy savings, excess generation, and peak demand benefits into the lifetime simple payback estimation using customer
load and individual rate forecasts provided by PacifiCorp.A full breakdown of all inputs used in the economic analysis is
provided in Table 3-10 below.
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Table 3-10. Distributed generation forecast economic analysis inputs'
Cost/benefit category
Technology cost data— Distributed generation cost data compiled in$/kW(AC&DC)—used in
installed cost determining year one installed system costs DNV
Technology cost data— Distributed generation fixed($/kW)&variable($/kWh)O&M data—used in
annual O&M determining annual system costs DNV
EIA Annual Energy
Fuel cost data Natural gas cost data($/MMBtu) Outlook 2024
Hourly generation profiles for each technology by state—used in calculating
Technology generation self-consumption savings,excess generation credits,and peak demand
profiles savings DNV
Hourly average customer load profiles by state—used in calculating self-
Customer load profiles consumption savings,excess generation credits,and peak demand savings PacifiCorp
Customer tiered,TOU,and peak demand rates by size,segment,and state
—used in calculating self-consumption savings,excess generation credits,
Customer rates and peak demand savings PacifiCorp
Distributed generation cost data forecasts for installed system costs and NREL Annual
annual O&M costs—used in determining year one installed system costs Technology Baseline
Technology cost forecasts and future year annual system costs (ATB)
Individual customer count and load(kWh)forecasts by customer segment
Customer&load forecasts and state—used in calculating future year system costs and benefits PacifiCorp
Rate forecasts applied to each customer segment—used in calculating EIA Annual Energy
Outlook 2024
future year self-consumption savings,excess generation credits,and peak
Customer rate forecasts demand savings PacifiCorp
'Detailed input data can be found in Appendix section 5.1 (Appendix Attachment A)
DNV calculated simple payback for each technology(solar PV, solar PV+ battery,wind, hydro, reciprocating engines, and
microturbines)by applicable individual customer segments (residential, commercial, industrial, and irrigation)for each
installation year in the analysis timeframe(2024—2035). These payback results were combined with technical feasibility by
customer segment and integrated into the Bass diffusion adoption model to determine annual distributed generation
penetration throughout PacifiCorp's territory.
3.3.2 Technical feasibility
The maximum amount of the technically feasible capacity of distributed generation was determined individually for each
technology considered in the distributed generation forecast. Each technology was generally limited by customer access
factors, system size limits, and energy consumption.The customer load shapes, provided by PacifiCorp, were used to
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calculate annual energy use(kWh)cutoffs used in identifying the total number of customers that could technically support
the installation of a specific technology. Other data sources specific to each technology were used to determine the amount
of capacity that can be physically installed within PacifiCorp's service territory, such as:
• Hydropower potential data and environmental attributes for all HUC10 watersheds in PacifiCorp's service territory"
• Building rooftop hosting area and suitability for solar PV12
• Wind resource potential data by state13
3.3.3 Market adoption
DNV modeled market adoption using Bass diffusion curves customized to each state, technology, and sector. The Bass
diffusion model was developed in the 1960s and is widely used to model market adoption over time.
The formula for new adoption of a technology in year t is given by14
s t =m (p+q)2 e-t(p+q)
O p (1+a e-t(p+q))2
P
Where:
s(t)is new adopters at time t
m is the ultimate market potential
p is the coefficient of innovation
q is the coefficient of imitation
t is time in years
Figure 3-10 shows a generalized Bass diffusion curve.The cumulative adoption curve takes a characteristic"S"shape with a
new unknown and unproven technology having relatively slow adoption that accelerates over time as the technology
becomes more familiar to a wider segment of the population.As the pool of potential buyers who have not yet adopted the
technology shrinks, the rate of adoption (as a percent of the total pool of potential adopters)decreases until eventually
everyone who will adopt has adopted.The corresponding chart shows the rate of annual new adoption.
11 Kao,Shih-Chieh,Mcmanamay,Ryan A.,Stewart,Kevin M.,Samu,Nicole M.,Hadjerioua,Boualem,Deneale,Scott T.,Yeasmin,Dilruba,Pasha,M.Fayzul K.,
Oubeidillah,Abdoul A.,and Smith,Brennan T.New Stream-reach Development:A Comprehensive Assessment of Hydropower Energy Potential in the United States.
United States:N.p.,2014.Web.doi:10.21 72/1 1 30425.
12 Gagnon,P.,R.Margolis,J.Melius,C.Phillips,and R.Elmore.2016.Rooftop Solar Photovoltaic Technical Potential in the United States:A Detailed Assessment.
NREL/TP-6A20-65298.Golden,CO:National Renewable Energy Laboratory.
13 Draxl,C.,B.M.Hodge,A.Clifton,and J.McCaa.2015."The Wind Integration National Dataset(WIND)Toolkit."Applied Energy 151:355366.
14 Bass,Frank(1969)."A new product growth for model consumer durables".Management Science.15(5):215-227
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Figure 3-10. Bass diffusion curve illustration
70%
Cumulative Adoption 3%o Annual Adoption
M M
p 60% « 3%
50% \ 2%
c 40% c
C G 2%
C 30%
M 20% M 1
ro
10% 1%
R
0% 0%
V 0 5 10 15 20 25 30 35 40 45 50 0 5 10 15 20 25 30 35 40 45 50
Cumulative adoption Annual adoption
In the illustration,the cumulative curve approaches 60% market penetration asymptotically, corresponding to the value of m
(ultimate market potential)that we chose for the illustration. For our adoption models,we tied the value of m to payback,
following Sigrin and Drury's15 survey findings on willingness to pay for rooftop photovoltaics based on payback. Because
payback varied by technology, state, and sector, so did the Bass diffusion curve.
Due to regional and sectoral differences,we made significant adjustments to the willingness-to-adopt curves to better align
with the observed relationship between historic cost-effectiveness and current market adoption by technology, state, and
sector in PacifiCorp's service territory. Based on PacifiCorp data on current and recent levels of distributed generation
adoption, Utah in particular showed higher adoption than published willingness-to-pay curves would suggest,which we
believe may be due to regional variation in how customers value resilience. To account for this variation across states,we
developed three willingness-to-adopt curves to capture observed state variation. Table 3-11 shows which willingness-to-
adopt curve was used for solar for each state and sector. Current adoption for the other modeled technologies was too low
to discern variation across states, so we assumed the average propensity to adopt for wind, small hydro, reciprocating
engines, and microturbines.
Table 3-11. Solar willingness-to-adopt curve used by state and sector
Average propensity to adopt High propensity to adopt Low propensity to adopt
• California residential,
Wyoming all sectors
commercial, irrigation
• Utah all sectors
• Idaho commercial, industrial,
• Idaho&Oregon 0 Oregon commercial, industrial, irrigation
residential irrigation
• California industrial
• Washington all sectors
15 Sigrin,Ben and Easan Drury.2014.Diffusion into New Markets:Economic Returns Required by Households to Adopt Rooftop Photovoltaics.Energy Market Prediction:
Papers from the 2014 AAAI Fall Symposium
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Figure 3-11 shows the willingness-to-adopt curves for residential, commercial, and industrial sectors assuming an average
propensity to adopt(the"Mid"case). There was too little irrigation adoption to assess the sector independently, so we used
the commercial curves for the irrigation sector.
Figure 3-11.Willingness to adopt based on technology payback
120%
100%
c 80%
c
.a 60%
0
Q 40%
20%
0%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22
Payback(years)
Residential Commercial -Industrial
The right-hand chart in Figure 3-12 shows the high, mid, and low adoption curves for the residential sector only.The high
and low curves for the other sectors show similar variation on the left.
Figure 3-12.Willingness to adopt based on technology payback, by sector and scenario
Willingness to adopt by sector and average Residential willingness to adopt, and high-low-mid
propensity to adopt adoption curves
100% 100%
90% 90%
EL a
0 80% 0 80%
0 70% 0 70%
rn 600/0 rn 60%
c c
3 50% 50%
40% 40%
ar a)
30% 2 30%
Q 20% a 20%
10% ` 10%
0% 0%
1 3 5 7 9 11 13 15 17 19 21 1 3 5 7 9 11 13 15 17 19 21
Payback(years) Payback(years)
Res Mid Com Mid Ind Mid Res Low Res 1,1id Res High
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The willingness-to-adopt curves established a different m parameter for each diffusion curve. In addition to varying by
technology, state, and sector, m also changed over time due to changing payback resulting from changing technology costs,
incentives, and tax credits, among other economic factors).
The timing of our modeled adoption also varied, as we set to for each diffusion curve based on the earliest adoption of each
technology by state and sector. For example, the first residential PV installed in PacifiCorp's Oregon service territory was in
2000,while the first commercial PV installation in its Idaho service territory wasn't until 2010. For technology/state/sectors
where there is currently no adoption,we assumed that the first adoption would occur in 2025.
The p and q parameters of the Bass diffusion curves were calibrated so that the predicted cumulative adoption from to
through 2023 was equal to the current market penetration of each technology by state and sector(we fixed the relationship
between p and q at q= 10p to make it possible to solve for p). For technology/state/sectors where there is currently no
adoption,we assumed average values for p and q.
The result of this process was Bass diffusion curves customized for each technology, state, and sector that also accounted
for variation in willingness-to-adopt as cost-effectiveness changes over time.The calibrated curves show some segments
are still in the very early phases of adoption,while other markets are more mature. Our forecast of annual adoption reflects
these differences.
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4 RESULTS
In the base case scenario(Table 4-1), DNV estimates that 4,182 MW of new distributed generation capacity will be installed
in PacifiCorp's service territory over the next twenty years(2024-2043). Figure 4-1 shows the relationship between the base
case and low and high case scenarios. The low-case scenario estimates 3,129 MW of new capacity over the 20-year
forecast period—compared to the base case, retail rates increase at a slower rate, and technology costs decrease at a
slower rate. In the high case, retail rates increase at a faster rate, and technology costs decrease at a faster rate;this results
in 4,871 MW of new distributed generation capacity installed by 2043.
Table 4-1. Cumulative adopted distributed generation capacity by 2043, by scenario
Cumulative capacity(2043 MW-AC)
High 4,871
Base 4,182
Low 3,129
Figure 4-1. Cumulative new distributed generation capacity installed by scenario(MW-AC), 2018-2043
5,000
4,500
4,000
i
3,500 � i
i _
Q 3,000
i
i
2,500 i
> 2,000
i
m i
1,500
cj 1,000
500
0
O�cb O�� O0O O�� O��OHO � O�� OHO O`1A O�cb OHO 000 00� O��000 O�� 03� OHO O�� 00Z 000
2022 Study —Historical —Low Base —High
The sensitivity analysis showed a greater margin of uncertainty on the low side than on the high side. The IRA extends tax
credits for distributed generation that create favorable economics for adoption, and those are embedded in the base case.
We therefore limited our upper bound forecast to lower technology costs and higher retail electricity rates, and these
produced only a small boost to adoption for technologies that were already cost-effective under the IRA. In contrast,when
we modeled our lower bound,we found that the decreases in cost-effectiveness were enough to tamp down adoption. The
low case assumed higher technology costs and lower retail electricity rates than the other cases, reducing the economic
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appeal of distributed generation despite incentives being unchanged. The low-case forecast is 25% less than the base case,
while the high-case cumulative installed capacity forecasted over the 20-year period is just 15%greater than the base case.
Figure 4-2. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case
6,000
5,000 -
U
Q
4,000
> 3,000
r
E 2,000 r
U
1,000
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine � Micro Turbine 2022
Figure 4-3. Cumulative new capacity installed by technology(MW-AC), 2024-2043, low case
6,000
5,000
U
Q
4,000
73
3,000
M —
E 2,000
U
1,000 f
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine � Micro Turbine — — 2022
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Figure 4-4. Cumulative new capacity installed by technology(MW-AC), 2024-2043, high case
6,000
5,000
U
Q
4,000
_____---
3,000
►- ---
m --
E 2,000
1,000
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine �Micro Turbine — —2022
The majority of historical and new capacity in all scenarios is either solar PV or solar PV+ battery storage. Therefore, the
following three charts highlight other technologies(wind and CHP)forecasted adoption by scenario.The high scenario
adoption is significantly higher than both the base scenario and low scenario compared to the charts with all technologies
(solar PV or solar PV+ battery storage included). This is largely due to the influence of more influential adoption parameters
having a greater effect in the high scenario compared to the base and low scenarios.
Figure 4-5. Cumulative new capacity installed by technology(MW-AC), 2024-2043, base case(Excluding PV&PV+
Battery)
50
45
40
U
35
30
> 25
20
E 15
U 10
5
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
Wind Small Hydro Reciprocating Engine Micro Turbine — —2022
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Figure 4-6. Cumulative new capacity installed by technology(MW-AC), 2024-2043, low case(Excluding PV&PV+
Battery)
50
45
40
U
Q 35
30
25
m 20
E 15 a
U 10
5
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
r—Wind r_Small Hydro Reciprocating Engine r_Micro Turbine — —2022
Figure 4-7. Cumulative new capacity installed by technology(MW-AC), 2024-2043, high case(Excluding PV&PV+
Battery)
50
45 -
40 -
U
Q 35 =�
30 -
25
m 20 -
E 15 r
U
10
5
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
Wind � Small Hydro Reciprocating Engine Micro Turbine — —2022
4.1 Generation capacity results by state
The following sections present the results by state for each forecast scenario.Additional exhibits for total PV capacity
forecasted are provided by sector. PV Only and PV+ Battery capacity make up at least 95%of each state's projected
distributed generation capacity, so providing results for the other technologies by sector would not provide useful context to
the results.The full set of results by state, sector, and new/existing construction for the forecasts is provided in Appendix B,
section 5.2.
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Figure 4-8 shows the base case forecast by state, compared to the previous(2022)study's total base case forecast. This
figure indicates that Utah and Oregon will drive the most distributed generation installations over the next two decades,
which is to be expected given these two states represent the largest share of PacifiCorp's customers and sales. The base
scenario estimates approximately 2,567 MW of new capacity will be installed over the next 10 years in PacifiCorp's
territory-59%of which is in Utah, 28% in Oregon, and 5% in Idaho. Since the 2022 study,the federal ITC has been
extended for ten years at its original base rate levels and expanded to include energy storage.The tax credit increase and
extension lowered the customer payback period for all technologies, making the customer economics of this study's base
case more similar to the previous study's high case. In addition to the change in customer economics, projected PV capacity
is expected to grow at a faster rate in the early years and at a slower rate towards the end of the forecast period.The key
drivers of these differences include larger average PV system sizes, decreases in PV+ Battery costs, and the maturity of
rooftop PV technology.The adoption model DNV developed for this study was calibrated to existing levels of technology
adoption for each state and sector. Technology adoption follows an S-curve with adoption initially increasing at an increasing
rate, but eventually passing an inflection point where adoption continues to increase at a decreasing rate.
Figure 4-8. Cumulative new capacity installations by state(MW-AC), 2024-2043, base case
6,000
U 5,000
Q
4,000
3,000
co _
2,000
E
U 1,000
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
�CA � ID OR �UT WA �WY --- 2022
4.1 .1 California
Customers in PacifiCorp's service territory in northern California are projected to install about 60 MW of new distributed
generation capacity or-3,000 new customers over the next two decades in the base case. The 20-year high projection is
about 15%greater than the base case and the low projection is 10% less than the base case, or 71 MW and 55 MW,
respectively.
California does not currently have any state incentives available for distributed generation and uses a net billing structure for
DER compensation.The residential sector has the largest share of the distributed generation capacity, ranging from 49% in
the low case to 38% in the high and base cases. The next largest share of the capacity is forecasted in the commercial
sector, ranging from 36% in the low case to 36% in the base and high cases.
DNV — www.dnv.com Page 34

DNV
Figure 4-9. Cumulative new distributed generation capacity installations by scenario(MW-AC), California,2018-2043
80 -
70 do-*
i
i
i
60
i
U 50
Q
40
a�
'- 30
E 20
U
10
0
_ ,�4� ,� -�o- �'� r1�L rL� rLb �h r1ro rl'1 rL� �� 3� „�'� nj�• �1 It, P4D Ibb �jA njlb n�� p I �^ p`l D�
�o_ , '19 ,yo �o, �yo 'yo T T T 'yo T T 'yo 'yo �o �yo ,yo �yo �yo T T T T ,yo ,yo �yo
— — 2022 Study —Historical —Low —Base —High
Figure 4-10. Cumulative new capacity installations by technology(MW-AC), California base case, 2024-2043
80
70
Q 60 _
50 .., -- -- - -
- --
40
30
U 20
10
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine — — 2022
DNV — www.dnv.com Page 35

DNV
Figure 4-11. Cumulative new capacity installations by technology(MW-AC), California low case, 2024-2043
80
70
Q 60
c 50 ��-
4) 40 -
>
2 30 t
20
U
10
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine — 2022
Figure 4-12. Cumulative new capacity installed by technology(MW-AC), California high case, 2024-2043
80
70
Q 60
� 50 �
40
30 s '
E -
U 20
10
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine — 2022
DNV — www.dnv.com Page 36

DNV
4.1.1.1 California PV adoption by sector
The impact of the three different scenarios on PV adoption by sector is shown in Figure 4-13,which presents the differences
in PV capacity relative to the base case for the three modeled scenarios across the four sectors. In the residential sector,the
share of PV+ Battery capacity is about 6%of total PV capacity in 2043 for the high case.The share of PV+ Battery
capacity is about 20%of total commercial PV capacity in 2043 for the high case.The irrigation sector has a similar portion of
its PV capacity in PV+ Battery configurations, at 14%of total capacity in the high case.
Figure 4-13. Cumulative new PV capacity installed by sector across all scenarios, California, 2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
25 25
20 20
Q a f
15 15
10 10
E E
U U
5 5
0 0
`l�o �� r>j0 o`, o� ono �- �o �7 D� ,Lb �b �16 �O „�`1- o� �0 016 �o �r1 �R
�o 'Vo �o ro '0 �o ,LO �o �O 'o �o
Industrial Irrigation
0.06 18
16
0.05
14
0.04 12
10
> 0.03
1m 8
5
3 0.02 6
U U
4
0.01
2
0.00 0
�° ti�O �� o0 0� o° o`O o� �o �,y �° o�� ode ode o0o Doti ooa oo�O o00 0°0 o°ti o°o
T rp �yo T '10 ,yo ro ,yo 'yo ,yo yo ti ti ti ti ti ti ti ti ti ti
DNV — www.dnv.com Page 37

DNV
4.1 .2 Idaho
PacifiCorp's customers in Idaho are projected to install about 167 MW of new distributed generation capacity or—15,500
new customers over the next two decades in the base case.The 20-year high projection is about 20%greater than the base
case, and the low projection is 36% less than the base case, or 247 MW and 127 MW, respectively.
Idaho has an incentive program for residential customers that boosted the sector's adoption, compared to the other sectors.
The incentives are provided through the Residential Alternative Energy Income Tax Deduction, discussed in section 3.1.6.
DNV assumed Idaho would use the same net billing structure for DER compensation as Utah for the study period (2024-
2043).The residential sector has the largest share of the distributed generation capacity, ranging from 59% in the base and
61% in the high case to 57% in the low case.The next largest share of the capacity is forecasted in the commercial sector,
ranging from 31% in the low and base cases to 26% in the high case.
Figure 4-14. Cumulative new distributed generation capacity installed by scenario(MW-AC), Idaho,2018-2043
300
250
200 W'
U
Q
150
i
WP
5
100
E
v 50
0
2022 Study —Historical —Low Base —High
DNV — www.dnv.com Page 38

DNV
Figure 4-15. Cumulative new capacity installations by technology(MW-AC), Idaho base case, 2024-2043
300 — — — —
U 250 — — —
Q
200 — —
> 150
cc
E 100
: r
U
50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine - -- 2022
Figure 4-16. Cumulative new capacity installations by technology(MW-AC), Idaho low case,2024-2043
300 — — —
250 � — — —
U
a
200 — — —
> 150
ca '
100 — — --
1
j -
U 50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine 2022
DNV — www.dnv.com Page 39

DNV
Figure 4-17. Cumulative new capacity installations by technology(MW-AC), Idaho high case, 2024-2043
300
250
200
150
io � -
100
U 50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind — Small Hydro
Reciprocating Engine � Micro Turbine — 2022
DNV — www.dnv.com Page 40

DNV
4.1.2.1 Idaho PV adoption by sector
The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are
presented in the following charts. In the residential sector,the high case share of PV+ Battery capacity is about 15%of total
residential PV capacity in 2042.The share of PV+ Battery capacity is about 8%of total commercial PV capacity in 2042.
The irrigation sector has a slightly higher portion of its PV capacity in PV+ Battery configurations, at 4%of total capacity.
The industrial sector did not have any PV+ Battery adoption forecasted.
Figure 4-18. Cumulative new PV capacity installed by sector across all scenarios, Idaho, 2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
160 80
140 70
U 120 U 60
Q a
100 50
> 80 > 40
E 60 30
U 40 U 20
20 10
0 0
11 OO 016 0000� 0000HO �� �� 00� O0O O0O 000 00 00 000
`(00 `0 L3 0 `0 O `O O L L L L L L0 00 O HO O O��
Industrial Irrigation
70 70
60 60
Q 50 Q 50
2 40 2 40
(D
@ 30 @ 30
E E
�j 20 20
10 10
0 0
ti� tiO
TO TO �O �O LO L0 �O �O �O If, ,yO 10 L0 L0 �O �O �O L0 '0 '0 'O �O
DNV — www.dnv.com Page 41

DNV
4.1 .3 Oregon
PacifiCorp's customers in Oregon are projected to install about 1,030 MW of new distributed generation capacity or
--119,250 new customers over the next two decades in the base case. The 20-year high projection is 18% higher than the
base case and the low projection is 22% less than the base case, or 1,260 MW and 985 MW, respectively.
Oregon has incentives available through the Oregon Department of Energy(DOE)for PV+ Battery systems and the Energy
Trust of Oregon (ETO)for PV Only configurations. The ETO offers incentives for both residential and business customers,
while the Oregon DOE provides incentives for residential customers only. The incentives are discussed further in section
3.1.6. The PV+ Battery incentives offered for residential customers by the Oregon DOE provided a boost to customer
economics that led to the majority of PV+ Battery adoption growth being in the residential sector. The majority of the PV
Only adoption growth in the early years of the forecast is in the commercial sector,with the residential sector following
closely behind and eventually overtaking the forecast in the later years. Oregon's net metering policies were assumed to
stay in place throughout the study, providing more favorable economics for PV Only compared to PV+ Battery systems.
Figure 4-19. Cumulative new distributed generation capacity installed by scenario(MW-AC), Oregon,2018-2043
1,600
1,400
1,200
U 1,000
Q
800 _
'— 600
E 400
U
200
0
O�(b O�� o`l� o`l� O`1�o`l� � O`1� O�ro 0`1A o`lOb O`lcb O�R) Oaf O�L,O[6 Ord Ogh O b O�A
2022 Study —Historical —Low —Base —High
DNV — www.dnv.com Page 42

DNV
Figure 4-20. Cumulative new capacity installations by technology(MW-AC), Oregon base case, 2024-2043
1,600 -
1,400
Q 1,200
1,000 — - +
75
1
> 800
600
E
400
U _
200
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind — Small Hydro
Reciprocating Engine � Micro Turbine - -- 2022
Figure 4-21. Cumulative new capacity installations by technology(MW-AC), Oregon low case, 2024-2043
1,600
1,400
Q 1,200 i
1,00075
> 800
600
r
C
400
U
200
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Ivlicro Turbine 2022
DNV — www.dnv.com Page 43

DNV
Figure 4-22. Cumulative new capacity installations by technology(MW-AC), Oregon high case,2024-2043
1,600
1,400
Q 1,200
1.000
800
600
r
C
400
U
200
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine � Micro Turbine — 2022
DNV — www.dnv.com Page 44

DNV
4.1.3.1 Oregon PV adoption by sector
The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are
presented in the following charts. In the residential sector,the share of PV+ Battery capacity is about 4%of total residential
PV capacity in 2042. The share of PV+ Battery capacity is about 2%of total commercial PV capacity in 2042. The irrigation
sector has a similar portion of its PV capacity in PV+ Battery configurations, at 3%of total capacity. The industrial sector
had a smaller share of its PV capacity in PV+ Battery configurations at less than 1%.
Figure 4-23. Cumulative new PV capacity installed by sector across all scenarios, Oregon,2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
1,200 350
1,000 300
U U 250
a 800 a
2 200
600 ;
T 150
E 400 E
U 100
200 50
0 0
O�11 OHO O 6 000 00l 00� 000 000 Otp O��O�� 00� 0�6 O��O30 03ti OOb OHO O5� OHO Opti OAR
ti ti ti ti ti ti ti ti ti ti ti ti T rp IV T T ti I ti �
Industrial Irrigation
14 40
12 35
a 10 a 30
25
2 8 2
> > 20
m g io
E E 15
U 4 U 10
2 5
0 0
001, 00O OHO 000 OOry 00N 000 000 OHO O�� O�� 00� OHO OHO 000 00� 00� 000 zN
DNV — www.dnv.com Page 45

DNV
4.1 .4 Utah
PacifiCorp's customers in Utah are projected to install about 1,653 MW of new distributed generation capacity or-127,000
new customers over the next two decades in the base case.The 20-year high projection is 11%greater than the base case
and the low projection is 25% less than the base case, or 2,596 MW and 1,733 MW, respectively.
Utah has an incentive program for residential and business customers, but the residential PV-only incentive expired in 2023.
The remaining incentives are provided through the Utah Office of Energy Development Renewable Energy Systems Tax
Credit, discussed in section 3.1.6. DNV assumed Utah's net billing policies would remain in place throughout the study. In all
cases,the residential sector has the largest share of the distributed generation capacity forecasted—ranging from 56%to
61% in the high and low cases, respectively. The commercial sector represents 40%of the capacity forecast in the high and
42% in the base scenarios, but only 36% in the low case.
Figure 4-24. Cumulative new distributed generation capacity installed by scenario(MW-AC), Utah, 2023-2043
All Technologies
3,000
2,500
Q 2,000 000
doo
wo
1,500 .00
op
1,000
U
500 illillillillillllllllIIIIIIIIIIIIIIIIIIIIIIililillillillilllllliiilillillso
0
cb O 0 O 0� 0 0 O 0� 0 0� 0� 00 000 ON 000 H0000 � 0 00000 OHO
2022 Study —Historical Low —Base —High
DNV — www.dnv.com Page 46

DNV
Figure 4-25. Cumulative new capacity installations by technology(MW-AC), Utah base case, 2024-2043
3,000
2,500
U
Q
2,000
75
1,500 f
1,000
U 500 Ir
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine - -- 2022
Figure 4-26. Cumulative new capacity installations by technology(MW-AC), Utah low case, 2024-2043
3,000
2,500
U
Q
3: 2,000
75
dM
> 1,500
CIO
�
1,000
U 500
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Ivlicro Turbine 2022
DNV — www.dnv.com Page 47

DNV
Figure 4-27. Cumulative new capacity installations by technology(MW-AC), Utah high case,2024-2043
3,000 — — -
2,500
U
Q
2,000 —
1,500 1
E 1,000 -
:3 _
U 500
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine — 2022
DNV — www.dnv.com Page 48

DNV
4.1.4.1 Utah PV adoption by sector
The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are
presented in the following charts. In the residential sector,the share of PV+ Battery capacity is between 28 and 32%of total
residential PV capacity in 2042.The share of PV+ Battery capacity is about 4%of total commercial PV capacity in 2042.
The industrial sector has a lower portion of its PV capacity in PV+ Battery configurations, at 1%of total capacity.About 5%
of the irrigation sector PV capacity forecasted is in a PV+ Battery configuration.
Figure 4-28. Cumulative new PV capacity installed by sector across all scenarios, Utah,2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
1,200 1,200
1,000 1,000
Q 800 Q 800
> 600 > 600
U400 3 400
200 /000� 200
0 0
, , HO00041000 , OO O0� 03; b060NI00b`
` `L 10 If, `L0 10 i0 O `O lO 10 If, `O 0 11P O O O
Industrial Irrigation
16 70
14 60
Q 12 Q 50
10
2 40
> 8 >
30
E 6 E
c i 4 cj 20
2 10
0 0
`L� `V `L� ,�0 "�� r5 00 0 �O �' �t `L� �6 �O 30 0� "��' "fir° "�� R0 t. �R
,tiO TO -O rO -0 'O ryO fO f ,tiO �O rL0 ,yO
DNV — www.dnv.com Page 49

DNV
4.1 .5 Washington
PacifiCorp's customers in Washington are projected to install about 218 MW of new distributed generation capacity or
--16,150 new customers over the next two decades in the base case.The 20-year low projection is about 29% less than the
base case, or 187 MW. The high case is 25% higher than the base case, or 351 MW, as seen in
Figure 4-29.
Washington state currently offers no incentives for distributed generation technologies.The residential sector has the largest
share of the distributed generation capacity, ranging from 66% in the high case, 68% in the base case, and 70% in the low
case. The next largest share of the capacity is forecasted in the commercial sector, ranging from 24% in the low case to
27% in the base and high cases.Washington's net metering policies were assumed to stay in place throughout the
assessment, providing more favorable economics for PV Only compared to PV+ Battery systems.
Figure 4-29. Cumulative new distributed generation capacity installed by scenario(MW-AC),Washington, 2018-2043
All Technologies
400
350
300
U
250
200
150
5
E
v 100
50
0
Cb
,�O �O ,LO �O yO ,�O ,�O �O LO yO �O
2022 Study -Historical Low Base -High
DNV — www.dnv.com Page 50

DNV
Figure 4-30. Cumulative new capacity installations by technology(MW-AC),Washington base case, 2024-2043
400
350
Q 300
250
200 -
150
100
U
50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine Micro Turbine 2022
Figure 4-31. Cumulative new capacity installations by technology(MW-AC),Washington low case, 2024-2043
400
350
Q 300
250
200
M 150
100 -
U
50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind Small Hydro
Reciprocating Engine Micro Turbine — — 2022
DNV — www.dnv.com Page 51

DNV
Figure 4-32. Cumulative new capacity installations by technology(MW-AC),Washington high case,2024-2043
400
350
Q 300
250 --
200
150
U 100
50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine � Micro Turbine — 2022
DNV — www.dnv.com Page 52

DNV
4.1.5.1 Washington PV adoption by sector
The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are
presented in the following charts. In the residential sector,the share of PV+ Battery capacity is about 4%of total residential
PV capacity in 2042. The share of PV+ Battery capacity is about 3%of total commercial PV capacity in 2042.The industrial
sector has a higher portion of its PV capacity in PV+ Battery configurations, at 8%of total capacity. In the irrigation sector,
the share of PV+ Battery capacity is between 2%and 4%, depending on the forecast scenario, of total irrigation PV capacity
in 2042.
Figure 4-33. Cumulative new PV capacity installed by sector across all scenarios,Washington,2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
250 120
200 100
Q 80
3� 150
> > 60
m in
100
�
40
U U
50 20
0 0
Industrial Irrigation
5 20
4 18
4 16
Q 3 Q 14
2i 12
3
> > 10
v 2
D 8
U 2 U 6
1 4
1 2
0 0
OHO O�� O�� O�� OHO O�� OHO O�� O�� OHO O'b OHO O0 Off`
DNV — www.dnv.com Page 53

DNV
4.1 .6 Wyoming
PacifiCorp's customers in Wyoming are projected to install about 75 MW of new distributed generation capacity or—10,450
new customers over the next two decades in the base case.The 20-year high projection is approximately 37%greater than
the base case and the low projection is 48% less than the base case, or 132 MW and 43 MW, respectively.
Wyoming currently offers no incentives for distributed generation technologies. The residential sector has the largest share
of the distributed generation capacity, ranging from 71% in the low case to 78% in the high case, and 79% in the base case.
The next largest share of the capacity is forecasted in the commercial sector, ranging from 21% in the high and base cases
to 28% in the low case.Wyoming's net metering policies were assumed to stay in place throughout the study, providing
more favorable economics for PV Only compared to PV+ Battery systems.
Figure 4-34. Cumulative new distributed generation capacity installed by scenario(MW-AC),Wyoming,2018-2043
All Technologies
140
120
U 100
Q
80
60
E 40
20
0
,o Cb�o°' o o N o o o,oA oo ), 0� N yo`ti�oeb� �y �� 0y31�0�y3°'� ao o
'y� r y r ytidy y y y3o o1 , g �
p 2022 Study —Historical —Low —Base —High
DNV — www.dnv.com Page 54

DNV
Figure 4-35. Cumulative new capacity installations by technology(MW-AC),Wyoming base case, 2024-2043
140 -
120
U
Q 100 —
2E 80
a�
60 -
40
U
20
I M gong
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine Micro Turbine - - 2022
Figure 4-36. Cumulative new capacity installations by technology(MW-AC),Wyoming low case, 2024-2043
140
120
U
Q 100
80
a�
60
40 --
U
20 ---
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine ram+ Micro Turbine — 2022
DNV — www.dnv.com Page 55

DNV
Figure 4-37. Cumulative new capacity installations by technology(MW-AC),Wyoming high case,2024-2043
140
120
U
Q 100
2i 80
a�
60 —
40
U
20
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
PV Only PV+Battery Wind ® Small Hydro
Reciprocating Engine Micro Turbine — 2022
DNV — www.dnv.com Page 56

DNV
4.1.6.1 Wyoming PV adoption by sector
The differences in PV capacity relative to the base case for the three modeled scenarios across the four sectors are
presented in the following charts. In the residential sector,the share of PV+ Battery capacity is between 19%and 23%of
total residential PV capacity in 2042, depending on the forecast scenario. The share of PV+ Battery capacity is about 6%of
total commercial PV capacity in 2042.The industrial sector has a lower portion of its PV capacity in PV+ Battery
configurations, at 5%of total capacity. The irrigation sector did not have any PV(PV Only or PV+ Battery)adoption
forecasted.
Figure 4-38. Cumulative New PV capacity installed by sector across all scenarios,Wyoming, 2024-2043
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
Residential Commercial
120 30
100 25
Q 80 Q 20
60 > 15
E 40 E 10
U U
20 5
0 0
�yo ,yo yo �yo ,yo �o ,yo ,yo ,yo ,yo �yo yo yo yo ,yo yo rp ,yo do yo yo ,yo
Industrial Irrigation
0.50 0.30
0.45
0.40 0.25
U 0.35 U
Q ¢ 0.20
0.30
> 0.25 > 0.154000
7s 0.20
�j 0.15 U 0.10
0.10 0.05
0.05
0.00 0.00
gyp, `LC° ti(b �° ;I- 3� "��° `�� �° �0' b� ,Lb `L(o ti� „�O "'`L 0b „��o �0 �O �� DR
,ti0 'O '0 rO 'O 'O 'o TO ,LO ,�O �O ,LO ,LO �O 4O f f f
DNV — www.dnv.com Page 57

DNV
5 APPENDIX
5.1 Technology assumptions and segment-level inputs
Appendix A.xlsx
5.2 Detailed results
Appendix B.xlsx
DNV — www.dnv.com Page 58

DNV
5.3 Behind-the-meter battery storage forecast
DNV prepared a behind-the-meter battery storage forecast as a part of the Long-Term Distributed Generation Resource
Assessment for PacifiCorp covering their service territories in Utah, Oregon, Idaho,Wyoming, California, and Washington to
support PacifiCorp's 2024 Integrated Resource Plan (IRP).This study evaluated the expected adoption of behind-the-meter
battery storage systems coupled with PV systems over a 20-year forecast horizon (2024-2043)for all customer sectors
(residential, commercial, industrial, and agricultural). Residential and non-residential battery energy storage systems(BESS)
can be installed as a standalone system, added to an existing PV system, or the system can be installed together with a new
PV system. DNV assumed all battery installations would be paired with a PV system in an AC-coupled configuration, as
standalone systems are ineligible for the federal ITC—explained further in section 3.1.6.
The adoption model DNV developed for this study is calibrated to the current16 installed and interconnected behind-the-
meter battery capacity that is paired with a PV system, shown in Figure 5-1.
Figure 5-1. Historic cumulative installed behind-the-meter battery storage capacity, PacifiCorp,2014-2024
Historic Cumulative Installed Battery Capacity by State Historic Cumulative Installed Battery Capacity
by Sector
70
Non-Residential
3%
60
50
40
30
E
U 20
10 Residential
slow 97%
0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
■CA ID ■OR ■UT WA ■WY
5.3.1 Study methodologies and approaches
DNV modelled two technologies in the behind-the-meter battery storage forecast:
1. PV+Battery: BESS product installed together with a new PV system,
2. Battery Retrofit: BESS product installed as an add-on to an existing PV system.
16 PacifiCorp distributed generation interconnection data as of April 2024.
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DNV
DNV used the same forecasting methodologies and approaches for the BTM battery storage forecast as the distributed
generation forecast. The methods used to develop the results of the forecast are described in detail in section 3.3 of the
report.
Data on battery system costs used in the BTM battery storage forecast is explained in detail in section 3.1.1.2 of the report.
That section includes current and projected future costs of battery storage systems used in the forecast for the different
sectors.The detailed assumptions for the system configurations, including system sizes, in each sector and state can be
found in Appendix A, section 5.1.
5.3.2 Battery dispatch modelling
DNV utilized its proprietary solar plus storage operational modeling tool—Lightsaber—to model battery dispatch. Battery
dispatch strategy dictates the flow of energy between the PV system, battery, and the grid.The battery dispatch model
includes strategies such as peak shaving, energy arbitrage, and manual dispatch. Self-consumption was modeled for all
sectors' BESS control strategy,which utilizes the battery by charging only from excess PV and discharging if PV production
falls below load. For residential customers,the dispatch model used energy arbitrage to reduce time-of-use charges.f'For
non-residential customers,the dispatch model used energy arbitrage to reduce demand charges and time-of-use charges,
where applicable.
5.3.3 Results
In the base case scenario, DNV estimates 407 MW of new BTM battery storage capacity will be installed in PacifiCorp's
service territory over the next twenty years(2024-2043)(Table 5-1). Figure 5-2 shows the relationship between the base
case and low and high case scenario forecasts,with the cumulative totals a summation of the existing -62 MW of installed
battery capacity and the forecasted 20-year adoption. The low-case scenario estimates 337 MW of new capacity over the
20-year forecast period—compared to the base case, retail rates increase at a slower rate, and technology costs decrease
at a slower rate. In the high case, retail rates increase at a faster rate, and technology costs decrease at a faster rate. The
twenty-year total new capacity forecasted in the high case is about 34%greater than the base case,while the low case is
24% less.
Table 5-1. Cumulative adopted battery storage capacity by 2043, by scenario
Cumulative capacity (2043 mw)
High 530
Base 407
Low 337
17 Modeling parameters include PacifiCorp's actual on-and off-peak ratios,which are relatively low when compared to other jurisdictions.
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DNV
Figure 5-2. Cumulative new battery storage capacity installed by scenario(MW), 2023-2042
600
500
U
Q 400
2
> 300
Co
E 200
U
100
0
2018 2022 2026 2030 2034 2038 2042
*w Range Base Historical
Figure 5-2 shows how the forecasts by customer sector and technology for each scenario. In all scenarios of the forecast,
the residential sector represents about 90%of the new battery storage capacity forecasted to be installed over the next
twenty years. The commercial, industrial, and irrigation sectors have been bundled into a single"Non-Residential"sector to
present the results in the report, as the capacity forecasts in the individual sectors are very small relative to the total
forecast. PV+ Battery systems represent the greatest share of the new battery capacity forecasted in the base and high
cases. Battery Retrofit systems representing a greater share of the new battery capacity forecasted in the low case indicate
that customers are more likely to adopt a PV Only system over a PV+ Battery system when technology costs are higher,
and electricity rates are lower.
5.3.4 Storage capacity results by state
As was the case in the distributed generation forecast, Utah represents the largest share of the battery capacity forecast. To
date,the majority of installed battery storage capacity and annual growth in storage capacity has been in Utah,which
represents the largest portion go PacifiCorp's customer population. Battery adoption is expected to continue to grow in Utah,
with the state's share of total new capacity reaching between 81% and 84%, depending on the scenario, over the next
twenty years. The net billing structure in place in Utah incentivizes PV+ Battery storage co-adoption more so than traditional
net metering, as customers can lower their electricity bills by charging their batteries with excess PV generation and
dispatching their batteries to meet on-site load during times of day when retail energy prices are high. Oregon represents the
second largest portion of the new capacity forecasted, between 8%and 10%. Net metering is the DER compensation
mechanism in place in Oregon, but customer economics are boosted by PV+ Battery incentives provided through the
Oregon Department of Energy."
180regon.Gov."Oregon Solar+Storage Rebate Program.".https://www.oregon.goy/energV/Incentives/Pages/Solar-Storage-Rebate-Prop ram.aspx
DNV — www.dnv.com Page 61

DNV
Figure 5-3. Cumulative new battery storage capacity installed by state (MW), 2024-2043, base case
500
400
300
M
E
�j 200
100
0
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
■CA • ID ■OR ■UT WA ■WY
Figure 5-4. Cumulative new battery storage capacity installed by state (MW), 2024-2043, low case
500
3: 400
a�
300
M
E
�j 200 --
100
0
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
■CA ID ■OR ■UT WA ■WY
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DNV
Figure 5-5. Cumulative new battery storage capacity installed by state (MW),2024-2043, high case
500
3: 400
a�
.' 300
�o
�j 200
100
0 =
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 203a 2039 2040 2041 2042 2043
■CA ID ■OR ■UT WA ■WY --
The following figures show the state-level forecasts in more detail. Background and commentary on the individual states'
results can be found in section 4.1 of the report.
California
Figure 5-6. Cumulative new battery storage capacity installed by scenario(MW), California, 2028-2043
3.0
2.5
U
Q 2.0
73
> 1.5
3 1.0
U
0.5
0.0
2018 2022 2026 2030 2034 2038 2042
Range Base Historical
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DNV
Figure 5-7. Cumulative new battery storage capacity installed by technology across all scenarios (MW), California,
2023-2042
Upper and lower bounds(in blue)represent the high and low case forecasts,with a line for the base case.
CA Residential PV+ Battery CA Residential Battery Retrofit
1.8 0.25 -
1.6
1.4 - 0.20
1.2
1.0 0.15 -
Y '
R
0.8
E E 0.10
�j 0.6 v
0.4 - - -
0.05
0.2
ti6P tiQP ti60 tiQP Le tiQ;P 2���ti��1 ti�Ip R� �p`L3,Lp`L�',LQ`bI �p`L°' LQ` ,,Lp`33�p3�,Lp`3l �p �pb1
CA Non-Residential PV+ Battery CA Non-Residential Battery Retrofit
1.0 0.30 -
0.9
� 0.8 . 3: 0.25 - -
1
> 0. S
0.20
2 0.6 - m
v0.5 E 0.15 -
0.4 v
0.3 0.10 -
0.2
0.1 - 0.05
b9
DNV- www.dnv.com Page 64

DNV
Idaho
Figure 5-8. Cumulative new battery storage capacity installed by scenario(MW), Idaho, 2018-2043
30
25
U
Q 20
15
10
U
5
0
2018 2022 2026 2030 2034 2038 2042
�Range —Base Historical
DNV — www.dnv.com Page 65

DNV
Figure 5-9. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Idaho, 2023-
2042
Upper and lower bounds(in blue)represent the high and low case forecasts,with a line for the base case.
ID Residential PV+ Battery ID Residential Battery Retrofit
9 1.0
7 0.8
6 0.7
-
0.6
5
0.5 —
4
E E 0.4 -
V 3
v 0.3
2
0.2
1 - -
0.1
,Lp`1.3,Lp`L5,Lp`L� '1p`L°�,Lp�,Lp33,Lp35 2�3� ,Lpb°',Lpp,'`
ID Non-Residential PV+ Battery ID Non-Residential Battery Retrofit
1.8 — 0.050
1.6 - 0.045
1.4 3:0.040
1 2 - >0.035
`0 1.0 °0.030 —
ci 0.8 0.025
U
0.6 0.020
0.015
0.4
0.010
0.2 -
0.005
5 0`L'1 9 3 5 1 9
ti0`L ti ti0`L `LOB •1,0� ti0� �03 ti0� ti0�
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DNV
Oregon
Figure 5-10. Cumulative new battery storage capacity installed by scenario(MW), Oregon,2018-2043
450
400
350
U
Q 300
I a�
250
>
200 �-
D 150
U
100
50
0
2018 2022 2026 2030 2034 2038 2042
Range —Base Historical
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DNV
Figure 5-11. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Oregon,
2023-2042
Upper and lower bounds(in blue)represent the high and low case forecasts,with a line for the base case.
OR Residential PV+ Battery OR Residential Battery Retrofit
18 4.5
16 4.0
14 3.5
12 3.0
> 10 >_ 2.5
M y
l9
2.0
ci 6 ci 1.5
4 1.0
2 0.5
`LOi3`L `L `LO`Lg`L03� L03�20 'V 'L03�'V Q`fl QP 60 Q`V' Q` ' 033 625 p31 ZIP pNII
`1. 2 2 `L `L 'L
OR Non-Residential PV+Battery OR Non-Residential Battery Retrofit
3.5 3.0
3.0 2.5
3
2.5 -
.Z >_ 2.0 —
� Y
2.0
3 3 1.5
v 1.5 t)
1.0 1.0
loo,
0.5 0.5
2zq"b Lzp`bZp 2�`L°'`L��1 "b "b 2 A
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DNV
Utah
Figure 5-12. Cumulative new battery storage capacity installed by scenario(MW), Utah,2018-2043
450
400
350
U
Q 300
I a�
250
>
200 �-
D 150
U
100
50
0
2018 2022 2026 2030 2034 2038 2042
Range —Base Historical
DNV — www.dnv.com Page 69

DNV
Figure 5-13. Cumulative new battery storage capacity installed by technology across all scenarios (MW), Utah,
2023-2042
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
UT Residential PV+Battery UT Residential Battery Retrofit
140 - 90
120 80
70
100 - 60 —
m80
> > 50
m �
60 5 40
E E
U 40 _ �j 30
20
20
10
�031 �039�OP ,L(9L1,L41b,Lp91 ,L41,Lp'S'�,L6P 2p`i5,Lp�1 2pIp,LppN�
UT Non-Residential PV+ Battery UT Non-Residential Battery Retrofit
7 — 8
6 7
m 5 — —
6
> >
a 5 —
4 — R
E '
E 4 —
t1 3 V
3
2
2 -
1
1
DNV — www.dnv.com Page 70

DNV
Washington
Figure 5-14. Cumulative new battery storage capacity installed by scenario(MW),Washington,2018-2043
8
7
U 6
Q
5
4
M
E 3
U 2
1
0
2018 2022 2026 2030 2034 2038 2042
Range —Base Historical
DNV— www.dnv.com Page 71

DNV
Figure 5-15. Cumulative new battery storage capacity installed by technology across all scenarios (MW),
Washington,2023-2042
Upper and lower bounds (in blue)represent the high and low case forecasts, with a line for the base case.
WA Residential PV+ Battery WA Residential Battery Retrofit
2.0 - 1.2
1.8
1.6
1.0
2 1.4 0.8 -
1.2
1.0 - 0.6 —
0.8 B
U
3
0.6 V 0.4
0.4
0
0.2
.2
`LO`I3 20`1�`LO`�� LO`L9`L03� L03�20`'�`L03� L03�20�� p`L`3 p`15 621
WA Non-Residential PV+ Battery WA Non-Residential Battery Retrofit
1.2 — 0.25
�
1.0 30.20
0.8 - >
R 0.15 —
0 0.6 E
L) 3
0.4 — V 0.10
0.2 0.05
bb ti 2�'b9 2 b�1 3 5 1 9 3 5 1 0
TO`i' `LO`L ti0`l
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DNV
Wyoming
Figure 5-16. Cumulative new battery storage capacity installed by scenario(MW),Wyoming,2018-2043
20
18
16
Q 14
12
10
5 8
E
U 6
4
2
0
2018 2022 2026 2030 2034 2038 2042
Range —Base Historical
DNV — www.dnv.com Page 73

DNV
Figure 5-17. Cumulative new battery storage capacity installed by technology across all scenarios (MW),Wyoming,
2023-2042
Upper and lower bounds(in blue)represent the high and low case forecasts, with a line for the base case.
WY Residential PV+ Battery WY Residential Battery Retrofit
6 0.040 —
0.035
5
0.030
4 - 0.025
R 3 0.020
E 2 E 0.015 —
U
0.010
1
0.005
`L9��`LOO'�`LO`1� `LOO'g 29�129��`LO��29�� ti9�9 ti9�1 p`L3 p`L6 p`L'1 p`L9 p`3� �`33 p3� p`3'1 p`39 pp,�
WY Non-Residential PV+ Battery WY Non-Residential Battery Retrofit
0.9 0.020
0.8 — 0.018
0.7 0.016
0.6 0.014
0.5 — 2 0.012
c'i 0.4 E 0.010 —
U
0.3 0.008
0.2 0.006
0.1 0.004
0.002
3 h '1 9 � 3 5 1 9 �
`LO`L `LO`L ti0� ti0`L `LOB 'P 20� �03 'P 2�A
DNV — www.dnv.com Page 74

DNV
About DNV
DNV is a global quality assurance and risk management company. Driven by our purpose of safeguarding life, property and
the environment,we enable our customers to advance the safety and sustainability of their business. We provide
classification, technical assurance, software and independent expert advisory services to the maritime, oil &gas, power and
renewables industries. We also provide certification, supply chain and data management services to customers across a
wide range of industries. Operating in more than 100 countries, our experts are dedicated to helping customers make the
world safer, smarter and greener.

DNV

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK
APPENDIX M - STAKEHOLDER FEEDBACK
As of December 2024, stakeholder have submitted 46 stakeholder feedback forms, summarized
below. PacifiCorp has responded to 40 of these submissions with public postings to the IRP
website and six additional forms have been mailed. The stakeholder feedback forms have allowed
the company to review and summarize issues by topic as well as identify specific recommendations
that were provided. Information collected is used to inform the 2025 IRP development process,
including feedback related to process improvements and input assumptions, as well as responding
directly to stakeholder questions.
Footnote references to stakeholder feedback are also included in the chapters and appendices of
the 2025 IRP where relevant.
Stakeholder Feedback Form Summary
The table below summarizes the publicly available forms and PacifiCorp responses.
Table CA —Stakeholder Feedback Form Summary
SIFF# Request'topic PacifiCorp Reply Reference
2025.001 Peter Gross(1/11/24) Nuclear power PacifiCorp is managing risks to ensure that any nuclear resource must bring
value to customers. Chapter 7
2025.003 OPUC(5/7/24) Modeling inputs and scenarios Anticipated inputs and assumptions listed in slide 34 of 1/25/24 PIM;inputs
discussed throughout the PIM series. Appendix C
2025.004 PRBRC(5/6/24) TerraPower agreement Natrium demonstration project will be updated in 2025 IRP. Chapter 10
2025.005 PRBRC(5/6/24) Bridger Units 3&4 2023 IRP Assumptions will be refreshed in 2025 IRP.
date errata request Chapter 8
2025.006 Renewable NW(5/3/24) Distributed generation study DNV/PacifiCorp working to improve modeling approach on an ongoing
basis. Chapter 6
2025.007 Renewable NW(5/3/24) Renewable resource cost PacifiCorp will seek feedback on cost structure/forecasting as part of the
estimates 2025 public input process;modeling best available information. Chapter 7
2025.008 WRA(5/6/24) IRP Updates Updates required in OR and filed in other jurisdictions as informational Appendix B
2025.009 RNW(5/2/24) PLEXOS settings Optimirnization modeling and details of the PLEXOS modeling process
provided in 1/25/24 and 3/14/24 PIMs. Chapter 8
2025.010 UCARE(6/3/24) Utah legislative sensitivity case Legislative impacts and proposed sensitivities discussed in August and
September PlMs. Appendix M
Chmate modeling thermal State policy updates discussed in August,no changes to water use and
2025.011 UEC(6/10/24) resources options,water management,broad range ofgeothemmal cost scenarios being considered. Appendix G;
resources Chapter 10
2025.012 UAE(6/24/24) Errors in 2023 IRP Chapter 6 Acknowledgement of errors and where to view Excel files far tables.
tables Chapter 6
2023 IRP Update assumptions locked before SB-224 passed;legislative
2025.013 Emma,Verhannne(6/24/24) Coal retirement in UT impacts and proposed sensitivites for the 2025 IRP to be discussed in
August and September PIMs. Chapter 3
2025.014 Joan Entwistle(4/23/24) 2023 IRP Update drivers Discussion of inputs and assumptions to continue through 2025 IRP PlMs. Chapter 8;
Chapter 10
Methane and gas energy Scenarios included a CO2 price and the social cost of greenhouse gases.
2025.015 Sierra Club(4/29/24) sources PLEXOS endogenously determined coal retirement dates and new
renewable resources. Chapter 8
Compliance with EPA PacifiCorp will complete holistic modeling for EPAs GHG Rule,including
2025.016 PRBRC(4/30/24) greenhouse gas emissions rules compliance scenarios,descriptions,charts,and details as part of the 2025 Chapter 3
Distributed generation study, Chapter 6;
2025.017 OPEC(7/3/24) transmission modeling, Responses provided to each detailed question by subject. Chapter 7;
recommendations from analysis Chapter 8;
of 2023 IRP Update Chapter 10
189

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK
Table C.1 —Stakeholder Feedback Form Summary(continued)
SFF# Request Topic PacifiCorp Reply Reference
Wildfire risk,regional and Wildfire-related costs are part of the SCGHG scenario.Regional and
2025.018 OCA(7/19/24) interregional transmission plans are developed through the NorthernGrid Chapter 5;
interregional transmission
regional planning process. Chapter 8
Chehalis natural gas plant and
2025.019 OCA(7/19/24) WA Climate Commitment Act PacifiCorp considers the cost and dispatch impacts of the WA CCA cap-
cap-and-invest program, and-invest program
modeling scenarios Chapter 8
2025.021 FPA(7/9/24) Configuration details far Table ofPLEXOS Production Settings provided.
PLEXOS mode' exercises Chapter 8
2025.022 SLC(7/29/24) PLEXOS model variant The IRP is based on proxy resource costs and related assumptions that are
generic and intended to be broadly applicable. Chapter 8
2025.023 NPE(8/9/24) Non-enrittnng peakers- Responses provided to each request.
Hydrogen fuel availability Cha ter 7
2025.024 NPE(8/9/24) Candidate resource costs Resource cost adjustments explained. Chapter 7
2025.025 NPE 8/9/24 Carbon capture storage Descitpion of FEED study role;CCS assumptions and status. Chapter 7
Distributed generation study,
2025.026 VSO(8/9/24) Please see responses to individual questions in the form
sensitivities Chapter 6
2025.027 VSO(8/9/24) Tax Credits Modeling accounts for tax credits and bookend sensitivities will cover
unknown magnitudes outside of PacifiCorp control Chapter 8
PLEXOS modeling and
2025.028 UCARE(8/30/24) differential coal quality cost Modeling accounts for coal costs on a BTU-adjusted basis.
iniliacts Chapter 8
2025.029 UCE(8/9/24) Modeling coal costs and risks in Description of coal reporting,supply assumptions,and risks.
2025 IRP process Chapter 8
Proposed RMP rate increase in The IRP process selects the least-cost,least-risk portfolio under given
2025.30 Katie Pappas(8/13/24) Utah conditions.Renewable energy is expected to make up an increasing
proportion of energy generated by the PacifiCorp system over time. Chapter 8
The IRP process selects the least-cost,least-risk portfolio under given
2025.031 Jane Myers(8/13/24) Utah rate increase conditions.Renewable energy is expected to make up an increasing
proportion of energy generated by the PacifiCorp system over time. Chapter 8
PacifiCorp is committed to achieving emissions reduction targets as required
by state and federal regulatory obligations and welcomes the development of
2025.032 Sara Kenney(8/14/24) Carbon Dioxide Emissions alternative fuel sources that can provide a sinvlar level of system flexibility as
traditional thermal resources at reduced emissions rates. Chapter 8
2025.035 WEA(8/20/24) 'Business as Usual"reference Defined and clarified the case requirement from Utah investigative order. Chapter 8
case
Numerous topics including
DSM,granularity,Energy Each topic addressed in terms of 2025 IRP modling,reporting and access to
2025.036 SC(8/27/24) Infrastructure Reinvestment, materials.
Federal legislation,resource
availability Chapter 8
2025.037 UCARE 8/30/24 Utah state legislative actions Will be addressed in the September 25-26 public input meeting. Chapter 3
2025.039 WRA(9/9/24) hnformation and market variant Further information about the origri of the Wyoming market treatment and
request WRAP. Chapter 8
2025.040 RNW 9/11/24 IRP transmission planning Please see responses to individualquestions in the form Chapter 8
2025.041 Nathan Strain(9/20/24) Nuclear&geothermal Sensitivity studies planned for nuclear and geothermal costs.
development in Utah Chapter 7
2025.042 FPA 9/23/24 Request for LT plan settings Not available;to be provided with the work a ers in the IRP filing Chapter 8
2025.044 SC(9/28/24) CC modeling constraint Please see responses to individual questions in the form Chapter 8
2025.045 UCE(11/7/24) Conservation potential Latest UT code plus amendments being used in CPA.
assessment modeling Chapter 7
Requests energy efficiency& Not included in
2025.046 UCE(11/7/24) demand response data from Please see responses to individual question in the form the Draft 2025
past filings IRP;refers to
2023 IRP and
2023 IRP Update
190

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK
Requested Additional Studies
Stakeholder feedback forms provided approximately 45 requests for data and modeling changes
or considerations in the 2025 IRP development cycle. These requests fell into three broad
categories:
1. Requests for data inputs or modeling work that was already planned or required
2. Requests to add detailed legislation, technologies or special interests to base inputs and
assumptions for all studies
3. Requests for additional cases studies, either variants or sensitivities
There were seven request in the third category, seeking additional studies. A review of these
requests indicated synergies with cases already slated for analysis(such as a low cost of renewables
study and a high use of IRA/IIJA funding). Advances in post-model reporting have increased the
amount of information available from every study, making some additional studies unnecessary.
The seven specifically requested cases are summarized below.
I. Utah Legislative Sensitivity Case (SFF #10, Utah Citizens Advocating Renewable
Energy): The 2025 IRP includes several cases that would help inform what a portfolio may
look like if new resources and transmission are required for Utah as a consequence of
legislative activity, specifically the Low Cost Renewables and No Coal 2032 studies.
2. Customer Choice Variant(SFF#22, Salt Lake City Corp): This request proposed a variant
based on amounts of potential resource availability in an earlier timeframe than currently
allowed in IRP modeling. The additional resources would be associated with programs
and tariffs that could bring resources into commercial operation prior to 2028. PacifiCorp
does not foreclose the opportunity for such projects;however,the Integrated Resource Plan
(IRP) is based on proxy resource costs and related assumptions that are generic and
intended to be broadly applicable.
3. Cluster Transmission Cost Reduction Variant(SFF #36, Sierra Club): This is a scenario in
which transmission network upgrade costs in Cluster Areas 1, 2, 4, 12, and 14 are reduced
by 30 percent. This narrowly defined scenario is better considered under the umbrella of a
studies with broader application, such as the Low Cost Renewables case,which has the net
effect of reducing the cost of resource-plus-transmission on an aggrgeate basis, driving a
similar outcome.
4. EIR Financing Variant(SFF #36, Sierra Club): This requested variant is represented by the
Low Cost Renewables case.
5. Hunter/Huntington SCR Variant(SFF#36, Sierra Club): This variant would implement SCR
or SNCR at all five Hunter and Huntington Units. Emissions reductions from these
technologies are available in practice, and the effective cost per ton of potential emissions
reductions from installation of SNCR or SCR can be calculated from the model results.
Because both SNCR and SCR technology have little impact on resource operating parameters
such as heat rate and maximum output,there would be little impact on system dispatch from
including those options in the model. Note that CCS installation are assumed to include SCR
technology.
191

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK
6. Wyoming Market Removal Variant(SFF#39, Western Resource Advocates): Assumes there
is no access to the presumed Wyoming market. This study request will be addressed by the
study limiting access to all markets.Note also that in the 2025 IRP it is assumed that there is
no market availability during peak hours.
7. Declining Market Availability Variant(SFF#39,Western Resource Advocates): Assumes
there is no access to the presumed Wyoming market, and market access declines to 25% of
current assumption over 5 years. This study request will be addressed by the study limiting
access to all markets.
Published Stakeholder Feedback Forms
The pages below include all of the publicly available feedback forms received by PacifiCorp in
the 2025 IRP cycle at the time of this writing. Feedback forms and PacifiCorp's responses can also
be found via the following link:
https://www.pacificop2.com/energy/integrated-resource-plan/comments.html
192

PacifiCorp - Stakeholder Feedback Form (ool)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-01-11
*Name: Peter Gross Title:
*E-mail: [e-mail] Phone:
*Organization: Customer of RMP
Address: 643 Dragonfly TRL
City: Moab State: UT Zip: 84532
Public Meeting Date comments address: ❑ Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Nuclear power
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Frankly, I was astonished to read that Rocky Mountain Power is contemplating replacing
coal plants in Emery County with small nuclear reactors reactors. The nuclear industry
has a half century history of massive cost overruns and multi-year construction delays of
its own making. The nuclear industry has tried to reinvent itself for at least a quarter
century. All four of the only nuclear reactor construction starts in the U.S. this
century fell a decade behind schedule and suffered multi-billions in cost overruns.
Virgil C Summer Units 2 and 3 were simply abandoned. The nuclear industry gravitated to
larger capacity reactors from the outset for economic reasons. This is not unique to the
United States. Flamanville Unit 3 in France and Olkiluouto Unit 3 in Finland have both
come in triple to quadruple the already expensive original cost estimates while falling
at least a decade behind schedule. So called SMRs remain unproven with a dubious future.
Meanwhile, wind and especially solar costs continue to plummet. I urge RMP not to gamble
on the nuclear folly and follow through with its wind and solar plans.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list
those attachment names here.
https://www.energymonitor.ai/power/weekly-data-renewables-overtake-nuclear-in-global-
electricity-mix/?cf-view https://www.colorado.edu/cas/2022/04/12/even-china-cannot-
rescue-nuclear-power-its-
woes#:-:text=Thiso20decline%20is%20a%20result%20of%20nuclear%20power%E2%80%99s,electric%2
Ogrid%E2%80%94and%20they%20cost%20a%201ot%20to%20operate.
https://en.wikipedia.org/wiki/List of canceled nuclear reactors in the United States#Canc
elled nuclear reactors
* Required fields

https://en.wikipedia.org/wiki/Flamanville Nuclear Power Plant#Unit 3
https://en.wikipedia.org/wiki/Olkiluoto Nuclear Power Plant#Unit 3
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp Response 1/22/24:
Thank you for participating in the PacifiCorp 2025 IRP stakeholder process.Nuclear resources considered in the 2023
IRP have been intentionally limited to years outside of the action plan window with the understanding that while nuclear
is an existing fuel technology,the Natrium project has a long lead time that requires continued evaluation of its potential.
Ongoing negotiations are commercially sensitive, and any future contracts will be structured to minimize risks and costs
for PacifiCorp's customers.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (003)
2025 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2025 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 5-0 7
*Name: Will Mulhern Title:
*E-mail: [e-mail] Phone: (503) 385 - 3294
*Organization: Oregon Public Utility Commission
Address:
City: State: Zip:
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting: JP Batmale, Sudeshna Pal, Kim Herb, Abe
Abdallah, Isaac Kort-Meade
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Modeling inputs and scenarios
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Can PacifiCorp list at the next public input meeting the exact list of inputs and
scenarios that it plans to lock down in September? Can this list be released before the
next public input meeting to support discussion? At which public input meeting will
stakeholders have the chance to provide input on which scenarios will be used?
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
OPUC Staff recommends PAC specifically outline the inputs and scenarios it will be
locking down in its modeling in September, provide these to stakeholders in advance of a
public input meeting, and allow for discussion of these inputs and scenarios at a public
input meeting.
PacifiCorp Response 5/7/2024:
For a list of anticipated inputs and assumptions to be discussed at future public input meetings,please refer to slide thirty-
four from PacifiCorp's first 2025 IRP Public Input Meeting on January 25,2024. The Company is rearranging the
cadence of upcoming public input meetings to adapt to the January draft IRP requirement, and a revised schedule of topics
will be presented at the next meeting to be held June 26-27,2024. The agenda is intended to cover all data and
assumptions development and methodologies, all of which is intended to be locked in September. The Company is also
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adding an additional public input meeting in July to aoccomodate materials to be covered. The added meeting will be
announced in the upcoming invitation to the June meeting.
The Company looks forward to your participation at upcoming meetings.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (004)
2025 Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the 2025 IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain
open communication and provide the broader Stakeholder community with useful information,the Company will generally
post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2024-05-06
*Name: Shannon Anderson Title:
*E-mail: [e-mail] Phone:
*Organization: Powder River Basin Resource Council
Address: 934 N. Main St.
City: Sheridan State: WY Zip: 82801
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ® Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
2023 IRP Update
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP
website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the May 2, 2024 IRP meeting, PacifiCorp representatives stated that there is an "oral
agreement" in place with TerraPower such that PacifiCorp customers will not be charged
any costs related to the Natrium nuclear power plant. Please explain why the company
feels an "oral agreement" is sufficient for this purpose and explain the details of such
agreement - who made it? when was it made? was it further represented by any writing or
more formal conditions or agreements between the parties? Please also explain what
"costs" were included in the agreement - construction costs? initial fuel costs? testing
and analysis costs? regulatory costs? or does it also include operating and maintenance
costs once the Natrium plant is operational and serving customers? Please also explain if
it is PacifiCorp's understanding that the Natrium nuclear power plant will serve
PacifiCorp customers exclusively as is represented in the 2023 IRP and previous IRPs or
whether TerraPower plans to operate it as a merchant plant that sells power to PacifiCorp
but not exclusively? Please see the Inside Climate News Story linked below that says the
power will serve California - is that statement made simply because of the EIM or because
TerraPower plans to sell directly to customers in California?
Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e.gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
https://insideclimatenews.org/news/04052024/wyoming-terrapower-nuclear-plant/
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
* Required fields

PacifiCorp should identify new/amended action items for the 2025 IRP Action Plan to
ensure protection of ratepayers from unjust costs and expenses associated with the
Natrium Nuclear Power Plant.
PacifiCorp Response 5/8/2024:
From the onset, PacifiCorp's engagement with TerraPower has been based on the understanding that Natrium
demonstration project must be cost effective for our customers. This was emphasized in a June 2021 news
release, which is available here: TerraPower,Wig Governor and PacifiCorp announce efforts to advance nuclear
technology ice, omg
In this new release,then president and CEO of Rocky Mountain Power, Mr. Gary Hoogeveen is quoted:
"We are currently conducting joint due diligence to ensure this opportunity is cost-effective for our customers
(emphasis added) and a great fit for Wyoming and the communities we serve."
Despite the inclusion of the Natrium demonstration project in the preferred portfolio, PacifiCorp, as of now, has not
entered into any binding contractual agreements with TerraPower concerning the Natrium Project. The Natrium project
has a long lead time that requires continued evaluation of its potential. Ongoing negotiations are commercially sensitive,
and any future contracts will be structured to minimize risks and costs for PacifiCorp's customers, based on the specific
costs and operational details of a potentially binding agreement, once one is available for consideration.PacifiCorp is
not aware of any plans for TerraPower to sell output from the Natrium to customers in California.
The 2025 IRP Action Plan related to the Natrium demonstration project will be updated accordingly.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (005)
2025 Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the 2025 IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain
open communication and provide the broader Stakeholder community with useful information,the Company will generally
post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2024-05-06
*Name: Shannon Anderson Title:
*E-mail: [e-mail] Phone:
*Organization: Powder River Basin Resource Council
Address: 934 N. Main St.
City: Sheridan State: WY Zip: 82801
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ® Check here if not related to specific meeting
List additional organization attendees at cited meeting: Shannon Anderson
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
2023 IRP Update
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP
website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the May 2, 2024 PIM it was stated by PacifiCorp representatives that the preferred
portfolio selection of carbon capture at Bridger Units 3&4 is unachievable. As such, we
request PacifiCorp to issue an errata document to the 2023 IRP Update that explains this
error to regulators, stakeholders, and the power plant community. Please also explain how
these incorrect results are being addressed within the scope of the 2025 IRP for load and
resource balance assumptions.
Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e.gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
See above. We request an errata be issued related to Bridger 3&4. Thank you.
PacifiCorp Response (5/16/24):
A change in assumptions regarding the timing of implementation of carbon capture on Jim Bridger 3 & 4
occurred after the results of the 2023 integrated resource plan update were produced. It is not practical to issue
an errata for model assumptions that change after an IRP or an update is completed. As is the case with all
assumptions, assumptions related to carbon capture at Bridger Units 3 and 4 will be refreshed for the 2025 IRP.
* Required fields

Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (006)
2023 Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the 2023 IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain
open communication and provide the broader Stakeholder community with useful information,the Company will generally
post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 5-0 3
*Name: Katie Chamberlain Title:
*E-mail: [e-mail] Phone:
*Organization: Renewable Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ® Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Distributed Generation Study
Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP
website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the May 2 public input meeting, PacifiCorp and its consultant DNV discussed the
methodology and assumptions behind the distributed generation (DG) study. The goal of the
study is to estimate the market potential for DG resources by customer segment and by
state across the 20-year planning horizon. The study uses three different scenarios: a
base case, a low adoption scenario, and a high adoption scenario. It\u0019s important
that the forecast is as accurate as possible given that the results will inform the 2025
IRP. Meeting participants also discussed the need to ensure that the low, base, and high
DG adoption scenarios actually presented different possible futures, and PacifiCorp
reiterated that the high case should result in materially higher adoption rates than the
base case. It is unclear if the current assumptions will have that effect. RNW is
following up on a few of the questions we posed in the meeting to better understand some
of the assumptions behind the study. Why did DNV/PacifiCorp choose to use the average
of the \u0018conservative\u0019 and \u0018moderate\u0019 NREL ATB cost forecasts for the
base DG adoption case? NREL\u0019s \u0018moderate\u0019 forecast is the expected level of
technology innovation, which could be a more appropriate assumption for the base case.
The DNV consultant suggested that he could connect with PacifiCorp to provide
documentation on the selection of these cases, which we would appreciate. Why did
DNV/PacifiCorp choose to use the \u0018moderate\u0019 NREL ATB cost forecast for the high
DG adoption case? It may be more appropriate to use NREL\u0019s \u0018advanced\u0019
forecast for this scenario to sufficiently capture expected adoption levels if technology
costs decline more rapidly. As above, we would appreciate any further reasoning or
documentation on the selection of this cost forecast. Why did DNV/PacifiCorp use the base
case assumption (\u001Capplicable state and federal incentives based on current
legislation\u001D) for the high DG adoption scenario, instead of assuming a higher level
of incentives or an extension of existing incentives?
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Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e.gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
PacifiCorp Response(5/23/24):
Thank you for your comments and feedback on the Distributed Generation(DG) Study. PacifiCorp agrees that it is
important to develop the most accurate forecast for the 2025 IRP ensuring that variables informing DG adoption are
accurately represented in our modeling. To the extent practical,DNV/PacifiCorp is working to improve modeling by
incorporating the most recent adoption data, export rates, and relevant stakeholder feedback into base, low, and high cases
in the modeling approach. Additionally, during the upcoming June 26-27th public input meeting we will share the study's
specific assumptions for each case based on feedback from stakeholders. PacifiCorp responds as follows to the questions
raised by RNW:
• Stakeholder Question 1: RNW is following up on a few of the questions we posed in the meeting to better
understand some of the assumptions behind the study. Why did DNV/PacifiCorp choose to use the average of
the conservative and moderate NREL ATB cost forecasts for the base DG adoption case?
• Response 1: DNV reviewed the cost forecasts in the NREL ATB data and found that the moderate cost decline
forecast for solar PV was more aggressive than DNV's internal national cost models and what the market has
experienced historically(-10 years). Recent cost increases or a general leveling of cost declines also adds to this
assumption. The technology cost forecast used in the DG study base case has a—35%price decrease through
2035, as opposed to the—50%decrease forecasted in the NREL moderate case.
• Question 2: Why did DNV/PacifiCorp choose to use the NREL ATB cost forecast for the high DG adoption
case?
• Response 2: DNV/PacifiCorp used the moderate NREL ATB cost forecast for the high scenario to maintain
consistency with the other scenarios. The high scenario in this study is more focused on other market factors that
could stimulate market growth and adoption,which are contained in the model's adoption parameters. These
factors are changed in the high scenario to reduce market barriers over time and simulate the effects of a wide
array of factors,which could also include components of technology cost. Moving forward,DNV and PacifiCorp
will evaluate whether to incorporate a more aggressive NREL ATB cost forecast to inform the high scenario;this
may be represented by using either advanced ATB cost forecast or a blend of the advanced and moderate ATB
cost forecasts.
• Question 3: Why did DNV/PacifiCorp use the base case assumption(state and federal incentives based on
current legislation)for the high DG adoption scenario, instead of assuming a higher level of incentives or an
extension of existing incentives?
• Response 3: PacifiCorp elected to the use the base case assumption for federal and state tax incentives for all
scenarios as these assumptions are not easily predictable and challenging to develop trends around. Therefore,the
company believes it is more appropriate to look at other variables to inform the high and low case as these
variables seem more likely to change in the near-term.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

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PacifiCorp - Stakeholder Feedback Form (007)
2025 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2025 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 5-0 3
*Name: Katie Chamberlain Title:
*E-mail: [e-mail] Phone:
*Organization: Renewable Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Renewable resource cost estimates
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
In our comments on PacifiCorp\u0019s 2023 IRP, RNW identified that PacifiCorp\u0019s
overnight capital cost forecast for renewable resources is substantially higher than
forecasts used by PGE and the CPUC. PacifiCorp used cost assumptions developed by WSP,
which were primarily informed by the NREL ATB, and then made adjustments based on the
Company\u0019s experience. In reply comments, PacifiCorp explained that: \u001Cthe cost
forecasts in WSP\u0019s report were developed before PacifiCorp witnessed the impact of
recent tighter trade tariffs and inflation on the utility scale market. Upon observing
those impacts PacifiCorp adjusted the cost forecasts to reflect what was observed in the
market in 2022.\u001D Pacificorp used the same renewable resource cost estimates in the
2023 IRP Update, despite OPUC Staff and multiple parties expressing skepticism about
their accuracy and requesting further explanation as to how PacifiCorp arrived at these
estimates. RNW requests that PacifiCorp explain in greater detail why they made
modifications to WSP\u0019s cost forecast and provide documentation of these changes.
Specifically, RNW would like to understand how PacifiCorp observed changes in the market
in 2022 and the methodology the Company used to increase the renewable resource cost
forecast. 1. PacifiCorp states that they adjusted WSP cost forecast to reflect what was
observed in the market in 2022.In particular, PacifiCorp witnessed the impact of recent
tighter trade tariffs and inflation on the utility scale market. Can the Company explain
how they witnessed and observed these changes in the market? 2. Are PacifiCorp renewable
resource cost estimates based on bids the Company received in recent RFPs? If so, please
provide documentation demonstrating higher average bid prices, the year in which those
bids were received, and how those prices translate to the higher overnight capital costs
reflected in PacifiCorp IRP. Please note that we are not requesting individual bid
prices, which are confidential; instead, we are requesting averages. 3. If the renewable
resource cost estimates were not based on RFP bids, please provide the underlying
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quantitative information that justifies the increased renewable resource cost estimates.
4. How does PacifiCorp plan to forecast renewable resource costs for the 2025 IRP?
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
PacifiCorp Response 5/23/24:
Please note that the 2023 IRP and 2023 Update supply-side resource table does not present overnight cost but
rather in-service cost for each resource. Please refer to the 2023 IRP Volume I, Chapter 7, and specifically Table
7.3 on page 189.The values presented include direct costs (equipment, buildings, installation/overnight
construction, commissioning, contractor fees/profit and contingency), owner's costs (land, water rights,
permitting, rights-of-way, design engineering, spare parts, project management, legal/financial support, grid
interconnection costs, owner's contingency), and financial costs (allowance for funds used during construction
(AFUDC), capital surcharge, property taxes and escalation during construction, if applicable).
Consequently, any comparison of third-party costs characterized as overnight costs will be lower than our in-
service costs, which reflect the cost to our customers and not just the development costs.
Moreover, escalation is often another area where misaligned comparisons are made. Many third-party public
sources present their costs in real terms and routinely are silent on escalation. We also present our in-service
costs in real dollars, but also present and include nominal escalation forecasts. To ensure an apples to apples
comparison is being made, both sets of data need to be adjusted for inflation to arrive at figures presented in
the same year dollars for any given year that a comparison is being made.
1. Yes.Adjustments to the WSP and NREL cost forecast were grounded in actual project costs the company
received.These initial adjustments were made to years when the company had actual cost data of real, proposed
projects. Rather than drop immediately to the NREL/WSP pricing in later years,the costs were de-escalated over
time to correspond to NREL starting in 2029 and converging with NREL in 2032. Please reference figure 5.3 in the
2023 IRP Update to see this escalation and de-escalation visually.
2. Generally,yes. PacifiCorp is preparing a slide on this topic for a future public input meeting which will cover the
range of prices at which renewable resources are available in both the near and longer term.
3. N/A
4. As part of the conversation referenced in response to question 2, and as in past IRP public meetings, PacifiCorp
will seek feedback on cost structures/forecasting and will be finalizing that plan as part of the 2025 IRP public
input process.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (008)
2025 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2025 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 5-0 2
*Name: Nancy Kelly Title:
*E-mail: [e-mail] Phone: (208) 704 - 0488
*Organization: Western Resource Advocates
Address: 307 W. 200 S. Suite 200
City: Salt Lake City State: UT Zip: 84101
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ®Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
IRP updates
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please identify which states require an IRP update. Provide the docket number and date
of the order requiring the update, or if a state has planning rules, the rule and its
requirement.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
PacifiCorp Response(5/16/24):
Oregon Administrative Rule 860-027-0400(8)provides, in part,that"Each energy utility must provide an annual update
on its most recently acknowledged IRP. The update must be submitted on or before the acknowledgment order
anniversary date."PacifiCorp's IRP Update, submitted on April 1,2024, in Oregon Public Utility Commission Docket
No. LC 82,was filed in compliance with Oregon Administrative Rule 860-027-0400. PacifiCorp also submitted its IRP
Update in other jurisdictions as an informational filing.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (oog)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2024-05-02
*Name: Jim Himelic Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Renewables Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
PLEXOS Settings
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Renewable Northwest is requesting that Pacificorp address specific elements of their
PLEXOS modeling process during an upcoming stakeholder meeting. The items of interest are
divided into two main categories: Category 1: LT Plan Temporal Configuration Discuss
step size and overlap; as well as any application of PLEXOS' rolling horizon feature.
Review Chronology Method options: partial, fitted, sample. Examine Duration Curve Type
and the number of blocks per curve.In addition, discuss what process Pacificorp takes in
maximizing model accuracy with problem size (i.e. run times) Discuss what slicing method
is activated and discuss the strengths and weaknesses between peak/off peak and weighted
least squares. Discuss the use of global variables, such as slicing blocks and sampling
years. Delve into expansion decisions regarding integer optimality: whether using LP or
MILP, and details on the integerization horizon if MILP is used. Category 2: Performance
Settings Evaluate solver selection, solver method, and MIP gap settings. Consider the use
of solver tuning optimization software programs. Review parallelization settings and CPU
hardware capabilities of PacifiCorp, including RAM, physical cores, and CPU speed.
Additional topics related to the administering and running of the PLEXOS models will be
discussed in future meetings.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
* Required fields

PacifiCorp response(7/15/2024/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process. The subject matter expertise and
experience required to meaningfully engage in discussion concerning the requested technical details is beyond the scope of a public
input meeting.PacifiCorp analysts and technical teams consider all of the above strategies in its technical implementation of PLEXOS
and maintains an ongoing relationship with Energy Exemplar experts in order to balance and optimize model functionality.
PacifiCorp covered optimization modeling and details of the PLEXOS modeling process at the January 25,2024 and March 14,2024
Public Input Meetings.As explained in the March meeting,PacifiCorp has explored the suggested avenues and has been engaged
specifically in ongoing efforts to improve LT model granularity and performance.
* Required fields

PacifiCorp - Stakeholder Feedback Form (olo)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 6-0 3
*Name: Stanley Holmes Title:
*E-mail: [e-mail] Phone:
Utah Citizens Advocating Renewable
*Organization: Energy (UCARE)
Address:
City: State: UT Zip:
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ®Check here if not related to specific meeting
List additional organization attendees at cited meeting: See PacifiCorp 2025 IRP Public Input Meeting
#3, May 2, 2024 attendees list.
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Transmission Selections and Coal Retirements; Utah Legislative Sensitivity Case
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
PacifiCorp's May 2, 2024 public input discussion raised questions about potential impacts
of statutes issuing from the 2024 Utah Legislature session, to include Senate Bills 161,
224 and House Bills 48, 191. The new Utah laws could, within the 2025 IRP timeframe,
make available to PacifiCorp new energy generation units within Utah and influence EGU
retirement plans for PacifiCorp assets. One or more additional transmission lines might
have to be considered. PacifiCorp is therefore urged to create a placeholder sensitivity
within the 2025 IRP for analysis of Utah statute-related factors as they may arise.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
https://le.utah.gov/-2024/bills/static/SBO16l.html,
https://le.utah.gov/-2024/bills/static/SBO224.html,
https://le.utah.gov/-2024/bills/static/HB0048.html,
https://le.utah.gov/-2024/bills/static/HBO19l.html
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Recommend that PacifiCorp create a placeholder sensitivity case within the 2025 IRP for
analysis of Utah statute-related factors as they may arise.
PacifiCorp response(7/10/2024):
* Required fields

Thank you for your feedback and suggestions as we prepare the 2025 IRP. Further
discussion of legislative impacts and proposed sensitivities will be included in the
upcoming August and September public input meetings as these potential impacts are
considered.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (o11)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 6-10
*Name: Monica Hilding Title: Chair
*E-mail: [e-mail] Phone: [phone]
*Organization: Utah Environmental Caucus
Address: 155 South Lincoln Street
City: S l c State: UT Zip: 84102
Public Meeting Date comments address: 0 6-2 6-2 0 2 4 ®Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Climate modeling,Thermal Resources options,Water Resources
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
1) Please update how RMP's lengthy delay of renewable and storage purchases could affect
Utah Community Renewable Energy purchases --esp. with revisions under 2024 Utah Senate
Bill 214-- and affect 2025 IRP horizon assumptions. 2) How is RMP-Pacificorp taking water
use into consideration for cooling the coal plants whose lives were recently extended in
contravention of the 2023 IRP? 3) With RMP having filed deferred accounting orders with
the Utah PSC for wildfire claims [Docket 23- 035-30] and rising insurance costs [23-035-
40] , respectively, and the rising insurance costs docket now moving forward, how much of
the subsequent financial burden will Utah ratepayers have to shoulder alone and how much
shared across PacifiCorp's grid? 4) How will geothermal advances recently demonstrated by
the FORGE project be reflected as portfolio sensitivities for the 2025 IRP.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
https://le.utah.gov/-2024/bills/static/SBO214.html,
https://pscdocs.utah.gov/electric/23docs/2303530/329837230353On9-15-2023.pdf,
https://psc.utah.gov/2023/08/21/docket-no-23-035-40/,
https://www.sltrib.com/news/environment/2024/05/31/utah-lab-proves-it-pulling-heat/
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Recommend a portfolio sensitivity for water consumption by power plants.
Please submit your completed Stakeholder Feedback Form via email to
[e-mail]
* Required fields

Thank you for participating.
PacifiCorp Response (7/15/24) :
1 . PacifiCorp expects to address state policy updates in its August 14-15
public input meeting as these matters are considered.
2 . The Utah coal plant lives listed in the 2023 IRP Update preferred portfolio
are the same as the dates for the same coal units that were listed in the
2021 IRP preferred portfolio. From a water use and management perspective,
there have been no changes . RMP will therefore manage water consumption
going forward as it has been in the past, relying on a collection of water
resources and water rights .
3. The matter of insurance costs and their inclusion in rates is outside the
scope of the IRP.
4 . PacifiCorp is considering the broad range of geothermal cost scenarios
presented in the National Renewable Energy Laboratory (NREL) 2024 Annual
Technology Baseline (ATB) . The Company will most likely model geothermal
under the ATB' s "Moderate Scenario" quoted below, and the "Mature
Hydro/Flash" technology option which has the lowest cost and cost forecast,
and the lowest uncertainty for the moderate scenario among the technology
options. The Company recognizes that the "Advanced Scenario" for Enhanced
Geothermal Systems (EGS) may become more cost competitive within the next
decade; there is no plan to model that scenario at this time. However,
planning for sensitivities and variants is a subject being addressed in the
upcoming July 17-18 public input meeting and will also be addressed in
subsequent meetings responsive to stakeholder feedback.
Moderate Technology Innovation Scenario (Moderate Scenario) : Drilling
advancements (e.g. , doubled ROP and bit life from GeoVision baseline and reduced
number of casing intervals and associated drilling materials) detailed as part of
the GeoVision report (DOE,2019) and EGS stimulation successes from DOE-funded EGS
Collab and FORGE projects (Kneafsey et al.,2022); (Dupriest and Noynaert,2024) and industry
demonstration projects (Norbeck et al.,2023); (El-Sadi et al..2024); (So et al.,2024) result in
cost improvements that are fully achieved industrywide by 2035. Also, as part of
2024 ATB updates, this scenario assumes EGS power plants are built to a capacity
of 40 megawatts (MW) .
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PacifiCorp - Stakeholder Feedback Form (012)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 6-2 4
*Name: Don Hendrickson Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Utah Association of Energy Users
Address: 111 E Broadway, Suite 1200
City: SLC State: UT Zip: 84111
Public Meeting Date comments address: ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Suspected Errors in IRP Document Tables - System Capacity Load and Resource Balance
without Resource Additions
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
It appears that there are errors in the \u001CSystem Capacity Load and Resource Balance
without Resource Additions\u001D tables in the 2023 IRP and the 2023 IRP Update. 2023
IRP: Table 6.12 appears to show incorrect data on two rows, West Obligation + Reserves
and West Position. The apparent error occurs in years 2023 and 2024. We suspect this is
a formula error in the underlying Excel file. 2023 IRP Update: Tables 4.2 and 4.3
appear to show incorrect data on two rows, West Obligation + Reserves and West Position.
The apparent errors occur in years 2034 through 2042 in both tables 4.2 and 4.3. We
suspect this is an error in putting the data into the main document. Please confirm the
errors in the 2023 IRP and 2023 IRP Update or state why you believe the data in the
above-referenced rows is correct. If you confirm the errors, please correct these errors
in the 2025 IRP.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
We also recommend that the Excel version of these tables be moved from the Confidential
set of data to the Public set of data since the data is public in .pdf form already.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
* Required fields

Thank you for participating.
PacifiCorp response(7/10/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process.
2023 IRP:PacifiCorp can confirm that there are errors in the West Obligation+Reserves and West Position rows in Table 6.12 for the
years 2023 and 2024.These errors are the result of an incorrect formula in the underlying Excel file used to generate the table.For the
years 2023 and 2024,the formula for West Obligation+Reserves erroneously added New Energy Efficiency to the Planning Reserve
Margin instead of West Total obligation.The West Position formula was correct,but it used the incorrect data from the West
Obligation+Reserves row for 2023 and 2024.
2023 IRP Update:PacifiCorp can confirm that there are errors in the West Obligation+Reserves and West Position rows for the years
2034 through 2042 in both Tables 4.2 and 4.3.There are identical errors in Tables 4.2 and 4.3 as a result of an incorrect formula in the
underlying Excel file used to generate the part of the table displaying values from 2034 to 2042.The formula for West Obligation+
Reserves incorrectly added New Energy Efficiency to the Planning Reserve Margin instead of West Total obligation.This incorrect
value was then used in the West Position formula.
The Excel files used to create these tables are already available in the public data discs.To view the file used for the 2023 IRP tables,
go to the public data disc posted on May 31It and use the following path: Chapters,Appendices,and Input Assumptions\Chapters and
Appendix\CH6-Load and Resource Balance\(P)_Fig 6.2-6.7,Tables 6.11-6.12,2023 IRP-L&R.To view the file used for the 2023
IRP Update tables,go to the public data disc posted on April lst and use the following path: Chapters,Appendicies,and Input
Assumptions\Chapters and Appendix\CH4-Load and Resource Balance Update\(P)_PC_Table 4.2-3 6.4-5 Fig 4.3-4.4 2023 IRP
Update-L&R.
PacifiCorp will verify that the System Capacity Load and Resource Balance without Resource Additions tables in the 2025 IRP do not
replicate these errors.
* Required fields

PacifiCorp - Stakeholder Feedback Form (013)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 6-2 4
*Name: Emma Verhamme Title:
*E-mail: [e-mail] Phone: (860) 324 - 2638
*Organization: (individual)
Address: 848 N Lafayette Drive
City: Salt Lake City State: UT Zip: 84116
Public Meeting Date comments address: 0 6-2 6-0 2 0 4 ®Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Coal Retirement
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
How have new federal laws and Utah state laws shaped the IRP? Specifically, how has UT
bill SB-224 affected the timeline for retirement of coal in Utah? Also, how does this
bill affect the rate payer and the tax payer in Utah?
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
https://le.utah.gov/-2024/bills/static/SB0224.html
Recommendations:
PacifiCorp Response (7/10/2024) :
Assumptions for PacifiCorp' s 2023 IRP Update were locked down before SB-224 was passed,
so it had no impact on the retirement dates of coal resources in Utah, for example.
Further discussion of legislative impacts and proposed sensitivities for the 2025 IRP
will be included in the upcoming August and September public input meetings as these
potential impacts are considered.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

* Required fields

PacifiCorp - Stakeholder Feedback Form (014)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 4-2 3
*Name: Joan Entwistle Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: self
Address: 8231 Meadowview Ct
City: Park City State: UT Zip: 84098
Public Meeting Date comments address: 0 5-0 2-2 0 2 4 ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
2023 Updates
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please address why RMP will regress to pre-2021 IRP levels of solar, wind, battery
storage when these sources are now less expensive than other sources, and we will need to
increasing the supply of electricity.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Please resume the 2022 all source RFP that was proposed in 2021.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response(7/10/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process.For information regarding the drivers of
change in amounts and timing of resources in recent IRP filings,please refer to the 2023 IRP and 2023 IRP Update,publicly
accessible through this web link:Integrated Resource Plan(pacificorp.com)
* Required fields

PacifiCorp uses the Integrated Resource Planning process to select the least-cost,least-risk portfolio given prevailing conditions at the
time of planning.The need to meet system demand in all hours means that the Company must consider factors beyond the cost of a
resource,including whether the resource will reliably generate during peak load hours.Pages 6-7 of the 2023 IRP Update report that
the preferred portfolio includes 3,749 megawatts of new solar online by 2037,9,800 megawatts of new wind resources online by 2037,
and more than 4,000 megawatts of new storage capacity online by 2037.
PacifiCorp anticipates the discussion of inputs and assumptions to continue throughout the 2025 IRP public input meeting series.
* Required fields

PacifiCorp - Stakeholder Feedback Form (015)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 4-2 9
*Name: Bill Stoye Title:
*E-mail: [e-mail] Phone:
*Organization: Sierra Club
Address:
City: State: Zip:
Public Meeting Date comments address: ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
RMPs proposed customer lock into coal and methane gas energy sources.
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please divest from your continued use of coal powered electric generation. You know it's
outdated and backwards, as well as costing us more and adding to dirtier air and well,
you know, bolstering more climate change, in this needed time of renewable energy
sources.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
PacifiCorp response(7/10/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process.
PacifiCorp uses the Integrated Resource Planning process to select the least-cost, least-risk portfolio. In the 2023
Integrated Resource Plan(IRP)Update, coal plants were eligible for retirement any time after January 1,2024.Wind,
solar,hydro, and storage proxy resources were available for selection.Additionally,to represent the cost of emissions,
scenarios were run that included a CO2 price and the social cost of greenhouse gases. In consideration of all these factors
* Required fields

and others,the PLEXOS model endogenously determined coal retirement dates and procurement of new renewable
resources.
Each Integrated Resource Plan is contingent on current legislation,market and resource cost, and other key elements of
the planning environment. PacifiCorp anticipates the discussion of inputs and assumptions to continue throughout the 2025 IRP
public input meeting series.
* Required fields

PacifiCorp - Stakeholder Feedback Form (016)
2023 Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference calls, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the 2023 IRP, including,but not limited to the process, assumptions, and analysis.
In order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 2 0 2 4-0 4-3 0
*Name: Shannon Anderson Title:
*E-mail: [e-mail] Phone:
*Organization: Powder River Basin Resource Council
Address: 934 N. Main St.
City: Sheridan State: WY Zip: 82801
Public Meeting Date comments address: ❑Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Compliance with EPA greenhouse gas emissions rules
❑ Check here if you do not want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
We are requesting a slide prepared to show the implications of the EPA rule on greenhouse
emissions for the coal units.
Please provide a chart to stakeholders showing implications for each coal unit based on
the final EPA GHG rule. Please provide near-term and long-term implications based on
operating condition impacts and/or CCS requirements. In the 2025 modeling, please model
cost implications as well as alternative compliance options, such as earlier retirement
dates.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
EPA rule; coal unit retirement dates from 2023 IRP update preferred portfolio
PacifiCorp Response (7/12/2024-
PacifiCorp will complete holistic modeling for EPA's GHG Rule, including alternative compliance scenarios,
descriptions, charts, and details as part of the 2025 IRP. The analysis will report implications of the rule for both
near and long-term. Further discussion of legislative impacts and proposed sensitivities will be included in the
upcoming August and September public input meetings as these potential impacts are considered.
* Required fields

Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (017)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 7-0 3
*Name: Will Mulhern Title: Senior Utility Analyst
*E-mail: [e-mail] Phone: (503) 385 - 3294
*Organization: Oregon Public Utility Commission
Address: 201 High St. SE, Suite 100
City: Salem State: OR Zip: 97301
Public Meeting Date comments address: 05-02-2024 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Some of the comments relate to specific topics from the May 2nd meeting, while the rest
are recommendations from Staff\u0019s comments on the 2023 IRP Update
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
We would appreciate the response being posted publicly.
1. May 2 Public Input Meeting- Distributed generation study:
a) Why is non-rooftop solar not considered in land use requirements?
o Reply: Land-use requirement assumptions are inputs for all combinations of technology and customer
types when estimating future adoption.These are based on a combination of existing system sizes for
customer installations and technical feasibility factors. Non-rooftop solar is included in some larger
commercial, industrial, and irrigation customer bins, but these overall sizes are capped because they
also include assumptions for rooftop solar installations within the same customer type bins.
b) What is the definition of the"diffusion model"used in this study?
o Reply:The diffusion model is based on the Bass diffusion approach for technology adoption.This
approach uses segment-level adoption rate curves, customer economic metrics, and historical
customer adoption as inputs to forecast future adoption of distributed generation across the
PacifiCorp territory. Please refer to the forecast methodology slide deck that was presented in the May
2 stakeholder meeting for more information.
c) Does the model use different capacity factors based on location?
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o Reply:Yes. Capacity factors vary by state.
d) Will Oregon specific avoided costs—as reflected in UM 1893 Phase II - be used in the DSM forecast for the
2025 IRP? If not,will the updated EE avoided costs from UM 1893 be used in the CEP and if so, how?
o Reply: No,the 2025 IRP does not use the avoided costs developed in UM-1893,though it does
incorporate some of the same concepts and input assumptions, as discussed in more detail below.
o Transmission and Distribution Capacity Credits: a comparable methodology is in the 2025 IRP,
but the specific values won't be reflected in UM 1893 until after acknowledges the 2025 IRP or
otherwise adopts the assumptions for use in UM 1893.
o Generation Capacity Credits:the UM-1893 methodology uses the all-in fixed cost of a simple
cycle combustion turbine.The 2025 IRP identifies the least-cost portfolio of resources needed
to meet capacity requirements throughout the study horizon, based on the net cost of capacity
(resource costs less the energy value the resource provides). The portfolio of resources
includes varying combinations through time. The IRP modeling doesn't explicitly identify a net
cost of capacity.
o Energy prices:the UM-1893 methodology uses monthly HLH/LLH market prices as the energy
value. In the IRP,the system value and marginal energy value is calculated based on the energy
efficiency volumes in each hour. Heating and cooling measures tend to provide greater energy
savings under more strained conditions (colder in the winter or hotter in the summer), so the
value of associated energy savings may be higher than a monthly average. The prices in the IRP
also reflect the impacts of a given portfolio, as plentiful wind and solar resources can result in
congestion resulting in energy values that are lower than the market price.
o Clean energy requirements:the most recent UM 1893 filing included higher avoided energy
costs based on possible HB 2021 compliance requirements.The 2025 IRP will endogenously
account for Oregon's HB 2021 compliance requirements and will include a combination of
clean resources and new energy efficiency selections(offsets to load).
The 2025 IRP will select cost-effective energy efficiency bundles based on an optimization subject to all of
the aspects described above. The cost-effective energy efficiency bundles may be modified in the CEP,based
on additional analysis of possible compliance pathways.
2. May 2 Public Input Meeting-Transmission modeling:
a) Please explain with examples how the new 2025 IRP granularity adjustments to transmission modeling
would be an improvement over the previous approach.
o Reply: In the previous approach,transmission options did not receive a granularity adjustment,
meaning the LT model's did not benefit from the data provided by the more granular ST model. For
example, on a lower granularity time-block LT model basis, due to aggregation, a transmission
option may appear to be valuable during periods where enabled resources cannot effectively make
use of the transmission. Giving the LT model the benefit of the ST model's more granular hourly view
will improve the selections the LT model is able to make.This change will also align with the
methodology that is already in place for resources.
b) Is the ST import and export margin typically greater than the LT import and export margins?
o Reply: Not necessarily,the margin could be lower indicating the transmission is not as valuable in
the ST as the LT.
c) How is LMP forecasted for both short and long-term?
o Reply:The Locational Marginal Price is calculated as the value of the final MW added to a topology
location in the model.
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d) How does the granularity adjustment impact interconnection transmission options that do not have flow to
other bubbles? Is this kind of adjustment more in line with how flows occur in practice or is it only a
modeling adjustment?
o Reply:The exact mechanics of modeling granularity adjustments on interconnection options has
not yet been finalized.As such, PacifiCorp is not yet able to determine what the impact may be.
However,transmission options that are only for interconnection and do not provide incremental
transmission capacity between topology bubbles are valued in the ST model based on
optimization,just like any other resource.
3. 2025 IRP recommendations based on analysis of 2023 IRP Update:
a) PacifiCorp should continue to improve transparency and interactive improvements in the portfolio
integration step to combine state policy portfolios with the system portfolio.
o Reply:Thank you for your feedback. PacifiCorp has implemented reporting which compares the
various portfolios to show differences in resource selections between the state specific and
integrated portfolios.We welcome further feedback on these reporting enhancements.
b) PacifiCorp should report the steps taken to reduce the magnitude of reliability and granularity adjustments
due to portfolio integration.
o Reply:Thank you for your feedback. PacifiCorp has directly engages internal and Energy Exemplar
subject matter experts on an ongoing basis, and has diligently pursued enhancements to its
modeling to reduce the gap between LT and ST solutions. Regarding portfolio integration,the
reliability and granularity are unique to each portfolio and impact initial resource selection.The
integration leverages both LT and ST results from reliable portfolios and thus mitigates the impact of
initial reliability or granularity adjustments as neither are considered in the system dispatch and
valuation of individual resources in the ST model. It is the more granular ST model that is used to
evaluate portfolio cost and risk.
c) PacifiCorp should improve the temporal granularity in the capacity expansion modeling to avoid the large
number of modeling adjustments that incorporate sequential commitment and dispatch.
o Reply:At this time,with the complexity of the PacifiCorp system and to comply with state
requirements and stakeholder requests, it is not feasible to increase the level of granularity in a 20
year capacity expansion run. Other stakeholders have also advocated for this change. In order to
immediately improve the granularity in a 20 year run there would have to be trade-offs that have
been noted as undesirable by stakeholders, such as reducing resource options available to the
model, reducing the granularity of the topology,fewer options for thermal plant selections and
retirements, a non-endogenous selection of transmission, and relaxed tolerances for optimality
and feasibility.
d) PacifiCorp should update the temporal configure of battery charging and discharging along with seasonal
variability of renewables at the beginning of the modeling process to better capture their dynamics and
possible combinations in capacity expansion analysis.
o Reply:Thank you for your feedback. PacifiCorp is testing a variety of modeling improvements,
including updates to battery properties, renewables shapes and updated transmission constraints
which are likely to meet this goal.The objective is to allow the model the maximum practical range
to optimally determine resource dispatch and storage usage following hourly system conditions,
which may or may not confirm to a broader notion of seasonality in any given period.
e) PacifiCorp should layer in the fixed fuel costs at Jim Bridger and other coal plants within the PLEXOS model
upfront rather than through post-processing workbooks.
o Reply:Thank you for your feedback.All fuel costs related directly to actual operations of coal
plants are included in PLEXOS modeling. Modeling of fixed costs related to mines or other external
entities is not currently contemplated in PLEXOS.
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f) PacifiCorp should provide workpapers showing how system portfolio resources are modified to support
state policy decisions, as the Portfolio Optimization &Integration of state policy appears to be a new
source of subjective judgement for resource selection.
o Reply: Please see the response to subpart a) above.The integration approach is designed to avoid
subjectivity, in that resources are integrated on the basis of which portfolio include or exclude each
resource.This information is used to determine which states are assumed to participate in each
resource decision.The 2025 IRP will pursue great visibility into any adjustments that are not directly
represented in the portfolio data.
g) PacifiCorp should provide more detail and a thorough explanation of its approach to brining the Bridger 3
and 4 CCUS project into service by 2029.
o Reply:Thank you for your feedback.Thermal unit options for the 2025 IRP are currently being
developed for the August 14-15 public input meeting, and the timing for Bridger 3 and 4 CCUS is
part of that development process.
h) PacifiCorp should provide a sensitivity that shows the impact of CCUS delays on the lifetime cost/benefit
of the Bridger 3 and 4 units.
o Reply:Thank you for your feedback. Sensitivities for the 2025 IRP are currently being reviewed in
the 2025 IRP public input meeting series.
i) PacifiCorp should engage stakeholders to develop more accurate hydrogen modeling assumptions.
o Reply: Updated assumptions are gathered for every IRP cycle. PacifiCorp appreciates feedback
suggesting alternative data sources and considerations for hydrogen cost assumptions.
j) PacifiCorp should provide updated Natrium assumptions that reflect actual events and project milestones.
o Reply:Thank you for your feedback.Assumptions for the Natrium project to be used in the 2025 IRP
are currently being developed.These assumptions will reflect the most current milestones
available to PacifiCorp at the time of modeling the 2025 IRP.
k) PacifiCorp should address how asymmetric upside risk of market purchases during periods of peak
demand is reflected in its market price projections.The Company should also address how declining
market trading volumes are factored into the 2025 IRP model.
o Reply:Thank you for your feedback. PacifiCorp is exploring tightening limits on market purchases
based on historical data related to peak demand days. Currently modeled market volumes are
Lower than historical market activity.
l) PacifiCorp should incorporate the requirements of the finalized 111 rules into PLEXOS.
o Reply:As discussed in the July Public Input Meeting, PacifiCorp is planning to use EPA rule 111 d as
part of the 2025 IRP analysis.
m) PacifiCorp should better consider the risks associated with emissions regulations across the west trending
more toward tighter regulation to avoid over-exposing itself to regulatory risk.
o Reply: Risk assessment is a core function of PacifiCorp's approach to modeling and evaluation.
Feedback suggesting additional data and considerations is welcome.
n) PacifiCorp should specifically detail their Oregon-specific resource procurement strategy and the impact
of its current financial position, as discussed in the May 30, 2024 Public Meeting, on this procurement
strategy.
o Reply: PacifiCorp's Oregon-specific procurement strategy is being developed in ongoing IRP and
CEP processes. In the IRP, procurement objectives may be incorporated in the action plan.
o) Related to its levers for new resource additions in the 2023 CEP update,the Company should:
o Test multiple allocation strategies that are feasible within the context of MSP and for which the
Company is willing to advocate.
o Ensure that each allocation strategy supports simultaneous compliance with all state-level policies
to which PacifiCorp is subject.
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o Be transparent about allocation assumptions and their implications, including the timing of any
crucial allocation decisions to support policy compliance.
o Recognize the benefits of resources allocated to Oregon to the overall portfolio and reflect those
cost savings in Oregon-allocated cost estimates.
■ Reply: PacifiCorp is currently participating in the process to determine the timing and
nature of next steps for Oregon potential procurements and other levers as introduced in
the April 2024 CEP Supplement. Multiple strategies are expected to be addressed, and
portfolios are expected to be compliant with all state regulatory requirements.
p) Related to its lever for adding energy efficiency in the 2023 CEP update,the Company should:
o Consider additional energy efficiency within Oregon to contribute to achieving HB 2021 GHG
targets, support Oregon communities, and reduce the need for generation,transmission, and
distribution investments.
■ Reply:The company's integrated portfolio selected Oregon specific energy efficiency and
demand response which was incrementally higher than the original portfolio in order to
meet these needs.
o Adopt at least one Community Benefit Indicator(CBI)that reflects community benefits associated
with energy efficiency selection in Oregon and recognizes the value of avoided transmission
upgrades.
■ Reply:Avoided transmission benefits are currently a component of small scale resource
planning.
q) Related to its levers for adjusting dispatch strategies for emitting resources in the 2023 CEP update,the
Company should:
o Discuss how it intends to operationalize changes rather than just treating them as modeling
assumptions.
■ Reply: PacifiCorp recognizes the need to describe details regarding the pros and cons of
each of the levers, and what it means to operationalize particular assumptions.This
analysis is planned for the 2025 CEP as the next step in the analysis introduced in the CEP
Supplement.
o Compare the total systemwide GHG emissions under the alternative operational strategy to the
total systemwide GHG emissions under a business-as-usual or economic dispatch operational
strategy.
■ Reply: System emissions are expected to be a component of reporting for each portfolio
used to evaluate the levers.
r) Related to its levers for changes to the DEQ Emissions Calculations in the 2023 CEP update, PacifiCorp
should dialogue with DEQ over the coming months to determine if a change to the emissions methodology
for qualifying facilities may be a worthwhile strategy to pursue.
o Reply: PacifiCorp is currently engaging with DEQ related to this topic.
s) PacifiCorp should provide analysis supporting the assumption that new natural gas plants are capable of
converting to alternative fuels in the future. Further, are these plants modeled with non-emitting fuels in
any of the analyses or is this just an assumption that impacts the economic life of gas plants?
o Reply: In conversations with various developers, PacifiCorp has been informed that this conversion
is possible as of today. New natural gas plants are modeled as operating under natural gas
throughout the life of the plant and the approximate modeled cost of alternative fuels and natural
gas with a carbon tax cost adder are equivalent beginning in 2040.
t) Would PacifiCorp consider conducting an RFI prior to the 2025 IRP/CEP to better understand the market
prices for new generation?
o Reply:This is not under consideration at this time.
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Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (018)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 7-19
*Name: William Achi Title:
*E-mail: [e-mail] Phone: (478) 456 - 1166
*Organization: Wyoming Office of Consumer Advocate
Address: 2515 Warren Ave, Suite 304
City: Cheyenne State: WY Zip: 82002
Public Meeting Date comments address: ❑Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
wildfire risk, regional and interregional transmission
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Given the wildfire costs that PacifiCorp has experienced, how does the Company plan to
address the wildfire risk associated with regional and interregional transmission
projects and assets, especially those located within high risk zones/high fire
consequence zones? Does the IRP model consider wildfire mitigation techniques (e.g.
undergrounding, covered conductors, EFR reclosers, etc. ) and their associated costs when
resource selections include regional and interregional transmission? If it does, how does
the model determine when and which wildfire mitigation techniques are needed?
Additionally, does the model consider the liability costs and legal liability costs
related to transmission related wildfire risk?
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
If PacifiCorp does not currently include wildfire risk related costs in the IRP model, it
should do so when resource selections include regional and interregional transmission.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp Response (8/12/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process.
PacifiCorp does not currently include wildfire-related costs distinctly in its modelling for the Integrated Resource Plan
(IRP). Wildfire-related costs are assumed in the social cost of greenhouse gas price-policy scenario. Transmission-related
costs for mitigation techniques are incorporated in IRP modeling to the extent they are a component of the costs assumed
for specific transmission options. Regional and interregional transmission plans are developed through the NorthernGrid
regional planning process. Any transmission-related costs derived from wildfire mitigation considerations in the
NorthernGrid regional planning process would be reflected in the cost estimates assumed for specific transmission
options. Transmission-related wildfire mitigation strategies are being actively considered for both existing and new
transmission.Any transmission-related costs derived from wildfire mitigation considerations would be reflected in the
cost estimates for transmission and distribution deferral values used in the IRP.
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PacifiCorp - Stakeholder Feedback Form (o19)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 7-19
*Name: William Achi Title:
*E-mail: [e-mail] Phone: (307) 777 - 5705
*Organization: Wyoming Office of Consumer Advocate
Address: 2515 Warren Ave, Suite 304
City: Cheyenne State: WY Zip: 82002
Public Meeting Date comments address: 0 7-18-2 0 2 4 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Chehalis natural gas plant, Washing Climate Commitment Act cap-and-invest program,
modeling scenarios
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the July 18, 2024 IRP meeting PacifiCorp stated that for all scenarios that will be
modeled, emissions from the Chehalis natural gas plant will incur the forecasted cost of
allowances under the cap-and-invest program established in the Climate Commitment Act
(CCA) passed by the Washington Legislature in 2021. Given that several states have
already rejected the inclusion of these costs in rates, and that PacifiCorp has
challenged these costs in court, we find it concerning that the Company\u0019s modeling
strategy does not include any scenarios in which Chehalis is modeled without the cost and
dispatch impacts of the cap-and-invest program.
Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e.gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
We would recommend the Company provide resource selections modeled without the cost and
dispatch impacts of the WA CCA cap-and-invest program on the Chehalis natural gas plant.
PacifiCorp Response(8/1/2024):
Thank you for your recommendation. We have not modeled Chehalis without considering the
cost and dispatch impacts of the WA CCA cap-and-invest program. Notwithstanding that
certain commissions have declined to allow the company to recover these cost, the company
continues to incur these costs. The company is monitoring ballot measures that could
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appeal the CCA. Chehalis provides capacity to the system and demonstrated cost-
effectiveness in the 2023 IRP.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (021)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-07-03
*Name: Jim Himelic Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Renewable Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: ❑Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Configuration details for Plexos Modeling Exercises
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
While Renewable Northwest (RNW) is still awaiting a response from PacifiCorp regarding
our original Stakeholder feedback form submitted on May 2nd, which inquired about the
specific PLEXOS LT settings PacifiCorp is employing, we would like to add the following
PLEXOS-related questions to that request:
• PLEXOS Production Settings: Please provide a copy of the production settings used
for all final PLEXOS runs. If separate settings were used for LT and MT-ST runs,
please provide each set of settings.
• PLEXOS Performance Settings: Please provide a copy of the performance settings used
for all final PLEXOS runs. If separate settings were used for LT and MT-ST runs,
please provide each set of settings.
• PLEXOS Horizon Settings: Please provide a copy of the horizon settings used for all
final PLEXOS MT-ST runs.
o Has PacifiCorp explored the impacts on modeling results and run times when
using Typical Week Per Month reduced chronology for the ST Schedule?
o Note: While RNW does not encourage this setting for reliability-focused ST
runs, the mode can be effective in reducing run time requirements when
performing economic-focused simulations across an extended planning horizon.
• PLEXOS MT Settings: Please provide a copy of the performance settings used for the
MT phase of PLEXOS simulations.
o For the decomposition of the MT targets, does PacifiCorp implement this as a
quantity-based target (i.e. , a hard constraint) or as a price-based target
(i.e. , a soft constraint) ?
0
• Other:
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o Please discuss to what extent PacifiCorp has explored the various options
provided by Energy Exemplar to PLEXOS users for configuring PLEXOS LT runs,
particularly in balancing the tradeoffs between chronology resolution and run
times. Specifically, please address whether PacifiCorp has considered options
such as:
■ Mixed Chronology
■ Rolling Horizons
■ Multistep Optimization with overlapping steps
■ Integerization horizon for expansion decisions optimality
o Has PacifiCorp explored using the Projected Assessment of System Adequacy
(PASA) modeling stage to assist with a first pass reliability run or creating
planned maintenance schedules for their thermal generation fleet?
o Related to performance settings, has PacifiCorp explored using the Gurobi
Tuner software program provided by Energy Exemplar?
■ This tool optimizes the settings for the Gurobi solver specific to each
model by using an MPS file description of the modeled portfolio.
■ The program identifies the optimal set of solver settings, including
undocumented parameters beyond those available through the PLEXOS
interface, for a user-specified MIP gap.
o Has PacifiCorp explored using the [Load Subtracter] property under the
Generator class?
■ This parameter allows the chronology algorithm in PLEXOS LT to be
applied to the net load profile (i.e. , gross load netted out with zero
variable costs generation) rather than the gross load profile.
■ This enables a more efficient allocation of the fixed number of blocks
accessible to the optimizer to the critical periods in the planning
horizon.
o Does PacifiCorp perform any backcasting validation runs on their PLEXOS model
regularly?
Please note that RNW is requesting this information to assist PacifiCorp in addressing
their modeling needs. RNW recognizes the complexity associated with effective capacity
expansion, resource adequacy, and production cost modeling. Given the size and complexity
of PacifiCorp' s portfolio, these tasks are even more challenging. In that spirit, RNW has
PLEXOS modeling expertise under retainer and offers this support in the spirit of
collaboration and continuous progress for the IRP process. RNW is also supportive of
PacifiCorp hosting a technical modeling workshop to discuss these items, along with other
related modeling topics, if that would be most effective for all stakeholders.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response (8/XX/2024):
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Thank you for your feedback and engagement in the Integrated Resource Planning process. Please see the following
tables, which display the Plexos settings used in the 2023 IRP Update:
PLEXOS Production Settings:
LT Models MT/ST Models
Category - -
Dispatch by Power Station (Yes/No) Yes Yes
Power Station Aggregation Mode None None
Unit Commitment Optimality Linear Linear
Rounding Up Threshold 0.5 0.5
Rounded Relaxation Commitment Model Central Central
Rounded Relaxation Tuning(Yes/No) No No
Rounded Relaxation Start Threshold 0.25 0.25
Rounded Relaxation End Threshold 0.75 0.75
Rounded Relaxation Threshold Increment 0.05 0.05
DP Capacity Factor Threshold(%) 20 20
DP Capacity Factor Error Threshold(%) 20 20
Capacity Factor Constraint Basis Installed Capacity Installed Capacity
Forced Outage Relaxes Min Down Time(Yes/No) No No
Gas Demand Resolution Interval Interval
Heat Rate Detail Detailed Detailed
Unit Commitment Heat Rate Detail(Yes/No) Yes Yes
Integers in Look-ahead Never Never
Cooling States Enabled (Yes/No) No Yes
Run Up and Down Enabled (Yes/No) No Yes
Transitions Enabled (Yes/No) Yes Yes
Start Cost Method Optimize Optimize
Start and Stop Enabled (Yes/No) No Yes
Ramping Constraints Enabled (Yes/No) Yes Yes
Pump and Generate(Yes/No) No Yes
Increment and Decrement(Yes/No) Yes Yes
Fuel Use Function Precision 0 0
Max Heat Rate Tranches 5 3
Min Heat Rate Tranche Size 0 0
Heat Rate Error Method Warn Adjust Report Adjusted Warn Adjust Report Adjusted
Formulate Upfront(Yes/No) Yes Yes
Formulate Ramp Upfront(Yes/No) Yes Yes
Warm Up Process Enabled (Yes/No) Yes Yes
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PLEXOS Performance Settings:
LT Models MT/ST Models
Category - -
SOLVER Gurobi Gurobi
Small LP Optimizer Auto Auto
Small LP Nonzero Count 250000 250000
Cold Start Optimizer 1 Barrier Homogeneous Auto
Cold Start Optimizer 2 None None
Cold Start Optimizer 3 None None
Hot Start Optimizer 1 Barrier Homogeneous Auto
Hot Start Optimizer 2 None None
Hot Start Optimizer 3 None None
Concurrent Mode Deterministic Deterministic
Presolve(Yes/No) Yes Yes
Scaling(Yes/No) Yes Yes
Crossover(Yes/No) Yes Yes
Feasibility Tolerance 0 0
Optimality Tolerance 0 0
Objective Scalar 1 1
Objective Tolerance 0 0
Maximum Threads -1 -1
MIP Root Optimizer Auto Dual Simplex
MIP Node Optimizer Auto Dual Simplex
MIP Relative Gap 0.0002 0.0002
MIP Improve Start Gap 0 0
MIP Absolute Gap 0 0
MIP Max Relative Gap 0 0
MIP Max Absolute Gap 0 0
MIP Max Time(s) 7200 3600
MIP Max Relaxation Repair Time(s) -1 -1
MIP Maximum Threads -1 12
MIP Start Solution Within Step Within Step
MIP Focus Balanced Balanced
Carry over MIP Time(Yes/No) Yes No
MIP Max Time with Carry over(s) -1 -1
MIP Hard Stop(s) -1 -1
MIP Interrupt(Yes/No) No No
Hint Mode Start Start
Monitoring Periodic Clearing 0 0
Monitoring Maximum Threads -1 -1
Maximum Monitored MIP Iterations -1 -1
Maximum Parallel Tasks -1 -1
Feasibility Repair Failure Continue Continue
PLEXOS Horizon Settings:
*Required fields

LT Models MUST Models
Category -
Periods per Day 24 24
Compression Factor 1 1
Date From 1/1/2023 1/1/2023
Step Type Year Year
Step Count 20 20
Look-ahead Count 0 0
Day Beginning 0 0
Week Beginning 0 0
Year Ending 0 0
Chronology Full Full
Chrono Date From 1/1/2023 1/1/2023
Chrono Period From 1 1
Chrono Period To 24 24
Chrono Step Type Day Week
Chrono At a Time 1 1
Chrono Step Count 7305 1043
Look-ahead Indicator(Yes/No) No Yes
Look-ahead Type Day(s) Day(s)
Look-ahead At a Time 2 3
Look-ahead Periods per Day 12 12
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PLEXOS MT Settings: Performance settings.
There do not appear to be any"MT Schedule"settings in PLEXOS 9.2,that relate to"...the decomposition of the MT targets..."as
described in this question.
MT targets are generally set based on the specific property and associated spanning condition.PacifiCorp is taking steps to
change the model properties in order to bypass the MT phase where appropriate when running an ST deterministic model run.For
example:we have specifically defined the"Max Capacity Factor Week"for DSM-Demand Response. Rather than attempting to
optimize demand response dispatch based in the MT phase,a portion of the overall demand response capability is allocated to each
week in the relevant season,with more events in periods with greater risk or need. This emulates actual practice,where,outside of an
emergency where a program would immediately be used to the maximum extent allowed,a portion of the events will be reserved in
case they are needed in the remainder of the season.
Other:
• Configuring PLEXOS LT runs
o PacifiCorp has explored and continues to explore all model setups/options on an ongoing basis in an
attempt to improve modeling performance and in order to achieve LT portfolio results that are more
reliable and consistent with the results we see in the ST phase of PLEXOS modeling. We do not see a
setting for"Mixed Chronology",however,we currently use the"Partial"chronology setting in our LT
model runs.
Fitted and sampled have been tested multiple times.We see the best results using the combination of partial
and our custom slicing combined with 7 Blocks/Month.Rolling Horizons had been tested in the past but
this setup was not functioning;however Energy Exemplar has indicated this functionality has been fixed
and should work. We are testing this setup currently for the 2025 IRP,but it reports faulty infeasibilities.
Te s t s using the integerization horizon for expansion decisions has not resulted in meaningful run-time
improvements.
PacifiCorp has found that focusing on specific unit types being modeled as linear/integer rreults in more
significant run-time improvements.For example,only existing plant retirements and certain transmission
upgrades may need to be considered on an integer basis.
o PacifiCorp has not explored the use of the PASA modeling stage.
o PacifiCorp has not explored using the"Gurobi Tuner"software,but the Company is interested to learn
more about this. As stated,we are always looking to improve our model setups and assumptions.
o Load Subtracter:PacifiCorp had tested using a load subtractor setup to help the model with Blocking,but
it did not appear to provide a useful improvement. Because load subtractor is tied to specific volumes
identified prior to running the LT,it does not incorporate the outcomes of the portfolio selection. This
setup would not work with our current LT setup that uses custom slicing which accounts for our wind and
solar profiles.
o PacifiCorp has not attempted to perform any type of backcasting validation within PLEXOS. PacifiCorp
has been reviewing historical load,market price,and generator availability data to see whether the
forecasting and modeling of these inputs can be improved to better reflect both the expected variation in
these inputs experienced on an actual basis and the correlation among these inputs. In actual operations,
PacifiCorp balances much of its requirements using market products transacted on a forward and day-ahead
basis. PLEXOS currently only uses hourly balancing,so it does not have forward and day-ahead market
products,nor does it capture all of the impacts of hedging requirements and forecast error. For the 2025
IRP,PacifiCorp is working to incorporate the forward showing requirements associated with the Western
Resource Adequacy Program(WRAP),and those requirements are likely to impact how forward market
transactions are used in practice. Similarly,PacifiCorp expects to begin operating within the CAISO's
Enhanced Day-Ahead Market(EDAM)starting in 2026,which may also impact operations.These two
developments are likely to improve the alignment between actual operations and PLEXOS and will reduce
the relevance of recent actual results.PacifiCorp remains open to specific suggestions that might improve
the performance and accuracy of our modeling.
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PacifiCorp - Stakeholder Feedback Form (022)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-07-27
*Name: Christopher Thomas Title:
*E-mail: [e-mail] Phone: (385) 228 - 6873
*Organization: Salt Lake City Corp
Address: 451 S. State Street
City: Salt Lake City State: UT Zip: 84111
Public Meeting Date comments address: 0 7-17-2 0 2 4 ®Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Numbered slide 51 titled \u001CVariants\u001D
°BJ Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please include an additional variant, \u001Cnear-term customer choice energy\u001D that
would allow for the selection of energy resources by the PLEXOS model for operation in
2026 and 2027 in the following amounts: 493 MW of solar, 126 MW of wind, and 32 MW
of geothermal. These numbers reflect the total summer megawatts (MW) in the PacifiCorp
interconnection queues that have completed Facilities studies with a requested commercial
operation date prior to December 31, 2026 for each of these energy resource types. The
rationale for including this variant is that PacifiCorp\u0019s core cases do not allow
for the selection of wind or solar resources before calendar year 2028, reflecting a
constraint that represents the regulatory timeline of initiating an all-source RFP and
completing contracting and project construction. However, there are programs and
tariffs that could allow for large customers or groups of customers to acquire energy
from the projects in PacifiCorp\u0019s interconnection queues before 2028. Given that, it
would be prudent to use one IRP model variant to examine whether limited amounts of new
energy resource acquisition prior to 2028 would be cost effective from the perspective of
the PacifiCorp system as a whole. The 2023 IRP update preferred portfolio found that
near-term resource acquisition would be cost effective, to the tune of 654 MW of solar or
solar + storage in 2027 and 79 MW of wind in 2027.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
* Required fields

Please ensure that the \u001Cnear-term customer choice energy\u001D variant will allow
for the selection of solar and wind resources in the amounts listed above without co-
located storage.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response(7/XX/2024):
Thank you for your participation and engagement in the Integrated Resource Planning process.
PacifiCorp is actively considering projects that have a commercial operation date before l/l/2028 and does not foreclose
the opportunity for such projects. The Integrated Resource Plan(IRP) is based on proxy resource costs and related
assumptions that are generic and intended to be broadly applicable. Thus,the IRP has typically not allowed resources to
be selected within the initial few years of the model run even if PacifiCorp might still be able to pursue projects that could
enter commercial operation during those initial few years.
The Company is currently considering all requests for additional sensitivity and variant studies to be completed in the
2025 IRP. Possible options will be discussed in the August 14-15 and September 25-26 Public Input Meetings.
* Required fields

PacifiCorp - Stakeholder Feedback Form (023)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-0 9
*Name: Jon Martindill Title:
*E-mail: [e-mail] Phone:
*Organization: NP Energy LLC
Address:
City: State: Zip:
Public Meeting Date comments address: 0 6-2 7-2 0 2 4 ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting: Nick Pappas, Max Greene, James Himelic
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Non-Emitting Peakers - Hydrogen fuel availability
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
RNW seeks additional analysis and due diligence from PacifiCorp regarding its hydrogen
cost and availability assumptions. Non-emitting peakers play a large role in
PacifiCorp\u0019s 2023 IRP, and an even greater role in the 2023 IRP Update. The 2023 IRP
includes 1,240 MW of non-emitting peakers by 2036. In the 2023 IRP Update, all gas
peakers are assumed to be capable of transitioning to hydrogen, an assumption that
extends the modeled operational life of all natural gas resources, culminating in 5,000
MW of non-emitting peakers in 2041. The growth of non-emitting and hydrogen-capable
peakers seems to be driven in part by Oregon compliance, but more broadly due to coal
retirements. In comments submitted on June 14, 2024, RNW identified four gaps in
PacifCorp\u0019s planning. 1) Additional energy production requirements necessary to
produce green hydrogen; 2) Water consumption to produce green hydrogen; 3) Cost and
viability of infrastructure to transport and store hydrogen; and 4) Impact, monitoring,
and mitigation necessary to address hydrogen leakage In the June 27 Public Input Meeting,
PacifiCorp acknowledged many of the drawbacks and challenges to combusting green hydrogen
to generate power, including its poor round-trip efficiency, need for significant new and
expensive infrastructure, and leakage. Further, PacifiCorp acknowledged that there is
\u001Ca lot of work that would need to be done to create a hydrogen economy at a scale
for utility power generation\u001D including a \u001Ctremendous amount of
infrastructure\u001D. In this same session, PacifiCorp clarifies that the 2023 IRP update
does not have specific plans to run the hydrogen-capable peakers with 100% hydrogen, and
that these are included as a \u001Chedge against the possibility that they will need to
run 100% hydrogen at a point in the future. \u001D RNW seeks additional clarification
from PacifiCorp on how it would address these uncertainties and ensure that, to the
extent hydrogen peakers are a necessary element of a compliant portfolio, it will ensure
that these resources are both capable of utilizing and supplied by green hydrogen to the
designated state or federal standard.
* Required fields

Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Meeting cited: https://www.youtube.com/watch?v=ifpGWdeOnBI&t=2106s
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
As long as PacifiCorp\u0019s IRP models operate on optimistic assumptions about hydrogen
availability and cost, RNW asks for specific planning on how PacifiCorp plans to acquire,
store, and potentially produce the of hydrogen necessary to generate power.
Specifically, RNW recommends that PacifiCorp: 1) Incorporate the green hydrogen energy
requirement as an incremental portfolio requirement for renewable energy production,
enabling PLEXOS LT to increase clean energy production to meet electrolysis demand. 2)
Perform a viability and cost assessment of electrolyzer sites that minimize cost of
delivered green hydrogen to planned non-emitting peakers. These sites must meet grid
connectivity requirements and water availability requirements. 3) Perform a viability and
cost assessment of hydrogen storage siting and sizing to determine the capital and
operational expenses associated with relying on hydrogen fuel for power generation. 4)
Perform a viability and cost assessment of hydrogen transportation infrastructure. 5)
Include leak monitoring and leak mitigation into hydrogen infrastructure planning, and
include global warming impacts of hydrogen leakage into emissions assessments.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response (9/10/2024):
Thank you for your feedback. With regard to your recommendation 1, for an incremental portfolio requirement,the
company believes that proposed analysis of Oregon and Washington compliance requirements will achieve comparable
results. At the August 14-15,2024 public input meeting,the company presented both tank and cavern storage options for
hydrogen,which in combination with electrolysis could allow for increased clean energy production. The company is still
finalizing this modeling for the 2025 Integrated Resource Plan(IRP),and does not intend to conduct site-specific or
project-specific evaluations as suggested in recommendations 2-5,as those are outside the scope of the IRP,which does
not evaluate specific projects. PacifiCorp appreciates the expertise offered by RNW and believes these recommendations
may be helpful in developing specifications and requirements for non-emitting peaking resources for inclusion in a
Request for Proposals(RFP) following the 2025 IRP.
* Required fields

PacifiCorp - Stakeholder Feedback Form (024)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-0 9
*Name: Jon Martindill Title:
*E-mail: [e-mail] Phone:
*Organization: NP Energy LLC
Address:
City: State: Zip:
Public Meeting Date comments address: 0 7-18-2 0 2 4 ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting: Nick Pappas, Max Greene, James Himelic
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Candidate Resource Costs
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
RNW seeks additional information from PacifiCorp regarding its assumptions and methods
around resource costs. In comments submitted on June 14, RNW questioned PacifiCorp\u0019s
unsubstantiated escalators for renewable energy resources used in the 2023 IRP and 2023
IRP Update. In those comments, RNW demonstrated that third-party sources of information,
including NREL ATB 2024, did not support PacifiCorp\u0019s assumptions about renewable
resource costs and their change over time. In the July 18 Public Input Meeting,
PacifiCorp stated that they are basing cost estimates for proxy resources on NREL ATB
2024, but that there are additional costs that PacifiCorp adds to the ATB estimate to
more accurately reflect the true cost. In order to meaningfully engage with the resource
costs, a critical input to any planning exercise, PacifiCorp must provide additional
information and substantiation on this adjustment step than has been made available
previously. Therefore, RNW asks that this adjustment step be made as transparently as
possible.
Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
Please provide specific information on the following questions: 1) What specific costs
are added in this adjustment step, and what information sources are used to estimate
these costs? 2) How do cost adjustments vary by resource? 3) How do cost adjustments vary
over time? 4) How will this cost adjustment step be transparent to stakeholders? 5) Will
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PacifiCorp share the specific cost adjustments applied to each resource and the rationale
behind each adjustment?
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
PacifiCorp Response:
1) Regarding capital costs presented in the Supply-side Resource table(column heading"CAPEX"),the National
Renewable Energy Laboratory(NREL)Annual Technology Baseline(ATB)provides overnight capital cost
(OCC)in 2022 dollars for the year of commercial operation(COD year). The ATB's OCC for the appropriate
soonest COD year is escalated to from 2022 dollars to 2024 dollars. Then the following costs are added:
• Allowance For Funds Used During Construction(AFUDC): this reflects the cost of funds used prior to
commercial operation and incorporates PacifiCorp's confidential financial costs in the calculation. This is
used instead of the ATB's Finance Factor.
• Capital surcharge: administrative and general costs,which cannot be charged directly to a capital project,
in accordance with the Federal Energy Regulatory Commission(FERC)and generally accepted
accounting principles(GAAP).
• Property tax: 1.2%
2) The CAPEX described in response to question 1 varies by location and tax incentive rules. Locational cost
factors were obtained from the United States Energy Information Agency report: "Capital Cost and Performance
Characteristics for Utility-Scale Electric Power Generating Technologies, January 2024."For resources that do
not have a cost forecast, standard inflation is applied.Additionally,instead of using the ATB's interconnection
costs,the Company's PLEXOS modeling reflects location-specific interconnection cost estimates from
throughout PacifiCorp's transmission system.
3) CAPEX costs vary over time according to the ATB's cost forecasts, adjusted for inflation.
4) The cost adjustments indicated above were discussed at the July and August public input meetings for the 2025
IRP (Public Input Process(pacificorp.com).Additional information provided in this response is publicly available
along with the 2025 IRP Supply-side Resource table Integrated Resource Plan(pacificorp.com).
5) The overarching rationale is to provide information that is more consistent with PacifiCorp's expected costs in its
operating areas than that represented by the nationwide average costs provided in the ATB. The rationale behind
each individual resource adjustment does not vary except as described above.
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (025)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal
*Name: Jon Martindill Title:
*E-mail: [e-mail] Phone:
*Organization: NP Energy LLC
Address:
City: State: Zip:
Public Meeting Date comments address: 0 7-18-2 0 2 4 ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting: Nick Pappas, Max Greene, James Himelic
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Carbon Capture and Storage
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
RNW seeks additional information and due diligence from PacifiCorp regarding its
application of carbon capture and storage (CCS) in its 2023 IRP Update. The 2023 IRP
Update extends and expands reliance on existing fossil infrastructure, including
significant increases in CCS at PacifiCorp\u0019s coal units. RNW seeks additional due
diligence on the compliance risk and economic risk of relying on CCS to prolong coal
plant operations and reduce emissions. There are many technical barriers to overcome for
effective CCS, as well as a variety of lifecycle emissions and local pollutants that make
continued coal operations inherently risky. In addition, the economics of coal plan
operations remain sensitive to a variety of factors.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
Please provide specific information on the following questions: 1) What is the plan for
the captured carbon? Is there a specific storage or utilization plan? Are the costs of
storage and/or utilization included in the economic analysis? 2) Has PacifiCorp performed
a sensitivity analysis on the economics of CCS? To what extent is this selection
sensitive to CCS efficiency, coal fuel costs, and carbon storage/utilization costs? 3)
What data source (s) informed NVE\u0019s estimate of $32.71/kw-year for fixed costs to
operate a 330 MW CCUS retrofit? NREL ATB 2024 estimates a range of $148-$161/kw-year for
a similar retrofit installed in 2028. 4) Are air quality impacts from coal trans
included in your analysis?
* Required fields

Please submit your completed Stakeholder Feedback Form via email to [e-mail]
PacifiCorp Response (8/28/2024):
PacifiCorp's 2023 IRP Update identified the Jim Bridger units 3 and 4 carbon capture project as a potential economic
benefit to customers. This analysis relied upon high-level proxy costs in the economic modeling which needs to be
validated by a front-end engineering design(FEED) study before advancing a carbon capture project. The Company is
pursuing a FEED study that will evaluate the capture,transport and storage of CO2 from Jim Bridger units 3 and 4.
1. The FEED study will evaluate an option for transport and storage of the CO2. Cost for transportation and
storage are accounted for in the economic modeling.
2. The company used a single set of CCUS cost inputs and is aware that many of the factors used to
determine those cost inputs are highly uncertain.We have not yet conducted a specific analysis for the
breakeven point for coal fuel cost, efficiency, etc., due to the significant amount of uncertainty
surrounding these factors. The FEED study identified above is expected to provide better information on
possible outcomes so that such analysis could be conducted in the future.
3. The NETL 2023 Report—"Eliminating the Derate of Carbon Capture Retrofits"includes cost items that
PacifiCorp does not take into account in fixed operations and maintenance cost. However,those line
items are being included in the total cost of the project.
4. The company has three plants where coal is received via rail: Bridger,Dave Johnston and Hayden. The
company operates Bridger and Dave Johnston while Hayden is operated by Xcel Energy. For plants
operated by the company, dust suppression is applied to all the trains where required(those loaded from
Powder River Basin origins). This would include all coal destined for Dave Johnston and some of the coal
destined for Jim Bridger. That dust"topper" is purchased on a$/ton rate and applied at the mine as the
coal is loaded in the cars. IRP modeling is based on the delivered cost of coal, and includes both rail and
dust suppression,as applicable. The company doesn't have direct control of the Hayden trains, so it does
not have details for that plant,though it expects practices are similar.
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (026)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-08-09
*Name: Kate Bowman Title:
*E-mail: [e-mail] Phone: (801) 872 - 3234
*Organization: Vote Solar
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Distributed Generation Study, Sensitivities
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Questions: Does the distributed generation study include any locational forecasting of
DER adoption more specific than state level? Does the IRP evaluate any interactive
effects between distributed energy resource adoption and other customer-sited
technologies? For example, interactive effects between high DER adoption and high
electrification, or high adoption of EVs? In the June 26 - 27 presentation, slide 42
states \u001CNet-billing states tied to avoided cost forecast from IRP.\u001D In this
context, does avoided cost refer to PURPA rates for qualifying facilities? Or something
else? How are forecasts for future avoided costs developed? In the June 26 - 27
presentation, slide 42 states the value of backup power is \u001CIncluded in customer
benefits of PV + Battery technology.\u001D How specifically is the value of backup power
used as an input to the \u001Chigh\u001D forecast? Why does PacifiCorp believe that it is
appropriate to assume no value for backup power in the \u001Cbase\u001D case as well as
the \u001Clow\u001D case? What assumptions does the distributed generation study include
about how customer batteries are dispatched? For example, how many hours, how many days a
year, or which hours? Does the presence of solar/storage systems in the adoption
forecasts result in a different load profile than solar alone? Does the load forecast
account for the load effects of a customer dispatching their battery, for example in
response to a time of use rate? Have PacifiCorp\u0019s past RFPs allowed for distributed
generation resources to bid into the RFP? For example, could a virtual power plant bid
into an RFP as a potential resource? Recommendations: Increase the granularity of
distributed energy resource forecasting and include locational forecasts of distributed
energy resource adoption. Locational forecasting of DER adoption is necessary to capture
the full value of DER resource additions and supports efficient investment decisions. See
the following reports: NREL: \u001CValue of Distributed Energy Resources Largely Depends
on Three Things: Location, Location, Location.\u001D Available at:
https://emp.lbl.gov/news/value-distributed-energy-resources Electric Power Systems
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Research: \u001CValuing Distributed Energy Resources for Non-Wires Alternatives.\u001D
Available at: https://www.sciencedirect.com/science/article/pii/S0378779624004073 Explore
multiple scenarios that integrate potential futures for distributed energy resource
adoption and other demand-side technology, in order to understand how DERs could enable
additional loads from electrification. Ensure next RFP invites participation from
distributed energy resources and aggregated distributed energy resources that are able to
meet the energy, capacity, and grid services needs identified in the RFP. Integrate any
competitive distributed energy resource bids from RFPs into future IRPs as selectable
resources in the supply-side resource table. Include future scenarios that evaluate
interaction of DERs and electrification. Include a sensitivity that evaluates the
interactive effects between high distributed energy generation adoption and high
electrification. Incorporate use of the Energy Infrastructure Reinvestment act to retire
or repurpose eligible resources as a scenario or sensitivity to understand the potential
impacts on unit retirement date and replacement portfolio.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
NREL: \u001CValue of Distributed Energy Resources Largely Depends on Three Things:
Location, Location, Location.\u001D Available at: https://emp.lbl.gov/news/value-
distributed-energy-resources Electric Power Systems Research: \u001CValuing Distributed
Energy Resources for Non-Wires Alternatives.\u001D Available at:
https://www.sciencedirect.com/science/article/pii/S0378779624004073
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp Response:
a) Does the distributed generation study include any locational forecasting of DER adoption more specific than state
level?
There is no locational forecasting in this study
b) Does the IRP evaluate any interactive effects between distributed energy resource adoption and other customer-
sited technologies?For example,interactive effects between high DER adoption and high electrification, or high
adoption of EVs?
We do include the private generation forecast in our baseline projections, and also use that forecast to inform
battery forecasts for the DR programs as well. We do use the expected case and not a high generation case for
our reference case projections.
c) In the June 26-27 presentation, slide 42 states\u00ICNet-billing states tied to avoided cost forecast from
IRP.\u001D In this context,does avoided cost refer to PURPA rates for qualifying facilities? Or something else?
How are forecasts for future avoided costs developed?
The avoided cost forecast for net-billing states reflects the hourly marginal energy values for locations around the
Company's system based on the 2023 IRP preferred portfolio. The hourly energy values are weighted for each of
the hourly profiles for different private generation technology types. Avoided cost does not refer to PURPA rates
for qualifyingfacilities.
d) In the June 26-27 presentation, slide 42 states the value of backup power is\u001CIncluded in customer benefits
of PV+Battery technology.\u001D How specifically is the value of backup power used as an input to the
\u001 Chigh\u001 D forecast?
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The value of backup power is used as a direct annual benefit in the economic analysis portion of the modeling
process. This influences customer paybacks and other economic metrics which are inputs in the ultimate adoption
curves.
e) Why does PacifiCorp believe that it is appropriate to assume no value for backup power in the\u001Cbase\u001D
case as well as the\u001Clow\u001D case?
As discussed on stakeholder calls, the scenarios were created to provide a bandwidth of potential DER adoption
futures, and the value of backup power was added in the high case to simulate enhanced adoption tied to actual
customer value placed on having backup power.
f) What assumptions does the distributed generation study include about how customer batteries are dispatched? For
example,how many hours,how many days a year,or which hours?
Part of the modeling process includes an hourly billing analysis that requires customer load and resource dispatch
shapes. Battery dispatch is determined by reducing onsite energy use and customer demand charges (where
applicable). The batteries are assumed to charge/dispatch daily(one cycle/day), and the total hours and time of
day is determined by individual customer load shapes and onsite energy use.
g) Does the presence of solar/storage systems in the adoption forecasts result in a different load profile than solar
alone?
The solar profile in the solar+storage configuration would not change, but storage is used to reduce onsite
customer load and demand charges where applicable. Please see Figure 3-1 in the 2023 report' as an example.
h) Does the load forecast account for the load effects of a customer dispatching their battery, for example in response
to a time of use rate?
Please see Figure 3-1 in the 2023 report' as an example.
i) Have Pacif'iCorp\u0019s past RFPs allowed for distributed generation resources to bid into the RFP?For example,
could a virtual power plant bid into an RFP as a potential resource?
PacifiCorp's 2022 All-Source RFP allowed for all resource types, including demand response resources, which
could be a type of virtual power plant.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
1 "2023-2042 PRIVATE GENERATION FORECAST Behind-The-Meter Resource Assessment:PacifiCorp."Feb 2,2023.Available
online: PacifiCorp Private_Generation_Resource_Assessment.pdf
* Required fields

PacifiCorp - Stakeholder Feedback Form (027)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-0 9
*Name: Kate Bowman Title:
*E-mail: [e-mail] Phone: (801) 872 - 3234
*Organization: vote solar
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Tax Credits
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Questions: In the June 26 - 27 presentation, slide 6 describes Washington UTC
requirements related to the IRA/IIJA. Will the policy statement developed to meet WUTC
requirements only describe and apply to Washington load and resources, or system-wide
load and resources? In the June 26 - 27 presentation, slide 5 states (regarding the ITC
and the PTC) : \u001CThe IRP has included these credits on all future resources built
through 2037\u001D and \u001CBased on location or development, resources can be eligible
for a bonus credit \u0013 ONLY the location bonus is applied in modeling.\u001D Does the
IRP make any resources available for low-income bonus incentives, including the low-
income incentive for solar on commercial and multifamily properties? Does the IRP model
availability of the Energy Communities bonus adder for eligible resources?
Recommendations: Incorporate the Energy Infrastructure Reinvestment Act financing into
the IRP analysis, either by including a tranche of resources that are eligible for the
bonus adder (reflected by incrementally lower costs) or by decrementing eligible resource
costs to reflect the the availability of the Energy Infrastructure Reinvestment Act
financing across a large portion of PacifiCorp\u0019s service territory.
PacifiCorp Response (8/16/2024):
Each model run is made with requirements appropriate for the states participating in
those requirements. Once model runs are completed representing all states, the portfolio
results are integrated, capturing all modeled state requirements in one portfolio. The
integration process ensures that each state' s best portfolio remains whole and that each
resource is shared according to which portfolios included the resource. This approach
combines individual selectivity based on each states' requirements while also avoiding
potential overbuild.
* Required fields

Resources that are eligible for Production Tax Credits or Investment Tax Credits have a
base level of 1000 of the credit applied. Yes, only the location bonus is assumed for
those resources which would be located in eligible coal communities. The IRP has not
assumed the additional bonus for meeting American manufacturing thresholds as that bonus
is outside the bounds of what can be reasonably determined or assured in planning.
As discussed in the August 14-15, 2024 Public Input Meeting, sensitivities will be
performed assuming highly discounted resources based on assuming high levels of IIJA
participation and assuming the pass-through of those benefits to PacifiCorp.
Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (o2s)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-0 9
*Name: Stanley Holmes Title:
*E-mail: [e-mail] Phone:
Utah Citizens Advocating Renewable
*Organization: Energy (UCARE)
Address:
City: Salt Lake City State: UT Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
PLEXOS Modeling and Differential Coal Quality Cost Impacts
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
A review of the 2023 IRP documents suggests that PLEXOS modeling does not distinguish
between different quality grades of coal that may be used in PacifiCorp electricity
generation units; nor does PLEXOS analyze how fuel quality gradients could factor into
least-cost, least-risk portfolio selection. Variations in sulfur, ash minerals, and
moisture content between coal grades could significantly affect costs associated with
coal supply acquisition and inventory maintenance, greenhouse gas emissions reduction,
and waste disposal among other considerations. Coal grades vary not only between mines
but sometimes within the same mine, with some customers getting the preferred grade and
others purchasing lower quality coal. In Utah, PacifiCorp EGUs might face price
competition with Bonanza and Intermountain Power Project (IPP) coal EGUs --plus foreign
exports-- for the best grades of coal, which may sometimes be in short supply. The
Intermountain Power Authority, which owns IPP, has reported to Utah state entities that
"coal costs are rising significantly" and that it "hasn't received its contracted [coal]
tonnage requirements from suppliers for at least nine years. " Unsatisfied with the
quality of coal received from Wyoming, IPA has imported coal from as far away as Indiana.
The Jackson Walker Final Report for Feasibility of Intermountain Power Plant gives an
idea of the coal quantity and quality issues facing operators of coal EGUs in Utah.
The 2025 IRP should address variations in least-cost, least-risk factors if PacifiCorp
coal EGUs burn different fuel grades, given what inventory and availability conditions
may suggest or necessitate. For the 2025 IRP, please specifically identify and, for
comparative resource cost purposes, assess: 1) Grades and amounts of coal currently being
used in PacifiCorp EGUs. . .by individual EGU and in total. 2) Sources of coal from which
PacifiCorp currently purchases, and could purchase, fuel. This includes sources where
PacifiCorp has a proprietary interest, such as the Fossil Rock Mine (aka. Cottonwood
Tract; formerly Mountain Trail Mine) , and those sources that are third-party owned. 3)
Modeling assumptions and sensitivity scenarios for: . . . the use of different grade
* Required fields

coal fuels and the MWh production costs by grade; . . . conditions where competition for
better grade fuel significantly increases costs of acquisition; . . . costs to reduce
emissions and other pollutants resulting from the use of lesser grade fuels; and, . . .
potential additional operations and maintenance costs, and accident liability costs,
resulting from reopening geologically challenged mines, such as Fossil Rock Mine.
Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
IPA purchases coal from Indiana: https://www.argusmedia.com/en/news-and-insights/latest-
market-news/2595473-utah-power-plant-takes-illinois-basin-coal Jackson Walker Report on
IPA/IPP: https://le.utah.gov/interim/2023/pdf/00004542.pdf March 21, 2024 SITLA Agenda
(Cottonwood Tract / Fossil Rock Mine) : https://www.utah.gov/pmn/files/1098477.pdf
SITLA's royalty rate reduction incentive to reopen Fossil Rock mine:
https://www.utah.gov/pmn/files/1103161.pdf
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
For the 2025 IRP, please specifically identify and, for comparative resource cost
purposes, assess: 1) Grades and amounts of coal currently being used in PacifiCorp
EGUs. . .by individual EGU and in total. 2) Sources of coal from which PacifiCorp currently
purchases, and could purchase, fuel. This includes sources where PacifiCorp has a
proprietary interest, such as the Fossil Rock Mine (aka. Cottonwood Tract; formerly
Mountain Trail Mine) , and those sources that are third-party owned. 3) Modeling
assumptions and sensitivity scenarios for: . . . the use of different grade coal fuels
and the MWh production costs by grade; . . . conditions where competition for better
grade fuel significantly increases costs of acquisition; . . . costs to reduce emissions
and other pollutants resulting from the use of lesser grade fuels; and, . . . potential
additional operations and maintenance costs, and accident liability costs, resulting from
reopening geologically challenged mines, such as Fossil Rock Mine.
Response(8/28/2024):
• The PLEXOS model used in the development of the IRP accounts for coal cost on a BTU-adjusted basis. The
effect of other coal quality characteristics, such as Sulfur content,Ash content, etc., on plant operations are
manifest in the operations&maintenance costs assumed for each individual coal unit.These costs are included as
variable costs in the PLEXOS model.
• For clarification purposes,PacifiCorp does not own mines in Utah,including the Fossil Rock mine.
• The Company is considering using high coal costs in the high gas/high CO2 case,where the proposed high coal
costs would be three times the expected costs.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (029)
2025 Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public input meeting and/or stakeholder conference
calls,as scheduled.PacifiCorp values the input of its active and engaged stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp
requests that stakeholders provide comments using this form,which will allow the Company to more easily review and summarize comments by topic and to readily
identify specific recommendations,if any,being provided.Information collected will be used to better inform issues included in the 2025 IRP,including,but not limited
to the process,assumptions,and analysis.In order to maintain open communication and provide the broader Stakeholder community with useful information,the Company
will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 8/9/2024
Sarah Puzzo,Regulatory Associate
*Name: Logan Mitchell,Climate Scientist and Energy Title:
Analyst
* spuzzogUtahCleanEnergy.org,
E-mail: Logankutahcle Phone:
anenergy.org
*Organization: Utah Clean Energy
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
• Modeling coal costs and risks in the 2025 IRP planning process
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
In November 2022,we submitted a stakeholder feedback form requesting information about coal supply chain
issues resulting from the Lila Canyon Coal Mine fire and for ongoing updates as the situation evolved! At the time,the
Lila Canyon coal mine fire was an emerging situation, and PacifiCorp would not speculate about potential impacts. Since
then however,the Company has not provided any updates to stakeholders in the 2025 IRP public input meetings.Yet in
recent months coal supply issues have been addressed at length in other forums:
• Docket No. 24-035-13: In their audit of PacifiCorp's fuel inventory prices,the Division wrote about PacifiCorp's
fuel inventory report and described coal fuel supply disruptions and other force majeure events at coal mines that
affected coal supplies in Utah.Many of the details of the report are redacted,however.'
• Docket No.24-035-04: In his Direct Testimony,Ramon Mitchell provides another,more comprehensive
description of the situation and its impact on the Company's application for a rate increase.'Mitchell's testimony
reveals an extensive list of issues affecting coal supplies and costs in Utah:
o "In 2022 through 2024,the coal market experienced strained conditions. The unprecedented increase in
coal prices, instability in coal supply and overall market fluctuations have caused adverse impacts to the
Company and other large consumers. This negative impact is due to multiple factors,including but not
limited to: (1)increased coal demand due to high domestic natural gas prices; (2)low inventories at coal-
fired power plants; (3) increased demand abroad for coal exports; (4)international and domestic supply
chain constraints; (5)labor and material shortages; and(6)weather events and general market inflation.
Moreover,the Lila Canyon mine fire removed approximately 25 percent of Utah coal production
and disrupted the same portion of the Company's coal supply needs in Utah. On November 18, 2023,the
Company was informed that the Lila Canyon mine will not reopen and will be permanently closed. The
' See.https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023-irp/2023-ir -
comments/2023.031.%20Utah°/o20Clean%20Energy%2011-23-22%20(with%20response).pdf.
'See https:Hpscdocs.utah.gov/electric/24docs/2403513/333586RdctdDPUCmnts4-30-2024.pdf.
' See https:Hpscdocs.utah.gov/electric/24docs/2403504/334494RdctdDirTstmnyRamonJMitchelIRMP6-28-2024.pdf.
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closure of Lila Canyon created a significant coal production shortfall in Utah in 2023 and will continue to
have negative impacts to all large consumers, including the Company, in 2024 and potentially 2025.
In addition to the Lila Canyon mine issues in Utah, coal suppliers continue to experience issues
relating to unfavorable geologic and mining conditions, delays and pressure relating to securing federal
mining leases, limited availability of trucking and railway transportation for coal, long lead-times for
procurement of necessary mining equipment,and limitations in availability of financing,which has put
them at an increased risk of becoming insolvent. . . . The impact of these coal supply challenges is an
increase of$264 million on a total-company basis. This increase is driven by increased market purchases
to cover the generation reduction. ,4
Examining EIA data on coal costs provided to the Hunter coal plant,the weighted average coal prices
dramatically increased by 41%in 2023 compared to prior years:5
Average Coal Price($/ton),Hunter Coal Plant
$65.00
$60.00
$55.00
$50.00
$45.00
$40.00
$35.00 - - - -
$30.00 - - - -
$25.00 -
2008 2010 2012 2014 2016 2018 2020 2022 2024
Source:EIA,analysis by Utah Clean Energy
In addition, DPU's audit mentioned above noted that,due to the coal supply chain issues in Utah, S&P Capital IQ
reported that the capacity factor at Hunter decreased from 61.8%in 2022 to only 32.9%in 2023. This decreasing capacity
factor is confirmed in EIA's electricity data browser:6
Hunter,monthly t DOWNLOAD
megamtthoum
1.000,000
750,000
500,000
250,000
2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024
Net generation-all primern—m-
eia) Data source.US Energy Intormat—Anministration
4 See id. at 20-22.
5 See https://www.eia.gov/coal/data/browser/#/shipments/plant/6165/?freq=A&pin=.
6 See.https://www.eia.gov/electricityZdata/browser/#/plant/6165.
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This decreasing capacity factor raises reliability concerns as explained by NERC's 2024 State of Reliability
Report identifies.NERC has observed an increasing trend of weighted equivalent forced-outage rates (WEFOR) for coal
resources:7
Ch*ter 4:Grid Performance
14% Resource Mix%
11 % Nuclear,10%
Hydro,12% Other,9%
12%
Coal,22%
10%
Gas,48%
z
2 8%
6.4%
3
6%
4%
2%
2%
0%
2014 tU18 2023 2014 1018 M23 2014 2018 2023 2014 2018 2023
OCoal OGas Hydro (✓•Nuclear —2019-2023 WEFOR by Fuel Type
Figure 4.5:10-Year Annual WEFOR by Fuel Type and 2023 Resource Mix by Net Maximum
Capacity
NERC's report examined the rising trend of forced outage rates of coal and found that it correlates mostly closely
with capacity factors falling below 60%. The report states:
"Although coal-fired generation experienced a large decrease in WEFOR in 2023 (12.0%in 2023 versus 13.9%in
2022), it remains above pre-2021 rates.Due to year-over-year variability, coal generation is the primary driver of
change in the overall WEFOR despite more energy being produced by both natural gas and nuclear power in
2023. Further investigation into baseload coal generation indicates that a unit's WEFOR negatively correlates
most strongly to capacity factor. Notably, once capacity factor falls below approximately 60%, unweighted
average EFORs of units begin increasing more rapidly than those between 60%and 100%. Although forced-
outage hours are a definite contributor to lower capacity factor units' increased WEFOR,the disproportionate
change appears to be driven more by maintenance/planned outage hours and decreased service hours. This aligns
with industry statements indicating that reduced investment in maintenance and abnormal cycling that are being
adopted primarily in response to rapid changes in the resource mix are negatively impacting baseload coal unit
performance."'
The recent real-world experience of an exceptionally fragile coal supply chain and volatile global market prices
that will cost ratepayers hundreds of millions of dollars of additional costs has exposed the true costs and risks of
PacifiCorp's overreliance on coal. These risks and costs are in addition to the carbon pollution driving the changing
climate and causing societal impacts like increasing wildfire risks,which are also impacting ratepayers. Therefore, it is
imperative to understand how these costs and risks are incorporated in PacifiCorp's 2025 IRP,which includes the
quantitative modeling aspects and the qualitative assessments.
To better understand how spiking coal costs and risks affect the 2025 IRP modeling,we request the following
information:
1. How are coal costs represented in PLEXOS?Is there an average price used for all coal plants, or are coal
prices specific to each coal plant?If an average price for all coal plants is used,how are price spikes such as
those in Utah reflected in PLEXOS? Similarly,how are operations and maintenance costs reflected?What
costs are excluded from the PLEXOS model because they're considered"sunk"or"fixed"costs?How many
coal plants have"minimum take"requirements?
https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%2ODL/NERC_SOR 2024_Technical_Assessment.pdf,at 59.
8 Id.
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Reply:
■ Coal costs in PLEXOS are specific to the plant. Costs at Bridger differ from costs at Hunter(as an
example). Coal prices are based on anticipated levels of supply at a specific price point. Data is put into
the model as $/MMBTU for the cost, and as a quantity of MMBTU that are available.Many coal plants
(but not all)have multiple coal fuels available(an initial amount at a certain price,then a"tier 2"fuel
with some other amount available at a higher price etc.).
■ Fixed Operations and Maintenance(O&M)costs, and ongoing capital costs are modeled as a single
levelized fixed Operations cost.Any ongoing capital that is not recovered is added to the retirement cost
on a declining balance basis so the model does see an ability to"get out'of the balance of the cost by
retiring the unit.
■ No coal plants were modeled with minimum take requirements in the 2023 IRP. For the 2025 IRP,there
is a contract in place for Hunter/Huntington that may require representation in PLEXOS modeling
through 2030, after which time the requirement would be released.
2. Coal fuel costs are a critical factor to consider in terms of understanding how different resources compare to
each other and contribute to overall portfolio costs. In past IRPs, Chapter 3 has had a section on Natural Gas
Prices that includes Henry Hub Price Forecasts. Coal prices should also have a forecast in the 2025 IRP. A
coal price forecast should start at prices consistent with current market conditions and should assume
escalating prices into the future given the state of the market.Please provide the coal price forecast that is
used to inform the PLEXOS model.We understand that specific coal contract terms cannot be revealed
publicly,but there must be a way to aggregate the data in a meaningful way for public disclosure, for example
by overall price at the plant level like the EIA data shown above.
Reply:
• The coal costs used for PLEXOS modeling is available in the Master Assumptions folders on the
confidential data disc.
3. Additionally,please report the cost of coal in terms of$/MWh for the 20-year planning horizon, including
fuel, fuel transportation, operations,maintenance, depreciation and any other relevant costs. Please describe
which costs are included in the $/MWh and which costs are not included.
Reply:
• As discussed in the August 14-15,2024 Public Input Meeting, coal use is heavily dependent upon the heat
rate curve of the coal plants in question, and the number of MW produced by the plant varies based on the
heat rate curve. O&M numbers are aggregated for each thermal unit, and are not broken out by type of
O&M, so providing the specific coal related O&M Costs used by the model is not feasible. All costs
associated with the delivery and combustion of coal are incorporated into the fuel price used.
4. Given recent changes in coal suppliers,please describe how variations in coal composition and quality, such
as the content of sulfur, ash, and moisture,will affect coal plant heat rate and efficiency. How does coal
quality affect the price of the electricity produced in$/MWh?Will changes in coal quality affect the
maintenance or reliability of plants?Are coal composition factors modeled within PLEXOS for each coal
plant?
Reply
• As discussed in the August 14-15,2024 Public Input Meeting, coal fuel characteristics are all included in
the fuel price and emissions rate per MMBTU of fuel consumed. These figures and characteristics are
aggregated across the coal supply for each plant and are not broken out independently.
5. How will changes in coal suppliers and quality affect emissions from the plants in terms of NOx, S02, and
carbon?
Reply
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• As discussed in the August 14-15, 2024 Public Input Meeting, emissions rates per MMBTU of fuel
consumed are determined in forecasts provided to the IRP team. Should changes in forecasted supply
quality cause these rates to change,these rates would be aggregated and updated to reflect that change.
All of PacifCorp's coal units are required to meet NOx and SO2 rates that are based on permitted limits.
PacifiCorp will continue to meet these NOx and SO2 rates regardless of coal quality. CO2 emissions could
increase or decrease based on coal quality and gross calorific heat value but will generally increase with
lower coal rank and quality.
6. Please describe how coal fuel supply risks will affect the planning reserve margin given recent experience that
supply chain disruptions caused significantly reduced capacity factors for Utah coal plants.
Reply
• PacifiCorp's IRP plans to meet the hourly demand requirements of the system,including reserves
requirements. To the extent outages are higher, or reserve holding capabilities of plants are diminished,
and additional resources are selected in the IRP model to meet PacifiCorp's obligations.
7. Please describe how coal plant reliability metrics are being tracked as their capacity factor decreases. How are
these reliability metrics being incorporated into the 2025 IRP modeling process?
Reply
• As discussed in the August 14-15,2024 Public Input Meeting during the Daily Shapes portion of the
presentation,historical actuals are being used in modeling.
8. How are disruptions like the recent Lila Canyon coal mine fire being incorporated into stochastic risk metrics
throughout the planning horizon?For example,how would a coal supply disruption in a specific year affect a
given portfolio (e.g. a force majeure event in 2030 removing>25%of coal supply)?Disruptions like this
should be examined for cost and reliability metrics.
Reply
• Depending on incoming requests and requirements,PacifiCorp is willing to consider a sensitivity
changing coal supply assumptions.
9. In DPU's review of PacifiCorp's coal fuel supply report linked above,they discussed six PLEXOS scenarios
that were run to examine coal risks (pg 8),however the DPU's description of those scenarios was partially
redacted. Please provide an un-redacted and detailed description of those scenarios and the conclusions from
them.
Reply
• In February 2024,PacifiCorp evaluated six different scenarios for the Hunter and Huntington Plants using
different assumptions and inputs to the PLEXOS model. The base scenario assumed the coal supply
agreements (CSA)at the Hunter and Huntington plants with Wolverine Fuels,the principal coal supplier
in Utah,were renegotiated and amended. The alternative scenarios assumed other coal supply options
and/or market conditions. The evaluation assessed the total cost of each scenario on a present value
revenue requirement(PVRR)basis. The cost of the base scenario was significantly lower than the other
scenarios and led to PacifiCorp's decision to amend the Hunter/Wolverine CSA and
Huntington/Wolverine CSA. The following is a brief description of the different scenarios:
• Scenario 1 -The Hunter/Wolverine CSA is amended to include additional years to the term. The
prospective Fossil Rock Mine will begin to provide volumes to Hunter in 2025. The
Huntington/Wolverine CSA is amended with no extension of the current 2029 term. The Utah coal market
becomes stable again and generation constraints recede.
• Scenario 2 -PacifiCorp does not sign amendments with Wolverine.Pricing is assumed to be reset to
current Utah market prices which is higher than the anticipated Hunter/Wolverine and
* Required fields

Huntington/Wolverine amendments. The Fossil Rock Mine does not reopen and coal supply in Utah
remains constrained and unstable.
• Scenario 3 -PacifiCorp does not sign amendments with Wolverine.Pricing is assumed to be reset to
current Utah market prices.Wolverine does eventually reopen the Fossil Rock Mine, and the Utah coal
market becomes more stable.
• Scenario 4 -PacifiCorp does not sign amendments with Wolverine.PacifiCorp's existing contracts are
terminated, and the pricing is assumed to be reset to current Utah market prices plus a premium price
which assumes fewer coal suppliers in the region. The Fossil Rock Mine does not reopen and coal supply
in Utah remains constrained and unstable.
• Scenario 5 -PacifiCorp does not sign amendments with Wolverine.PacifiCorp receives limited Utah
market coal supply for a period.PacifiCorp spends capital to build a rail unloading facility in central Utah
and modify the Utah Plants to consume Powder River Basin coal.
• Scenario 6 -PacifiCorp does not sign amendments with Wolverine. PacifiCorp receives limited Utah
market coal supply for a period. PacifiCorp spends capital to build a rail unloading facility in central Utah
and purchases additional coal from Colorado mines.
Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e. gas forecast is too high-this forecast from EIA is more
appropriate).If electronic attachments are provided with your comments,please list those attachment names here.
- See footnotes.
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
- See above
Please submit your completed Stakeholder Feedback Form via email to IRPkPacificorp.com
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (030)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-13
*Name: Katie Pappas Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Ratepayer
Address: 424 K s t
City: Salt Lake City State: UT Zip: 84103
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Proposed Rocky Mountain Power Rate Increase in Utah
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Rocky Mountain Power, with help from the Utah legislature and governor\u0019s office,
wants all of us in Utah to foot the bill, in a backward attempt to prop up what\u0019s
left of the Utah coal industry. Rather than move toward a more sustainable, healthier,
lower energy cost future, they are hellbent on prolonging dependence on dirty fossil
fuels. Why? Ironically, the very issues their rate increases seek to address are made
worse by their climate busting practices. Utah has an opportunity to be a leader
in the development of several cheaper, greener energy sources that actually cost less,
don\u0019t pollute our air and won\u0019t negatively impact our health. We have never
factored in the external costs of burning fossil fuels but now spend billions to mitigate
damage caused by climate change. Utahns deserve better. Our energy policies and
decisions should be guided by science, not by politicians and corporations. Please oppose
this outrageous assault on ratepayers. Katie Pappas Salt Lake City, UT
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp Response (8/29/2024):
Thank you for your feedback. PacifiCorp uses the Integrated Resource Planning process to select the least-cost, least-risk
portfolio given prevailing conditions at the time of planning. Renewable energy is a critical component of PacifiCorp's
resource mixture and will make up an increasing proportion of the energy generated by the PacifiCorp system over time.
* Required fields

Pages 6-7 of the 2023 IRP Update report that the preferred portfolio includes 3,749 megawatts of new solar online by
2037, 9,800 megawatts of new wind resources online by 2037, and more than 4,000 megawatts of new storage capacity
online by 2037.While renewable energy plays an ever-growing role in PacifiCorp's resource mixture,PacifiCorp's
diverse portfolio of resources help to ensure system reliability during critical hours. In the 2023 IRP Update,thermal
resources operated at a low-capacity factor in future years but were critical in ensuring system reliability during peak load
hours. PacifiCorp is committed to achieving emissions reduction targets as required by state and federal regulatory
obligations and welcomes the development of alternative fuel sources that can provide a similar level of system flexibility
as traditional thermal resources at reduced emissions rates.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (031)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any, being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-13
*Name: Jane Myers Title:
*E-mail: [e-mail] Phone: (801) 081 - 4315
*Organization: rate payer
Address: 5317 W Wheatridge Ln
City: West Jordan State: UT Zip: 84081
Public Meeting Date comments address: 0 8-14-2 0 2 4 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
I am addressing the 30% rate increase that is "serving and benefiting Utah customers."
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
After returning from Scandinavia, I am shocked that we are still stressing coal in our
energy policies. Even though Norway has found oil, they have 88% hydro power and are
using more wind and solar. The coal is more expensive and dirtier for our unhealthy air
quality in Utah than even natural gas (which is also readily available) .
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high- this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list
those attachment names here.
https://energifaktanorge.no/en/norsk-energiforsyning/kraftproduksjon/
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
We have roof-top solar. The transmission lines are already in existence. Batteries can be
added. We should not be pursuing coal in our future plans and we should be putting in
many more transmission lines for the energy needs five years from now. We should be
putting in more wind production. Our air quality is steadily getting worse, which effects
climate change and global warming.
PacifiCorp Response (8/29/2024):
Thank you for your feedback. PacifiCorp uses the Integrated Resource Planning process to select the least-cost, least-risk
portfolio given prevailing conditions at the time of planning. Renewable energy is a critical component of PacifiCorp's
resource mixture and will make up an increasing proportion of the energy generated by the PacifiCorp system over time.
Pages 6-7 of the 2023 IRP Update report that the preferred portfolio includes 3,749 megawatts of new solar online by
2037, 9,800 megawatts of new wind resources online by 2037, and more than 4,000 megawatts of new storage capacity
online by 2037. PacifiCorp welcomes specific suggestions to enhance cost and other input assumptions for all types of
resources. These assumptions are critical inputs that drive Plexos model selections. While renewable energy plays an
* Required fields

ever-growing role in PacifiCorp's resource mixture,PacifiCorp's diverse portfolio of resources help to ensure system
reliability during critical hours. In the 2023 IRP Update,thermal resources operated at a low-capacity factor in future
years but were critical in ensuring system reliability during peak load hours. PacifiCorp is committed to achieving
emissions reduction targets as required by state and federal regulatory obligations and welcomes the development of
alternative fuel sources that can provide a similar level of system flexibility as traditional thermal resources at reduced
emissions rates.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (032)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any, being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-14
*Name: Sara Kenney Title:
*E-mail: —[e-mail] Phone:
*Organization: N/A
Address:
City: Lehi State: UT Zip: 84043
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Carbon Dioxide Emissions
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
I object to the reduction in your renewable energy portfolio mix and the increase in
emissions resulting from this decision to continue to rely on coal and fossil fuels more
than renewables. Pacificorp should be able to read the room and realize just because the
our legislators and conservative courts are making it easier for you to continue relying
on fossil fuels, doesn't make it the right choice. Regardless of your obligation to
compliance or laws, you should be thinking about the future of our children and our
environment. Allowing for a long term increase in emissions compared to even the original
2023 plan, is a failure of leadership on your part. Renewable energy is cheaper, just as
reliable and better for the environment and public health than coal and fossil fuels. To
quote a recept op ed in the Desert by Malin Moench, " The premium that utilities now pay
to use coal rather than renewables averages 30% nationally, but is 50% for RMP\u0019s
Utah coal plants, according to national plant-specific cost data compiled in a recent
study. From these data, we can calculate that RMP could avoid operating costs of $260
million annually by switching from coal to solar \u0014 savings large enough to pay for
full battery backup for such solar facilities." Pacificorp and Rocky Mountain Power
should take advantage of IRA funding to increase renewable energy now, not later on when
it's too late. Do the right thing and make the switch to renewable energy now. Thank you.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high- this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list
those attachment names here.
https://www.deseret.com/opinion/2024/08/11/rocky-mountain-power-rate-hike-legislation-
blocking-renewable-energy/
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
* Required fields

PacifiCorp Response (8/29/2024):
Thank you for your feedback. PacifiCorp uses the Integrated Resource Planning process to select the least-cost, least-risk
portfolio given prevailing conditions at the time of planning. Renewable energy is a critical component of PacifiCorp's
resource mixture and will make up an increasing proportion of the energy generated by the PacifiCorp system over time.
Pages 6-7 of the 2023 IRP Update report that the preferred portfolio includes 3,749 megawatts of new solar online by
2037, 9,800 megawatts of new wind resources online by 2037, and more than 4,000 megawatts of new storage capacity
online by 2037. PacifiCorp welcomes specific suggestions to enhance cost and other input assumptions for all types of
resources. These assumptions are critical inputs that drive Plexos model selections. While renewable energy plays an
ever-growing role in PacifiCorp's resource mixture,PacifiCorp's diverse portfolio of resources help to ensure system
reliability during critical hours. In the 2023 IRP Update,thermal resources operated at a low-capacity factor in future
years but were critical in ensuring system reliability during peak load hours. PacifiCorp is committed to achieving
emissions reduction targets as required by state and federal regulatory obligations and welcomes the development of
alternative fuel sources that can provide a similar level of system flexibility as traditional thermal resources at reduced
emissions rates.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (035)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-08-20
*Name: John Jenks Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Wyoming Energy Authority
Address: 1912 Capitol Ave #305
City: Cheyenne State: Zip: 82001
Public Meeting Date comments address: 0 8-14-2 0 2 4 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
2025 IRP Study List Update
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the August 14, 2024 IRP Stakeholder Meeting, PacifiCorp representatives were giving
updates on various IRP studies and particularly the sensitives given to each state. For
Wyoming in particular, there is a line that reads, \u001CBusiness as usual.\u001D I asked
a clarifying question as to what is meant by, \u001CBusiness as usual.\u001D I was
curious if this meant projected load growth both in the state and throughout the service
territory was being considered because if it is, there could be some concern regarding
study sensitives being labeled as constant or \u001Cbusiness as usual, \u001D especially
in terms of considerations with generation resources. There was quite a bit of confusion
and vagueness here and the RMP representatives weren\u0019t quite sure, either.
Unfortunately, the recording is missing this part on the YouTube videos, too. So largely,
can PacifiCorp please clarify what is meant and what assumption are being used for
\u001Cbusiness as usual?\u001D Thank you. OP
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp should clarify and clearly articulate the assumptions being used for "business
as usual" in Wyoming and how this is affecting the modeling for the 2025 IRP.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
* Required fields

Thank you for participating.
PacifiCorp Response (9/10/2024):
Thank you for your feedback and engagement in the Integrated Resource Planning process.
Per the Wyoming Public Service Commission's(WPSC)2019 Investigation Order(DOCKET NO. 90000-144-XI-19, and
DOCKET NO. 90000-147-XI-19), "reference case"is the formal terminology for the business-as-usual study. Regarding
this study,the WPSC mandates the following:
In the anticipated 2021 IRP, and in IRPs and updates thereto filed by the Company
thereafter,Rocky Mountain Power shall:
a)Include a Reference Case based on the 2017 IRP Updated Preferred
Portfolio, incorporating updated assumptions, such as load and market prices and any
known changes to system resources and only incorporate environmental investments or
costs required by current law;
It is therefore not acceptable to hold load constant. PacifiCorp supports the commission's language as being necessary to
produce a study that reflects a reference case which accounts for known commitments,requirements and key updates that
have occurred since the 20217 IRP Update.Primarily,PacificCorp adheres to this required study, as defined by the
commission,by aligning thermal retirement options in the model to those represented in the outcome of the 2017 IRP
Update preferred portfolio. The study is also based on a price-policy scenario that does not have a CO2 proxy adder,
which in past IRPs is referred to as the medium-gas,no CO2 (MN) scenario.
In the 2025 IRP,PacifiCorp expects to produce a business-as-usual(BAU) systemwide study for its reference case using
updated inputs and forecasts, including an updated load forecast. End-of-life retirements will be assumed for all thermal
resources that have not already committed to a specific future such as an established retirement date.
* Required fields

PacifiCorp - Stakeholder Feedback Form (036)
2025 Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public input meeting and/or stakeholder conference
calls,as scheduled.PacifiCorp values the input of its active and engaged stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp
requests that stakeholders provide comments using this form,which will allow the Company to more easily review and summarize comments by topic and to readily
identify specific recommendations,if any,being provided.Information collected will be used to better inform issues included in the 2025 1",including,but not limited
to the process,assumptions,and analysis.In order to maintain open communication and provide the broader Stakeholder community with useful information,the Company
will generally post all appropriate feedback on the IRP website unless you request otherwise,below.
Date of Submittal 8/27/2024
*Name: Rose Monahan Title: Staff Attorney
*E-mail: Rose.monahangsierraclub.org Phone: [phone]
*Organization: Sierra Club
Address: 2101 Webster Street,Suite 1300
City: Oakland State: CA Zip: 94612
Public Meeting Date comments address: ❑ Check here if not related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s)and/or Agenda Items: List the specific topics that are being addressed in your comments.
• Demand side management
• Granularity Adjustments
• Reliability Adjustments
• EIR
• Federal Regulations
• Resource Availability
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP
website.
*Respondent Comment: Please provide your feedback for each IItP topic listed above.
Sierra Club provides the following recommendations for PacifiCorp's 2025 IRP. Additional information
supporting these recommendations is attached to this Stakeholder Feedback Form
1. Demand Side Management
a. EE Supply Curves
i. Provide sufficient time for review of the EE supply curves and the opportunity to suggest
changes prior to modeling.
ii. Remove any cost thresholds above which EE measures cannot be considered for IRP
model selection, and instead include all possible EE measure bundles in the supply curve
and allow the model to select the bundles that minimize cost across the entire resource
portfolio
iii. Ensure that administrative costs are aligned with real-world administrative costs for
utility EE portfolios (i.e., less than 10%)
iv. Assume at a minimum EE measure incentive levels at 75-100%, and consider incentive
levels exceeding 100% (e.g., 125%, 150%)
v. Additional flexible load options:
* Required fields

1. Include bidirectional charging as a resource option
2. Consult with the Vehicle Grid Integration Council on best practices for
developing new vehicle to grid program opportunities
3. Consider new flexible load options for new large load customers,particularly data
centers
vi. Consider incremental heat pump costs relative to both a heating and cooling baseline
technology, informed by recent research on heat pump costs and available federal
incentives, including information already compiled by Calmus on behalf of PSE (and
excerpted below).
b. Include EE/DR bundles as potential reliability adjustment resources
Reply:
a. i. Thank you for your feedback. The energy efficiency options for use in the IRP modeling
are developed by an outside consultant, Applied Energy Group (AEG). AEG has presented
their findings and plan related to the Conservation Potential Assessment(CPA) in several
IRP Public Input Meetings within the 2025 IRP Planning cycle. Planning and timelines for
the CPA were presented in the January 25, 2024 Public Meeting with information starting on
slide 19. Further conversation and opportunity for feedback related to the CPA took place in
the May 2 and July 17/18 Public Input Meetings (starting on slide 5 and 75 respectively) and
will be included in the upcoming September meeting. AEG provided forums and
opportunities for engagement outside of these meetings. Due to the time required to develop
CPA outcomes and also continuously review stages of work with feedback from
stakeholders, this timeline would be challenging to accelerate beyond the acceleration that
has already occurred.
ii. PacifiCorp does not, nor has it ever, applied any cost threshold above which DSM-EE
measures cannot be considered for selection in the IRP.
iii. Thank you for the suggestion. PacifiCorp is currently working with AEG to examine the
way it will be modeling these administrative costs across all states in the 2025 CPA,based
on historical annual report trends.
iv. Thank you for the suggestion. PacifiCorp is currently working with AEG to examine
modeled EE measure level incentives for the 2025 CPA.
v. AEG will be sharing details about demand response modeling methodology in the
upcoming public input meeting September 25-26, 2024.
vi. Thank you for sharing the relevant Cadmus study. The CPA currently does include both
baseline type costs for heat pumps in the characterization, in line with Rocky Mountain
Power programs.
b. All resources (including EE/DR bundles) are eligible to be selected to cover ST reported,
shortfall-adjusted load in following iterations of the LT model.
2. Granularity Adjustments
a. Reporting Recommendations
i. Report steps taken to reduce out-of-model granularity adjustments, including any
differences between the 2025 and 2023 methodology, including whether decreasing fixed
cost(slide 44, March meeting) was part of the process in 2023 and if not, how that
addition is improving the granularity adjustment process.
ii. Clearly report methodology, values, and impacts of adjustments.
b. Modeling Recommendations
i. Granularity adjustments should primarily be applied to flexible resources, i.e. resources
the value of which is not fully captured in the LT model because of the lower temporal
resolution: energy storage and peakers.

ii. Ensure that the energy value of a resource's output in the LT Model and that in the ST
model include the same cost components for a consistent comparison.
Reply:
a. The Granularity Adjustment is inherently an "in-model" adjustment as it directly takes
model outputs and feeds them back into PLEXOS. In order to review model results and
verify reasonability of model outcomes, there is a reporting "pause" in this step, however
there could be a direct loop setup in PLEXOS that would integrate the differences between
LT and ST values directly in model runs.
i. The Granularity Adjustment has always either been a cost increase (for items the
LT views as more valuable than the ST) or a cost decrease (for items the LT views
as less valuable than the ST).
ii. In the 2023 IRP update, granularity adjustments were calculated automatically on
each portfolio based on the difference between the LT and ST value of each
resource. This value was fed back into the LT models for each following iteration
(i.e. iteration 2 used values from iteration 1; iteration 3 used values from iteration 2
etc.). This methodology was discussed in the narrative of the 23 IRP Update, and
the values of all granularity adjustments were included on the data disc.
b. Granularity adjustments are applied to all resources, and applying a granularity adjustment
to only a subset of resource types would skew the value of those resources relative to other
options. The automatic calculation of the difference between values in the LT and ST is
part of an iterative process, which has been reviewed by modeling consultants with
Energy Exemplar. PacifiCorp's process of using a granularity adjustment has been
described by Energy Exemplar as a "gold standard" of model use. Additionally, a member
of the PacifiCorp IRP team has been asked to present on PacifiCorp's granularity
adjustment and reliability load adder at an Energy Exemplar symposium in Seattle on
October 15. The company expects this modeling approach will help other clients obtain
better results.
The granularity adjustment is calculated automatically in the same way for each resource
from the PLEXOS LT and ST output and can be viewed in reporting on the data disc.
3. Reliability Adjustments
a. Reporting Recommendations
i. Provide PLEXOS output files for the initial and reliability-adjusted portfolios, as well as
a spreadsheet mapping the initial and reliability-adjusted portfolios,together with a list of
the resources that have been added, removed, delayed, or in any way adjusted by the
Company, and a justification for this choice.
b. Modeling Recommendations
i. Provide details on the rationale and methodology of reliability adjustments during the
public input meetings prior to the filing of the draft IRP.
ii. Provide stakeholders with an opportunity to recommend alternative reliability
adjustments.
iii. Resources options considered for addressing the identified reliability issues should
include renewable energy sources, energy storage, and demand side resources.
Reply:
a. In the 2023 IRP Update, PacifiCorp allowed the model to endogenously select all
resources and made no resource additions outside the model for the purpose of achieving
reliability. As such, there is no reporting of resources that have been manually adjusted by
the company because the company did not manually adjust resource selections.

Reliability in the 2023 IRP update was achieved by adding hourly shortfalls identified by
the ST model to the base LT load file and allowing the PLEXOS model to select a new
suite of resources based on this additional load. All LT model reports were published on
the Data Disc, and by comparing iteration 1 to iteration 2 it is possible to see the change in
resources (due to both the granularity adjustment and also the additional load).
In light of stakeholder feedback, PacifiCorp has confirmed with Energy Exemplar
consultants this is an appropriate use of model functionality and data. Energy Exemplar
consultants have described PacifiCorp's iterative approach as the "gold standard".
b. Given the above process, where the model endogenously selects resources for reliability,
responses are as follows:
i. The model is endogenously selecting resources based on the methodology of
adding shortages to the load file; there is no exogenous selection of resources thus
no rationale/methodology to explicitly explain.
ii. Stakeholders are welcome to recommend alternatives to the endogenous selections
at any point, but note there are no exogenous reliability adjustments, and given the
updated process, no exogenous additions or adjustments to the portfolio are
considered.
iii. The model considers ALL modeled resource options to cover the load; resources
are selected using PLEXOS core functionality and data.
4. Energy Infrastructure Reinvestment Program
a. Reporting Recommendation
i. Provide an update on PacifiCorp's efforts to secure EIR financing from the DOE Loan
Program Office and any analysis that has been conducted to assess the associated
benefits.
b. Modeling Recommendation
i. Incorporate financing opportunities made available under the EIR program, which can
enable the closure of coal plants, the replacement of fossil resources with cleaner
alternatives, and the development of transmission infrastructure. Specifically,PacifiCorp
should conduct:
1. A scenario in which transmission network upgrade costs in Cluster Areas 1, 2,4,
12, and 14 are reduced by 30 percent; and
2. A scenario in which EIR financing is assumed for early retirement and
replacement of Jim Bridger Units 3 and 4, Huntington,Hunter, and Wyodak. In
this scenario the model should be allowed to select the economic retirement of
those units assuming EIR financing.
Reply:
a. Thank you for your feedback. Opportunities are being evaluated and pursued; PacifiCorp
will provide a public update of these activities when available. Sensitivity studies are
planned to assess high, medium and low levels of program adoption relevant to the IRA
and IIJA.
b. As discussed in the August Public Input Meeting, PacifiCorp is evaluating an extremely
low cost renewables scenario which leverages the lowest required return on investment at
the standard Investment Tax Credit rate for a resource (assuming federally subsidized
financing), the most aggressive cost decline curves from NREL, and extending the
construction timing eligibility for Production Tax Credits indefinitely. PacifiCorp believes
modeling these parameters for future proxy resources is a reasonable representation of

being able to acquire resources while successfully leveraging every possible program.
5. Compliance with Federal Regulations
a. Clean Air Act 111(d) Regulation & CO2 Price Assumptions
i. Compliance with the EPA 111(d) rule should be modeled as part of the base model, not
as a variant or price-policy scenario (MR). The five price-policy scenarios (including
MM), as defined in the 2023 IRP analysis can be used, with all of them requiring Section
111(d) compliance of existing coal and new gas resources, while the N, M, H, and SC
assumptions will define the CO2 price in addition to the required EPA 111(d)
compliance.
ii. CO2 prices should be included in LT,but the Company should also conduct and report
ST results without the carbon cost included in the dispatch decisions.
iii. Cumulative carbon costs associated with each portfolio, although not included in dispatch
decisions, should be reported through a post-optimization calculation.
iv. Variants that perform well should have LT runs presented for all price-policy scenarios.
b. Regional Haze Program
i. As part of the base model (i.e., included in all portfolio runs), include an SCR
requirement at Hunter 2, Huntington 1 and Huntington 2. Additionally, require that the
model select either SCR or SNCR at Naughton, Wyodak, and Dave Johnston 1, 2, and 4.
ii. As a variant case, include an SCR requirement at all five units at Hunter and Huntington,
while keeping the same modeling assumptions at the Wyoming units.
Reply:
a. A CO2 Price has always been intended to be representative of future policy driving towards
the reduction in CO2 emissions (excepting where there is a legally binding price in
existence such as the Social Cost for Washington, or the Carbon adder at Chehalis).
Including EPA 111(d) compliance in the Low/No and Medium/No price-policy scenarios
would be counter to evaluating portfolios developed in an environment where policy is
ultimately not implemented. Given the Medium CO2 case is intended to represent
"expected" future policy, replacing this assumption with a currently articulated future
policy (EPA 111(d)) seems the most prudent action for the Medium case. The High case
would be intended to explore a future where the cost of compliance is even higher than
meeting EPA 111(d). Note that the Social Cost of Greenhouse Gasses price-policy view is
mandated under Washington law.
i. See the reply to part a) above
ii. PacifiCorp currently evaluates candidate portfolios under other price-policy
scenarios and will continue to do so. Reporting on each of these is provided in the
document and on the data disc.
iii. PacifiCorp would be interested to understand what types of calculations Sierra
Club would propose. The currently provided emissions output data may be
sufficient if the desire is to apply additional emission costs on a post-model basis.
iv. Given the number of model runs required, PacifiCorp will be developing portfolios
for variants under an MN future. As discussed in response to part ii, these
portfolios will be evaluated under all identified price-policy futures. Variant
portfolios will not be developed under every price-policy scenario.
b. Please see responses below:
i. Emissions reductions from these technologies are available in practice, and the
effective cost per ton of potential emissions reductions from installation of SNCR
or SCR can be calculated the model results. Because both SNCR and SCR

technology have little impact on resource operating parameters such as heat rate
and maximum output, there would be little impact on system dispatch from
including those options in the model.
The model will have an availability to select CCUS (including SCR technology) at
each of these locations and can make that selection independent of the selections at
other sites, excepting locations where other environmental compliance
requirements would prevent continued coal-fired operation:
1. Naughton 1&2 which are currently slated to either gas convert in 2026 or
retire
2. Dave Johnston 1&2 which are currently slated to retire in 2028 with an option
to gas convert to continue operating after that date.
ii. As above, the model will be able to select CCUS (including SCR technology) at
the above sites.
6. Resource Availability
a. Evaluate whether there are resource bids proposed in the 2022 RFP that could be available prior
to 2028 and include those resource options in the model
Reply:
a. Any cluster study/transmission options that are eligible to be in service prior to 2028 will
be included as proxy resource options starting in 2027.
Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments.(i.e.gas forecast is too high-this forecast from EIA is more
appropriate).If electronic attachments are provided with your comments,please list those attachment names here.
Please see attached
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
Please see above
Please submit your completed Stakeholder Feedback Form via email to IRPgPacificorp.com
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Feedback on Paci#iCorp 2025 IRP
Demand Side Management
1. Review of EE Supply Curves
In the May 2, 2024 stakeholder meeting, Paci*iCorp provided the following timeline for the
Conservation Potential Assessment:
Timeframe ---MiFestone Public Input Request
nn.i Q,2024n
*�* �
Feedbark
May 2,2022 Share Key Drivers of Potential and Assumptions Review methodology and resources
September 2024 Present Draft Results and Share Measure Data Review materials and provide feedback
October 2024 Present Final Supply Curves Review changes made due to feedback
November 2024 Draft CPA for Review Provide input on draft report
January 2024 Publish Final Report With feedback incorporated
This suggests that the EE supply curves will not be available for review until September or
October,which may be too late for additional changes prior to being committed as inputs to
the IRP modeling. Sierra Club requests that there be suf*icient time for review of the EE
supply curves and the opportunity to suggest changes prior to modeling. In particular,
Sierra Club is concerned about the following potential issues:
a. Exclusion of Measures from Supply Curve: In the Ainal 2023 CPA Report,the following
methodological approach was described:
In general, this study did not consider the cost of energy efficiency measures, as this analysis is performed
within PacifiCorp's IRP.However, because, by default, the technical (and achievable technical)assumes that the
highest efficiency equipment option will be adopted by all customers at the time of replacement, this has the
potential to skew the amount of cost-effective potential. For example, assuming that all customers adopt high-
cost SEER 24 central air conditioners would not only create a large amount of high-cost potential that the IRP
model would be unlikely to select,but it would also reduce the available potential for lower-cost non-equipment
measures that can save cooling load (e.g., insulation). To account for this, the achievable technical potential
excluded equipment measures with significantly high upfront costs unlikely to be deemed economic within the
IRP. This screening used a levelized cost threshold of$160/MWh for California, Utah, Idaho, and Wyoming, and
a higher threshold of$17S/MWh for Washington to reflect the 10%conservation credit applied within the IRP
for measures in that state.

In other words, Paci*iCorp's approach was to set an arbitrary cost threshold, above which
EE measures cannot even be considered for IRP model selection - even if those measures
could be an optimal part of the overall portfolio. Sierra Club disagrees with this approach
since it assumes,without any supporting evidence, that higher cost measures would not be
selected by the model and should therefore be excluded from consideration.While it is
certainly possible that higher cost measures will be selected in fewer quantities, there is no
logical basis for initially excluding them from the supply curve, and thus from possible
selection in the IRP model.A better approach would be to include all possible EE measure
bundles in the supply curve and simply allow the model to select the bundles that minimize
cost across the entire resource portfolio.
b. Admin Costs: Measures included in the 2023 CPA assumed administrative costs that
were exceedingly high, even up to 48% of the total cost in some cases. Typically,
administrative costs for utility EE portfolios are less 10%. For example,
administrative costs for Rocky Mountain Power's DSM portfolio in the 2023 program
year were approximately 2% of the total portfolio budget.'
c. Incentive Levels: During the May 2, 2024 PIM, Paci*iCorp explained that EE measure
costs included an assumed incentive level that varies by state as shown below:
CE Test TRC, TRC TRC UCT UCT UCT
10%adder
Measure Cost $1,000 $1,000 $1,000 n/a n/a n/a
Incentive Paid n/a n/a n/a $430(43%) $380(38%) $390(39%)
Utility Admin% 48% 45% 29% 48% 22% 40%
Admin Spend $480 $450 $290 $480 $220 $400
Cost for Bundling $1,480 $1,450 $1,290 $910 $600 $790
** Administrative costs will be updated during the 2025 study
However it is unclear if additional quantities of EE measure bundles can be selected by the
IRP model at higher incentive levels. Sierra Club recommends that the model be provided
with EE bundles at higher incentive levels -- and correspondingly higher quantities -- as an
option for the model to select.This re*lects that overall customer adoption of EE measures
would generally increase as the level of incentives increases.At a minimum, incentive levels
should be set at 75% and 100% of incremental measure costs.Additionally, there is no
reason to cap the incentive level at 100% of the incremental cost of the measure. It may be
more cost effective from a resource portfolio perspective to increase the adoption of EE
1
hUps://www.paci#icorp.com/content/dam/pcorp/documentslenlpaci*icorp/environment/dsm/utah/UT En
ergo EL*iciency and Peak Reduction Report 2023.pdf

measures, even if that means increasing the incentive levels above 100%.PaciAiCorp should
consider incentive levels at 125% and/or 150% of the incremental cost of the measure.
d. Additional Flexible Load Options:
Sierra Club appreciates PaciAiCorp's consideration of new Alexible load options as part of its
demand-side resource portfolio. However, Sierra Club recommends that two additional
Alexible load options be included as part of the overall portfolio.
First,while PaciAiCorp has included an Electric Vehicle Direct Load Control,this appears to
be limited to one-way managed charging of EVs. In reality, many new EV models - including
both LDVs (e.g. Ford F150) and MD/HDVs (e.g. school buses) - are capable of bidirectional
charging, often referred to as "vehicle to grid", "vehicle to building", W2X" or"V2G." These
technologies are currently being deployed around the country to serve as a grid resource
during times of peak need. This stands to provide roughly twice the grid capacity bene*it as
simple managed charging, and only a small fraction of EV participation is needed to reach
potentially several hundreds of MW of grid resource. Sierra Club recommends that
PaciAiCorp include this as a resource option in its IRP modeling.Additionally, Sierra Club
recommends that PaciAiCorp consult with the Vehicle Grid Integration Council on best
practices for developing new V2X program opportunities that draw upon lessons learned
from other utility programs.z
Third,Sierra Club recommends that PaciAiCorp consider new Alexible load options for the
emerging subset of new large load customers. For example, one data center company has
recently reported its ability to temporarily shift computing load based on the needs of the
grid.3
e. Treatment of Heat Pump Costs:
Recent technological advances in cold-climate heat pumps, along with incentives offered
through the InAlation Reduction Act mean that there should be substantial consideration of
this technology as a potential component of PaciAiCorp's DSM portfolio. Heat pumps can
offer a more efAicient form of cooling than traditional AC units or resistive heating. Sierra
Club recommends that PaciAiCorp consider incremental heat pump costs relative to both a
heating and cooling baseline technology. For example, the incremental cost of heat pumps
relative to a new AC cooling unit may be substantially less than the incremental cost versus
a gas furnace. Additionally, the assumed incremental costs should be informed by recent
research on heat pump costs and available federal incentives. Sierra Club recommends that
2 https:,I/www.vgicouncil.org/resources
3 https:[/cloud.google.com/blog/products/infrastructure/using-demand-response-to-reduce-data-center-
power-consumption

PaciAiCorp incorporate information recently compiled by Cadmus on behalf of PSE for this
purpose.4 The table below was excerpted from the Cadmus report.
Table 11. Potential Impaet of 25C Tax Credit and HEEHRA
Rebate on Cost of Heat Pumps(80%to 150%AMI)
I Base C, HEEHRA
Equipment Estimate Credit Value Rebate,
Centrally Ducted ASHP
Centrally Ducted ASHP—Base $14,B00 • ° $14,800
Centrally Ducted AMP—Dual Stage $17,17S • ° $17,175
r&trally Ducted AMP—ENERGY STAR S371800 $2,000' $8.000 57,800
Centrally Dined AMP—cold airme $19,42S $2,000r $400DO 59,425
Centrally_Duated_AMP—Dual Fuel 511,277 • ° S11,277
CentraIfyDuctedASHP+Furnace—DuuolFuel $16,250 ° ° S16,250
Ductless Mini-Split Heat Pump 11asaYttud3i wo_
Ductless Mini Wrt Heat Pump—Base $13.443 ` • ° S13,443
DuctlessMitiSpin Heat Pump—ENERGY STAR S14,886 I $2,000° $7,443 $5,443
DuctlessMiniSplit Heat Pump-cold Climate 1 S15,246 1 $2,0009 57,623d SS,623
Sources:26 C_F.R.§25C;An Act to provide for reconciliation pursuant to title H of S.Con_Res.14,Putbk Law 117-169(2M2)_
1817-2090.nttes!!ww. Inor r ovr117;n1avrs!oubll691FLAW-117e tx16q oef
•Wh4e this table shows the HEEHRA rebate estimate for residents making 80%to 150%of AMI,residents making less than
80%AMI would be expected to receive the ful'S8,000 for a;I qualifying heat pumps,given the cost estimates used.
'Equipment is not assumed to meet the effiaency criteria for ENERGY STAR or for CEE Tier 3.
Equipment meeting ENERGY STAR or different CCHP specifications may not meet CEE Tier 3 criteria.
"Equipment meeting CCHP specification may not qualify for ENERGY STAR designation_
2. EE/DR bundles should be included as potential"reliability adjustment"
resources.
In the 2023 IRP, PaciAiCorp's modeling approach included a"reliability adjustment" step in
which incremental resources were added after the initial ST model runs to account for any
energy shortfalls. However,the potential set of resource options added to address reliability
needs did not include any Energy EfAiciency or Demand Response resources. Sierra Club
recommends that PaciAiCorp update its approach to allow EE and DR resources to be added
in the reliability adjustment step. Notably, this step is conducted outside of the cost-
optimization, and thus there is no need to consider "cost-effectiveness" in the traditional
sense. In other words,the addition of supply side resources to address residual reliability
needs are agnostic to cost. Similarly, additional reliability-driven EE resources should be
considered for inclusion, even if they would not screen a traditional cost-effectiveness test.
This would be the only way to consider EE resources on an equal playing Aield with supply-
side resources.Additionally, PaciAiCorp should clearly identify all the resources added as
part of the reliability adjustment step, including EE/DR resources. To the extent that EE/DR
resources are included, PaciAiCorp should also update its EE/DR implementation plans to
4 https:llapiproxy.utc.wa.gov/cases/GetDocument?docID=3616&year=2022&docketNumber=220066

include these additional reliability-driven EE/DR resources.This might be accomplished by
including a"reliability adder"as part of the cost-beneAit evaluation,and/or when selecting
the level of customer rebate/incentive.
Granularity& Reliability Adjustments
In its comments for the 2023 IRP analysis, Sierra Club has expressed concerns for the
manual adjustments performed by the Company to the resource portfolios. Those include
reliability and granularity adjustments.While both are addressing real modeling concerns,
they do so in a way that is not fully transparent and is excessively impacting the Ainal
portfolios. These manual adjustments undermine the role of a modeling process and tool
like PLEXOS,while stakeholders spend time reviewing inputs and outputs that in the end
are overwritten by the Company's adjustments.
Granularity Adjustments
For the granularity adjustments, Sierra Club is concerned that based on previous reviews,
coal units might be receiving a signiAicant and unjustiAied adjustment which reduces their
Aixed cost and could result in keeping uneconomic units online.The example of"swapping"
driven by Granularity Adjustments presented during the March 14, 2024 meeting is
especially concerning as it shows the impact those adjustments have on the portfolio. For
example,between phases 3 and 4 wind grows by more than 75%, which shows the impact
that the Company's out-of-model changes can have on the Ainal portfolios.
During the same meeting, the Company stated that"The Granularity Adjustment reAlects
the marginal value of the LAST MW of a resource that is added, and in runs that are reliable,
this last MW has less value than the last MW in an unreliable run." This raises concerns
with respect to the Company's modeling process and sequence of steps: if the granularity
adjustment is performed prior to the reliability adjustment step,then an energy shortfall
could result in an unreasonably high energy value for coal units based on the $1000/MWh
shortfall price. However,that energy shortfall could be addressed during the reliability step
signiAicantly reducing the energy value of said coal units. Furthermore,the energy value of
coal units is partly determined by the company's assumed coal prices,which Sierra Club
and other stakeholders have expressed concerns about.
Sierra Club provides the following recommendations:
Reporting Recommendations
• Report steps taken to reduce out-of-model granularity adjustments. Explain any
differences between the 2025 and 2023 methodology,including whether decreasing
Aixed cost(slide 44, March meeting)was part of the process in 2023 and if not,how that
addition is improving the granularity adjustment process.

• Clearly report methodology,values, and impacts of adjustments. Provide clearly labeled
workpapers that include the initial adjustments, and the adjustment values for each
iteration, as well as the model results and PLEXOS output Ailes (and a spreadsheet that
clearly explains the adjustments and Aile names of each iteration). For each of the
portfolios presented, explain why the iterative process stopped at the Ainal portfolio.
Modeling Recommendations
• Granularity adjustments should primarily be applied to Alexible resources,i.e.resources
the value of which is not fully captured in the LT model because of the lower temporal
resolution: energy storage and peakers.
• Ensure that the energy value of a resource's output in the LT Model and that in the ST
model include the same cost components for a consistent comparison. In its Response
to Sierra Club Data Request 29 for the 2023 IRP analysis, PaciAiCorp noted that"existing
plants are no longer capitalizing initial build costs whereas proxy resources do
capitalize these items over the study horizon impacting net Aigures." This statement
implies that the granularity adjustment is impacted by whether the unit is existing or a
new addition (through the inclusion of initial build costs). However, initial build costs
are not relevant for the granularity adjustment which is meant to capture only the
Alexibility value that the LT model might not be fully capturing because of its lower time
resolution.Thus, Sierra Club recommends that for the granularity calculation the energy
value should not be net of annualized initial build costs, even for new resources.
Reliability Adjustments
Reliability adjustments also have a signiAicant impact on the Ainal portfolios as the
Companies choose to delay, add, or subtract resources. Sierra Club has analyzed its
concerns regarding the Company's practice of adding resources and delaying retirements to
address the reliability issues, a concern that was shared by Staff in its comments,
requesting increased transparency and an effort to reduce the out-of-model adjustments.
PaciAiCorp has not shared any details about how the reliability adjustments will inform the
2025 IRP.
Reporting Recommendations
• Provide PLEXOS output*iles for the initial and reliability-adjusted portfolios,as well as
a spreadsheet mapping the initial and reliability-adjusted portfolios,together with a list
of the resources that have been added, removed, delayed, or in any way adjusted by the
Company, and a justiAication for this choice.
Modeling Recommendations

• Provide details on the rationale and methodology of reliability adjustments during the
public input meetings prior to the Ailing of the draft IRP.
• Provide stakeholders with an opportunity to recommend alternative reliability
adjustments. These alternatives should be evaluated in parallel to those selected by
PaciAiCorp,with an opportunity for revisions and feedback from stakeholders prior to
the IRP Ailing.
• Resources options considered for addressing the identiAied reliability issues should
include renewable energy sources, energy storage, and demand side resources.
Energy Infrastructure Reinvestment (EIR) Program:
In the Commission's Order adapting Staffs recommendations 24-073, the Commission
included a recommendation coming from Sierra Club's comments:
#21: In the 2025 IRP/CEP PaciAiCorp shall provide an update on PaciAiCorp's efforts
to secure Energy Infrastructure Reinvestment(EIR) Ainancing from the DOE Loan
Program OfAice.Assume EIR Ainancing through the DOE Loan Program OfAice in the
Preferred Portfolio or include a variant portfolio that optimizes resource additions
and retirements under the assumption of EIR Ainancing.
PaciAiCorp has not shared any details about how this recommendation will be included in
the Company's analysis.
Reporting Recommendation:
• Provide an update on PaciAiCorp's efforts to secure EIR Ainancing from the DOE Loan
Program OfAice and any analysis that has been conducted to assess the associated
bene*its.
Modeling Recommendation:
• Incorporate Ainancing opportunities made available under the EIR program,which can
enable the closure of coal plants, the replacement of fossil resources with cleaner
alternatives, and the development of transmission infrastructure. SpeciAically,
PaciAiCorp should conduct:
o A scenario in which transmission network upgrade costs in Cluster Areas 1, 2, 4,
12, and 14 are reduced by 30 percent; and
o A scenario in which EIR Ainancing is assumed for early retirement and
replacement of Jim Bridger Units 3 and 4, Huntington, Hunter, and Wyodak. In
this scenario the model should be allowed to select the economic retirement of
those units assuming EIR Ainancing.

Compliance with the EPA 111(d) rule and CO2 price
In its 2023 IRP analysis PaciAiCorp evaluated resources under Aive price-policy scenarios
assuming different CO2 and natural gas prices:
- MN: Medium natural gas/No federal CO2 regulations
- MM: Medium natural gas/Medium CO2 cost
- HH: High natural gas/High CO2 cost
- LN: Low natural gas/No federal CO2 regulations
- SC: Medium natural gas / Social cost of greenhouse gases
For the 2025 IRP, PaciAiCorp is lowering the high CO2 forecast for the HH scenario and
replacing the MM with a new price-policy scenario:
- MR: Medium natural gas/current federal CO2 regulations, under Section 111 of
Clean Air Act
Modeling Recommendations
• Compliance with the EPA 111(d) rule should be modeled as part of the base model, not
as a variant or price-policy scenario (MR). The Aive price-policy scenarios (including
MM),as deAined in the 2023 IRP analysis can be used,with all of them requiring Section
111(d) compliance of existing coal and new gas resources, while the N, M, H, and SC
assumptions will deAine the CO2 price in addition to the required EPA 111(d)
compliance. SpeciAically:
o All coal units should be modeled based on three compliance options identiAied in
the August public input meeting:
■ Continued Operations/retirement by end of 2031.
■ CCS by end of 2031, no retirement obligation.
■ Natural Gas/Alternative Fuel: co-Airing of at least 40%natural gas or
similar emission reductions from an alternative fuel, starting 2030. 100%
natural gas or alternative fuel starting 2039. This compliance option
should include any conversion costs as well as incremental fuel supply
and transportation costs.
o If new combustion turbines or combined cycle resources are available for
selection in the model, they should be compliant with EPA 111(d):
■ CCS by January 1st, 2032 (or other technology option meeting the
standard)
■ Operating with an upper limit capacity factor of 40 percent during each
year.
• CO2 prices should be included in LT,but the Company should also conduct and report
ST results without the carbon cost included in the dispatch decisions.

Reporting Recommendations
• Cumulative carbon costs associated with each portfolio, although not included in
dispatch decisions, should be reported through a post-optimization calculation.
• Variants that perform well should have LT runs presented for all price-policy scenarios.
Compliance with the EPA Regional Haze Rule
In August 2024, EPA proposed to disapprove both Wyoming and Utah's Round 2 Regional
Haze State Implementation Plans (SIPS). EPA's Ainal decision on Wyoming and Utah's SIPS
are expected by November 22, 2024. In EPA's proposed disapproval of Wyoming's SIP, EPA
faulted Wyoming for failing to consider pollution emission reductions from some of the
state's largest sources, including Jim Bridger,Wyodak, Naughton, and Dave Johnston. This
indicates that pollution controls are likely to be required at PaciAiCorp's Wyoming coal Aleet.
At a minimum,it indicates a regulatory risk that controls will be required. PaciAiCorp should
factor this risk into its long-term planning,where the Company examines a variety of
possible futures.
In EPA's proposed disapproval of Utah's SIP, EPA stated that"[s]ince installing SCR at
Hunter Unit 3 would achieve signiAicant emissions reductions at a cost of$4,401/ton
(below Utah's $5,750/ton cost-effectiveness level) and the State did not address this issue
in its SIP submission,we Aind that Utah unreasonably rejected SCR for this unit." EPA also
stated, "[t]he information in the record indicated that installation of SCR, at an estimated
cost of$5,979-$6,533/ton NOx reduced, may well be cost-effective for Hunter Units 1 and 2
and Huntington Units 1 and 2 (or some subset of these units)."Accordingly, there is also
regulatory risk that SCR will be required at all Aive units at Hunter and Huntington,which
should also be accounted for in PaciAiCorp's IRP.
Modeling Recommendations
• As part of the base model (i.e., included in all portfolio runs), include an SCR
requirement at Hunter 2, Huntington 1 and Huntington 2.Additionally, require that
the model select either SCR or SNCR at Naughton, Wyodak, and Dave Johnston 1, 2,
and 4.
• As a variant case, include an SCR requirement at all Aive units at Hunter and
Huntington,while keeping the same modeling assumptions at the Wyoming units.
Resource Availability
During the July public input meeting, PaciAiCorp presented modeling details around supply
side resources, including energy storage, solar,wind, geothermal, nuclear, and gas turbines.
Energy storage and solar are assumed to have a 12 month construction duration while

onshore wind a 12-24 month construction duration. The soonest commercial operation
date possible for the three resource types is assumed to be 2028. However,there might be
resource bids proposed in the 2022 RFP,which could be potentially available prior to 2028.
Sierra Club recommends that any such resources are identi*ied and included as resource
options in the model.

PacifiCorp - Stakeholder Feedback Form (037)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 8-3 0
*Name: Stanley Holmes Title: Outreach Coordinator
*E-mail: [e-mail] Phone:
Utah Citizens Advocating Renewable
*Organization: Energy (UCARE)
Address:
City: Salt Lake City State: UT Zip:
Public Meeting Date comments address: 0 8-14-2 0 2 4 ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
State Updates; Multi-State Protocol; RMP Separation from PacifiCorp; Near-, Mid-,
Long-Term Acquisition Strategies
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please identify all potential system-wide resource planning impacts if RMP separates from
PacifiCorp, or if a Utah-Idaho-Wyoming consortium of state managers takes control, at
near-, mid-, and long term stages of the 2025 IRP planning horizon. Utah state
legislators recently expressed concern about the current PacifiCorp structure and
requested a "restructuring" report from RMP. . .due in November 2024. Suggest Multi-State
Protocol advisory group of UT/WY/ID/WA/OR/CA state representatives be resurrected and
meet asap.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
https://utahnewsdispatch.com/2024/08/21/utah-legislature-asks-rmp-to-restructure-its-
rate-system-and-split-pacificorp/,
https://le.utah.gov/Interim/2024/pdf/00002837.pdf?r=169
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
Please ensure that implications of recent Utah state legislative actions are raised in
relevant sections of the September 25-26 PIM agenda and that RMP describes what it plans
to address in its November 2024 restructuring report to the Utah Legislature.
PacifiCorp Response: (9/16/2024)
* Required fields

PacifiCorp anticipates including this topic in its 2025 IRP September 25-26 public input meeting agenda.However,
review and planning for Utah's legislative request is ongoing, and the company will not be able to provide a
comprehensive response in this timeframe.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (039)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 9-10
*Name: Nancy Kelly Title:
*E-mail: Phone:
*Organization: Western Resource Advocates
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
INFORMATION REQUEST,MARKET VARIANT REQUESTS
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
INFORMATION REQUEST
1. Please provide more information supporting the addition of the new Wyoming hub.
In developing the 2023 IRP Update,PacifiCorp added a 500 MW hub in Wyoming that it had never previously modeled.
This same modeling assumption is carried forward into the 2025 IRP.
The stated justification for this new modeling assumption is provided in a single sentence on page 41 of the IRP Update
and in a single bullet on page 42 of the July Public Input Meeting("PIM")presentation. The July PIM explanation is
more complete than the 2023 IRP Update explanation. It states: "the addition of the Wyoming energy market reflects
improved access to additional utilities facilitated by the construction of Gateway South."
More information is needed to justify this 500 MW addition. If this market is assumed to be available in all hours of
every year over the 20-year planning period,this is the equivalent of adding a 500 MW facility in Wyoming but with no
forced outage rate.
Please provide, at a minimum,the following information:
• Does PacifiCorp assume these 500 MWs are available in all hours of every year over the 20-year planning period?
If so,why does PacifiCorp believe this energy will continue to be available in all hours across the 20-year planning
period? If not,what products is PacifiCorp assuming will be available and in what time periods?
• Which utilities can PacifiCorp now access that it couldn't previously?
• What experience does PacifiCorp have with these sellers?
• How liquid and deep does PacifiCorp expect this new market hub to be?Please provide all supporting
documentation.
2. Please provide the price forecast for the Wyoming market hub.
Page 39 of the July PIM presentation shows Quarter 2 price forecasts for the market hubs,but no market price forecast is
provided for the new Wyoming hub. Please provide the forecast for this hub that will be used for modeling.
* Required fields

MARKET VARIANT REQUESTS
1. Market Variant One
• Model the MM scenario,but without assuming access to a Wyoming hub.
Justification: In other proceedings,the Company has described declining liquidity at all market hubs and has shown that
market reliance is a large risk and significant driver for increases in net power cost requests across the states. This variant
tests what happens if the new market hub does not play out as PacifiCorp forecasts.
2. Market Variant Two
• Model the MM scenario,but without assuming access to a Wyoming hub.
• Additionally, assume the short-term market caps at the other five hubs extend out as is currently modeled over the
first 3 years only. In the 4th year,reduce the availability at each hub by 50%, and in the fifth year,reduce the availability
by 75%.
Data Support: If applicable,provide any documents,hyper-links,etc.in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Justification: In each IRP,PacifiCorp assumes that market hubs are liquid for five years and then dry up. This has the
effect of encouraging ongoing near-term market reliance which may or may not be in customers' best interest. This
variant tests what happens if the new market hub does not play out as PacifiCorp forecasts and markets tighten earlier and
in a more gradual manner than PacifiCorp has assumed.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp Response:
PacifiCorp's transmission system in eastern Wyoming is connected to the following other utilities,including:
- NorthWestern Energy(in Montana)
- Western Area Power Administration-Rocky Mountain Region
- Tri-State Generation and Transmission
- Black Hills Power
- Basin Electric Power Cooperative
Through these entities,there are also connections to the Southwest Power Pool(SPP) in Western Nebraska.
These entities have limited access to liquid western markets, like Mid-Columbia and Palo Verde, and are thus more likely
to have resources available when supplies at those markets are restricted. These connections are not new,but with
Gateway South in service, it is also more likely that incremental supply sourced from these neighboring utilities would be
able to reach PacifiCorp's major load centers in Utah.
Like the other markets modeled in the IRP,the short-term(ST)modeling reflects hourly balancing transactions in all
hours,though unlike the other markets,the Company is not modeling market sales in Wyoming, as the resource mix in the
area is typically dominated by low-cost thermal resources and wind and likely to be limited by transmission constraints.
For modeling purposes,purchases from the Wyoming market were assumed to have the same price as Palo Verde.
While this"all hours"treatment is consistent with other market modeling,PacifiCorp recognizes that it is not really a firm
commitment. Importantly,under the Western Resource Adequacy Program(WRAP),balancing transactions without a
specified source will not count toward forward showing capacity requirements. PacifiCorp is modelling WRAP capacity
requirements in the 2025 IRP starting in 2028, and does not intend to count capacity from markets(including Wyoming)
as part of WRAP compliance for modeling purposes. Note that in practice"market"products exist that would meet
forward showing requirements, e.g. annual hydro slice purchases, and WRAP compliance could be met with short-term or
long-term products.
While markets may not count toward WRAP compliance,the Western Energy Imbalance Market(WEIM) already
provides opportunities to balance resources in real-time across a broad footprint that covers most of the Western
interconnect. CAISO's Enhanced Day-ahead Market(EDAM)is expected to provide further optimization by coordinating
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day-ahead decisions. The WEIM and EDAM are likely to enable greater system balancing under nearly all conditions,
though PacifiCorp recognizes they are not replacements for the firm resources needed for WRAP compliance.
For the first time the 2025 IRP will separate the balancing function of markets from the reliability aspects,which should
address some of the concerns identified. PacifiCorp appreciates the suggestions about market scenarios and intends to
examine how WRAP requirements and market reliance interact in the 2025 IRP results before considering further
analysis.
Please submit your completed Stakeholder Feedback Form via email to IRP@Pacificorl).com
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (040)
Integrated Resource Plan
PacifiCorp(the Company)requests that stakeholders provide feedback to the Company upon the conclusion of each public
input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and engaged
stakeholder group,and stakeholder feedback is critical to the IRP public input process.PacifiCorp requests that stakeholders
provide comments using this form,which will allow the Company to more easily review and summarize comments by topic
and to readily identify specific recommendations,if any,being provided.Information collected will be used to better inform
issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In order to maintain open
communication and provide the broader Stakeholder community with useful information,the Company will post appropriate
feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-0 9-12
*Name: Jim Himelic Title:
*E-mail: [e-mail] Phone:
*Organization: Renewable Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Modeling of transmission upgrades in PAC's PLEXOS model
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Current General Understanding of PAC IRP Transmission Planning
Below is a high-level description of the overall PAC TX planning process as RNW currently understands it.Please review
and correct any of the statements listed below that are either inaccurate or incomplete.
• PacifiCorp (PAC)models two types of transmission upgrade options in its PLEXOS IRP model:
o Incremental(INC)transmission(TX)transfer capacity:Network upgrades that increase the transfer capacity
between transmission regions(e.g.,the exchange of electricity between the Wyoming East and Bridger transmission
regions).
o Interconnection(CON)TX upgrades: Network upgrades that enable candidate generators and storage devices to
interconnect within one of PacifiCorp's transmission regions(e.g.,allowing a resource to interconnect in the Summer
Lake transmission region).
Reply: The effect of the INC and CON distinction in the model is as described,however INC and CON
transmission upgrade options are a categorization for IRP modeling only, and don't have any inherent tie to
particular kinds of transmission studies or outcomes. For example,upgrades for ERIS interconnection may result
in incremental transfer capability.Also, a transmission option that has incremental transmission between locations
in the real world but is located completely within an IRP topology bubble will be represented in the modeling as a
CON item.
Figure 1: PacifiCorp Preliminary 2025 IRP Transmission Topology
• For the near-term planning horizon,both the INC and CON transmission upgrade options are derived from
previous cluster studies conducted by PacifiCorp's transmission team.
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Reply: For the near-term planning horizon,previous cluster studies(or previous serial queue studies)conducted
by PacifiCorp's transmission planning team generally provides the most up-to-date information,but because
cluster study requests do not comprehensively cover PacifiCorp's system,transmission planning also provides
estimates for locations not covered in cluster study results.
• PAC's IRP team gathers information from multiple Cluster Studies (e.g., 1, 2, 3,4) and uses the latest available
data from the most recent round of studies up until a specified cutoff date.
Reply: The IRP team generally relies on transmission planning to provide forecasted transmission upgrade
options,though it has supplemented with more recent Cluster Study results at times in consultation with
transmission planning.
o Within each cluster study, a contingent facilities list is provided(for both ERIS-and NRIS-related upgrades)and
specifies whether these facilities are binding for the projects under current evaluation.
o If a listed contingent facility is binding,that associated TX work must be completed before any of the projects
under current consideration can interconnect with PAC's TX system.
Reply: In general,contingent facilities must be in place before a resource can interconnect. However,Provisional
Interconnection Service can allow for projects to interconnect early using unutilized interconnection capability. A
separate request queue and process exists for this service. For example, one project in a cluster might be able to
interconnect even though the cluster as a whole requires contingent facilities.Alternatively, if an earlier queued
resource(from a prior cluster)has selected a later COD, interconnection capacity might be available without
additional upgrades prior to that COD.
• Within each cluster study,the required TX upgrade projects can be categorized as either project-specific or shared
costs.
o Charges related to interconnection facilities and station equipment are project-specific.
o Network upgrades are pooled expenses,with the amount assigned to each project allocated on a proportional basis
according to the nameplate capacity of the requested POI.
• PacifiCorp's IRP PLEXOS model assigns TX upgrade-related constraints as a continuous variable(i.e.,non-
integer).
o As a result,the model can access a portion of the incremental INC or CON MWs that are enabled by the upgrade,
paying only for a proportional share of the total project cost.
Reply: Cost allocation for interconnection facilities and network upgrades are outlined in the PacifiCorp Open
Access Transmission Tariff(GATT) Section 39.2.1. Currently, system network upgrades are allocated on a
proportional basis according to the nameplate capacity,however, once FERC Order 2023 becomes effective
system network upgrades will be allocated based on the proportional impact of each individual generation facility
in the Cluster that relies on the need for a specific system network upgrade or set of upgrades. Station equipment
costs can be shared if multiple requests are submitted for the same interconnection point. Station equipment costs
have distinct allocation in the cluster study process and are classified either as direct assigned facilities or network
upgrades. The station equipment classified as network upgrades are refunded to interconnection customers on the
same basis as other network upgrades.
Transmission upgrades are intended to be modeled as integer decisions, for example, Gateway South and
Boardman to Hemingway cannot readily be scaled down. PacifiCorp does recognize that certain upgrades could
be reduced if a smaller quantity of resources was selected and the remaining requests were withdrawn, such that
linear treatment might be realistic. Given the difficulty of modeling integer transmission upgrades, and the
iterative nature of PacifiCorp's modeling,resolution of integer values for transmission upgrades may require
variant analysis(with and without), and may be limited to major near-term projects.
General Questions Related to Cluster Studies/Transmission Modeling in the IRP
• Is it correct to assume that all CON-related TX options are derived from Energy Resource Interconnection Service
(ERIS)-related required TX upgrades listed in PAC's cluster studies?
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o If not,what is the source of PAC's assumptions for CON-related TX upgrade options,as defined in the PLEXOS
model?
• Similarly, is it correct to assume that all INC-related TX options are derived from Network Resource
Interconnection Service(KRIS)-related required TX upgrades listed in PAC's cluster studies?
o If not,what is the source of PAC's assumptions for INC-related TX upgrade options as they are defined in the
PLEXOS model?
Reply: The IRP model does not distinguish ERIS and NRIS interconnection options. Any transmission upgrades
that do not result incremental transfer capability in the IRP topology are categorized as "CON", and all others that
do result in incremental transfer capability in the IRP topology are categorized as "INC". The IRP model reflects
PacifiCorp Energy Supply Management's transmission rights,which it uses on behalf of its retail customers,plus
the rights it could receive as a result of potential transmission upgrades. Transmission rights are managed through
the transmission service request(TSR)process,which is distinct from interconnection. Interconnection, including
NRIS, does not provide transmission service. The transmission topology and transmission upgrade modeling in
the IRP is a significant simplification of these various processes, so as to facilitate proxy-based long-term
planning.
• How are ERIS-enabled generator and storage resource options configured in the PLEXOS model?
o Does this configuration differ at all for those resources that are NRIS-enabled?If so,how?
Reply: ERIS and NRIS are not distinguished in the IRP,though transmission upgrade options that are included in
the IRP may have come from studies of either type.Because the NRIS study is intended to include costs for
upgrades needed to transfer resources to load, it is more likely to receive an"INC" categorization.
• Are the line transfer capacities listed in the PLEXOS model- for both existing and incremental upgrade options -
based solely on firm transmission service?
o Does PAC's PLEXOS model include any non-firm, as-available transmission service for candidate INC upgrade
projects?
Reply: The IRP model includes firm transmission capability and doesn't include any non-firm capability.
• Is there a separate configuration in PLEXOS for resources listed as Designated Network Resources (DWR)
(which use network TX to transfer power from the facility site to PAC load centers) compared to non-DWR resources
(which require point-to-point service to transfer power to load)?
Reply: IRP modeling does not distinguish the type of transmission service and includes both network and existing
long-term firm point-to-point capacity rights held by PacifiCorp Energy Supply Management.
• Near-term TX upgrade options defined in PLEXOS -both INC and CON types- are sourced from PAC TX's
cluster studies,but what is the source of these longer-term options that the PAC IRP team uses when defining these items
in the model?
o Is it correct to assume that projects originating from PAC TX are exogenously prescribed in PLEXOS
(i.e.,not modeled as decision variables)?
o Will a complete list of all these manually specified TX upgrades be included in the 2025 IRP data disk, along with
relevant data such as the first year of service and the regional incremental INC and CON MW amounts?
• When porting over the TX options from the cluster studies into the PLEXOS model,how does the PAC IRP team
account for the prerequisite TX upgrades associated with higher-priority interconnections listed in each cluster study?
o Are all the listed TX projects exogenously defined in PLEXOS, or are some of the upgrades treated as candidate
options and thus represented by decision variables in the model?
Reply: Longer-term options are forecasts provided by PacifiCorp Transmission. Generally,the upgrades have
previously been identified in a cluster study,though withdrawn requests may have eliminated particular upgrades.
The forecast can also cleanly cut off the megawatt quantities once a particular upgrade is fully utilized,whereas
the cluster study identifies requirements for the entire cluster and has to round up to the next major upgrade even
if it is only needed in part. In general,the IRP only models transmission options,and does not track costs for
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contingent facilities or upgrades that are required regardless of the model selections, as this is not required as part
of the optimization.
Unless the study is a transmission-related sensitivity, all available options are the same for every study. These
options have been presented in the 2025 public input meeting series and will be presented in the filed 2025 IRP.
In addition, each LT model's accompanying outcome file reports transmission options selected for the relevant
portfolio,including the selected in-service year for the upgrade.
o Does the PAC IRP team embed any dependency logic in their PLEXOS model to ensure all upstream
requirements are fully resolved before a candidate TX upgrade project is eligible for selection by the model?
Reply: Yes. Transmission upgrades are generally cumulative and each successive upgrade in a location is subject
to a constraint in PLEXOS requiring the previous upgrade(s)in that location to have been completed. Some
upgrades are required for multiple areas or later upgrade options.
• Does the affected system information listed in each cluster study have any impact on PAC's IRP modeling
process?
Reply: If impacts on affected systems are known,it could be reflected by the timing of the earliest in-service year
of an upgrade option. Unless there are known costs for affected systems, costs only reflect the impacts on
PacifiCorp's system.
• In the June Stakeholder meeting,there was a discussion on the interaction between PAC TX's long-term projects
and PAC IRP's long-term plans. As a follow-up to that conversation,can you please address the following questions:
o Is the overall amount of CON and INT TX service across PAC's entire TX topology updated to reflect the
impacts of these projects at their assumed in-service dates?
❑ For each of these long-term projects sourced from the company's TX group,will the 2025 IRP data disk include
the incremental CON and INT regional capacities associated with each of these discrete projects?
Reply: All of the transmission upgrade options for the 2025 IRP are sourced from PacifiCorp Transmission.
Given the lead time for major transmission upgrades,if a major transmission option is included in PacifiCorp
Transmission's long-term plan,particularly in the next few years,the IRP is likely to model it as available starting
in the identified in the plan as it is difficult to compress existing timelines that have already been developed and
for which planning is underway. The IRP model would still be allowed to select a later date. The timing of later
upgrades in the plan may be more flexible and the IRP model can evaluate earlier dates if they are feasible.
Transmission upgrades options do not need to be part of PacifiCorp Transmission's long-term plan to be
considered in the IRP.
The available options have been presented in the 2025 public input meeting series and will be presented in the
filed 2025 IRP. In addition, each LT model's accompanying outcome file reports transmission options selected for
the relevant portfolio, including the selected in-service year for the upgrade.
o What reliability and cost-benefit analysis does PAC Transmission conduct when determining which projects to
move forward with?
❑ Is any of this information available to external IRP stakeholders interested in learning more?
o Is it correct to assume that none of the costs associated with these projects will be assigned to any of the candidate
generator or storage objects defined in the PLEXOS IRP model?
Reply: Transmission upgrades that are required are typically not modeled in the PLEXOS model, as it would not
impact the optimization. If later upgrades are contingent upon the required upgrade, its timing could impact the options
that are modeled. If a required upgrade enables interconnection capability,the capability could be modeled at zero cost(or
reduced cost if there are additional project-specific requirements).
Because the transmission options for both CON and INC provided for use in the PLEXOS model are generally
derived from interconnection studies and not associated with transmission upgrades that are otherwise required to
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meet NERC and WECC reliability standards and criteria,the cost-benefit and reliability analysis is conducted
through the IRP models in deriving the least-cost, least-risk resource portfolio,balancing both cost and reliability.
• Is it correct to assume that PAC doesn't define a[Min Capacity Reserve Margin] requirement in PLEXOS for
each TX region during the long-term(LT)portion of the model run?
o Similarly, is it correct to assume that PLEXOS' [Firm Capacity] property is also not defined, either for existing or
candidate resources?
o I ask these questions because I am wondering if PacifiCorp allows for any capacity sharing across TX regions
during a PLEXOS LT run.
Reply: Correct,the Min Capacity Reserve Margin and Firm Capacity properties are not defined in PLEXOS for
the IRP. For the 2025 IRP,PacifiCorp is developing constraints that are similar to these properties to represent
the Western Resource Adequacy Program(WRAP),including the associated planning reserve margin
requirements and resource-specific qualifying capacity contribution values (QCCs). This was discussed at the
June 26-27,2024 public input meeting. PacifiCorp expects to comply with WRAP as a single system,but may
need to account for limitations on transfers between the east and west side of its system. Capacity sharing within
each side of the system is allowed implicitly.
Sample Use Cases
In this section I walk through are two examples to ensure I understand how PacifiCorp's IRP modeling team uses
information from PAC's cluster studies to define eligible transmission system upgrades.
Sample Walk through Example#1
Table 1 lists the projects that were modeled in Cluster 2—Cluster Area 13. Included in the table is a record of the projects
that were studied in the initial cluster study and the first restudy. Table 2 provides a summary of the total amount of
MWs evaluated in each cluster study,broken out by technology type.
Table 1: Candidate Projects from Cluster Study 2-Cluster Area 13
Nov 2022 Aug 2023 Project MW Type POI COD Requested Service
x C2-134 57.5 Solar&Battery Storage Clear Lake substation 12/1/2026 NR/ER
x x C2-179 40 Geothermal Black Rock substation 12/31/2029 ER
x C2-202 90 Solar&Battery Storage Pavant substation 12/15/2026 NR
x C2-211 49.9 Solar&Battery Storage Brush Wellington-Pavant transmission line 2/11/2025
NR/ER
Table 2: Summary of Candidate Proejcts By Technology Type for Cluster Study 2-Cluster Area 13
Cumulative Availability Aug-22 Study Nov-23 Study
Solar&Battery Storage 197.4 0
Geothermal 40 40
Table 3 lists the project-specific and shared costs for TX work required for the successful interconnection of these projects
onto PAC's system.
Table 3: TX-Related Expenses Assigned to Each Project for Cluster Study 2-Cluster Area 13
Cost Category Project Nov 2022 Study($k) Aug 2023 Study($k)
Interconnection Facilities C2-134 1,390
Station Equipment C2-134 5,700
Network Upgrades(ERIS) C2-134 19,008
Total C2-134 26,098
Interconnection Facilities C2-179 750 750
Station Equipment C2-179 5,080 5,080
Network Upgrades(ERIS) C2-179 13,223 10,420
Total C2-17919,053 16,250
Interconnection Facilities C2-202 1,600
Station Equipment C2-202 10,500
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Network Upgrades(ERIS) C2-202 29,752
Total C2-202 41,852
Interconnection Facilities C2-211 1,310
Station Equipment C2-211 8,940
Network Upgrades(ERIS) C2-211 16,496
Total C2-21126,746
Request for Confirmation:
• Were the PAC IRP team to represent Cluster Area 13 after the November 2022 study(but before the
commencement of the August 2023 restudy), candidate generator and battery storage resources would be instantiated in
the PLEXOS model for the Southern UT topology region.
o The TX region would encompass only two technology types: hybrid solar and geothermal projects.
o PLEXOS would allow for a maximum of 197.4 MW of hybrid solar-storage and 40 MW of geothermal capacity
to be selected by the model,with project start dates defined by the respective CODS listed in Table 2.
o The PLEXOS model would also include constraints to account for applicable CON and INC TX network upgrade
options required to interconnect these resources to PAC's system.
• Upon completion of the August 2023 restudy,the PLEXOS model would be modified to reflect only the option
for 40 MW of new geothermal capacity located in the Southern Utah region.
o If PLEXOS opts for the full 40 MW of geothermal, it will also incur$16.25 million in transmission-related
upgrade charges.
o Since PLEXOS models TX upgrade constraints as a continuous variable,the model can also opt for a portion of
the generation(e.g.,20 MW) and incur a proportional share of the TX-related expense. In this case, $8.125 million.
o TX-related upgrade costs are annualized(i.e. $/kw-yr)prior to being entered into PLEXOS model. PacifiCorp
assigns the appropriate financing assumptions to convert this overnight CAPX expense into an annuity calculation.
Questions Related to Cluster 2 Study Report: Cluster Area 13
• Upon completion of the November 2022 Cluster Study, is it correct to assume that if PLEXOS wants to select
even 1 MW from any of the four project units listed in Table 1, a pro-rata share of all required network upgrades listed in
the cluster study would also need to be completed?
o These pro-rata network upgrade costs would be in addition to any project-specific interconnection facilities and
station equipment work that is also required, correct?
• In both the November 2022 study and the April 2023 study, it states,"No additional upgrades beyond those
identified for ERIS are required for NRIS.All ERIS upgrades are required for NRIS."Based on this statement, is it
correct to assume that the geothermal unit will automatically qualify as an NRIS-eligible facility by completing all of the
ERIS-related TX upgrades?
• What is the source for the transmission projects listed as"assumed to be in service" for Cluster Area 13? Do they
originate from PacifiCorp's long-term transmission plan?If so,are any costs associated with those projects assigned to the
projects listed in Table 1?
• In the final Facilities Report for C2-179 , it is stated that the customer opted for ERIS service. How is this an
available option if the network upgrades listed in the August 2023 restudy were already for ERIS interconnection service?
Reply: Because the IRP is intended to evaluate proxy resources, and not specific requests,it generally includes
relatively little project-specific information and does not tie the results of a cluster study to individual requests in
that study. The relevant transmission upgrade information used for modeling generally includes the following:
-IRP topology location
-Total amount of potential interconnection capability(in megawatts)
-Total transfer capability and point of delivery
-Total cost(for station equipment and network upgrades)
-First available in-service date
- Special considerations on available resource types. Solar and storage are generally available in most locations,
and as they are inverter-based,have less complicated impacts on the transmission system. Geothermal and wind
are generally only viable in a few locations. The presence of these resource types would indicate they are viable
in that area,the absence of requests for those resource types in a given area could indicate they are not, or are at
least less likely. There is flexibility in the interconnection process to modify the specific level of storage
combined with solar, and surplus interconnection provides another means of creating hybrid resources. Given
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that flexibility,PacifiCorp generally lets the model select any combination of available resources, so long as the
actual generation remains within the interconnection limit in each hour.
Sample Walk through Example#2
Table 4 lists the projects that were modeled in Cluster 2—Cluster Area 7 for each round. In the initial cluster study, 15
projects were evaluated,totaling 2,607 MW. In the first restudy, 6 projects—comprising 1,418 MW of generation and
storage options—were studied. Finally,the second restudy included 4 projects,totaling 1,098 MW.
Table 4: Candidate Projects from Cluster Study 2-Cluster Area 7
Nov 2022 Aug 2023 Apr 2024 Project MW Type POI COD Requested Service
C2-30 199 Solar&Battery Storage Bridgerland substation 12/31/2025 NR/ER
x x x C2-32 500 NuclearNaughton substation l l/l/2030 NR
x x x C2-48 48 Natural Gas Naughton substation 5/18/2022 ER
x C2-55 150 Battery Storage Naughton-Treasureton transmission line 10/31/2024 NR
x C2-63 220 Wind Railroad substation 9/1/2026 NR/ER
x C2-77 100 Solar&Battery Storage Plymouth substation 12/31/2027 NR/ER
x C2-84 150 Solar&Battery Storage Plymouth substation 6/30/2025 NR/ER
x x C2-105 300 Wind Monument substation 12/31/2025 ER
x x x C2-106 400 Wind Naughton-Ben Lomond#2 transmission line 12/31/2025 ER
x C2-121 20 Solar Cutler-El Monte Willard Pump Tap transmission line 12/1/2025
ER
x x C2-122 20 Solar Ben Lomond-Honeyville transmission line 12/1/2025 ER
x C2-130 199 Solar&Battery Storage Plymouth substation 12/1/2026 NR/ER
x C2-139 150 Solar&Battery Storage Blue Rim-South Trona transmission line 12/1/2026
NR/ER
x C2-143 90 Wind Evanston-Anschutz transmission line 12/31/2026 NR/ER
x C2-155 110 Solar&Battery Storage Muddy Creek substation 12/31/2026 NR/ER
x x x C2-205 150 Solar&Battery Storage Bridgerland-Cache transmission line 10/31/2026
ER
Table 5 provides a summary of the projects studied in the second restudy,broken down by technology type,while Table 6
lists the corresponding network upgrades—both ERIS-and NRIS-related—required for those projects to interconnect with
PAC's bulk TX system.
Table 5: Summary of Proejcts from Cluster Study 2-Cluster Area 7(Apr 2024 Restudy)
Cumulative AvailabilityMW
Solar&Battery Storage 150
Nuclear 500
Natural Gas 48
Battery Storage 0
Wind 400
Solar 0
Table 6: Shared Transmission Network Upgrades Costs($k) for Cluster Study 2-Cluster Area 7(Apr 2024 Restudy)
Type Location Project Apr 2024 Study($k)
ERIS Naughton substation Install new 230 kV breaker 1,500
ERIS Naughton—Ben Lomond 345kV TX line New approx. 88 miles of 230 kV TX line 349,500
ERIS Ben Lomond substation Seven(7)230 kV breaker replacements 4,300
ERIS Plain City substation breaker replacement 500
NRIS Jim Bridger substation 345/230kV 700MVA transformer 16,100
NRIS Ben Lomond-Plain City Rebuild approx. 2 miles of 138kV TX line 3,800
NRIS Ben Lomand substation Replace Ben Lomond-Plain City relay 300
NRIS Plain City substation Replace Ben Lomond-Plain City relay 300
NRIS Ben Lomond-Cold Water Rebuild approx. 9 miles of 138kV TX line 14,400
NRIS Plain City to West Ogden North Tap Rebuild approx. 6.5 miles of 138kV TX line 8,600
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NRIS West Ogden North Tap to Midland West Tap Rebuild approx.2.5 miles of 138kV TX line 4,000
NRIS Warren to West Ogden South Tap Rebuild approx. 6.5 miles of 138kV TX line 8,500
NRIS West Ogden South Tap to Midland East Tap Rebuild approx. 2.5 miles of 138kV TX line 4,000
NRIS Midland East Tap to Clinton East Tap Rebuild approx. 5.5 miles of 138kV TX line 7,800
NRIS Clinton East Tap to Syracuse Rebuild approx. 3.5 miles of 138kV TX line 4,600
NRIS Cold Water-El Montel Rebuild approx. 5.5 miles of 138kV TX line 7,200
NRIS Ben Lomond-Warren Rebuild approx. 5 miles of 138kV TX line 6,900
NRIS Ben Lomond-Birch Creek and Ben Lomond-Naughton Rebuild approx. 8 miles of 230kV TX line
sections42,900
NRIS Naughton substation RAS work 300
ERIS Network Upgrades(subtotal) 355,800
NRIS Network Upgrades(subtotal) 129,700
Network Upgrades(total) 485,500
Table 7 lists the project-specific and shared network upgrade costs for project C2-106,which is the construction of a 400
MW wind facility at a new substation located off the Ben Lomond-Naughton#2 transmission line. The $198.1 k listed for
network upgrade costs in the Apr 2024 Study represents C2-106's proportional share of the shared costs listed in Table 6.
The pro-rata allocation of these shared expenses is based on the POI nameplate capacity for all projects listed as active in
the April study.
Table 7: Project-Specific and Shared Transmission Network Upgrade Costs ($k)for Project C2-106.
Cost Type Project Nov 2022 Study Aug 2023 Study Apr 2024 Study
Interconnection Facilities: Collector C2-106 800 800 1,300
Interconnection Facilities: POI C2-106 1,600 1,600 1,300
Station Equipment C2-106 8,200 8,200 12,700
Network Upgrades(ERIS) C2-106122,131110,141150,893
Network Upgrades(KRIS) C2-106 64,420 126,08247,250
Network Upgrades(subtotal) C2-106 186,552236,223198,142
Total 197,152246,823213,442
Questions Related to Cluster 2 Study Report: Cluster Area 7
• How does the PAC IRP team configure shared network upgrade costs across multiple projects in their PLEXOS
model?
o Will the model have to absorb the entire costs of the projects listed in Table 6 before a MW from any of the
technology options listed in Table 5 can be added to PAC's system, or is there a proportional TX-related charge that gets
applied based on how much generation PLEXOS wants to add in this TX region?
• According to queue information posted by PAC Transmission,project C2-106 requested ER interconnection
service. Consequently,will the PAC IRP model reflect both ERIS- and NRIS-eligible wind resource options in the
Wyoming region?
o If so,will the ERIS-eligible wind resource exclude the NRIS-related TX network upgrade expenses?
• In the August 2023 restudy,the Naughton—Ben Lomond 345 kV transmission line is listed in both the ERIS
section(Section 9) and the NRIS section(Section 13). Is this an error, or is it correct?
o If correct,what are the grounds for a TX project to be listed as both an ERIS-and NRIS-related upgrade?
• How are TX expenses related to contingent facilities handled by PAC's IRP team?
o Are any of these costs—triggered by cluster studies from previous years—assigned to the projects listed in Table
4?
o Is all the TX work required to resolve these contingent facilities approved and assumed to be in place by a certain
date within the model?
o Conversely, if the TX work to resolve the contingent facilities is still under consideration by PAC TX, are there
sequential INC and CON TX constraints that PLEXOS must navigate to access the generation and storage options listed
in Table 4?
Reply: IRP modeling does not differentiate the costs specific to individual cluster requests -the total cost and
total interconnection are modeled. Initial modeling allows this total to be considered on a linear basis. To the
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extent an integer determination(i.e. all of a particular upgrade or nothing)is needed in the final result, additional
analysis would be performed.
With regard to contingent facilities, each of the successive upgrade options in a given location are assumed to be
contingent on the prior upgrades unless they are known to be distinct. When upgrades are contingent on upgrades
in other locations,constraints are used to ensure prior requirements are met. The modeled costs of all transmission
network upgrades reflect PacifiCorp Energy Supply Management's share of the overall PacifiCorp Transmission
customer base,which is around 80%,with PacifiCorp Transmission's other customers contributing the remainder.
This is true for all network upgrades,whether triggered by reliability requirements,PacifiCorp Energy Supply
Management requests, or those of other customers of PacifiCorp Transmission. Costs are generally not modeled
for transmission upgrades that are required(not optional),as the cost would appear in every result and would not
have any bearing on the optimization.
Questions Related to Surplus Interconnection
• Is there any significance associated with ERIS/NRIS designations in surplus interconnection studies?
o For example, is the surplus option configured differently if it's modeled at a location with existing ERIS
compared to a facility qualified for NRIS?
Reply: ERIS/NRIS has no bearing on surplus interconnection studies and is not modeled differently.
Data Support: If applicable,provide any documents,hyper-links,etc. in support of comments. (i.e. gas forecast is too high
-this forecast from EIA is more appropriate). If electronic attachments are provided with your comments,please list those
attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
PacifiCorp Response:
Thank you for the feedback.As discussed in the in-line responses throughout your request,the modeling in the IRP has
significant simplifications relative to cluster study results and process.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (041)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-09-20
*Name: Nathan Strain Title:
*E-mail: [e-mail] Phone: (435) 200 - 5963
*Organization: Citizen
Address: 259 East 4800 South Apt. 4
City: Murray State: UT Zip: 84107
Public Meeting Date comments address: 0 8-15-2 0 2 4 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Existing Thermal Resource Options
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
With the volatility of coal supply and the environmental concerns associated with coal
has Pacificorp placed a heightened interest in conventional Nuclear? I am aware that suel
for SMRs is more scarce and expensive, perhaps a large conventional Nuclear plant at the
site of the Hunter Power Plant or a purchase of the stalled Blue Castle Nuclear Project
is warranted. Construction of conventional nuclear in Utah is likely to be politically
and socially popular. Pacificorp should also accelerate development of Geothermal in
Utah.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
Explore a large conventional Nuclear plant in Utah at the site of Hunter Plant or the
Blue Castle Project. More aggressively pursue geothermal.
PacifiCorp Response:
PacifiCorp's supply-side resource table for the 2025 IRP includes nuclear and geothermal resource options and was
recently posted to the Company's website:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2025-irp/2025-
irp-support-studies/Public_SSR Database_Summary_Tab_2025.xlsx
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The IRP generally does not evaluate specific projects but can identify general locations that might be favorable for
different resource types. PacifiCorp would note that the inclusion or exclusion of different resource types in the preferred
portfolio is an indication of the relative performance based on the supply-side resource assumptions. PacifiCorp is also
planning to prepare sensitivity studies based on"advanced"nuclear and geothermal costs,which start lower than the
baseline cost forecast and decline faster through time. The decision to move forward with particular resource offerings is
based on bids for specific projects,which can vary widely, along with consideration of a variety of less tangible risks
related to both the existing resource mix and potential resource additions.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (042)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-09-23
*Name: Jim Himelic Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: First Principles Advisory
Address:
City: State: Zip:
Public Meeting Date comments address: ❑ Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
PLEXOS LT Settings
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please provide a copy of the LT Plan settings used by PacifiCorp for their all final
capacity expansion modeling optimization runs conducted in PLEXOS. Please include in that
discussion the application of any global variables and/or undocumented parameters such as
slicing blocks, sampling years, and mixed chronology timestep blocks.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
I originally submitted this form back in May of this year but I never received a
response. Resubmitting it here again. Please confirm receipt
PacifiCorp Response:
We are currently working on inputting data for 2025 IRP and are also testing performance and various LT Plan settings.
We do not expect the settings to be settled until later in the process, and they are subject to further changes post-draft.
These settings will be provided as part of the data disc for the 2025 IRP.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form (044)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2024-09-28
*Name: Rose Monahan Title:
*E-mail: [e-mail] Phone: (415) 977 - 5704
*Organization: Sierra Club
Address: 2101 Webster Street, Suite 1300
City: Oakland State: CA Zip: 94612
Public Meeting Date comments address: 0 9-2 5-2 0 2 4 ® Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Thermal Resource Options
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
At the September 2024 PIM, PacifiCorp explained that CCUS will be considered for coal
units, including the Hunter and Huntington units, and that the CCUS option includes SCR
installation. Moreover, if the model selects CCUS at a single coal plant unit, CCUS must
be selected for all of the other coal units at that plant. Sierra Club urges PacifiCorp
to modify these assumptions as explained below. First, PacifiCorp should consider SCR as
a standalone requirement, and, as recommended by Sierra Club in its previous stakeholder
feedback form, include a modeling constraint that requires SCR at least one Hunter unit
and both Huntington units by no later than 2028. By including SCR within the CCUS option,
PacifiCorp is ignoring the possibility that SCR could be mandated at its coal units,
particularly the Hunter and Huntington plants, before CCS is required or could be
mandated even if the CCS requirement is not implemented. SCR is likely to be required at
the Hunter and Huntington coal plants under the Clean Air Act\u0019s Regional Haze
Program. Indeed, in proposing to disapprove Utah\u0019s regional haze state
implementation plan for the second implementation period, EPA faulted Utah for failing to
require SCR at Hunter Unit 3 and further stated that SCR likely should have been required
at the other Hunter and Huntington coal units. The current regional haze planning period
runs through 2028. As a result, it\u0019s likely that should SCR be required at the
Hunter and Huntington units, installation will be required before 2030, when PLEXOS
assumes CCUS becomes available. Moreover, the likely SCR requirement at the Utah coal
plants is separate from the CCS obligation under EPA\u0019s recent 111 (d) regulation for
coal plants that continue operating past 2035. While Sierra Club believes that the 111 (d)
regulation will be implemented, as PacifiCorp is well aware, environmental regulations
can be stayed, remanded to the agency, and/or vacated. If any of these options occur for
the 111 (d) regulation but not EPA\u0019s regional haze regulations for Utah, then the CCS
obligation may not apply while the SCR obligation does. By conflating these two separate
requirements in the PLEXOS modeling, PacifiCorp will be failing to clearly evaluate the
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least-cost approach to complying with both regulations. Second, PacifiCorp should change
the CCUS option in PLEXOS to CCS. The CCUS option is presumably meant to comply with
EPA\u0019s 111 (d) regulation, but that regulation does not authorize coal units to
utilize carbon capture, utilization, and sequestration technology. Instead, coal units
must install carbon capture and sequestration technology, otherwise the coal units are
not reducing their CO2 emissions but shifting them to a secondary purpose. There is no
reason to model a regulatory compliance obligation in a way that does not actually comply
with that regulation. Finally, PacifiCorp should remove the requirement that if the
PLEXOS model selects CCS at any one unit of a coal plant, that the model must select CCS
at all the plant\u0019s units. At the public input meeting, PacifiCorp asserted that this
constraint was reasonable because it is more cost effective to install CCS across an
entire plant rather than a single unit. While Sierra Club understands economies of scale,
it is not clear why PLEXOS cannot incorporate pricing assumptions that assume lower costs
for a second (or third) CCS installation at the same plant, rather than forcing the model
to select CCS for all units. Adjusting pricing assumptions for additional CCS
installations would allow PLEXOS to determine whether economies of scale warrant adding
CCS to additional units, rather than PacifiCorp making this assumption for the model
ahead of time. Not only does the constraint significantly skew the models internal logic,
but Sierra Club is also concerned that this constraint could result in PLEXOS running
entire coal plants longer than necessary to meet reliability requirements when those
reliability requirements could have been met with less than the entire coal plant\u0019s
output. For example, if the PLEXOS model finds that, in order to maintain reliability,
the PacifiCorp system requires continued operation of one Hunter unit, PacifiCorp\u0019s
proposed modeling constraint could force PLEXOS to select continued operation at all
three of the Hunter units, even though reliability would have been met with just one
unit. This is very likely to artificially keep coal plants operating\u0014with highly
expensive CCS and SCR controls\u0014when lower cost and more efficient options are
available. Indeed, it would skew the model to support high cost investments (for which
PacifiCorp earns a rate of return) over more cost effective options. This could be a
major liability in securing acknowledgment of the 2025 IRP before state public utility
commissions, not to mention achieving cost recovery in future rate cases.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above - specificity is greatly appreciated.
1. PacifiCorp should consider SCR as a standalone requirement, and, as recommended by
Sierra Club in its previous stakeholder feedback form, include a modeling constraint that
requires SCR at least one Hunter unit and both Huntington units by no later than 2028.
PacifiCorp Response:
Thank you very much for your feedback. The coal plant scenarios provided to the IRP team include continued operations
as currently configured, Gas Conversion and CCUS with SCR. The Company has SCR costs for each unit and estimated
emissions reductions that would result from SCR installation, such that the cost of the emissions reductions that would
result from an SCR can be calculated for any study result. The Company does not have information that would suggest
that SCR on its own would impact the operating characteristics of a unit, such as the heat rate,maximum operating level,
and so forth, so the inclusion of SCR is unlikely to change the way plants operate under current rules. Should rules change
in the future, PacifiCorp will work to identify the least cost,least risk pathway to compliance,which may include SCR,
placing limits on generation,replacing units or retrofitting units to burn other fuel types in some or any combination of
actions.
Regarding the concern related to requiring CCUS installation at all locations if the model would like to select CCUS at
one,in practice,PacifiCorp would not undergo the significant capital costs to install CCUS for a single unit when all units
at a site could leverage the technology for a nominal added cost. Regarding CCUS vs. CCS,PacifiCorp has called these
projects CCUS,but essentially is only modeling the Carbon Capture(or CC) side.Additionally,PacifiCorp is applying the
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largest eligible tax credit for a CCUS/CCS project. In order to maximize benefits(or reduce costs for customers),
PacifiCorp would certainly need to evaluate actual proposals knowing which level of tax credit would apply based on the
final CO2 use. While it may be of interest to see whether or not the model would select a single unit for CCUS conversion
or a final CO2 use that garnered lower tax credits,real world implementation of these options is implausible. Given
ongoing requests that PacifiCorp model actions which are as close to reality as possible (given the imperfect nature of
future proxy costs and performance) asking PacifiCorp to evaluate a choice it simply would not make is unnecessary.
Additionally, any selection of any change to an existing plant within the IRP will be subject to further consideration and
evaluations. In particular, selection of proxy CCUS costs and performance, or other high cost equipment such as an SCR
would be reviewed and validated using actual proposals from developers as part of the proposal,permitting and approval
process. In the absence of specific proposals with cost and performance that are projected to be a benefit to customers,the
project would not move forward.
PacifiCorp will consider calculating the cost of emissions reductions from an SCR within the constraints of 2025 IRP
timelines and requirements.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form (045)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-11-18
*Name: Kevin Emerson Title: Director of Building Efficienc
*E-mail: [e-mail] Phone: (801) 608 - 0850
*Organization: Utah Clean Energy
Address: 215 S. 400 E.
City: Salt Lake City State: UT Zip: 84129
Public Meeting Date comments address: 0 9-2 5-2 0 2 4 ®Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Baseline building energy code assumptions in the 2025 IRP Conservation Potential
Assessment
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
According to the presentation slides used at the 2025 Integrated Resource Planning Public
Input Meeting on September 25, 2024, AEG is using an inaccurate code baseline for
residential new construction in Utah. Slide 14 indicates that AEG is using the \u001C2015
IECC\u001D as representing Utah\u0019s energy code baseline for residential construction
in the state (see Note 1) . while Utah\u0019s residential energy code was updated by the
Utah Legislature in March 2024 (see Note 2) , the legislation maintained the numerous
weakening amendments in Utah\u0019s residential energy code, which has been previously
recognized as equivalent to the 2009 IECC. As per U.S. Department of Energy\110019s Status
of Energy Code Adoption map, despite the 2024 legislation, Utah\u0019s residential energy
code is still recognized as equivalent to the 2009 IECC (see Note 3) . The U.S. Department
of Energy estimates that Utah\u0019s residential energy code is 290 less efficient than
the 2021 IECC, the most recent model energy code. Using the correct residential energy
code baseline will impact the cost-effectiveness of new homes programs and more
accurately reflect the potential energy savings achievable though Rocky Mountain
Power\u0019s New Homes rebate program.
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high -this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
AEG\u0019s Conservation Potential Assessment modeling processes should be adjusted to
reflect the 2009 IECC as Utah\u0019s baseline residential energy code to capture the
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realistic level of energy saving potential associated with utility-sponsored new homes
rebate programs.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response:
Thank you for providing the information.Applied Energy Group(AEG)reviewed the US Department of Energy webpage
that Utah Clean Energy provided during the September 2024 Public Input Meeting, as well as text from Utah's House Bill
0518,passed in March 2024.AEG verified that the building envelope parameters now being used in the CPA are
"consistent with the latest Utah code plus amendments."
AEG noted that they primarily lean on the insulation and fenestration requirements in the component tables and other key
parameters such as duct insulation/air leakage requirements for residential measures. The commercial codes tend to have
much more complicated rules regarding controls and measure eligibility in new construction but were also verified against
the latest Utah code plus amendments.
* Required fields

PacifiCorp - Stakeholder Feedback Form (046)
Integrated Resource Plan
PacifiCorp (the Company) requests that stakeholders provide feedback to the Company upon the conclusion of each
public input meeting and/or stakeholder conference call, as scheduled. PacifiCorp values the input of its active and
engaged stakeholder group, and stakeholder feedback is critical to the IRP public input process. PacifiCorp requests that
stakeholders provide comments using this form, which will allow the Company to more easily review and summarize
comments by topic and to readily identify specific recommendations, if any,being provided. Information collected will be
used to better inform issues included in the IRP, including, but not limited to the process, assumptions, and analysis. In
order to maintain open communication and provide the broader Stakeholder community with useful information, the
Company will post appropriate feedback on the IRP website based on your selection below.
Date of Submittal 2 0 2 4-11-18
*Name: Kevin Emerson Title: Director of Building Efficienc
*E-mail: [e-mail] Phone: (801) 608 - 0850
*Organization: Utah Clean Energy
Address: 215 S. 400 E.
City: Salt Lake City State: UT Zip: 84129
Public Meeting Date comments address: ❑Check here if related to specific meeting
List additional organization attendees at cited meeting:
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
Updated Energy Efficiency and Demand Response Data Broken Out by State
® Check here if you want your Stakeholder feedback and accompanying materials posted to the IRP website.
*Respondent Comment: Please provide your feedback for each IRP topic listed above.
Please provide state-by-state data represented in Figure 1.11 \u0013 2023 IRP Update
Preferred Portfolio Energy Efficiency and Demand Response Capacity, which can be found on
page 10 of the 2023 Integrated Resource Plan Update. Specifically, we request to see
state-by-state data as presented in two tables from the 2023 Integrated Resource Plan
Volume II Appendices, Tables D.3 and D.4 (page 108) .
Data Support: If applicable, provide any documents, hyper-links, etc. in support of comments. (i.e. gas forecast is too
high - this forecast from EIA is more appropriate). If electronic attachments are provided with your comments, please list
those attachment names here.
Recommendations: Provide any additional recommendations if not included above- specificity is greatly appreciated.
PacifiCorp Response:
Thank you for the data request.
Note that Tables D.3 and DA from the 2023 IRP Appendix D show first year incremental resource selections in units of
MWh for energy efficiency(EE)and MW for demand response(DR). Meanwhile,Figure 1.11 in the 2023 IRP Update
report shows cumulative capacity in units of MW for both EE and DR.
Resource Incremental Selections Cumulative Capacity
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Demand Response Table D.3 (in MW) Figure 1.11 (in MW)
Energy Efficiency Table DA (in MWh) Figure 1.11 (in MW)
As such,PacifiCorp is presenting all four combinations of these figures,using the 2023 IRP Update data at the state level:
1) DR—First-Year Incremental(MW),like Table D.3
2) DR—Cumulative(MW),like Figure 1.11
3) EE—First-Year Incremental(MWh), like Table DA
4) EE—Cumulative(MW), like Figure 1.11
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1) DR First-Year Incremental(MW), like Table D.3
This figure does not include existing or planned DR resources, rather exclusively shows the new, incremental DR resource
selections in each year from the 2023 IRP Update. It also provides summer and winter DR capacity split-out. The figure is
not cumulative.
Table D.3-First Year Demand Response Resource Selections (2023 IRP Update)
(Units in MW)
Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
DR Summer- ID 0.0 0.0 1.0 8.6 0.4 4.0 0.3 0.0 0.6 9.2
DR Summer- UT 0.0 8.5 17.1 15.4 9.2 24.6 12.2 0.0 24.4 12.5
DR Summer-WY 0.0 0.0 10.5 1.6 0.6 27.1 0.5 0.0 0.9 0.3
DR Winter- ID 0.0 0.4 1.2 1.5 0.9 0.5 0.3 0.3 0.2 0.2
DR Winter- UT 0.0 0.0 11.1 13.7 8.4 7.8 6.0 6.5 4.9 4.9
DR Winter-WY 0.0 0.0 9.4 13.6 0.7 9.8 0.4 0.4 0.3 0.6
DR Summer- CA 0.0 0.0 1.5 1.2 0.5 1.7 0.1 0.0 0.3 0.1
DR Summer- OR 0.0 1.9 21.6 25.4 6.0 34.3 36.4 0.0 19.1 4.2
DR Summer-WA 0.0 2.8 4.7 7.5 1.1 15.0 0.9 0.0 4.8 0.6
DR Winter-CA 0.0 0.0 1.2 0.6 0.2 0.2 0.1 0.1 0.0 0.4
DR Winter-OR 0.0 14.7 11.9 19.3 6.0 7.4 3.1 3.4 0.0 52.8
DR Winter-WA 0.0 9.7 6.8 1.3 1.0 0.8 0.6 0.7 0.0 26.2
Resource 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
DR Summer- ID 0.0 0.2 0.1 0.2 20.9 11.1 0.0 0.7 0.6 0.0
DR Summer- UT 0.0 21.1 10.0 10.5 10.9 53.9 0.0 30.3 84.4 0.0
DR Summer-WY 0.0 0.3 0.0 0.0 0.0 9.9 0.0 0.2 0.5 0.0
DR Winter- ID 0.1 0.4 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DR Winter- UT 2.5 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DR Winter-WY 0.2 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5
DR Summer- CA 0.0 0.1 0.0 0.0 0.1 4.1 0.0 1.0 0.1 0.0
DR Summer- OR 0.0 16.5 0.3 0.3 11.1 22.0 0.0 37.3 6.5 0.0
DR Summer-WA 2.6 0.2 2.0 0.8 0.0 6.6 0.1 1.2 2.8 2.6
DR Winter-CA 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DR Winter-OR 1.2 0.4 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0
DR Winter-WA 2.2 1.8 1.3 0.0 0.0 0.0 0.0 0.1 0.0 0.0
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2) DR Cumulative (MW), like Figure 1.11
Different from Table D.3 above, this Figure 1.11 table shows cumulative DR capacity. It also sums the summer and winter
values to show a single state-wide capacity value. The figure does not include prior existing or planned DR resources.
Figure 1.11 -Cumulative Demand Response Resource Selections (2023 IRP Update)
(Sum of Summer&Winter;Units in MW)
Resource 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
DR- Idaho 0.0 0.4 2.6 12.8 14.1 18.6 19.2 19.5 20.4 29.7
DR- Utah 0.0 8.5 36.7 65.8 83.4 115.8 133.9 140.5 169.8 187.2
DR-Wyoming 0.0 0.0 19.9 35.1 36.3 73.3 74.2 74.6 75.7 76.6
DR-California 0.0 0.0 2.7 4.5 5.1 7.0 7.2 7.3 7.6 8.1
DR-Oregon 0.0 16.5 50.1 94.7 106.7 148.3 187.9 191.3 210.4 267.4
DR-Washington 0.0 12.5 24.0 32.8 35.0 50.8 52.3 53.0 57.8 84.6
Resource 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
DR- Idaho 29.8 30.5 30.7 31.0 51.9 63.0 63.0 63.7 64.3 64.3
DR- Utah 189.6 211.3 221.2 231.7 242.6 296.5 296.5 326.8 411.2 411.2
DR-Wyoming 76.7 77.2 77.2 77.3 77.3 87.2 87.2 87.4 88.0 88.5
DR-California 8.1 8.3 8.4 8.4 8.5 12.7 12.7 13.7 13.8 13.8
DR-Oregon 268.6 285.5 286.0 286.3 297.4 319.4 319.4 356.7 363.2 363.2
DR-Washington 89.4 91.3 94.7 95.6 95.6 102.2 102.3 103.6 106.3 109.0
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3) EE-First Year Incremental(MWh),like Table DA
This table shows EE savings selected in each year on a new, incremental, and first-year savings basis,in units of MWh. It
is not cumulative and does not include existing or planned EE resources. Savings from Home Energy Reports are
excluded as well.
Table DA-First-Year Energy Efficiency Resource Selections (2023 IRP Update)
(Excludes Home Energy Report Savings; Units in MWh)
State 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
EE -California 2,426 1,447 3,309 4,219 4,302 4,949 5,455 5,152 6,837 6,559
EE - Oregon 180,799 166,678 179,988 163,586 166,963 166,894 161,227 158,138 164,427 141,902
EE -WA 53,111 47,873 50,093 32,864 37,299 42,772 45,988 48,803 51,944 52,661
EE - Utah 266,501 267,939 272,287 328,565 376,872 418,663 447,683 461,195 479,295 490,851
EE - Idaho 11,998 14,924 17,533 23,331 25,929 29,383 31,060 31,616 33,629 34,674
EE -Wyoming 44,205 41,231 41,271 60,911 65,767 74,468 73,294 78,878 80,477 83,545
Total System 559,041 540,092 564,481 613,476 677,133 737,129 764,707 783,782 816,608 810,193
State 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
EE -California 6,313 6,068 4,840 5,899 6,455 4,929 4,416 4,180 3,782 2,889
EE -Oregon 129,397 128,891 124,318 119,729 116,967 94,132 93,169 107,376 81,309 97,751
EE -WA 48,740 46,200 41,550 40,853 35,002 31,963 28,115 27,882 24,825 23,594
EE - Utah 479,885 484,728 487,804 507,404 476,815 457,433 425,194 489,622 417,013 408,578
EE - Idaho 32,998 32,356 31,510 31,920 28,194 27,623 24,819 26,121 22,179 20,757
EE -Wyoming 79,290 78,293 73,052 72,758 63,554 61,514 57,448 63,129 48,250 51,786
Total System 776,623 776,535 763,075 778,562 726,987 677,594 633,161 718,310 597,357 605,354
* Required fields

4) EE-Cumulative(MW), like Figure 1.11
In alignment with Figure 1.11, this table shows capacity from EE resources, in units of MW, as opposed to energy savings
in MWh. It is shown in cumulative capacity and also does not include capacity from Home Energy Reports. The figure
does not include prior existing or planned EE resources.
Figure 1.11 -Cumulative Energy Efficiency Resource Selections (2023 IRP Update)
(Excludes Home Energy Report Savings; Units in MW)
State 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
EE -California 1.0 1.6 3.0 4.0 4.9 6.0 7.1 8.3 10.3 11.7
EE -Oregon 56.6 102.8 166.7 223.4 277.8 332.5 397.2 456.5 546.8 579.3
EE -Washington 16.6 31.4 47.9 54.0 61.0 69.2 78.3 88.1 97.8 108.7
EE - Utah 78.6 155.2 266.9 344.9 437.2 542.3 662.9 791.6 915.8 1,040.3
EE - Idaho 2.9 6.4 10.7 17.4 24.7 32.8 41.5 50.6 59.1 68.2
EE -Wyoming 9.6 18.9 32.1 43.9 56.7 71.3 85.4 100.7 114.9 131.4
Total System 165.3 316.3 527.3 687.6 862.4 1,054.1 1,272.5 1,495.8 1,744.7 1,939.6
State 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042
EE - California 13.0 14.3 15.3 16.5 19.1 20.2 21.2 22.2 23.0 24.1
EE -Oregon 629.7 682.0 742.1 782.7 881.6 899.7 930.2 977.0 1,024.5 1,134.2
EE -Washington 119.5 129.4 138.6 147.5 153.9 161.3 167.6 173.3 178.9 183.2
EE - Utah 1,173.9 1,315.4 1,477.2 1,654.8 1,821.7 1,961.8 2,082.8 2,227.5 2,388.6 2,574.9
EE - Idaho 77.6 87.0 96.4 106.1 112.9 120.2 127.0 134.4 141.9 147.0
EE -Wyoming 149.0 164.4 179.5 193.4 203.7 216.1 228.2 240.0 248.2 255.5
Total System 2,162.7 2,392.5 2,649.2 2,901.1 3,192.9 3,379.4 3,556.9 3,774.5 4,005.1 4,318.9
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
APPENDIX O - WASHINGTON CLEAN ENERGY
ACTION PLAN
Introduction
The Clean Energy Transformation Act (CETA) was passed by the Washington State Legislature
and signed into law by Governor Jay Inslee in May 2019. The legislation combines directives for
utilities to pursue a clean energy future with assurances that benefits from a transformation to clean
power are equitably distributed among all Washingtonians.'
The Washington Utilities and Transportation Commission began rulemakings to implement CETA
in June 2019, and the first phase concluded in December 2020. As directed by the legislation and
the new CETA rules, Washington electric utilities must file the following long-term planning
documents every four years:
Clean Energy Action Plan: The Clean Energy Action Plan(CEAP)is a ten-year planning
document that is derived from the IRP and included as an appendix to the IRP. The CEAP
provides a Washington-specific view of how PacifiCorp is planning for a clean and
equitable energy future that complies with CETA.
Integrated Resource Plan: The IRP is a comprehensive decision support tool and
roadmap for meeting the company's objective of providing reliable and least-cost electric
service to its customers. The plan is developed through open, transparent and extensive
public involvement from state utility commission staff, state agencies, customer and
industry advocacy groups, project developers, and other stakeholders.2
The key elements of the IRP include: an assessment of resource need, focusing on the first
10 years of a 20-year planning period; the preferred portfolio of supply-side and demand-
side resources to meet this need; and an action plan that identifies the steps that will be
taken over the next two-to-four years to implement the plan.
Clean Energy Implementation Plan: The Clean Energy Implementation Plan (CEIP) is
a plan that lists the specific actions PacifiCorp will take over the next four years to move
toward the 2030 and 2045 clean energy directives, while also describing long-term clean
energy interim targets through 2045. The CEIP also includes customer benefit indicators,
developed with input from advisory groups. PacifiCorp's inaugural CEIP, covering the
2022-2025 planning period,was filed December 30,2021. The company expects to file the
next CEIP October 1, 2025, focusing on years 2026-2029.3
This Appendix O is included with the 2025 IRP in fulfillment of the requirement to file a CEAP
for Washington. Described in WAC 480-100-620(12), the utility must develop a ten-year clean
energy action plan implementing the CETA clean energy standards and must:
(a) Be at the lowest reasonable cost;
12019 WA Laws Ch.288.
2 WAC 480-100-620.
3 WAC 480-100-640.
313

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
(b) Identify and be informed by the utility's ten-year cost-effective conservation potential
assessment as determined under RCW 19.285.040;
(c) Identify how the utility will meet the requirements in WAC 480-100-610 (4)(c)
including,but not limited to:
(i) Describing the specific actions the utility will take to equitably distribute
benefits and reduce burdens for highly impacted communities and vulnerable
populations;
(ii) Estimating the degree to which such benefits will be equitably distributed and
burdens reduced over the CEAP's ten-year horizon; and,
(iii) Describing how the specific actions are consistent with the long-term strategy
described in WAC 480-100-620 (11)(g).
(d) Establish a resource adequacy requirement;
(e) Identify the potential cost-effective demand response and load management programs
that may be acquired;
(f) Identify renewable resources, nonemitting electric generation, and distributed energy
resources that may be acquired and evaluate how each identified resource may reasonably
be expected to contribute to meeting the utility's resource adequacy requirement;
(g) Identify any need to develop new, or to expand or upgrade existing, bulk transmission
and distribution facilities;
(h) Identify the nature and possible extent to which the utility may need to rely on an
alternative compliance option identified under RCW 19.405.040 (1)(b), if appropriate; and
(i) Incorporate the social cost of greenhouse gas emissions as a cost adder as specified in
RCW 19.280.030(3).
The following sections describe how a long-run portfolio is optimized to meet CETA's clean
energy standards at least-cost, least-risk, in accordance with the requirements defined above.
Portfolio Development
The 2025 IRP process serves as the basis for developing and identifying the 10-year action plan
that will put the company on a path towards compliance with the CETA clean energy standards.
PacifiCorp's CEAP is planning toward a future in Washington that balances a rapid transition to
renewable and non-emitting energy as directed under CETA, with the company's continued
commitment to ensure that customers are served affordably, safely, and reliably. To meet
reliability standards in a future that includes an increasing number and type of variable resources,
the company carefully analyzes the way its programs, generation resources, customer load
obligations, cost-effective conservation potential fit together to ensure reliability.
The company's long-term load forecasts(both energy and coincident peak load) for the system are
summarized in Volume I, Chapter 6 (Load and Resource Balance) as well as for each state in
Appendix A(Load Forecast Details). The summary-level system coincident peak is presented first,
followed by a profile of PacifiCorp's existing resources. Finally, load and resource balances for
capacity and energy are presented. These balances are composed of a year-by-year comparison of
projected loads against the existing resource base, with assumed incremental new energy
efficiency savings from the preferred portfolio,before adding new generating resources.
314

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
Resource Portfolio Development
As discussed in Volume I, Chapter 8, PacifiCorp uses the Plexos LT model to produce resource
portfolios with sufficient capacity to meet all load and operating reserves requirements over the
study horizon appropriate to achievable granularity. Each of these portfolios is uniquely
characterized by variables on PacifiCorp's system, including type, timing, location, and size of
resources needed to achieve reliable operation. The portfolio modeling and selection process leads
to an optimized, lowest reasonable cost six-state integrated portfolio to serve PacifiCorp's
customers.
These resource portfolios reflect a combination of planning assumptions such as resource
retirements,CO2 prices(also applicable to CO2 equivalent emissions,or"CO2e"),wholesale power
and natural gas prices, load growth net of assumed distributed generation penetration levels, cost
and performance attributes of potential transmission upgrades, and new and existing resource cost
and performance data, including assumptions for new supply-side resources and incremental
demand-side management(DSM)resources. Changes to these input variables cause changes to the
resource mix, which influences system costs and risks.
Resource Adequacy
As described in Volume I, Chapter 8, the 2025 IRP ensures resource adequacy for the system and
by state by requiring each portfolio to include sufficient resources to be compliant with the Western
Resource Adequacy Program (WRAP), both in aggregate and for the loads and resources specific
to the jurisdiction under evaluation. In addition, portfolios must be able to meet hourly load
requirements without significant energy shortfalls, and the iterative portfolio development process
increases planning requirements within the LT model to account for shortfalls identified within the
more granular ST model.
Development of a Washington-compliant portfolio
The 2025 IRP produces an integrated preferred portfolio that is developed to be compliant with
state-specific requirements in all of PacifiCorp's jurisdictions, including Washington's CETA
standards,while ensuring that the allocation of resources within the portfolio reflects the selections
under the modeling requirements of each individual jurisdiction. All resources for Washington
customers and compliance obligations are optimized and selected under the social cost of
greenhouse(SCGHG)price policy assumption. The model optimizes across a range of supply-side
resource options, including renewable, non-emitting and storage resource options in addition to
DSM resources, given various economic and regulatory inputs and assumptions.
An important update in this 2025 IRP and CEAP, is that the modeling process allows for
endogenous selection of resources to serve individual state-specific requirements. Additionally,
the final draft preferred portfolio, integrates all system and state-specific resources into one final
resource portfolio. Several key assumptions are required to determine what existing resources are
allocated to Washington customers and at what share, what new proxy resources can be allocated
to Washington customers and if those resources are acquired as system or situs (allocated solely
to Washington customers), and how those resources and the energy generated contribute towards
CETA clean energy targets.
315

PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
To estimate the mix of energy forecasted to serve Washington customers in any given model run,
it was assumed that generation resources are allocated in accordance with the methodology defined
under the Washington Inter-Jurisdictional Allocation Methodology (WIJAM) for existing
resources and generally assumed that these assumptions hold into the future, in the absence of an
agreed upon future allocation methodology.'All new proxy resources (renewable or non-emitting
resources, only) are assumed to be either acquired for, and therefore allocated to,the system or are
an incremental requirement to satisfy state-specific compliance and are therefore situs allocated to
the state of origin. The allocations assumed for Washington are the Company's best estimate of
future allocations at this time and are best aligned with other ongoing filings in Washington.
To calculate the energy and the total amount of renewable and carbon non-emitting energy
allocated to Washington customers that make up the CETA clean energy interim targets, the
company made the assumptions set forth below. Generally, where a resource is assumed to
generate renewable energy credits (RECs),where one REC is generated for one megawatt-hour of
renewable energy, the resource was assumed to generate CETA-compliant energy. In addition to
REC-generating resources, it was assumed that all Washington-allocated energy from non-
emitting resources was also CETA compliant,namely hydroelectric and nuclear.'In summary,the
resource allocation assumptions are:
1. Allocation of energy for all renewable resources (non-QFs), existing and proxy, are
allocated according to system-generation(SG) factors, consistent with the WIJAM, if
designated a"system"resource.
2. Allocation of energy for new "system"non-emitting proxy resources are allocated on SG
factors, consistent with the WIJAM.
3. Allocation of energy for all Washington qualifying-facilities (QFs) are assumed to be
situs to Washington. No energy is allocated from QFs not originating in Washington,
consistent with Washington Utilities and Transportation Commission policy.
4. Washington customers are assumed to participate in a limited set of emitting resources as
defined under the West Control Area Inter-Jurisdictional Allocation Methodology
(WCA):
a. Washington customers receive costs and benefits from PacifiCorp's interest in the
Colstrip Unit 4 and Jim Bridger Units 1-4 thermal resources, subject to
elimination of all costs and benefits from coal-fueled Colstrip 4 and Jim Bridger
Units 3 and 4 until the end of 2025.
b. Washington customers continue to receive and benefits from Jim Bridger Units 1-
2 after they convert to run on natural gas start in 2024, until the end of 2029.
c. Washington customers participate in two gas-fired units, Chehalis and Hermiston,
through 2044.
5. New proxy renewable and non-emitting resources are allocated situs (100%) to
Washington when determined to be incremental resources for Washington need.
4 The WIJAM and the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol(2020 Protocol)define how resources
and costs are allocated to Washington customers through December 21, 2023. The Washington Utilities and
Transportation Commission approved the WIJAM and 2020 Protocol in its Final Order 09/07/12 in docket UE-191024
et. al., effective January 1, 2021. The company is in the process of negotiating its Multi-State Process (MSP) cost
allocation methodology with the commissions and stakeholders in the six states it serves. More information can be
found in Volume I,Chapter 3.
5 WAC 480-100-610(3)states that by January 1,2045,each utility must ensure that"non-emitting electric generation
and electricity from renewable resources supply one hundred percent of all retail sales of electricity to Washington
electric customers".
316

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Given the assumed allocations of resource energy and costs to Washington, CETA-compliant
energy is determined given the following:
I. For existing REC-generating resources, generation of CETA-compliant energy is
consistent with the company's REC entitlement start and end date.
2. Customer preference and voluntary renewable resources were not assumed to generate
RECs for the system or the state of Washington and thus are not included in the allocation
of renewable energy.
3. All new or proxy renewable and non-emitting resources were assumed to be CETA
compliant, including wind, solar, geothermal,hydro, and nuclear. For renewable resources
co-located with battery storage,RECs were assumed to be generated pre-storage;no RECs
are generated at battery discharge.
4. Emitting generation (coal or gas-fueled resources) are not CETA compliant.
Washington retail electric sales are defined as total energy served to customers annually, net of
distributed generation, existing and optimized energy efficiency and DSM resources. Retail
electric load does not include MWh delivered from Washington qualifying facilities under the
federal Public Utilities Regulatory Policies Act of 1978(PURPA).6 CETA compliance targets were
calculated annually as a percentage of Washington retail electric sales. Annual targets for CETA's
2030 and 2045 requirements were calculated as a percentage of Washington retail electric sales to
be the total renewable and carbon non-emitting energy the company estimates will be provided to
Washington customers.
Based on these assumptions, a CETA-compliant portfolio was developed and is the basis for the
clean energy interim targets depicted in the following section.
RCW 19.405.040 and 19.405.050 set the 2025, 2030, and 2045 goals for electric utilities in
Washington to meet. Specifically, utilities must show that by December 31, 2025, all coal-fired
generation has been removed from Washington's allocation of electricity. By January 1, 2030,
utilities must be greenhouse gas neutral,and by 2045,Washington's electric utilities must be 100%
renewable.
RCW 19.405.090 sets out four alternative compliance pathways that can be used to meet up to
20% of the carbon neutrality standards that begin in 2030 and run through 2044:
(i) Making an alternative compliance payment under RCW 19.405.090(2);
(ii) Using unbundled renewable energy credits, provided that there is no double counting
of any nonpower attributes associated with renewable energy credits within Washington or
programs in other jurisdictions, subject to conditions outlined in CETA;
(iii) Investing in energy transformation projects, including additional conservation and
efficiency resources beyond what is otherwise required under this section, provided the
6 RCW 19.405.020(36)(a)
317

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
projects meet the requirements of subsection (2) of this section and are not credited as
resources used to meet the standard under(a) of this subsection; or
(iv) Using electricity from an energy recovery facility using municipal solid waste as the
principal fuel source, where the facility was constructed prior to 1992, and the facility is
operated in compliance with federal laws and regulations and meets state air quality
standards.
The Draft 2025 IRP preferred portfolio, optimized and dispatched under the social cost of
greenhouse gas price policy for Washington customers, currently forecasts that PacifiCorp will
be on track to meet the compliance requirements in 2030 and 2045, serving 110% of Washington
retail sales with CETA-compliant energy by the end of 2030, as shown in Figure 0.1.
Figure 0.1 -- Clean energy interim targets for Washington customers from 2025 through 2045
Clean Energy Targets
300%
282%
274%273%271°,° 266°!0 271%272%268%265%262/°°
J 200°%
a i2029 4-year
Avg 45%
a ua%
0
124%125%1240/.124%
I10%107% 100Y Achieved
100
4^
2 3 ° 38% 35%
' 1 1
• 'j025 �016 ,41 ,p3% tiko'L S33 'p,0 Jo's Zob Zp�� lo" -10 two IQ", to" tw ,�a' -1-
■ Neutrality Targets through 2030 ■ Targets through IRP Horizon
Currently, PacifiCorp does not expect to use the alternative compliance payment, energy
transformation project, or energy recovery facility pathway to meet the standards under RCW
19.405.090. PacifiCorp is conducting stochastic analysis for inclusion in the final IRP filing that
includes annual variation in hydro, wind, and solar generation based on historical weather
conditions. Depending on the annual weather conditions,meeting targets for 2030 may require the
use of unbundled renewable energy credits, though impacts of annual variation are likely to be
closer to normal levels when evaluated over the four years of the first compliance period.
Table 0.1 below reports updated interim targets for the Company's second CEIP planning period
for years 2026-2029, reported as annual megawatt hours of energy rather than as percentages.
318

PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
Table 0.1 —Clean energy interim targets for Washin ton customers 2026-2029
2026 2027 2028 2029 Total
Retail Electric
Sales 4,081,072 4,250,939 4,428,652 4,437,788 17,198,451
Projected
Renewable and
Nonemitting
Eneray 1,262,556 1,608,692 1,548,245 3,284,829 7,704,322
Net Retail Sales 2,818,516 2,642,248 2,880,407 1,152,958 9,494,129
Target Percentage 31% 38% 35% 74%
Interim Clean
Energy Target 1,262,556 1,608,692 1,548,245 3,284,829 7,704,322
Specific Actions a.
Note— The following specific actions are anticipated for the 2025 IRP final filing on March
31, 2025, but may not be available before that time:
• Supply-ide resource actions
• Demand-side resource actions
[Customer Benefit Indicators
Note— The discussion regarding the current customer benefit indicators framework and
how it is included in the development of the CEAP is anticipated for the 2025 IRP final
filing on March 31, 2025, but may not be available before that time.
319

PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
320

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
APPENDIX P - ACRONYMS
AB =Assembly Bill
AC = alternating current
ACE=Affordable Clean Energy Rule
ACE=Area Control Error
AEG= applied energy group
AFSL=average feet(above) sea level
AFUDC = allowance for funds used during construction
AGC =Automatic Generation Control
AH=Ampere hour
A/m=Amperes per Meter
AMI=Advance Metering Infrastructure
AMR=Automated Meter Reading
ARO = asset retirement obligation
ATC =Available Transmission Capacity(Available Transfer Capacity?)
AVR=Automatic Voltage Regulator
AWEA=American Wind Energy Association
BA—Balancing Authority
BAA=Balancing Authority Area
BART=Best Available Retrofit Technology
BCF/D =billion cubic feet per day
BES =Bulk Electric System
BLM=Bureau of Land Management
BMcD =Burns and McDonnell
BPA=Bonneville Power Administration
BSER=best system of emission reduction
Btu=British thermal unit
CAES = compressed air energy storage
CAGR= compounded annual average growth rate
CAIDI= Customer Average Interruption Duration Index
321

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
CAISO= California Independent System Operator
CAP =Community Action Program
CARB =California Air Resources Board
CARI= Control Area Reliability Issues
CCCT= Combined Cycle Combustion Turbine
CCGT= Combined Cycle Gas Turbine
CCR= coal combustion residual
CCS = carbon capture and sequestration/Utah Committee of Consumer Services
CEC =California Energy Commission
CETA= Clean Energy Transformation Act
CF =capacity factor
CFL= Compact Fluorescent Light Bulb
CIPS = Critical Infrastructure Protection Standards
CIS = Corporate Information Security
CO =carbon monoxide
CO2 =carbon dioxide
Cogen= Cogeneration
COMPASS = Coordinated Outage Management Planning and Scheduling System?
CPA=Conservation Potential Assessment
CPU=Clark Public Utilities/cost per unit
CPUC = California Public Utilities Commission
CREA= Columbia Rural Electric Association
CSP= concentrated solar power
CTG= Combustion Turbine Generator
CUB = (Oregon) Citizen's Utility Board
DC =direct current
DF= duct firing
DG=Distributed Generation
DOE=Department of Energy
DPU=Utah Division of Public Utilities/Distribution Protection Unit(relay)
DR=Demand Response
322

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
DRA=Division of Ratepayer Advocates
DSM=demand-side management
EBIT=Earnings before Interest and Taxes
EDAM=extended day-ahead market
EE=Energy Efficiency
EEI=Edison Electric Institute
EIA=Energy Information Administration
EIM=Energy Imbalance Market
ELCC =Effective Load Carrying Capacity
EPA=Environmental Protection Agency
EPC= engineering,procurement, and construction
EPM=Energy Portfolio Management System
ERC =emission rate credit
ETO =Energy Trust of Oregon
EUBA=Electric Utility Benchmarking Association
EUI=Energy Utilization Index
EUL=effective useful life
EV=Electric Vehicle
FCC =Federal Communications Commission
FCRPS =Federal Columbia River Power System
FERC =Federal Energy Regulatory Commission
FIP = federal implementation plan
FIT =Feed-In Tariff
FLPMA=Federal Land Policy Management Ace
FOTs=Front Office Transactions
FRAC =Flexible Resource Adequacy Capacity
GAAP =Generally Accepted Accounting Principles
GBP =Great Britain Pound
GE= General Electric
GFCI= Ground Fault Circuit Interrupter
GHG=Greenhouse Gas
323

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
GIC =Generation Interconnection Contract
GIS = Geographic Information System
GPS = Global Positioning System
GRC= General Rate Case
GRID =Generation and Regulation Decision Model (used for net power cost pricing calc and
QF avoided cost calc)
GT= Gas Turbine
GW= Gigawatt
GWh=gigawatt-hours (gigawatt)
H=Hour
HB =House Bill
HCC =Hydro Control Center
HRSG=Heat Recovery Steam Generator
HVAC =heating, ventilation, and air conditioning
Hz=Hertz
IBEW=International Brotherhood of Electrical Workers
IC =internal combustion
ICE=Intercontinental Exchange
IECC= International Energy Conservation Code
IEEE=Institute of Electrical and Electronic Engineers
IGCC =integrated gasification combined cycle
IHS =Information Handling Services
ILR=Inverter Loading Ratio
IOU= Investor Owned Utility
IPC =Idaho Power Company
IPP =Independent Power Producer
IPOC= Idaho Power Company
IPUC= Idaho Public Utility Commission
IRA=Inflation Reduction Act
IRP= Integrated Resource Plan
IS =Information Systems
324

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
ISO =Independent System Operator
IT=Information Technology
ITC =Investment Tax Credit
K=kilo (thousand)
Kv=kiloVolt
kW=kilowatt
kWh=kilowatt-hour
kW-yr=Kilowatt-Year
kV=kilovolt
kVa=kilovolt-ampere
kVAr=kilovolt-ampere-reactive
kVArh=kilovolt-ampere-reactive-hour
Lb=Pound
LCOE=Levelized Cost of Energy
LED =light emitting diode
Li-Ion=lithium-ion battery
Lm= lumens
LNG=Liquefied Natural Gas
LOLH=loss of load hour
LOLP = loss of load probability
LRA=Local Regulatory Authority
LSE= load serving entities
MATS =Mercury and Air Toxics Standards
MMBpd=Million barrels of oil per day
MMBtu=Million British thermal units
MSP =Multi-State Process
MVA=megavolt-ampere
MVAr=megavolt-ampere-reactive
MVA LTC =megavolt-ampere, load tap changing
M W=Megawatt
MWh=megawatt hour
325

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
$MWh= dollars per megawatt hour
NAAQS =National Ambient Air Quality Standards
NA-PEE=National Action Plan for Energy-Efficiency
NCM=nickel cobalt manganese (sub-chemistry of Li-Ion)
NEEA=Northwest Energy Efficiency Alliance
NEEP =Northeast Energy Efficiency Partnerships
NEMA=National Electrical Manufacturer's Association
NEMS =National Energy Modeling System
NERC =North American Electric Reliability Corporation
NH3 =Ammonia
NOAAF =National Oceanic and Atmospheric Administration Fisheries
NRC=Nuclear Regulatory Commission
NREL=National Renewable Energy Laboratory
NOx=Nitrogen Oxides
NPV=net present value
NQC =Net Qualifying Capacity
NSPS =new source performance standards
NTTG=Northern Tier Transmission Group
NWEC =NW Energy Coalition
NWPCC =Northwest Power and Conservation Council
O&M= operations and maintenance
OAR= Oregon Administrative Rules
OASIS = Open Access Same Time Information System
OATT=Open Access Transmission Tariff
ODOE= Oregon Department of Energy
ODOT= Oregon Department of Transportation
OE= Owner's Engineer
OEM=Original Equipment Manufacturer
OFPC= Official Forward Price
OMS = Outage Management System
OPUC = Oregon Public Utility Commission
326

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
ORS =Oregon Revised Statutes
OTR= Ozone Transport Rule
PAC =PacifiCorp
PACE=PacifiCorp East?
PaR=Planning and Risk Model
PC =pulverized coal
PCB =Polychlorinated Biphenyls
PC CCS =pulverized coal equipped with carbon capture and sequestration
PDDRR=Partial displacement differential revenue requirement methodology(OR QF)
PG&E=Pacific Gas & Electric
PGE=Portland General Electric
PHES =pumped hydro energy storage
PJM=no definition
PM=particulate matter
PM2.5=Particulate Matter 2.5 microns and larger
PMIo=Particulate Matter 10 microns and larger
PNUCC =Pacific Northwest Utility Coordinating Council
POU=Publicly Owned Utility
PP=Pacific Power
PPA=Power Purchase Agreement
Ppb=parts per billion
PP&L=Pacific Power& Light Co.
ppmvd@15%02 =parts per million, dry-volumetric basis, corrected to 15% Oxygen (02)
PRM=Planning Reserve Margin
PSC=Public Service Commission
PSE=Purchasing-Selling Entity
Psia=Pounds per Square Inch-Absolute
PTC=Production tax credit
PTO =Participating Transmission Owner
PTP =point to point
PUC =Public Utility Commission
327

PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
PURPA=Public Utility Regulatory Policies Act
PV=photovoltaic
PVRR(d) =present value revenue requirement (delta)
PWC =PricewaterhouseCoopers
QC = Qualifying Capacity
RA=Resource Adequacy
RCRA=Resource Conservation and Recovery Act
RCW=Revised Code of Washington
REA=Rural Electrical Administration/Rural Electrification Administration
REC =renewable energy credit(certificate)
RFI=request for information
RFM=Rate Forecasting Model
RFP=Request for Proposal
RH=Relative humidity
RICE=Reciprocating Internal Combustion Engine
RMP=Rocky Mountain Power
RPS = Renewable Portfolio Standard
RTO=Regional Transmission Organization
RTF=Regional Technical Forum
RTP=real-time pricing
RVOS =Resource Value of Solar
SAIDI= System Average Interruption Duration Index
SAIFI = System Average Interruption Frequency Index
SB = Senate Bill
SCCT= Simple Combined Cycle Turbine
SCPC = Super-critical pulverized coal
SCPPA= Southern California Public Power Authority
SCR= selective catalytic reduction system
SEC= Securities and Exchange Commission
SEEM= Simple Energy Enthalpy Model
SEPA= Solar Electric Power Association
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PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
SIP = state implementation plan
SF = Senate File
SF6= Sulfur Hexafluoride
SNCR= selective non-catalytic reduction
SO= System Optimizer
S02= Sulfur Dioxide
SOX= Sulfur Oxide
SRSG= Southwest reserve sharing group
SSR= supply side resource (table)
STEP= Sustainable Transportation and Energy Plan
STG= Steam turbine generator
SWEEP = Southwest Energy Efficiency Project
T&D= Transmission&Distribution
th=Therm
TPL=transmission planning assessment
UAE=Utah Association of Energy Consumers
UDOT=Utah Department of Transportation
UMPA=Utah Municipal Power Agency
UNIDO =United Nations Industrial Development Organization
UP&L=Utah Power& Light Co.
UPC =Use per Residential Customer
UCE=Utah Clean Energy
UCT=Utility Cost Test
VERs =Variable Energy Resources
V=volt
VA=Volt-ampere
VDC =Volts Direct Current
VOC =volatile organic compounds
W=Watts
WAC=Washington Administrative Code
WACC =weighted average cost of capital
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PACIFICORP-2025 IRP APPENDIX P-ACRONYMS
WAPA=Western Area Power Administration
WCA=West Control Area
WECC =Western Electricity Coordinating Council
Wh=Watt-hour
WIEC =Wyoming Industrial Energy Council
WPSC =Wyoming Public Service Commission
WRA=Western Resource Advocates
WRAP =Western Resource Adequacy Program
WREGIS =Western Renewable Generation Information System
WSEC=Washington State Energy Code 2015
WSPP=Western Systems Power Pool
WTG=wind turbine generator
WUTC =Washington Utilities and Transmission Commission
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