20250506IRP Vol 1_Vol 2.pdf

RECEIVED
March 31, 2025
IDAHO PUBLIC
i iTii iTIES COMMISSION
_ ROCKY MOUNTAIN 1407 West North Temple, Suite 330
POWER. Salt Lake City, Utah 84116
A DIVISION OF PACIFICORP
March 31, 2025
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 2025 Integrated Resource Plan
Attention: Commission Secretary
Please find enclosed PacifiCorp's 2025 Integrated Resource Plan("2025 IRP").Copies of the 2025
IRP are also available electronically on PacifiCorp's ("Company") website, at
hgps://www.pacificorp.com/energy/integrated-resource-plan/support.html. As with previous
IRPs, the Company will provide workpapers and supplemental materials supporting the analyses
in the 2025 IRP. These materials,including non-confidential, confidential, and highly confidential
information, are planned for filing on or around April 11, 2025.
Confidential information in the 2025 IRP and workpapers will be available to state regulators and
any party who has intervened in this case and signed a non-disclosure agreement. PacifiCorp
requests that interested parties contact the state manager listed below for a copy of the non-
disclosure agreement that must be executed and submitted prior to obtaining a copy of the
confidential information.
All formal correspondence and data requests regarding this filing should be addressed as follows:
By E-mail (preferred): datarequest(&12acificor2.com
irpnpacificorp.com
mark.alder(ibpacific orp.com
j o seph.dallaskpacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries, including requests to receive a copy of the 2025 IRP filing, may be directed
to Mark Alder, Idaho Regulatory Affairs Manager, at(801) 220-2313.

Idaho Public Utilities Commission
March 31, 2025
Page 2
PacifiCorp appreciates the time and effort Idaho participants have dedicated to helping the
Company develop its 2025 IRP.
Sincerely,
)A 9�za�"D
Joelle Steward
Senior Vice President, Regulation
Enclosures
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

2025 1
Integrated Resource Plan
Volume I - March 31 , 2025
Imo:,
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PACIFICORR
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This 2025 Integrated Resource Plan is based upon the best available information at the time of
preparation. The IRP action plan will be implemented as described herein, but is subject to
change as new information becomes available or as circumstances change. It is PacifiCorp's
intention to revisit and refresh the IRP action plan no less frequently than annually. Any
refreshed IRP action plan will be submitted to the State Commissions for their information.
For more information, contact:
PacifiCorp Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
[e-mail]
www.pacificorp.com

PACIFICORP—2025 IRP TABLE OF CONTENTS
TABLE OF CONTENTS - VOLUME I
TABLEOF CONTENTS...............................................................................i
TABLE OF TABLES................................................................................Viii
TABLE OF FIGURES ............................................................................... Xi
CHAPTER 1 - EXECUTIVE SUMMARY
MAINTAINING CUSTOMER FOCUS....................................................................................................................I
ROADMAP..................................................................................................................................................................1
PACIFICORP'S INTEGRATED RESOURCE PLAN APPROACH.....................................................................2
PREFERRED PORTFOLIO HIGHLIGHTS...........................................................................................................4
NEWSOLAR RESOURCES...........................................................................................................................................6
NEWWIND RESOURCES.............................................................................................................................................7
NEWSTORAGE RESOURCES.......................................................................................................................................7
NEWNUCLEAR RESOURCES......................................................................................................................................8
DEMAND-SIDE MANAGEMENT..................................................................................................................................8
COAL AND GAS EXITS,RETIREMENTS,AND GAS CONVERSIONS...............................................................................9
CARBON DIOXIDE EMISSIONS..................................................................................................................................11
ACTIONPLAN.........................................................................................................................................................13
CHAPTER 2 - INTRODUCTION
INTRODUCTION.....................................................................................................................................................19
2025 INTEGRATED RESOURCE PLAN COMPONENTS.................................................................................20
THE ROLE OF PACIFICORP'S INTEGRATED RESOURCE PLANNING....................................................21
PUBLIC INPUT PROCESS.....................................................................................................................................22
CHAPTER 3 - PLANNING ENVIRONMENT
INTRODUCTION.....................................................................................................................................................24
WHOLESALE ELECTRICITY MARKETS.........................................................................................................24
POWERMARKET PRICES..........................................................................................................................................27
POWERMARKET DYNAMICS ...................................................................................................................................29
Non-CAISO WECC Generation and Capacity Mix............................................................................................29
Emissions and Environment...............................................................................................................................32
Non-CAISO WECC Demand Forecast...............................................................................................................32
ForwardInfluence of the IRA............................................................................................................................33
NATURALGAS PRICES.............................................................................................................................................33
2022 Summary...................................................................................................................................................33
2023 Summary...................................................................................................................................................35
2024 Summary...................................................................................................................................................36
2025-2032 Forward View..................................................................................................................................37
Conclusion.........................................................................................................................................................38
1

PACIFICORP—2025 IRP TABLE OF CONTENTS
PACIFICORP'S MULTI-STATE PROCESS....................................................................................................................38
ENVIRONMENTAL REGULATION.............................................................................................................39
FEDERAL POLICY UPDATE........................................................................................................................40
NATIONAL ELECTRIC VEHICLE INFRASTRUCTURE FORMULA PROGRAM.................................................................40
SECTION 11401 GRANTS FOR CHARGING AND FUELING INFRASTRUCTURE.............................................................40
NEW CREDITS AND CONSIDERATIONS FOR NON-EMITTING RESOURCES—INFLATION REDUCTION ACT..................40
NEW CREDITS AND CONSIDERATIONS FOR CUSTOMER RESOURCES—INFLATION REDUCTION ACT..........................41
NEW SOURCE PERFORMANCE STANDARDS FOR CARBON EMISSIONS FROM NEW AND EXISTING SOURCES—CLEAN
AIRACT§ 111(B)AND(D).......................................................................................................................................42
CREDIT FOR CARBON OXIDE SEQUESTRATION—INTERNAL REVENUE SERVICE§45Q............................................43
CLEAN AIR ACT CRITERIA POLLUTANTS—NATIONAL AMBIENT AIR QUALITY STANDARDS..................................43
OzoneNAAQS....................................................................................................................................................44
ParticulateMatter NAAQS................................................................................................................................45
REGIONALHAZE......................................................................................................................................................46
UtahRegional Haze...........................................................................................................................................46
WyomingRegional Haze....................................................................................................................................48
ColoradoRegional Haze....................................................................................................................................50
MERCURY AND HAZARDOUS AIR POLLUTANTS.......................................................................................................51
COALCOMBUSTION RESIDUALS..............................................................................................................................52
WATER QUALITY STANDARDS................................................................................................................................54
Cooling Water Intake Structures........................................................................................................................54
EffluentLimit Guidelines...................................................................................................................................54
RENEWABLE GENERATION REGULATORY FRAMEWORK..........................................................................................55
STATE POLICY UPDATE.............................................................................................................................56
CALIFORNIA............................................................................................................................................................56
IDAHO......................................................................................................................................................................57
OREGON..................................................................................................................................................................57
WASHINGTON..........................................................................................................................................................59
UTAH.......................................................................................................................................................................60
WYOMING...............................................................................................................................................................60
GREENHOUSE GAS EMISSION PERFORMANCE STANDARDS .....................................................................................62
RENEWABLE PORTFOLIO STANDARDS..................................................................................................62
CALIFORNIA............................................................................................................................................................63
OREGON..................................................................................................................................................................65
UT A H.......................................................................................................................................................................67
WASHINGTON..........................................................................................................................................................68
RECMANAGEMENT PRACTICES..............................................................................................................................68
CLEAN ENERGY STANDARDS....................................................................................................................69
WASHINGTON..........................................................................................................................................................69
OREGON..................................................................................................................................................................69
CALIFORNIA............................................................................................................................................................69
WYOMING...............................................................................................................................................................70
TRANSPORTATION ELECTRIFICATION..................................................................................................70
HYDROELECTRIC RELICENSING.............................................................................................................71
POTENTIALIMPACT.................................................................................................................................................72
TREATMENTIN THE IRP..........................................................................................................................................73
PACIFICORP'S APPROACH TO HYDROELECTRIC RELICENSING................................................................................73
RATEDESIGN..........................................................................................................................................................73
11

PACIFICORP—2025 IRP TABLE OF CONTENTS
RESIDENTIAL RATE DESIGN....................................................................................................................................73
COMMERCIAL AND INDUSTRIAL RATE DESIGN........................................................................................................74
IRRIGATION RATE DESIGN.......................................................................................................................................74
ELECTRICITY MARKET DEVELOPMENT UPDATE.....................................................................................74
RECENT RESOURCE PROCUREMENT ACTIVITIES...............................................................................76
2022 ALL-SOURCE RFP...........................................................................................................................................78
2024 UTAH RENEWABLES COMMUNITY RFP..........................................................................................................78
2025 ALL-SOURCE RFP...........................................................................................................................................78
CHAPTER 4 - TRANSMISSION
INTRODUCTION.....................................................................................................................................................79
REGULATORY REQUIREMENTS.......................................................................................................................80
OPEN ACCESS TRANSMISSION TARIFF.....................................................................................................................80
RELIABILITY STANDARDS........................................................................................................................................81
GENERATION INTERCONNECTION STUDY METHODOLOGY CHANGES......................................................................82
AEOLUS TO MONA/CLOVER(GATEWAY SOUTH—SEGMENT F)...............................................................................82
WINDSTAR-POPULUS(GATEWAY WEST—SEGMENT D)..........................................................................................82
POPULUS-HEMINGWAY(GATEWAY WEST-SEGMENT E)........................................................................................83
PLAN TO CONTINUE PERMITTING—GATEWAY WEST..............................................................................................83
BOARDMAN-HEMINGWAY(SEGMENT H)................................................................................................................83
SPANISH FORK—MERCER 345-KV LINE..................................................................................................................84
OTHER TRANSMISSION SYSTEM IMPROVEMENTS....................................................................................................85
ENERGY GATEWAY TRANSMISSION EXPANSION PLAN..........................................................................85
INTRODUCTION........................................................................................................................................................85
BACKGROUND.........................................................................................................................................................85
PLANNING INITIATIVES............................................................................................................................................85
Rocky Mountain Area Transmission Study........................................................................................................86
ENERGY GATEWAY CONFIGURATION......................................................................................................................87
ENERGY GATEWAY'S CONTINUED EVOLUTION.......................................................................................................88
EFFORTS TO MAXIMIZE EXISTING SYSTEM CAPABILITY......................................................................92
TRANSMISSION SYSTEM IMPROVEMENTS PLACED IN-SERVICE SINCE THE 2023 IRP..............................................93
PLANNED TRANSMISSION SYSTEM IMPROVEMENTS................................................................................................94
CHAPTER 5 - RELIABILITY AND RESILIENCY
INTRODUCTION.....................................................................................................................................................99
SUPPLY-BASED RELIABILITY............................................................................................................................99
REGIONALRESOURCE ADEQUACY..........................................................................................................................99
WECC WESTERN ASSESSMENT OF RESOURCE ADEQUACY REPORT.....................................................................100
NERC LONG-TERM RELIABILITY ASSESSMENT(LTRA)......................................................................................102
Resources.........................................................................................................................................................102
WECCSubregions............................................................................................................................................102
LTRAWECCAssessment.................................................................................................................................102
PACIFIC NORTHWEST POWER SUPPLY ADEQUACY ASSESSMENT..........................................................................103
WESTERN RESOURCE ADEQUACY PROGRAM(WRAP)..........................................................................................104
RELIABLE SERVICE THROUGH UNPREDICTABLE WEATHER AND CHALLENGING MARKET LIQUIDITY...................105
PLANNING FOR LOAD CHANGES AS A RESULT OF CLIMATE CHANGE....................................................................106
WEATHER-RELATED IMPACTS TO VARIABLE GENERATION...................................................................................106
III

PACIFICORP—2025 IRP TABLE OF CONTENTS
WildfireImpacts...............................................................................................................................................107
ExtremeWeather Impacts................................................................................................................................107
Impacts on Wind and Solar Energy..................................................................................................................108
WILDFIRE RISK MITIGATION.........................................................................................................................109
TRANSMISSION-BASED RELIABILITY..........................................................................................................110
FEDERAL RELIABILITY STANDARDS......................................................................................................................III
POWER FLOW ANALYSES AND PLANNING FOR GENERATOR RETIREMENTS...........................................................112
CHAPTER 6 - LOAD AND RESOURCE BALANCE
INTRODUCTION...................................................................................................................................................114
SYSTEM COINCIDENT PEAK LOAD FORECAST.........................................................................................114
EXISTINGRESOURCES......................................................................................................................................114
THERMALPLANTS.................................................................................................................................................114
RENEWABLE RESOURCES......................................................................................................................................116
Wind.................................................................................................................................................................116
Solar.................................................................................................................................................................118
Geothermal......................................................................................................................................................121
Biomass/B i ogas................................................................................................................................................122
Distributed Generation Resources...................................................................................................................122
ENERGYSTORAGE.................................................................................................................................................122
HYDROELECTRIC GENERATION.............................................................................................................................122
DEMAND-SIDE MANAGEMENT/DISTRIBUTED GENERATION..................................................................................124
DISTRIBUTED GENERATION FORECAST..................................................................................................................126
POWER-PURCHASE AGREEMENTS..........................................................................................................................127
CAPACITY LOAD AND RESOURCE BALANCE.............................................................................................128
CAPACITY BALANCE OVERVIEW...........................................................................................................................128
LOAD AND RESOURCE BALANCE COMPONENTS....................................................................................................129
Obligation........................................................................................................................................................129
Position............................................................................................................................................................130
CAPACITY BALANCE DETERMINATION..................................................................................................................130
Methodology....................................................................................................................................................130
CapacityBalance Results.................................................................................................................................131
CHAPTER 7 - RESOURCE OPTIONS
INTRODUCTION...................................................................................................................................................141
SUPPLY-SIDE RESOURCES................................................................................................................................142
DERIVATION OF RESOURCE ATTRIBUTES...............................................................................................................143
WIND AND SOLAR GENERATION PROFILES............................................................................................................146
NATRIUM DEMONSTRATION PROJECT...................................................................................................................146
RESOURCE OPTIONS AND ATTRIBUTES..................................................................................................................147
RESOURCE OPTION DESCRIPTIONS........................................................................................................................161
LOCATIONAL MODIFIERS AND SELECTED COST FORECASTS.................................................................................166
PVCost Forecast History................................................................................................................................166
WindCost Forecast History.............................................................................................................................167
EnergyStorage.................................................................................................................................................168
DEMAND-SIDE RESOURCES.............................................................................................................................171
RESOURCE OPTIONS AND ATTRIBUTES..................................................................................................................171
IV

PACIFICORP—2025 IRP TABLE OF CONTENTS
Source of Demand-Side Management Resource Data.....................................................................................171
TRANSMISSIONRESOURCES...........................................................................................................................177
MARKET PURCHASES...............................................................................................................................178
CHAPTER 8 - MODELING AND PORTFOLIO EVALUATION
INTRODUCTION...................................................................................................................................................182
KEY CHANGES SINCE THE 2023 IRP......................................................................................................................182
MODELING AND EVALUATION STEPS..........................................................................................................183
OVERVIEW OF STEPS IN AN ITERATIVE PHASE.......................................................................................................184
Step1................................................................................................................................................................184
Step2................................................................................................................................................................184
Step3................................................................................................................................................................184
Step4................................................................................................................................................................185
Step5................................................................................................................................................................185
Step6................................................................................................................................................................185
GRANULARITY ADJUSTMENT DETAIL....................................................................................................................185
RELIABILITY ADJUSTMENT DETAIL.......................................................................................................................186
RESOURCE PORTFOLIO DEVELOPMENT....................................................................................................188
LONG-TERM(LT)CAPACITY EXPANSION MODEL.................................................................................................188
TransmissionSystem........................................................................................................................................189
TransmissionOptions......................................................................................................................................190
TransmissionCosts..........................................................................................................................................192
ResourceAdequacy..........................................................................................................................................192
Granularity and Reliability Adjustments..........................................................................................................192
ThermalResource Options...............................................................................................................................193
NewResource Options.....................................................................................................................................194
CapitalCosts....................................................................................................................................................196
GeneralAssumptions.......................................................................................................................................196
COSTAND RISK ANALYSIS...............................................................................................................................199
SHORT-TERM(ST)SCHEDULE MODEL..................................................................................................................199
Reliability Assessment and System Cost...........................................................................................................200
STOCHASTICMODELING........................................................................................................................................201
Stochastic Portfolio Performance Measures....................................................................................................202
Forward Price Curve Scenarios......................................................................................................................203
Other PLEXOS Modeling Methods and Assumptions......................................................................................203
OTHER COST AND RISK CONSIDERATIONS.............................................................................................................204
FuelSource Diversity.......................................................................................................................................204
CustomerRate Impacts....................................................................................................................................204
MarketReliance...............................................................................................................................................204
PORTFOLIOSELECTION...................................................................................................................................205
FINAL EVALUATION AND PREFERRED PORTFOLIO SELECTION.......................................................205
CASE DEFINITIONS.............................................................................................................................................205
INITIALPORTFOLIOS..............................................................................................................................................206
JURISDICTIONAL DEFINITIONS AND MODELING.....................................................................................................206
INTEGRATEDPORTFOLIOS.....................................................................................................................................210
WASHINGTON PORTFOLIOS ...................................................................................................................................211
SENSITIVITY CASE DEFINITIONS............................................................................................................................212
V

PACIFICORP—2025 IRP TABLE OF CONTENTS
BusinessPlan Sensitivity..................................................................................................................................21 S
CHAPTER 9 - MODELING AND PORTFOLIO SELECTION
RESULTS
INTRODUCTION...................................................................................................................................................218
INITIAL PORTFOLIO DEVELOPMENT..........................................................................................................219
JURISDICTIONAL SHARES OF THE PREFERRED PORTFOLIO..............................................................220
FULL JURISDICTIONAL PORTFOLIOS..........................................................................................................222
THE 2025 IRP PREFERRED PORTFOLIO........................................................................................................227
NEWSOLAR RESOURCES.......................................................................................................................................228
NEWWIND RESOURCES.........................................................................................................................................229
NEWSTORAGE RESOURCES...................................................................................................................................229
NEWNUCLEAR RESOURCES..................................................................................................................................230
DEMAND-SIDE MANAGEMENT..............................................................................................................................230
WHOLESALE POWER MARKET PRICES AND PURCHASES........................................................................................232
COAL AND GAS RETIREMENTS/GAS CONVERSIONS...............................................................................................233
CARBON DIOXIDE EQUIVALENT EMISSIONS..........................................................................................................234
RENEWABLE PORTFOLIO STANDARDS...................................................................................................................237
OREGON HB 2021 COMPLIANCE...........................................................................................................................239
CAPACITYAND ENERGY........................................................................................................................................239
DETAILED PREFERRED PORTFOLIO........................................................................................................................241
INTEGRATED PORTFOLIO RESOURCE COMPARISONS BY TECHNOLOGY AND YEAR...............................................249
PREFERRED PORTFOLIO VARIANTS............................................................................................................259
VARIANT STUDY ANALYSIS..................................................................................................................................262
ADDITIONAL SENSITIVITY ANALYSIS..........................................................................................................276
WASHINGTONSCENARIOS...............................................................................................................................283
CHAPTER 10 - ACTION PLAN
INTRODUCTION...................................................................................................................................................285
THE 2025 IRP ACTION PLAN.............................................................................................................................286
PROGRESS ON 2023 ACTION PLAN.................................................................................................................293
1. Existing Resource Actions............................................................................................................................294
2. New Resource Actions..................................................................................................................................297
3. Transmission Action Items...........................................................................................................................299
4.Demand-Side Management(DSM)Actions.................................................................................................300
S.Market Purchases........................................................................................................................................301
6.Renewable Energy Credit(REC)Actions....................................................................................................301
ACQUISITIONPATH ANALYSIS.......................................................................................................................303
RESOURCE AND COMPLIANCE STRATEGIES...........................................................................................................303
ACQUISITION PATH DECISION MECHANISM...........................................................................................................303
PROCUREMENT DELAYS..................................................................................................................................311
IRP ACTION PLAN LINKAGE TO BUSINESS PLANNING...........................................................................311
Vl

PACIFICORP-2025 IRP TABLE OF CONTENTS
RESOURCE PROCUREMENT STRATEGY......................................................................................................312
RENEWABLE RESOURCES,STORAGE RESOURCES,AND DISPATCHABLE RESOURCES............................................312
RENEWABLE ENERGY CREDITS.............................................................................................................................312
DEMAND-SIDE MANAGEMENT..............................................................................................................................312
SMALL SCALE RENEWABLE ENERGY SUPPLY........................................................................................................313
ASSESSMENT OF OWNING ASSETS VERSUS PURCHASING POWER....................................................313
MANAGING CARBON RISK FOR EXISTING PLANTS.................................................................................314
PURPOSEOF HEDGING......................................................................................................................................314
TREATMENT OF CUSTOMER AND INVESTOR RISKS...............................................................................316
STOCHASTIC RISK ASSESSMENT............................................................................................................................316
CAPITALCOST RISKS............................................................................................................................................316
SCENARIO RISK ASSESSMENT................................................................................................................................316
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...........................................................................................................................13
CHAPTER 2 -INTRODUCTION
CHAPTER 3 -PLANNING ENVIRONMENT
TABLE 3.1-2023 AND 2024 MONTHLY AVERAGE ON-PEAK SPOT PRICES($/MWH)..................................................27
TABLE 3.2-2025-2027 FORWARD PRICE SPREAD($/MWH)........................................................................................28
TABLE 3.3—STATE RPS REQUIREMENTS.....................................................................................................................63
TABLE 3.4—CALIFORNIA COMPLIANCE PERIOD REQUIREMENTS.................................................................................64
TABLE 3.5—CALIFORNIA BALANCED PORTFOLIO REQUIREMENTS..............................................................................65
TABLE 3.6—PACIFICORP'S RECENT AND UPCOMING NEW RESOURCE ADDITIONS......................................................77
TABLE 3.7—PACIFICORP's REQUESTS FOR PROPOSAL ACTIVITY................................................................................77
CHAPTER 4 - TRANSMISSION
TABLE 4.1—ENERGY GATEWAY TRANSMISSION EXPANSION PLAN.............................................................................92
CHAPTER 5 -RELIABILITY AND RESILIENCY
TABLE 5.1—WARA DEMAND-AT-RISK SUMMARY...................................................................................................100
TABLE 5.2—WECC SUBREGION DESCRIPTIONS........................................................................................................102
TABLE 5.3—NERC LIRA FOR SELECTED WECC SUBREGIONS................................................................................103
TABLE 5.4—NORTHWEST POWER AND CONSERVATION COUNCIL 2029 ADEQUACY ASSESSMENT............................104
CHAPTER 6-LOAD AND RESOURCE BALANCE
TABLE 6.1—FORECASTED SYSTEM SUMMER COINCIDENT PEAK LOAD IN MEGAWATTS,BEFORE ENERGY EFFICIENCY
(MW)................................................................................................................................................................114
TABLE 6.2—COAL-FIRED PLANTS..............................................................................................................................115
TABLE 6.3—NATURAL GAs-FIRED PLANTS...............................................................................................................116
TABLE 6.4—OWNED WIND RESOURCES.....................................................................................................................117
TABLE 6.5—NON-OWNED WIND RESOURCES............................................................................................................117
TABLE 6.6—SOLAR POWER PURCHASE AGREEMENTS...............................................................................................119
TABLE 6.7—SOLAR QUALIFYING FACILITIES,OREGON.............................................................................................120
TABLE 6.8—SOLAR QUALIFYING FACILITIES,UTAH..................................................................................................121
TABLE 6.9—SOLAR QUALIFYING FACILITIES,WYOMING..........................................................................................121
TABLE 6.10—DISTRIBUTED GENERATION CUSTOMERS AND CAPACITY.....................................................................122
TABLE 6.11—STORAGE RESOURCES..........................................................................................................................122
TABLE 6.12—PACIFICORP HYDROELECTRIC GENERATION FACILITIES......................................................................123
TABLE 6.13—EXISTING DSM RESOURCE SUMMARY.................................................................................................126
TABLE 6.14--SUMMER PEAK—SYSTEM CAPACITY LOADS AND RESOURCES WITHOUT RESOURCE ADDITIONS .......132
TABLE 6.15—WINTER PEAK SYSTEM CAPACITY LOADS AND RESOURCES WITHOUT.................................................134
V111

PACIFICORP-2025 IRP TABLE OF CONTENTS
CHAPTER 7-RESOURCE OPTIONS
TABLE 7.1-SUPPLY-SIDE RESOURCE OPTION TABLES..............................................................................................148
TABLE 7.2-2025 THERMAL SUPPLY-SIDE RESOURCES,CHARACTERISTICS AND COSTS(2024$).............................149
TABLE 7.3-2025 NON-THERMAL SUPPLY-SIDE RESOURCES,CHARACTERISTICS AND COSTS(2024$).....................150
TABLE 7.4-2025 THERMAL SUPPLY-SIDE RESOURCES,OPERATING CHARACTERISTICS AND ENVIRONMENTAL DATA
(2024$).............................................................................................................................................................151
TABLE 7.5-2025 NON-THERMAL SUPPLY-SIDE RESOURCES,OPERATING CHARACTERISTICS AND ENVIRONMENTAL
DATA(2024$)...................................................................................................................................................152
TABLE 7.6-2025 IRP THERMAL SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M(2024$).153
TABLE 7.7-2025 IRP NON-THERMAL SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M
(2024$).............................................................................................................................................................154
TABLE 7.8-2025 IRP STORAGE SUPPLY-SIDE RESOURCES,ADDITIONAL ATTRIBUTES AND FIXED O&M(2024$)..155
TABLE 7.9-2025 IRP THERMAL SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS(2024$)156
TABLE 7.10-2025 IRP NON-THERMAL SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS
(2024$).............................................................................................................................................................157
TABLE 7.11-2025 IRP STORAGE SUPPLY-SIDE RESOURCES,VARIABLE O&M,TOTAL COST AND CREDITS(2024$)
.........................................................................................................................................................................158
TABLE 7.12-GLOSSARY OF TERMS USED IN THE SUPPLY-SIDE RESOURCE TABLES..................................................159
TABLE 7.13-GLOSSARY OF ACRONYMS USED IN CHAPTER 7....................................................................................160
TABLE 7.14-COMPARISON OF LAZARD LCOE+AND NREL ATB............................................................................170
TABLE 7.15-DEMAND RESPONSE EXISTING AND PLANNED PROGRAMS...................................................................173
TABLE 7.16-DEMAND RESPONSE PROGRAM ATTRIBUTES WEST CONTROL AREA,*................................................173
TABLE 7.17-DEMAND RESPONSE PROGRAM ATTRIBUTES EAST CONTROL AREA,*.................................................174
TABLE 7.18-2045 TOTAL CUMULATIVE ENERGY EFFICIENCY POTENTIAL BY.........................................................176
TABLE 7.19-STATE-SPECIFIC TRANSMISSION AND DISTRIBUTION CREDITS(2024$)................................................177
CHAPTER 8 - MODELING AND PORTFOLIO EVALUATION
TABLE 8.1-MAJORITY-OWNED COAL GENERATOR RESOURCE OPTIONS..................................................................193
TABLE 8.2-MINORITY-OWNED COAL GENERATOR RESOURCE OPTIONS..................................................................194
TABLE 8.3-NATURAL GAS GENERATOR RESOURCE OPTIONS...................................................................................194
TABLE 8.4-PRICE-POLICY CASE DEFINITIONS..........................................................................................................207
TABLE 8.5-PORTFOLIO VARIANTS............................................................................................................................208
TABLE 8.6-PORTFOLIO INTEGRATION RESOURCE EXAMPLE....................................................................................211
TABLE 8.7-SENSITIVITY CASE DEFINITIONS.............................................................................................................213
CHAPTER 9 - MODELING AND PORTFOLIO SELECTION RESULTS
TABLE 9.1-ITERATIVE PHASES OF OREGON MN PORTFOLIO ....................................................................................219
TABLE9.2-OREGON SHARE,^ ...................................................................................................................................221
TABLE 9.3-WASHINGTON SHARE.............................................................................................................................221
TABLE 9.4-UTAH,IDAHO,WYOMING,AND CALIFORNIA SHARE..............................................................................222
TABLE 9.5-OREGON FULL JURISDICTIONAL PORTFOLIO..........................................................................................223
TABLE 9.6-WASHINGTON FULL JURISDICTIONAL PORTFOLIO..................................................................................224
TABLE 9.7-UTAH,IDAHO,WYOMING,CALIFORNIA(UIWC)FULL JURISDICTIONAL PORTFOLIO............................225
TABLE 9.8-TRANSMISSION PROJECTS INCLUDED IN THE 2025 IRP PREFERRED PORTFOLIO 1,2.................................228
TABLE 9.9-2025 IRP COAL RESOURCE RESULTS.....................................................................................................234
TABLE 9.10-PACIFICORP'S 2025 IRP PREFERRED PORTFOLIO.................................................................................243
TABLE 9.11-PREFERRED PORTFOLIO WITH JURISDICTIONAL RESOURCE SELECTIONS..............................................244
TABLE 9.12-PREFERRED PORTFOLIO SUMMER CAPACITY LOAD AND RESOURCE BALANCE(2025-2034)...............245
TABLE 9.13-PREFERRED PORTFOLIO SUMMER CAPACITY LOAD AND RESOURCE BALANCE(2036-2045)...............246
TABLE 9.14-PREFERRED PORTFOLIO WINTER CAPACITY LOAD AND RESOURCE BALANCE(2025-2034)................247
TABLE 9.15-PREFERRED PORTFOLIO WINTER CAPACITY LOAD AND RESOURCE BALANCE(2035-2045)................248
1X

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE9.16-NEW GAS'............................................................................................................................................249
TABLE9.17-NUCLEAR'.............................................................................................................................................250
TABLE 9.18-RENEWABLE PEAKING' ........................................................................................................................250
TABLE 9.19-DSM-ENERGY EFFICIENCY................................................................................................................251
TABLE 9.20-DSM-DEMAND RESPONSE.................................................................................................................251
TABLE 9.21-UTILITY SCALE WIND'.........................................................................................................................252
TABLE9.22-SMALL SCALE WIND'...........................................................................................................................252
TABLE9.23-UTILITY SOLAR'...................................................................................................................................253
TABLE 9.24-SMALL SCALE SOLAR. .........................................................................................................................253
TABLE9.25-GEOTHERMAL......................................................................................................................................254
TABLE 9.26-BATTERY,<8 HOUR' ...........................................................................................................................254
TABLE 9.27-BATTERY,8-23 HOUR'..........................................................................................................................255
TABLE 9.28-BATTERY,24+HOUR'..........................................................................................................................255
TABLE 9.29-MAJORITY OWNED COAL RETIREMENTS..............................................................................................256
TABLE 9.30-CARBON CAPTURE AND SEQUESTRATION SELECTIONS........................................................................256
TABLE 9.31-COAL TO GAS CONVERSION SELECTIONS.............................................................................................257
TABLE9.32-GAS RETIREMENTS'..............................................................................................................................257
TABLE 9.33-JURISDICTIONAL STUDIES FOR VARIANTS AND PRICE-POLICY SCENARIOS..........................................259
TABLE 9.34-INTEGRATED PORTFOLIOS UNDER MEDIUM GAS/ZERO CO2...............................................................260
TABLE 9.35-INTEGRATED PORTFOLIOS UNDER LOW GAS/ZERO CO2 .....................................................................260
TABLE 9.36-INTEGRATED PORTFOLIOS UNDER HIGH GAS AND COAL/HIGH CO2...................................................261
TABLE 9.37-INTEGRATED PORTFOLIOS UNDER MEDIUM GAS/SOCIAL COST OF CO2•••••••••••••••...............................262
TABLE 9.38-LARGE-METERED LOAD TRANSMISSION SELECTIONS..........................................................................280
CHAPTER 10-ACTION PLAN
TABLE 10.1-2025 IRP ACTION PLAN.......................................................................................................................287
TABLE 10.2-2023 IRP ACTION PLAN STATUS UPDATE............................................................................................294
TABLE 10.3-NEAR-TERM AND LONG-TERM RESOURCE ACQUISITION PATHS...........................................................305
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 4-HOUR STORAGE CAPACITY'°2..................................................7
FIGURE 1.6-2025 IRP PREFERRED PORTFOLIO NEW 24+HOUR STORAGE CAPACITY'.................................................8
FIGURE 1.8-2025 IRP ENERGY EFFICIENCY AND DEMAND RESPONSE CAPACITY........................................................9
FIGURE 1.10-2025 IRP PREFERRED PORTFOLIO CO2 EQUIVALENT EMISSIONS AND PACIFICORP CO2 EQUIVALENT
EMISSIONS TRAJECTORY' ...................................................................................................................................I I
CHAPTER 2 -INTRODUCTION
CHAPTER 3 -PLANNING ENVIRONMENT
FIGURE 3.2-NATIONAL RPS TARGETS........................................................................................................................29
FIGURE 3.3-STATES WITH CO2 REDUCTION TARGETS................................................................................................30
FIGURE 3.4-NoN-CAISO WECC GENERATED ENERGY(TWH).................................................................................30
FIGURE 3.5-NoN-CAISO WECC CAPACITY ADDITION(GW)...................................................................................31
FIGURE 3.6-NoN-CAISO WECC CAPACITY RETIREMENT(GW)...............................................................................32
FIGURE 3.7-NoN-CAISO WECC CAPACITY RETIREMENT(GW)...............................................................................33
FIGURE 3.8-DAILY 2022 HENRY HUB SPOT PRICES(USD/MMBTU).........................................................................34
FIGURE 3.9-ANNUAL 2022-2023 CHANGE IN US NATURAL GAS PRODUCTION BY REGION(BCF/D)..........................35
FIGURE 3.10-LOWER 48 WEEKLY WORKING GAS IN UNDERGROUND STORAGE(BCF/D)..........................................36
FIGURE 3.11-HENRY HUB FUTURES...........................................................................................................................38
FIGURE 3.12-WESTERN ENERGY IMBALANCE MARKET EXPANSION..........................................................................75
CHAPTER 4 - TRANSMISSION
FIGURE4.1 -SEGMENT D.............................................................................................................................................82
FIGURE4.2-SEGMENT E..............................................................................................................................................83
FIGURE 4.3-ENERGY GATEWAY TRANSMISSION EXPANSION PLAN...........................................................................91
CHAPTER 5 -RELIABILITY AND RESILIENCY
CHAPTER 6-LOAD AND RESOURCE BALANCE
FIGURE 6.1-CUMULATIVE HISTORICAL AND NEW CAPACITY INSTALLED BY...........................................................127
FIGURE 6.2-CONTRACT CAPACITY IN THE 2025 IRP SUMMER LOAD AND RESOURCE BALANCE.............................128
FIGURE 6.3-ENERGY EFFICIENCY PEAK CONTRIBUTION IN SUMMER CAPACITY LOAD AND RESOURCE BALANCE
(REDUCTION TO LOAD,IN MW) .......................................................................................................................130
FIGURE 6.4-SUMMER SYSTEM CAPACITY POSITION TREND ....................................................................................136
FIGURE 6.5-WINTER SYSTEM CAPACITY POSITION TREND......................................................................................137
FIGURE 6.6-EAST SUMMER CAPACITY POSITION TREND..........................................................................................138
FIGURE 6.7 -WEST SUMMER CAPACITY POSITION TREND........................................................................................139
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PACIFICORP-2025 IRP TABLE OF CONTENTS
CHAPTER 7-RESOURCE OPTIONS
FIGURE 7.1-HISTORY OF SUPPLY-SIDE RESOURCE PV COST&FORECAST...............................................................167
FIGURE 7.2-HISTORY OF SUPPLY-SIDE RESOURCE WIND COSTS&FORECAST........................................................168
FIGURE 7.3-HISTORY OF BATTERY ENERGY STORAGE SYSTEM COSTS&FORECAST..............................................169
CHAPTER 8 -MODELING AND PORTFOLIO EVALUATION
FIGURE 8.1-PORTFOLIO EVALUATION STEPS WITHIN THE IRP PROCESS..................................................................184
FIGURE 8.2-GRANULARITY ADJUSTMENT DETERMINATION....................................................................................186
FIGURE 8.3-TRANSMISSION SYSTEM MODEL TOPOLOGY WITH MAJOR OPTIONS.....................................................190
FIGURE 8.4-CO2 PRICES MODELED BY PRICE-POLICY SCENARIO............................................................................198
FIGURE 8.5-NOMINAL WHOLESALE ELECTRICITY AND NATURAL GAS PRICE SCENARIOS ......................................199
FIGURE 8.6-LOAD AND PRIVATE GENERATION SENSITIVITY ASSUMPTIONS............................................................213
CHAPTER 9 -MODELING AND PORTFOLIO SELECTION RESULTS
FIGURE 9.1-PORTFOLIO INTEGRATION AND SELECTION WORKFLOW.......................................................................218
FIGURE 9.2-2025 IRP PREFERRED PORTFOLIO(ALL RESOURCES) ..........................................................................227
FIGURE 9.3-2025 IRP PREFERRED PORTFOLIO NEW SOLAR CAPACITY...................................................................228
FIGURE 9.4-2025 IRP PREFERRED PORTFOLIO NEW WIND CAPACITY.....................................................................229
FIGURE 9.5-2025 IRP PREFERRED PORTFOLIO NEW 4-HOUR STORAGE CAPACITYl°Z..............................................229
FIGURE 9.6-2025 IRP PREFERRED PORTFOLIO NEW 24+HOUR STORAGE CAPACITY l.............................................230
FIGURE 9.7-2025 IRP NEW NUCLEAR'.....................................................................................................................230
FIGURE 9.8-LOAD FORECAST COMPARISON BETWEEN RECENT IRPS(BEFORE INCREMENTAL ENERGY EFFICIENCY
SAVINGS)..........................................................................................................................................................231
FIGURE 9.9-2025 IRP PREFERRED PORTFOLIO ENERGY EFFICIENCY AND DEMAND RESPONSE CAPACITY..............232
FIGURE 9.10-2025 IRP PREFERRED PORTFOLIO MARKET PURCHASES....................................................................232
FIGURE 9.11-COMPARISON OF POWER PRICES AND NATURAL GAS PRICES IN RECENT IRPS...................................233
FIGURE 9.12-2025 IRP PREFERRED PORTFOLIO THERMAL RESOURCES...................................................................233
FIGURE 9.13-2025 IRP PREFERRED PORTFOLIO CO2 EMISSIONS AND PACIFICORP CO2 EQUIVALENT EMISSIONS
TRAJECTORY. ...................................................................................................................................................236
FIGURE 9.14-ANNUAL STATE RPS COMPLIANCE FORECAST...................................................................................238
FIGURE 9.15-PROJECTED ENERGY MIX WITH PREFERRED PORTFOLIO RESOURCES.................................................240
FIGURE 9.16-PROJECTED CAPACITY MIX WITH PREFERRED PORTFOLIO RESOURCES .............................................240
FIGURE 9.17-INCREASE/(DECREASE)IN PROXY RESOURCES WITH NO CCS ............................................................263
FIGURE 9.18-INCREASE/(DECREASE)IN SYSTEM COSTS WITH NO CCS ...................................................................263
FIGURE 9.19-INCREASE/(DECREASE)IN PROXY RESOURCES WITH NO NUCLEAR ....................................................264
FIGURE 9.20-INCREASE/(DECREASE)IN SYSTEM COSTS WITH NO NUCLEAR...........................................................264
FIGURE 9.21 -INCREASE/(DECREASE)IN PROXY RESOURCES WITH NO COAL POST-2032.........................................265
FIGURE 9.22-INCREASE/(DECREASE)IN SYSTEM COSTS WITH NO COAL POST-2032................................................265
FIGURE 9.23-INCREASE/(DECREASE)IN PROXY RESOURCES WITH OFFSHORE WIND...............................................266
FIGURE 9.24-INCREASE/(DECREASE)IN SYSTEM COSTS WITH OFFSHORE WIND......................................................267
FIGURE 9.25-INCREASE/(DECREASE)IN PROXY RESOURCES WITH NO FORWARD TECHNOLOGY.............................267
FIGURE 9.26-INCREASE/(DECREASE)IN SYSTEM COSTS WITH NO FORWARD TECHNOLOGY...................................268
FIGURE 9.27-INCREASE/(DECREASE)IN PROXY RESOURCES WITH GEOTHERMAL....................................................268
FIGURE 9.28-INCREASE/(DECREASE)IN SYSTEM COSTS WITH GEOTHERMAL..........................................................269
FIGURE 9.29-INCREASE/(DECREASE)IN PROXY RESOURCES WITH HUNTER RETIREMENT.......................................269
FIGURE 9.30-INCREASE/(DECREASE)IN SYSTEM COSTS WITH HUNTER RETIREMENT..............................................270
FIGURE 9.31 -INCREASE/(DECREASE)IN PROXY RESOURCES WITH MR....................................................................271
FIGURE 9.32-INCREASE/(DECREASE)IN SYSTEM COSTS OF MR PORTFOLIO OPERATING UNDER MN.....................271
FIGURE 9.33-INCREASE/(DECREASE)IN PROXY RESOURCES WITH MR NO CCS Vs.MR.........................................272
FIGURE 9.34-INCREASE/(DECREASE)IN SYSTEM COSTS WITH MR NO CCS vs.MR................................................272
Xii

PACIFICORP-2025 IRP TABLE OF CONTENTS
FIGURE 9.35-INCREASE/(DECREASE IN PROXY RESOURCES WITH HH....................................................................273
FIGURE 9.36-INCREASE/(DECREASE IN SYSTEM COSTS OF HH PORTFOLIO OPERATING UNDER MN.......................273
FIGURE 9.37-INCREASE/(DECREASE IN PROXY RESOURCES WITH LN.....................................................................274
FIGURE 9.38-INCREASE/(DECREASE IN SYSTEM COSTS OF LN PORTFOLIO OPERATING UNDER MN.......................274
FIGURE 9.39-INCREASE/(DECREASE IN PROXY RESOURCES WITH SCGHG.............................................................275
FIGURE 9.40-INCREASE/(DECREASE IN SYSTEM COSTS OF SCGHG PORTFOLIO OPERATING UNDER MN..............275
FIGURE 9.41 -INCREASE/(DECREASE IN PROXY RESOURCES WITH HIGH LOAD GROWTH........................................277
FIGURE 9.42-INCREASE/(DECREASE IN PROXY RESOURCES WITH LOW LOAD GROWTH.........................................277
FIGURE 9.43-INCREASE/(DECREASE IN PROXY RESOURCES WITH 1-IN-20 LOAD GROWTH.....................................278
FIGURE 9.44-INCREASE/(DECREASE IN PROXY RESOURCES WITH HIGH DISTRIBUTED GENERATION......................278
FIGURE 9.45-INCREASE/(DECREASE IN PROXY RESOURCES WITH LOW DISTRIBUTED GENERATION......................279
FIGURE 9.46-INCREASE/(DECREASE IN PROXY RESOURCES WITH LARGE-METERED LOAD GROWTH.....................280
FIGURE 9.47-INCREASE/(DECREASE IN PROXY RESOURCES WITH LOW-COST RENEWABLES..................................281
FIGURE 9.48-INCREASE/(DECREASE IN PROXY RESOURCES WITH LOW IRA/IIJA ELIGIBILITY...............................281
FIGURE 9.49-INCREASE/(DECREASE IN PROXY RESOURCES WITH ALL CCS...........................................................282
FIGURE 9.50-INCREASE/(DECREASE IN PROXY RESOURCES WITH...........................................................................283
CHAPTER 10 -ACTION PLAN
FIGURE 10.1-INCREMENTAL RESOURCES IN THE 2025 IRP PREFERRED PORTFOLIO........................................293
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PACIFICORP-2025 IRP TABLE OF CONTENTS
XIV

PACIFICORP-2025 IRP CHAPTER I-EXECUTIVE SUMMARY
CHAPTER I - EXECUTIVE SUMMARY
Maintaining customer focus
Our 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 linea 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 projecta 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.
New Resources
• The following resources are added in the 2025 IRP:
0 3,782 megawatts of new wind resources
0 7,524 megawatts of storage resources, including four-hour, and 100-hour durations
0 5,912 megawatts of new solar resources, including utility-scale and small-scale
0 500 megawatts of advanced nuclear(Natrium'reactor demonstration project)
Customer Programs
• 5,255 megawatts of capacity saved through energy efficiency programs
• 769 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
Yakima substation near Yakima, Washington
• Various upgrades that increase transfer capability between the Summer Lake substation
in Oregon and the Hemingway substation in Idaho
1

PACIFICORP-2025 IRP CHAPTER I-EXECUTIVE SUMMARY
• New transmission, including a 110-mile line from Summer Lake to Burns, Oregon, and an
88-mile line from Summer Lake to the planned Full Circle substation in Central Oregon.
These near-term upgrades connect with a later upgrade a new transmission line connecting
Walla Walla to the Full Circle substation, expected in 2039.
• 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
Key Thermal Outcomes
• 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 to comply with Wyoming's low
carbon portfolio standard
• Continue the process of coal-to-gas conversion of Naughton Units 1 and 2 in Kemmerer,
Wyoming, for completion by 2026
• Initiate the process of coal-to-gas conversion of Dave Johnston Units I and 2 in Glenrock,
Wyoming, for completion by 2029
PacifiCor 'serrated Resource 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 situs-allocated and deliverable 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(UIWC)2
o Cost-effective resources
o Includes WRAP compliance constraints for UIWC load
• Oregon
o Compliance with energy and emissions requirements from House Bill 2021 (HB2021)
o Includes WRAP compliance constraints for Oregon load
o Includes small-scale renewable capacity requirement
• Washington
o Compliance with clean energy requirements from the Clean Energy Transformation Act
(CETA)
o Includes WRAP compliance constraints for Washington load
Resources identified under each jurisdictional view are brought together into an "integrated"
portfolio and assumed to be situs 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 that 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 length and accelerating the timing of the coverage of all topics. Following the kick-off,
'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 1—EXECUTIVE SUMMARY
PacifiCorp hosted stakeholders in nine online public input meetings. 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
i
I 1
InputsI ' I l ' 1 _ I 1 ' 1 :fiction
Assumptions - ' 1rtfolio Plan
Analysis
I I 1 I
PIKerred 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 renewable
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
MW of solar additions, and 1,072 MW of battery storage capacity. These resources will come
online in the 2025 to 2026 timeframe.
4

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
The 2025 IRP preferred portfolio includes the advanced nuclear NatriumTM demonstration project,
anticipated to achieve online status by the fall of 2031. By the end of 2032, the preferred portfolio
includes 2,408 MW of energy storage resources,including 605 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 21-year planning horizon,
the 2025 IRP preferred portfolio includes 3,782 MW of new wind and 5,912MW of new solar.
Figure 1.2—2025 IRP Preferred Portfolio (Existing and Planned Resources)*
45000
40000 ■
35000
30000 __-25000gross
20000
15000
10000
5000
0
�O * ryo ryo ryo ryo ryo ryo ryo ryo * * ryo 4 4 40" 4', 4? 4 ry ryC
■Coal ■Converted Gas ■Gas ■Hydrogen Storage Peaker
Renewable Peaking m QF Hydro Nuclear
■Hydro Storage Battery Solar ■Wind
■Geothermal ■Energy Efficiency Demand Response 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 several transmission upgrades which increase transfer
capability between southern Utah and the Wasatch Front and between Walla Walla and Yakima
in Washington, as well as a series of upgrades that increase transfer capability between the
Hemingway substation in Idaho, the Summer Lake Substation in southern Oregon, the planned
Full Circle substation in Deschutes County, Oregon, and eventually connecting from Full Circle
to Walla Walla in Washington. 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. Currently, the Boardman-to-Hemingway transmission line (132H) 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 1—EXECUTIVE SUMMARY
Table 1.1 —Transmission Projects Included in the 2025 IRP Preferred Portfolio 1,2
2026 Utah South-Wasatch Front 138 kV reinforcement#1 250 250 250 30 10D°/u Utah South Wasatch From
2028 Cluster 1 Area 11:WMamette Valley 0 0 199 14 10D°/u n/a n/a
Closter 1 Area 14:Summer Lake 400 400 40D 111 100°/u Summer Lake Hemingway
Cluster 1Y1/3:Walla Walla 0 0 393 328 10D°/n n/a n/a
Serial queue:Central Oregon 0 0 152 4 10D°/u n/a n/a
Serial/Chister 1/2:Yakima 0 0 1 628 64 1001/. n/a n/a
Utah South-Wasatch Front 138 kV reinforcement#2 200 200 20D 12 10D°/n Utah South Wasatch From
2029 Cluster 2 Area 23:WMamette Valley 0 0 393 2 10D°/u n/a n/a
2030 Cluster 2 Area 19:Summer Lake to Central Oregon 500 k 1,500 1,500 670 1,283 100°/u Summer Lake Central OR
Walla Walla-Yakma 230 kV 400 400 40D 142 10D°/u Walla Walla Yakima
2031 Serial through Custer 1 Area 13:Southern Oregon 0 0 231 42 10D°/u n/a n/a
2032 Cluster 1 Area 12:Southern Oregon 0 0 300 1 303 10D% n/a n/a
2033 Cluster 2 Area 18:Central Oregon 500 kV Substation 0 0 518 1 372 10D% n/a n/a
2039 Walla Walla-Central Oregon 500 kV 11500 1,5001 6701 1,463 1 101r/ol Walla Walla Central OR
Grand Total 4,250 4,2501 5.4041 4,169
'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 some project-specific timing and costs.
In Chapter 9 (Modeling and Portfolio Selection Results), a sensitivity analysis evaluates the
impacts of significant new data center loads coming online in the 2027-2033 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 preferred portfolio includes 2,092 MW of new utility scale solar by the end of 2030,
3,822 MW by the end of 2035, and 4,765 MW by the end of 2045. Additionally, the 2025 IRP
preferred portfolio includes 320 MW of new small scale solar by the end of 2030, 417 MW by the
end of 2035, and 1,157 MW by the end of 2045. These cumulative totals are shown in Figure 1.3.
Figure 1.3—2025 IRP Preferred Portfolio New Solar Capacity
10,000
8,000 --
------------------------
♦♦----------
6,000
'�---
♦♦ --
4,000
U 2,000 ♦' — —
0
4" 4, 4,4ry, O 14^h 1Oa
4,
a 25IRP O25IRPOR =251RPWA O25 IRP UIWC ---2023IRPUpdate ---23IRP
6

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
New Wind Resources
As shown in Figure 1.4, PacifiCorp's 2025 IRP preferred portfolio includes 2,267 MW of new
wind generation by the end of 2030, 2,988 MW by the end of 2035, and 3,782 MW of cumulative
new wind by the end of 2045. Of note, all wind selections are utility scale.
Figure 1.4—2025 IRP Preferred Portfolio New Wind Capacity
10,000 ---------------
8,000
6,000 1 — —
4,000
----� i
0
�251RP =251RPOR 025IRPWA O25IRPUIWC ---2023 IRP Update ---23IRP
New Storage Resources
New storage resources in the 2025 IRP preferred portfolio are summarized in Figure 1.5 and Figure
1.6. The 2025 IRP preferred portfolio includes 1,684 MW of new 4-hour storage resources by the
end of 2030, 2,072 MW by the end of 2035 and 4,451 MW by the end of 2045. Additionally, the
2025 IRP preferred portfolio includes 511 MW of 100-hour iron air storage by the end of 2030,
616 MW by 2035 and 3,073 MW by 2045. Total storage selections, inclusive of both 4-hour and
100-hour resources, include a total of 7,524 MW of new storage.
Figure 1.5—2025 IRP Preferred Portfolio New 4-Hour Storage Capacity',2
10,000
8,000 — ---------------
6,000 i
./
U � /
2,000
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP =251RPOR 025IRPWA O25 IRP UIWC ---2023 IRP 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 2023 IRP and 2023 IRP Update totals shown in Figure 1.5 include a minimal amount of intermediate duration
storage.
7

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
Figure 1.6—2025 IRP Preferred Portfolio New 24+Hour Storage Capacity'
6,000
4,000
a
2,000
0 JF=;F=9T9F=9F=9F9 �71MMM77
ti ti ti ti ti ti ti ti ti ti o ti�' ry
ti ti1, �h
ti
■25 IRP 025 IRP OR 025 IRP WA 025 IRP UIWC
'The 2025 IRP preferred portfolio includes 41 MW of renewable peaking by the end of the planning horizon.
New Nuclear Resources
The 2025 IRP includes advanced nuclear as part of its least-cost, least-risk preferred portfolio. As
shown in Figure 1.7 ,the 500 MW advanced nuclear NatriumTM demonstration project is currently
scheduled to come online by the fall of 2031.
Figure 1.—2025 IRP New Nuclear'
2,000 -
1,500 --------------------------
Of
1,000 �
♦
J.
U 500 r—
251RP =251RP OR =251RP WA O25 IRP UIWC ---2023 IRP Update ---23 IRP
'While the 500 MW advanced nuclear NatriumTM demonstration project is currently scheduled to come online by
the fall of 2031,the PLEXOS model works best with beginning of year start dates for expansion candidates, so a
start date of l/1/2032 was assumed for the NatriumTM demonstration project in modeling.
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 12.3 percent
8

PACIFICORP—2025 IRP CHAPTER I—EXECUTIVE SUMMARY
and forecasted coincident system peak is down 5.3 percent when compared to the 2023 IRP. Over
the planning horizon, the average annual growth rate, before accounting for incremental energy
efficiency improvements, is 1.28 percent for load and 1.18 percent for peak. Changes to
PacifiCorp's load forecast are driven by a shift in the 2025 IRP in which demand from new large
customers is no longer included in the load forecast as those customers 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.As shown
in Figure 1.8, both energy efficiency and demand response show a lower trajectory in the latest
forecast,however the trajectories continue to trend upward across the long-term planning horizon.
• In the near-term years of 2025 through 2028, our ongoing conservation and cost-effective
demand-response initiatives will seek to deliver:
o 610 megawatts of energy efficiency from 2025 through 2028
o 83 megawatts of demand response from 2025 through 2028
Figure 1.7—2025 IRP Energy Efficiency and Demand Response Capacity
Energy Efficiency Demand Response
6,000 1,500
2,000 � 500
..��s�� u yy
0 0
�o. Cph^bam �l 1_� b Cp h
d 1�11�1 do1�1o10 doryodry 1�1 d ry R*do
25 IRP =25 IRP OR �25 IRP =25 IRP OR
=25 IRP WA 025 IRP UIWC =25 IRP WA O25 IRP UIWC
---2023 IRP Update ---23IRP ---2023 IRP Update ---23IRP
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
the company to reduce fuel consumption and associated costs and emissions and instead buy
increasingly low-cost 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 1.9, the 2025 IRP
converts 562 MW of coal fueled generation to natural gas fueled, exits PacifiCorp's share in 386
9

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
MW of minority-owned coal, and also assumes retirements of 220 MW at Dave Johnston and 156
MW of Naughton gas conversion by the end of the study horizon. Jim Bridger Units 3 and 4
convert to carbon capture in 2030 and operate during the 12 years of tax credit eligibility, retiring
in 2043. The balance of the coal units continues to operate through the end of the study horizon.
Figure 1.—2025 IRP Preferred Portfolio Thermal Resources
10,000
8,000 ,-�'---
6,000
ro
4,000
U
2,000
0
uu�Coal Coal-CCUS Gas-Steam Gas-CT/CCCT ---2023 IRP Update ---23 IRP
A summary of the coal unit exits,retirements, and conversions in the 2025 IRP preferred portfolio
and the 2023 IRP preferred portfolio is shown in Table 1.2. Also shown in Table 1.2 are the coal
unit changes which are projected to occur if necessary to comply with the current U.S.
Environmental Protection Agency (EPA) greenhouse gas (GHG) emissions regulation under
Section 111(d) of the Clean Air Act. 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.
Table 1.2 —2025 IRP Coal Resource Results Summary
Majority-Owned Coal
2025 IRP Retirement Year 2023 IRP Retirement Year
Unit Selected w/o 111(d)Regulation Selected w/111(d)Regulation As Selected
Dave Johnston 1&2 Not retired(Gas conversion 2029) No change 2028
Dave Johnston 3 2027(Clean air compliance) No change 2027(Clean air compliance)
Dave Johnston 4 Not retired Not retired(Gas conversion 2030) 2039
Hunter 1 Not retired 2032 2031
Hunter 2&3 Not retired Not retired(Alt.fuel conv.2030) 2032
Huntington 1&2 Not retired Not retired(Alt.fuel conv.2030) 2032
Jim Bridger 1&2 Not retired(Gas conversion 2024) No change 2037(Gas conversion 2024)
Jim Bridger 3&4 2042(CCS conversion 2030) No change 2037(Gas conversion 2030)
Naughton 1 2042(Gas conversion 2026) 1 No change 2036(Gas conversion 2026)
Naughton 2 Not retired(Gas conversion 2026) No change 2036(Gas conversion 2026)
Wyodak Not retired 2032 1 2039
ority-Owned 17oal
2025 IRP Retirement Year 2023 IRP Retirement Year
Unit As Input As Input
Colstrip 3 2025(Transfer capacity to unit 4) 2025(Transfer capacity to unit 4)
Colstrip 4 2029(PacifiCotp 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 1 2027(Assumed end of life) 2027(Assumed end of life)
10

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
Carbon Dioxide Emissions
The 2025 IRP preferred portfolio demonstrates PacifiCorp's ongoing commitment to providing
cost-effective clean energy solutions for its customers, continuing a trend of declining carbon
dioxide (CO2) and CO2 equivalent(CO2e) emissions over the next decade. Key drivers of this
decline include PacifiCorp's participation in the Energy Imbalance Market(EIM), the ongoing
transition to clean energy resources such as renewables, advanced nuclear,battery storage, and
transmission, as well as compliance with Regional Haze regulations.
The chart on the left in Figure 1.10 compares projected annual CO2e emissions between the 2025
IRP and 2023 IRP preferred portfolios. While the 2025 IRP emissions are projected to be slightly
higher than those in the 2023 IRP, this difference stems from updates to modeling assumptions.
The expected price-policy scenario in the 2025 IRP does not include a CO2 price or the Ozone
Transport Rule,both of which were included in the 2023 IRP. Increased emissions also result from
higher unspecified market purchases, assigned a default emissions factor, although market-wide
emissions are expected to decline with further renewable energy adoption. PacifiCorp is working
with regulators to adjust this factor to reflect the evolving energy market landscape.
The chart on the right in Figure 1.10 presents historical emissions data, assigning emissions to
unspecified market purchases, and indicates a long-term decline in system-wide CO2e emissions
compared to the company's baseline,with a slight increase toward the end of the planning
horizon due to the factors discussed in more detail in Chapter 9.
Figure 1.8 — 2025 IRP Preferred Portfolio CO2 Equivalent Emissions and PacifiCorp CO2
Equivalent Emissions Trajectory'
IRP CO2e Emissions Comparison PacifiCorp CO2e Emissions Trajectory
30 60
100%
50
25
u �
O
20 u 40
o e
15 F" 30 �/ c
10 20 40%
O C
O
5 10 20%
0 0lob 0•1
N N N N N N N N N N N N N N N N N N N N N N
02025 IRP CO2c■2023 IRP CO2a PacifiCorp Eminio (Milli-MT)
I PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2023 from owned facilities, specified sources
and unspecified sources.2024 emissions were not forecasted in the 2025 IRP and therefore reflect the forecast from the 2023 IRP
Update.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.
11

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
12

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
r
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
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.
13

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
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 Public Utility Commission of Oregon 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.
lg 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.
Federal Greenhouse Gas Emission Compliance:
li EPA finalized its regulation for existing coal-fueled steam units under Clean Air Act Section 111(d) in April 2024, though the
rule has been challenged in the D.C. Circuit. PacifiCorp will continue to update and evaluate alternatives for affected resources
while the legal process continues.
Dave Johnston Units 1 and 2:
lj PacifiCorp will initiate the process of converting Dave Johnston Units 1 and 2 to natural gas, including obtaining all required
regulatory notices and filings. Natural gas operations are anticipated to commencespring of 2029.
14

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
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, customer preference
2a 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 initiate with individual jurisdictions the process to issue as appropriate by individual jurisdiction need,one or more
independent Request for Proposals (RFP) to procure resources aligned with the 2025 IRP preferred portfolio that can achieve
2b commercial operations by the end of December 2029.3
Individual independent jurisdictional RFP filings will include timelines associated with the respective jurisdictions' process.
Considering the differentiated resource needs by jurisdiction identified in the 2025 IRP, scope and targeted resource needs may
vary by jurisdiction.
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
(Public Utilities Commission of Oregon).A portion of cost-effective demand response resources identified in the 2025 preferred portfolio in 2025 represent planned volumes
are expected to be acquired through a previously issued demand response RFP soliciting resources identified in the 2013 IRP. PacifiCorp will pursue all cost-effective
demand response resources identified as incremental to existing resources or as an expansion of existing resources offered through approved programs.
15

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
Action
Item ;N L_ ;;m 0
3. Transmission Action Items
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.
16

PACIFICORP—2025 IRP CHAPTER 1—EXECUTIVE SUMMARY
Action
4. Demand-Side Management (DSM)Actions
Item -MR 1 0
Energy Efficiency& Demand Response 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 Appendix D in
Volume II of the 2025 IRP.
PacifiCorp will pursue cost-effective energy efficiency resources.
ear First-Year Energy Efficiency (GWh) Annual Capacity- (NI«)
2025 595 92
2026 573 89
2027 597 209
2028 648 220
a
PacifiCorp will pursue cost-effective demand response resources targeting annual system capacity selections from the preferred
portfolio.4 Capacity impacts for demand response include both summer and winter impacts within a year and are incremental to
those already included as existing.5
Year Annual Incremental Capacity(NIW)
2025 18
2026 2
2027 0
2028 63
4 A portion of cost-effective demand response resources identified in the 2025 preferred portfolio in 2025 represent planned volumes are expected to be acquired through a
previously issued demand response RFP soliciting resources identified in the 2013 IRP.PacifiCorp will pursue all cost-effective demand response resources identified as
incremental to existing resources or as an expansion of existing resources offered through approved programs.
5 See Appendix D,Table D.3 for the split out between summer and winter capacity
17

PACIFICORP-2025 IRP CHAPTER 1-EXECUTIVE SUMMARY
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:
Balance of month and day-ahead brokered transactions in which the broker provides a competitive price.
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.
Action
Item 6. Renewable Energy Credit (REC) Actions
-.m r L
Renewable Portfolio Standards (RPS):
6a PacifiCorp may pursue unbundled REC RFPs and purchases to meet its state RPS compliance requirements.
PacifiCorp will issue RFPs seeking unbundled RECs that will qualify in meeting California RPS targets through 2026 and future
compliance periods, as needed.
6b Renewable Energy Credit Sales:
Maximize the sale of RECs that are not required to meet state RPS compliance obligations.
18

PACIFICORP—2025 IRP CHAPTER 2—INTRODUCTION
CHAPTER 2 - INTRODUCTION
CHAPTER HIGHLIGHTS
• 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 with respect to its obligations to customers, regulators, and
shareholders.
INTRODUCTION
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. 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.I
The 2025 IRP preferred portfolio is in addition to contracted resources,many of which are 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),
' See Chapter 7(Resource Options)
19

PACIFICORP-2025 IRP CHAPTER 2-INTRODUCTION
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
Volume I, Chapter I (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.
An
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
1, 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)
20

PACIFICORP—2025 IRP CHAPTER 2—INTRODUCTION
The IRP appendices, included as Volume II, contain the items listed below:
• Load Forecast (Volume 11,Appendix A)
• Regulatory Compliance (Volume I1, Appendix B)
• Public Input Process (Volume 11, 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 11, Appendix G)
• Stochastics (Volume 11, Appendix H)
• Capacity Expansion Results (Volume 11, Appendix 1)
• Capacity Contribution(Volume II, Appendix K)
• Distributed Generation Study (Volume II, Appendix L)
• Stakeholder Feedback Forms (Volume II, Appendix M)
• Washington Clean Energy Action Plan(Volume 11,Appendix O)
• Oregon Clean Energy Update (Volume 1I, Appendix P)
• Renewable Portfolio Implementation Plan (Volume 1I, Appendix R)
• Acronyms (Volume II,Appendix Z)
PacifiCorp is also providing supporting workpapers for the 2025 IRP. These electronically
provided materials support and provide additional details for the analysis described within the
document. Supporting workpapers 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" workpaper 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 otherwise have direct conflicts of interest
regarding commercially sensitive information.
The Role of PacifiCorp's Integrated Resource Planning
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. ,2 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.
2 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.
21

PACIFICORP-2025 IRP CHAPTER 2-INTRODUCTION
Vublic 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 nine 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.
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:
in2kpacificorp.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.pacificop2.com/energ_ /y integrated-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.
22

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 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 retail 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 established a cap-and-
invest program that 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
greenhouse gas emissions regulations when energy is transferred into the CAISO balancing
23

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
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.
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.
IVVholesale Electricity Markets
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
integrate these resources into the larger grid requires more flexible generation, transmission,
evolving storage technologies, and market design changes.
24

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
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 3. 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
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
' 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.
z 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)
25

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
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 7th,
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
standard, and the Ops Program will facilitate transfers between entities in a resource deficit and
those with excess resources.
4 2020 Long-term Reliability Assessment,December 2020,North American Electric Reliability Assessment
5 https://www.westempoweipool.org/about/programs/western-resource-adequacy-program
26

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
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 law6.
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%
Ju n 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
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
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 https://apps.ecology.wa.gov/publications/documents/2202047.ndf.
27

PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
2025 On-Peak power prices at Palo Verde,Mead,Four Corners, and Mid-Columbia are all trading
around$1054120 per MWh.
Figure 3.1 -Forward Prices at WECC Major Trading Hubs
$160.00
$140.00
$120.00
$100.00
$80.00 / i
$60.00 ARM ♦ /t /
$40.00 -
$20.00 X5%F/I
N w U-1 -4 w N N w U-1 �J w N N w U1 14 w N
\ \ \ \ \ N \ \ \ \ \ \ \ \ \ \
N N
N N N N N \ N N N N N \ N N N N N \
O O O O O N O O O O O N O O O O O N
N N N N N O N N N N N O N N N N N O
Ul U-1 Ui Ln U-1 N M a) Q1 Ol Q1 N _I V V V -4 N
Ui M V
PV On-Peak --- PV Off-Peak Mead On-Peak Mead Off-Peak
-4C On-Peak --- 4C Off-Peak MidC On-Peak MidC Off-Peak
Source: OTC, Siemens PTI
Table 3.2 reports the quarterly on-peak and off-peak price spread across the major WECC hubs,
driving the peaks and valleys observed in Figure 3.1 above.
Table 3.2 - 2025-2027 Forward Price Spread ($/MWh)
Palo VerdM= Mead 4corners Mid-Columbia
Date On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Oft-Peak
1/1/2025 $ 44.57 $ 44.53 $ 49.32 $ 49.35 $ 55.87 $ 60.23 $ 72.60 $ 57.25
---------------- ---------------•-------------- ---------------•--------------- --------------- ------ ---------------•---------------
5/1/2025 $ 18.04 1 $ 27.62 $ 21.12 1 $ 30.62 $ 17.05 1 $ 34.20 $ 26.81 1 $ 17.02
-------- ----- ---------------1...---.....---- -----.......---1--------------- --------------T-------------- --------------T--------------
8/1/2025 $104.89 $ 60.81 $120.14 $ 67.85 $111.56 1 $ 77.93 $103.20 $ 53.99
_.. ............................... ..............................
11/1/2025 $ 42.14 i $ 47.94 $ 46.28 i $ 51.86 $ 43.55 $ 54.89 $ 59.08 ; $ 47.28
--------------- --------------I-------------- ---------------a--------------- --------------+-------------- --- ---------a---------------
1/1/2026 $__63.81 i $ 73.32 $ 68.41 i $ 85.12 $ 79.99 ? $ 99.27 $100.52 i $ 92.19
--------------- - --------- ---------------.---------------
5/1/2026 $ 17.98 i $ 37.62 $ 16.18 i $ 39.84 $ 17.00 i $ 46.59 $ 27.99 1 $ 23.71
-----------------,-------------------------------,--------------- ---------.....-,------------------------........I...............
8/1/2026 $107.13 1 $ 71.57 $125.96 1 $ 59.86 $113.94 1 $ 91.72 $113.74 1 $ 56.61
---------------- ---------------•--------------- --- ---- ------ ---------------•-------------- ----------•---------------
11/1/2026 $ 45.38 1 $ 57.92 $ 46.83 1 $ 68.32 $ 46.89 1 $ 66.32 $ 75.27 1 $ 67.37
______ _______________1--------------- ----___________ --------------- -----------------------------------------------------------.-
1/1/2027 $ 71.36 ; $ 83.56 $ 70.01 1 $ 88.44 $ 89.44 1 $113.02 $102.48 1 $ 91.87
---------------- ------------- ---------------- --------------- ------ --------------- ..... ---------------.............
.
5/1/2027 $ 19.80 i $ 35.40 $ 9.73 i $ 35.70 $ 18.71 i $ 43.83 $ 34.07 i $ 34.10
--------------- --------------4-------------- ----------------r-------------- --------------a--------------- --------------a----------------
8/1/2027 $114.63 $ 80.80 $134.58 1 $ 81.71 $121.91 i $103.55 $125.72 1 $ 55.51
--------- - ------
11/1/2027 $ 41.95 1 $ 57.62 $ 54.19 $ 70.41 $ 43.35 1 $ 65.97 $ 82.83 1 $ 78.10
Source: OTC
28

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Power Market Dynamics
Non-CAISO WECC Generation and Capacity Mix
The generation mix in the non-CAISO WECC region reflects the influence of state RPS
(renewable portfolio standard) and emissions policies. In 2023, natural gas resources provided
about 31% 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.
Figure 3.2 -National RPS Targets
NH:
24.8%by
2025
VT:75% ME:100%by
� �� by 2032 2050
;
2030
RI:38.5%by
2035
CT.40%by
2030
�' • DE:25%by
• 2026
MD:50%by
;� 2021 2030
DC:100%
HI. 10006 by by 2032
204F,
1AState RPS ■State Goal
29

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
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 to ensure zero requiring zero carbon by 2040. 2050 enacted.
reduction by carbon carbon also RGGI
generation by 2050. also RGGI
2045 enacted generation by generation by participant artici ant
2050. 2030in p
OR:2021 Zero development I
carbon generation -
- Northeast and
by 2040 enacted Mid Atlantic
i
state carbon
e trading under
RGGI
NV:Zer
carbon:1, (NJ joins RGGI
2050 Jan.2020.VA
has advanced
efforts to join)
by 204 DC:100%
RPS by
CA:Active 2032
carbon trading
A832,and zero
carbon by 2045
NM:Zero
carbon by 2045
for IOUs.2050
HI,100 for coops
RPS by
2045
Active Carbon Trading ■Zero Carbon Generation Requirement
Carbon Trading Developing Zero Carbon Generation Requirements Developing
Source: Siemens PTI
Figure 3.4 -Non-CAISO WECC Generated Energy (TWh)
60(
500 ,
400
300
200
100
3
2022 2023 2024 2025 2026 2027 2028 2029 2030
■ oal ■ Natural Gas Nuclear ■ Hydro Solar ■ Wind ■Other
Source: IHS Markit, SNL, Siemens PTI
30

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
2025 2026 2027 2028 2029 2030
■Storage ■ Natural Gas ■Other ■Solar ■Wind
Source:IHS Markit, SNL, Siemens PTI
31

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.6 -Non-CAISO WECC Capacity Retirement(GW)
1
0.5
0
u 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 ten 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 I I I 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.
32

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 or 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.
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
33

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
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 3.8,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 �►
8.00 exports outpaces
production \4 t
6.00 / Above normal
summer temperature
Freeport LNG drives record demand }}}
4.00 R export terminal for power generation /
\ explosion /
Well freezeoffs reduces demand
2 00 Below normal winter
reduces temperature drives record
production demand for heating
0.00
Ian-22 Fe -22 Mar-22 Apr-22 May-22 Jun-22 RA-22 Aug-22 Aug-22 Ott-22 Oct-22 Now-22 Oet-22
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.
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
34

PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
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)
3
Permian
2.5
2
1.5 Haynesville
Appalachia
1 Eagle Ford
0.5 Bakken
AnadarKeulf 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.
35

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
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.
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 because of subdued
spot prices. Despite this, overall supply continued to outpace domestic demand, keeping
inventories above the five-year average.
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
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.
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
Figure 3.11 —Henry Hub Futures
$7.00 -
$6.00 -
$5.00 -
S4.00
$3.00
$2.00
$1.00
$0.00
V LO CD n 00 M O N CO q Lo CD n M O O N M � LO M 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 PTI, 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
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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 in 2025 for implementation
in 2026 and beyond. PacifiCorp's guiding principles in the development of the new allocation
methodology will continue to be:
I. 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
8. Provide the company with a reasonable opportunity to recover its costs
Environmental Regulation
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.
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Federal PoliyUpdate
National Electric Vehicle Infrastructure Formula Program
$5 billion FY2022-2026
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
• Long-term EV charging station data sharing
On February 6, 2025, the FHWA released a letter suspending approval of state electric vehicle
infrastructure deployment plans pending review of the policies underlying the implementation of
the NEVI Formula Program. The FHWA aims to have updated draft NEVI Formula Guidance
published for public comment in the spring. After the public comment period has closed, FHWA
will publish updated final NEVI Formula Guidance that responds to the comments received.
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. Opportunity to obtain funding through this grant closed on September
11, 2024.
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
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
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
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
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
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
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, 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.
1. Base load turbines (operating above 40% of maximum annual capacity factor) must
initially meet a standard reflective of an efficient combined cycle design and 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.
1. 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.
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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.
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 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 primary standards are set at a level
that protects public health with an adequate margin of safety. The secondary standards are set to
protect the public welfare from adverse effects including those related to effects on soils, water,
crops,vegetation, anthropogenic materials, among other impacts. If an area is determinedto be out
of compliance with an established NAAQS standard, the state is required to develop a state
implementation plan (SIP) to bring that area into compliance, and that plan must be approved by
Before February 9,2018,the tax credit was strictly for CO2.
s The tax credit reaches$35/tonne and$50/tonne in 2026.
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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 both the primary and secondary 8-hour 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 proposed a federal implementation plan
(FIP) to eliminate interstate transport of ozone precursors from states that EPA identified as
significantly contributing to downwind nonattainment or interfering with maintenance of the 2015
ozone NAAQS in other states. 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.
Specifically, EPA proposed in that action to implement emissions reductions by requiring some
sources within these states to participate in revised provisions of the Cross-State Air Pollution Rule
(CSAPR). EPA applied the interstate transport framework developed in CSAPR, the CSAPR
Update,the Revised CSAPR Update,and other previous ozone transport rules to propose to further
limit NOx emissions from electric generating unit (EGU) sources within the borders of 25 states
during the ozone season and to limit ozone season NOx emissions from non-EGU sources in 23
states to reduce interstate ozone transport.
On February 13, 2023, EPA finalized disapproval of interstate ozone transport SIP submissions
for the 2015 8-hour ozone NAAQS for multiple states and issued a partial disapproval for two
additional states.This included the SIP for Wyoming.In the same action,EPA deferred final action
on its proposed disapproval for Wyoming. 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 despite EPA previously recognizing, in an August 2018 memorandum, that state may
establish an alternative contribution threshold of 1 ppb. States, like Utah, for which EPA issued
disapproval actions of their interstate ozone transport SIPS were required to comply with the
interstate ozone transport FIP for the 2015 ozone standard upon finalization of that action on March
2023. Due to EPA's delayed final action on Wyoming's SIP submission, Wyoming was not
required to comply with the final interstate ozone transport FIP for the 2015 8-hour ozone NAAQS.
Numerous states and industries, including PacifiCorp, challenged certain provisions of the ozone
interstate transport SIP disapprovals and FIP for the 2015 ozone standard. The state of Utah and
PacifiCorp filed petitions and motions for stay of EPA's denial of the Utah SIP 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 interstate transport
FIP for the 2015 ozone NAAQS while the stay remains in place. In granting the stay, the court
indicated that PacifiCorp and the other petitioners are likely to succeed on the merits. 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 stayed.
The EPA finalized approval of Wyoming's interstate ozone transport SIP on December 19, 2023.
Given the approval of the Wyoming SIP, PacifiCorp facilities in Wyoming are not subject to the
interstate ozone transport FIP.Given the court stay of EPA's disapproval of Utah's SIP,PacifiCorp
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PACIFICORP-2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
was not subject to the interstate ozone FIP requirements for the 2015 ozone NAAQS during the
2023 ozone season. The Utah ozone case was transferred to the D.C. Circuit on February 16,2024,
for adjudication on the merits, leaving the stay in place. Requirements for the 2024 ozone season
and beyond will depend on the outcome of the litigation.
In addition to litigation over SIP disapprovals, numerous appeals of, and motions to stay, the
interstate ozone FIP were filed in four different circuit courts. On September 25, 2023, the D.C.
Circuit denied the motion to stay the interstate ozone transport FIP for the 2015 ozone standard
that was filed by several state and industry parties. The states of Ohio, Indiana and West Virginia
filed a request for an emergency stay of the interstate ozone transport FIP 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 a stay on the same
day. The U.S. Supreme Court granted a stay of the FIP on June 27, 2024. Accordingly, states are
not required to comply with the ozone transport FIP pending the stay.
On December 9, 2024, EPA signed a final rule to reclassify the Northern Wasatch front, which
includes Salt Lake County, from moderate to serious nonattainment for the 2015 Ozone NAAQS.
PacifiCorp's Gadsby facility is in the Northern Wasatch Front area and was previously identified
as a major source subject to Utah's moderate nonattainment area SIP for Ozone. In anticipation of
EPA's decision, the Utah Department of Environmental Quality(DEQ) requested that PacifiCorp
submit a reasonably available control technology(RACT) analysis to the Utah DEQ's Division of
Air Quality. PacifiCorp submitted the RACT analysis on January 9, 2024, and followed the top
down RACT analysis process for each nitrogen oxide and volatile organic carbon emission source
at the at the Gadsby plant. Plant emissions from 2017 were utilized to prepare cost effectiveness
analyses for add-on controls; these analyses demonstrated that no additional controls are cost
effective at this time.
Particulate Matter NAAQS
On October 17, 2006, EPA revised the level of the 24-hour PM2.5 NAAQS from 65 micrograms
per cubic (µg/m3) meter to 35 µg/m3. On May 10, 2017, the EPA Administrator signed a final
action to reclassify the Salt Lake City and Provo PM2.5 nonattainment areas from moderate to
serious for the 2006 24-hour PM2.5 NAAQS. PacifiCorp's Lake Side and Gadsby facilities were
subject to major source requirements due to their emissions of PM2.5. On April 27, 2017,
PacifiCorp submitted a Best Available Control Technology (BACT) determination 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 for the Lake Side
and Gadsby facilities in the SIP.
On November 17, 2020, EPA finalized redesignation of the Salt Lake City and Provo
nonattainment areas to attainment for the 2006 24-hour PM2.5 NAAQS. On April 6, 2021, EPA
reopened the comment period after adding supplemental information to the proposal. Re-
designation to attainment would have no effect on current emissions and operating limits for the
Lake Side and Gadsby facilities.
On March 6, 2024, EPA revised the primary annual PM2.5 NAAQS from 12.0 µg/m3 to 9.0 µg/m3.
EPA has not yet designated areas as attainment, nonattainment, unclassifiable/attainment, or
unclassifiable under this new standard.
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Regional Haze
Clean Air Act (CAA) Section 169A includes a program for protecting visibility in the nation's
mandatory Class I Federal areas, which include national parks and wilderness areas. The CAA
directs EPA to promulgate regulations to assure reasonable progress toward meeting the goal of
protecting visibility. In 1990, CAA section 169B was added to further address visibility
impairment, specifically, impairment from regional haze. EPA promulgated the Regional Haze
Rule in 1999,which 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 generally
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 July 6, 2005, EPA published final amendments to its regional haze rule to require emission
controls known as Best Available Retrofit Technology (BART) for industrial facilities meeting
certain regulatory criteria with emissions that have the potential to affect visibility. The regulated
pollutants include PM, NOx, S02, certain VOCs, and ammonia. The 2005 amendments included
BART guidelines for states to use in determining which facilities must install controls and
presumptive controls for certain sources subject to BART. 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 on July 8,2021,that discusses source selection, characterization of factors for
emission control measures, decisions on what control measures are necessary to make reasonable
progress, consideration of visibility in making control determinations, and the consideration of
five additional factors, among other topics.
Utah Regional Haze
In May 2011, the state of Utah submitted to EPA a regional haze SIP for the first planning period
requiring the installation of S02, NOx and PM controls on Hunter Units 1 and 2 and Huntington
Units 1 and 2. In December 2012, EPA approved the S02 portion of the Utah regional haze SIP
and disapproved the NOx and PM portions for Hunter Units 1 and 2 and Huntington Units 1 and
2. EPA's approval of the S02 SIP was appealed by environmental groups to the Tenth Circuit. In
addition, PacifiCorp and the state of Utah appealed EPA's disapproval of the SIP on the basis that
the NOx and PM BART determinations for the sources did not comply with the Regional Haze
rules. PacifiCorp and the state's appeals were dismissed as was the appeal filed by environmental
groups in the Tenth Circuit. In June 2015,Utah submitted a revised SIP to EPA for approval which
included an alternative BART NOx analysis incorporating a requirement for PacifiCorp to retire
Carbon Units 1 and 2 and crediting NOx emission reductions from Hunter Units 1, 2, and 3 and
Huntington Units 1 and 2. On July 5, 2016, EPA published a final rule to partially approve and
partially disapprove Utah's regional haze SIP and propose a FIP. The FIP established NOx
emission limitations on Hunter Units 1 and 2 and Huntington Units 1 and 2 that are reflective of
Selective Catalytic Reduction (SCR) and Low-NOx Burners (LNB) and Separated Overfire Air
(SOFA). On September 2, 2016, the state of Utah and PacifiCorp filed petitions for administrative
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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 as well as 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 that would require reporting of all deviations from compliance
with the applicable requirements under BART and the BART Alternative, including the emission
limits for Hunter and Huntington.
On January 22, 2020, EPA published its proposed approval of the Utah SIP revision and
withdrawal of the FIP requirements that would have required emissions limitations for the Hunter
and Huntington plants equivalent to SCR plus upgraded combustion controls (LNB/SOFA). EPA
subsequently finalized approval of the SIP and withdrawal of the FIP as proposed on November
27, 2020. On January 11, 2021, the Tenth Circuit granted Utah, PacifiCorp and EPA's motion to
dismiss the Utah regional haze petitions.
Environmental groups filed a petition for review in the Tenth Circuit on January 19, 2021,
objecting to EPA's approval of Utah's regional haze SIP for the first planning period.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. On August 14, 2023, the Tenth
Circuit determined EPA properly approved the Utah regional haze SIP for the first planning period
and denied environmental groups'petition.
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, and submitted the SIP to
EPA on August 2, 2022. The SIP differs from PacifiCorp's Reasonable Progress Analysis and
requires updated mass-based NOx limits.The SIP also concluded that existing S02 limits in Hunter
and Huntington's title V permits were necessary to make reasonable progress but required no
further S02 emission limits for the plants.
On December 2, 2024, EPA finalized a final partial approval and partial disapproval for Utah's
regional haze state implementation plan for the second planning period without simultaneously
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finalizing a federal implementation plan. Specifically, EPA disapproved the long-term strategy,
reasonable further progress goals, and federal land management (FLM) consultation components
of the SIP. EPA's disapproval of Utah's long-term strategy is based, in part, on EPA's rejection of
Utah's finding that installation of SCR or other physical NOx pollution controls for Hunter and
Huntington is not necessary to achieve reasonable progress. There are no new compliance
obligations for PacifiCorp at this time, as the disapprovals did not include a simultaneously
finalized FIP. PacifiCorp filed a petition for reconsideration on EPA's disapproval action on
January 30, 2025, and filed a petition for review in the Tenth Circuit the next day.
Wyoming Regional Haze
On January 30, 2014, EPA published a final rule partially approving and partially disapproving
the Wyoming regional haze SIP for the first planning period and promulgating a FIP to address
the deficiencies EPA found in the Wyoming SIP submission. As a result of the 2014 final rule and
FIP, the following controls were required at PacifiCorp facilities for the regional haze first
planning period:
• Naughton Units 1 and 2: LNB/OFA, with an emission limit of 0.28 lbs/MMBtu for each unit
• Naughton Unit 3 by December 31, 2014: SCR+LNB/SOFA, 0.07 lb/MMBtu (30-day
rolling average).
• Jim Bridger Unit 3 by December 31, 2015: SCR, with an emission limit of 0.07 lb/MMBtu
(30-day rolling average)
• Jim Bridger Unit 4 by December 31, 2016: SCR, with an emission limit of 0.07 lb/MMBtu
(30-day rolling average)
• Jim Bridger Unit 2 by December 31, 2021: SCR, with an emission limit of 0.07 lb/MMBtu
(30-day rolling average) and NOx emission limit of 0.26 lb/MMBtu by March 4, 2015
• Jim Bridger Unit 1 by December 31, 2022: SCR, with an emission limit of 0.07 lb/MMBtu
(30-day rolling average) and NOx emission limit of 0.26 lb/MMBtu by March 3, 2015
• Dave Johnston Unit 3: Either a commitment to retire by 2027 and LNB/OFA, with an
emission limit of 0.28 lbs/MMBtu(30-day rolling average) or SCR+LNB/OFA, with an
emission limit of 0.07 lbs/MMBtu(30-day rolling average)
Wyodak Unit 1: SCR+ LNB/SOFA, with an emission limit of 0.07 lb/ MMBtu (30-day
rolling average)
Naughton—In its 2014 rule, EPA approved Wyoming's determination that NOx BART for Units
1 and 2 was LNB and OFA. While EPA approved Wyoming's NOx BART determination of SCR
and LNB/OFA, with an emission limit of 0.07 lb/MMBtu (30-day rolling average) for Naughton
Unit 3, EPA stated that it would approve limitations that reflect the conversion of Unit 3 to natural
gas once Wyoming submitted the requisite SIP revision. On November 28, 2017, Wyoming
submitted to EPA a source-specific revision to its regional haze SIP for the first planning period
for the Naughton Unit 3 conversion. On March 7, 2017, Wyoming issued PacifiCorp a permit for
Unit 3's conversion to natural gas, which allowed Unit 3 to operate on coal through January 30,
2019. PacifiCorp ceased coal operation on Unit 3 on January 30, 2019, as required by the permit.
EPA's final rule approving Wyoming's SIP revision for Naughton Unit 3's 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 NOx 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
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environmental groups'petition.
Jim Bridger—In its 2014 rule, EPA approved Wyoming's determination that Jim Bridger Units 1
and 2 meet an emission limit of 0.07 lb/MMBtu (30-day rolling average) by 2022 and 2021,
respectively. EPA also approved Wyoming's NOx BART determination that required Jim Bridger
Units 1 and 2 to meet a NOx emission limit of 0.26 lb/MMBtu(30-day rolling average)by March
4, 2019. For Jim Bridger Units 3 and 4, EPA approved Wyoming's determination that the
appropriate level of NOx control for Units 3 and 4 for purposes of reasonable progress is the SCR-
based emission limit in the SIP of 0.07 lb/MMBtu, with compliance dates of December 31, 2015,
for Unit 3 and December 31, 2016, for Unit 4. Accordingly, 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 air permit application for monthly average plant-wide NOx and S02
emission limits, in addition to an annual combined NOx and S02 limit, on all four Jim Bridger
boilers in lieu of the requirement to install SCR on Units 1 and 2. PacifiCorp proposed that the
plantwide limits were more cost effective while leading to better modeled visibility than SCR
installations 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 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 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 to EPA for approval a revised regional haze SIP
requiring natural gas conversion of Jim Bridger Units 1 and 2. The SIP conversion replaces the
previous requirement for SCR at the units. Wyoming issued to PacifiCorp an air permit for the
natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022. PacifiCorp completed
the conversion. On April 10, 2024, EPA proposed to approve Wyoming's December 2022 SIP
revision for Jim Bridger Units 1 and 2. The SIP includes enforceable emissions and heat input
limits at Jim Bridger Units 1 and 2, consistent with the conversion of those units to natural gas.
EPA accepted comments on the proposed approval through May 10,2024,but has not yet finalized
the approval.
Dave Johnston — EPA's January 20, 2014, FIP action required either the installation of SCR on
Dave Johnston Unit 3 or that the unit retire by the end of 2027. PacifiCorp opted not to install
SCR. EPA approved Wyoming's NOx BART determination for Dave Johnston Unit 4 of an
emission limit of 0.15 lb/MMBtu (3 0-dayrolling average). EPA also approved Wyoming's NOx
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reasonable progress determinations for Dave Johnston Units 1 and 2 that no controls were
necessary.
Wyodak—EPA's January 20, 2014, FIP action determined SCR+LNB/SOFA to be NOx BACT.
PacifiCorp and Wyoming petitioned EPA's FIP that would require SCR at Wyodak in the Tenth
Circuit. On September 9,2014,the Tenth Circuit stayed the NOx emission limits for Wyodak Unit
1 in the regional haze 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. EPA, Wyoming and PacifiCorp signed a Settlement Agreement for Wyodak on
December 16, 2020. On January 4,2021,EPA published the proposed settlement agreement in the
Federal Register, requesting public comment. PacifiCorp submitted comments to EPA on March
5,2021, in support of the Wyodak proposed settlement agreement. However,EPA did not proceed
with final approval of the proposed settlement agreement but rather re-engaged with Wyoming
and PacifiCorp in mediation through the Tenth Circuit.Litigation for the Wyodak case challenging
EPA's denial of the Wyoming SIP and finalization of a FIP recommenced when the mediation
process was not successful. 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. Wyoming incorporated the four-factor analyses in its
SIP for the regional haze second planning period. Wyoming determined that emission limits and
planned unit retirements met the reasonable progress goals for Regional Haze.Wyoming submitted
the state's regional haze SIP for the second planning period to EPA on August 10, 2022.
On December 2, 2024, EPA finalized partial approval and partial disapproval of Wyoming's
regional haze SIP for the second planning period. Specifically, 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. There are no new compliance obligations for PacifiCorp at this time, as the
disapproval action did not include a simultaneously finalized FIP. On January 30, 2025, the state
of Wyoming submitted an"open letter"to EPA stating its concerns about the agency's disapproval
of the regional haze second planning period plan for the state. On January 31, 2025, the state also
filed a petition for review in the Tenth Circuit. PacifiCorp filed a petition for reconsideration with
the agency on January 30, 2025, and petition for review in the Tenth Circuit the next day.
Colorado Regional Haze
Craig- The Colorado regional haze SIP for the first planning period established SO2 BART emission
limits on Craig Units 1 and 2 of 0.11 lb/MMBtu(30-day rolling average). Colorado incorporated NOx
emission limits of 0.281b/MMBtu(30-day rolling average)for Craig Unit 1 and 0.08 lb/MMBtu(30-
day rolling average) for Craig Unit 2 in the SIP. Although the state determined that SNCR was
reasonable for BART for both Units 1 and 2,Tri-State and Colorado agreed to a NOx emission control
plan for Unit 2 that reflected SCR and was therefore more stringent than the BART determination.
Colorado determined that the PM BART emission limit is 0.03 lb/MMBtu(30-day rolling average)at
Craig Units 1 and 2,which could be met through the operation of the existing fabric filter baghouses.
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Hayden- In its regional haze SIP for the first planning period, Colorado determined that the SO2 BART
emission limit for Hayden Unit 1 is 0.13 lb/MlIl ffltu(30-day rolling average)and for Unit 2 is 0.131bA MBtu
(30-day rolling average).These limits are met with the operation of the existing controls.For NOx,Colorado
determined that the NOx BART emission limit for Hayden Unit 1 is 0.081b/MMBtu(30-day rolling average)
and for Unit 2 is 0.07 lb/MMBtu(30-day rolling average).These BART emission limits could be met through
the installation and operation of SCR. Colorado determined that the PM BART emission limit is 0.03
lb/MMBtu (30-day rolling average) for Hayden Unit 1 and Unit 2. These PM emission limits can be met
through the operation of the current fabric filter baghouses.
EPA found Colorado's determinations for the Craig and Hayden units to be approvable and fmalized
approval of the Colorado regional haze SIP for the first planning period on December 31, 2012.
Environmental groups appealed EPA's action in February 2013, 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, with a NOx BART emission
limit for Craig Unit 1 is 0.07 lb/MMBtu, calculated on a 30 boiler-operating-day rolling average
at Craig Unit 1 by August 31, 2021, 2021.
On May 26, 2017, Colorado submitted a SIP amendment to EPA that reflected further agreement
between the owners of Craig Unit 1, state and federal agencies, and parties to previous settlements
The revised SIP required Craig Unit 1 to meet an annual NOx emission limit of 4,065 tons per year
by December 31, 2019. The SIP revision also required the unit to either convert to natural gas by
August 31, 2023, and if converting to natural gas, comply with a NOx emission limit of 0.07
lb/MMBtu (30-day rolling average) beginning August 31, 2021, or shut down by December 31,
2025. 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 I 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 on March 22, 2021. However, EPA has not yet acted on the
Colorado regional haze SIP for the second planning period. The Colorado SIP is part of the
deadline suit filed by environmental 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 coal- and oil-fired facilities achieve emission standards for mercury, acid gas
hazardous air pollutants (HAPs), non-mercury HAP metals, and organic HAPs. 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. By April 2015, PacifiCorp had taken the required
actions to comply with MATS across its generation facilities. On April 25, 2016, in response to a
Supreme Court decision requiring consideration of costs, EPA published a Supplemental Finding
that determined that it is appropriate and necessary to regulate coal- and oil-fired EGUs under the
Clean Air Act.
On February 7, 2019, EPA published a reconsideration of the Supplemental Finding in which it
proposed to find that it is not appropriate and necessary to regulate HAPs, reversing the Agency's
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prior determination. On May 22, 2020, EPA published a reconsideration of its 2016 supplemental
finding.In the reconsideration action,EPA determined that it is not appropriate and necessary to regulate
HAP emissions from coal- and oil-fired EGUs. The rule was effective May 22, 2020. Several
petitions for review were filed in the D.C. Circuit by parties challenging and supporting 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 March 6,2023,EPA finalized
a rule rescinding the 2020 revocation of the appropriate and necessary finding. The rule therefore
reinstated the finding. Because PacifiCorp plants are in compliance with the MATS standards,the
reinstatement of the finding has immediate impact on PacifiCorp's operations.
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 existing lignite-fired units by 70 percent and sets a
more stringent standard for emissions of filterable particulate matter from existing coal-fired
power plants. The rule also requires that continuous emissions monitoring be used to demonstrate
compliance with the filterable PM standard.
Coal Combustion Residuals
On April 17, 2015, EPA finalized a rule to regulate the management and disposal of coal
combustion residuals (CCR) under the Resource Conservation and Recovery Act (RCRA). The
final rule became effective October 19, 2015. The rule establishes minimum nationwide standards
for new and existing CCR landfills and surface impoundments as well as all lateral expansions
consistent of location restrictions, design and operating criteria, groundwater monitoring and
corrective action, closure requirements and post closure care, recordkeeping, notification, and
internet posting requirements. In addition to other requirements,the rule requires existing unlined
CCR surface impoundment that is contaminating groundwater to stop receiving CCR and either
retrofit or close, except in limited circumstances. The rule also requires the closure of certain
landfills and CCR impoundments. 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.
On June 14, 2016, the United States Court of Appeals for the D.C. Circuit ordered the vacatur of
the "early closure" provisions in the 2015 CCR rule which would have allowed inactive CCR
surface impoundment units that had closed by a certain date to forgo groundwater monitoring or
other requirements. In response to this decision, EPA published a direct final rule on August 5,
2016, to extend for certain inactive CCR surface impoundments the compliance deadlines
established by the regulations for the disposal of CCR under RCRA.
On July 30, 2018, in response to further legal challenge, EPA finalized a rule to 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 EPA. The rule also revised groundwater protection standards for certain
constituents. In addition to adopting alternative performance standards and revising groundwater
performance standards for certain constituents,EPA extended the deadline by which facilities must
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cease the placement of waste in CCR units closing for cause in certain instances. The first phase
of the CCR rule amendments was made effective in August 2018 (the "Phase 1, Part 1 rule").
Following the March 2019 submittal of competing motions from environmental groups, EPA
finalized its Holistic Approach to Closure: Part A rule("Part A rule")on August 28,2020.The rule
reclassified compacted-soil lined surface impoundments from "lined" to "unlined," established a
deadline of April 11, 2021, by which unlined surface impoundments that failed aquifer location
restriction must initiate closure. In addition, the rule revised the alternative closure provisions to
grant facilities additional time to develop alternative capacity to manage both CCR and/or non-
CCR wastewater streams before they must stop receiving waste and initiate closure of their surface
impoundments. Finally, the rule revised certain requirements related to the annual groundwater
monitoring and corrective action report and the requirements for publicly accessible CCR internet
sites. A provision in Part A allows demonstrations to be submitted to 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.
On November 12, 2020, EPA published the final Holistic Approach to Closure: Part B rule ("Part
B rule"). The Part B rule finalizes a two-step process that allows 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. EPA
proposed these options as part of a subsequent proposal on March 3, 2020. On February 20, 2020,
EPA published a proposed rule to establish a federal CCR permit program in accordance with the
requirements of the Water Infrastructure Improvements for the Nation (WIIN) Act. Until the
proposals are finalized and fully litigated, PacifiCorp cannot determine whether additional action
may be required.
Separately, on August 15, 2017, EPA published a request for comment on its proposed permitting
guidance which describes EPA's interpretation of the WIIN Act provisions and how EPA will
review states' CCR permit programs 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 Utah will submit
an application to EPA for approval, but the timing of the submission remains uncertain. EPA
rejected Wyoming's application due to concerns about the state's ability to meet federal standards
for the safe management of coal ash.
On May 8, 2024, EPA finalized the legacy surface impoundments rule to (1) extend federal CCR
regulatory requirements to CCR surface 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 (CCR management units or CCRMUs) and (2) allow for alternative closure
provisions that allow a facility to complete the closure by removal in two stages. The final rule,
which became effective on November 8,2024,includes exemptions and establishes new categories
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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. The first phase of such a report is
due February 2026. Because the facility evaluation and report requirement will determine the
magnitude of compliance obligations, PacifiCorp cannot assess the full impacts of the rule at this
time.
On August 5, 2024, Utah, Wyoming and other Republican-led states filed a petition for review in
the D.C. Circuit on EPA's May 2024 legacy rule, arguing that EPA acted arbitrarily and beyond
its authority when enacting the new rule. On February 3, 2025, these same petitioners as well as
power companies, utilities and trade groups filed their opening brief in a consolidated case
contesting the rule in the D.C. Circuit.
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."In August 2014,EPA published a final rule, effective October 2014,under
section 316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The
final rule establishes requirements that apply to existing power generating facilities that withdraw
more than two million gallons per day,based on total design intake capacity, of water from Waters
of the United States (WOTUS) and use at least 25 percent of the withdrawn water exclusively for
cooling purposes. The rule includes standards to address 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). 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. 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.
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,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
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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 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 May 9, 2024, EPA finalized the Supplemental ELG and Standards for the Steam Electric
Generating Point Source Category(2024 ELG Rule),which includes a new subcategory for EGUs
permanently ceasing coal combustion by 2034. The 2024 ELG Rule also imposes a zero liquid
discharge requirement at coal-based generating units for bottom ash transport water, flue gas
desulfurization wastewater, and coal combustion residual leachate. The rule also eliminates 2020
ELG Rule's less stringent BAT requirements for two subcategories: high-flow facilities and low-
utilization electric generating units (LUEGUs), except to the extent they apply to one new
permanent cessation of coal combustion subcategory. The rule maintains,however,the 2020 ELG
Rule subcategory for EGUs permanently ceasing the combustion of coal by 2028 and oil-fired and
small(50 megawatts(MW)or less)EGUs established in the 2015 rule.The rule finalizes additional
reporting and recordkeeping requirements and zero-discharge limitations applicable after EGUs
cease coal combustion, as well as procedural requirements for affected facilities to demonstrate
permanent cessation of coal combustion or that permanent retirement will occur.
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. In October 2021,the Dave Johnston plant submitted a notice of planned participation
in 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,
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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.
State 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.
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
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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 several times since its inception. In September 2018, Governor Brown signed into
law 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. The California Energy Commission, California Public Utilities
Commission, and California Air Resources Board have not introduced rules on if and how electric
utilities will demonstrate compliance with SB 100. Interim targets for the carbon-free target were
subsequently adopted by SB 1020 in 2022.
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
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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-B,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 staged as follows: 27 percent for 2025-2029, 35 percent for
2030-2034, 45 percent for 2035-2039, and 50 percent for 2040 and every subsequent year
thereafter.The bill changes the renewable energy certificate(REC)life to five years,while allowing
RECs generated from the effective date of the bill passage until the end of 2022 from new long-
term renewable projects to have unlimited life. The bill also includes provisions to create a
community solar program in Oregon and encourage greater reliance on electricity for
transportation.
On March 10, 2020, Oregon Governor Kate Brown issued Executive Order 20-04 (EO 20-04),
which directs state agencies to take actions to reduce and regulate greenhouse gas emissions.
EO 20-04 establishes emissions reduction goals for Oregon and directs certain state agencies to
take specific actions to reduce emissions and mitigate the impacts of climate change. EO 20-04
also provides overarching direction to state agencies to exercise their statutory authority to help
achieve Oregon's climate goals.
In 2021, Oregon passed House Bill 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. An
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
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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 and every year thereafter. 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 2019,the Washington Legislature passed 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 retail electricity
sales be supplied from renewable and non-emitting resources by 2045. PacifiCorp submitted its
inaugural Clean Energy Implementation Plan (CEIP) 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 Legislature passed the Climate Commitment Act, which establishes a cap-
and-invest program that 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
serving 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
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Utah9
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, which
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 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, which 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 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 2024, the Utah Legislature passed HB 191, Electrical Energy Amendments, which
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;
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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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
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 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.
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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. Effective February 2025, the Washington Department of
Commerce issued a new rule lowering the emissions performance standard to 876 lb GHG/MWh.
PacifiCorp purchased Chehalis in 2008 and this 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.
Rene"e Portfolio Standard
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.
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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 adjusted"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
*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 2020.11 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,
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 (lX) 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.
10 Adjustments for generated or purchased from qualifying zero carbon emissions and carbon capture storage and
DSM.
"www leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbxl_2_bill_20110412_chaptered.pdf
12leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill id=201520160SB350
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Table 3.4—California Com liance 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*2 /0 021 Retail Sales)+(38.5%*2022 Retail Sales)
+(41.25/0 2023 Retail Sales)+(44 2024 Retail Sales)
Compliance Period 5 (2025-2027) (46.67% *2025 Retail Sales)+(49.33% *2026 Retail Sales)
+(52% *2027 Retail Sales)
Compliance Period 6(2028-2030) (54.67% *2028 Retail Sales)+(57.33% *2029 Retail Sales)
+(60% *2030 Retail Sales)
SB 2 (lX) established new"portfolio content categories" for RPS procurement, which delineated
the type of renewable product that may be used for compliance and 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.
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.I3
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.
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.
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Table 3.5—California Balanced Portfolio Requirements
California RPS Compliance Period 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
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.
14 www.leg.state.or.us/07reg/measpdf/sbO8OO.dir/sbO838.en.pdf
15 olis.leg.state.or.us/liz/2016R1/Downloads/MeasureDocument/SB1547/Enrolled
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- 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.16
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
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, after the
passage of Oregon House Bill 3161, effective January 1, 2024, ORS 469A.075 now aligns the
filing of a renewable plan(formally called the Renewable Portfolio Implementation Plan or RPIP)
with the filing of the IRP. Please see Appendix R for detailed information on PacifiCorp's 2025
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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RPS Renewable Plan, including annual targets, list of resources, applicable requirements, and
assumptions and methodologies. These RPS compliance reports and plans are available on
PacifiCorp's website."
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.
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.
17 www.pacificpower.net/ORrps
18 le.utah.gov/-2008/bills/sbillenr/sbO2O2.pdf
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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
corporate sustainability goals. An expansion of this program is currently under development to be
offered under a new tariff in Utah, Idaho and Wyoming.
19 www.secstate.wa.gov/elections/initiatives/text/1937.pdf
20 www.pacificpower.net/report
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Clean Energy Standards
Washington
In 2019, Governor Jay Inslee signed into law Senate Bill 5116, the Clean Energy Transformation
Act (CETA). 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 sales 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. In February 2025, the Commission adopted final rules that exempted multijurisdictional
electric companies with 60,000 or fewer customers in California from compliance with the
hourly reporting requirement.
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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 23. 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 could 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
23 Electric Vehicle Sales and the Charging-Infrastructure-Required Through 2035
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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 Relicensing
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
24 California Electric Vehicle Infrastructure Line Extensions(nacificnowennet)
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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 could 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'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 Design
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 several 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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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
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's past procurement efforts have resulted in a number of contracts for new resources
that have recently come online or are projected to come online through 2026 as summarized in
Table 3.6.25 These resources are also included in the resource tables presented in Chapter 6.
15 See Appendix M,stakeholder feedback form#59(Renewable Northwest)
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PACIFICORP—2025 IRP CHAPTER 3-PLANNING ENVIRONMENT
Table 3.6-PacifiCorp's Recent and Upcoming New Resource Additions
Resource Storage
Year Commercial
ores Type Capacity Capacity Source
coutracted operation
Appaloosa Solar Solar 200 n/a 2020 Jan 2024 Customer program:UT Sch 34
Rocket Solar Solar 80 n/a 2020 Feb 2024 Customer program:UT Sch 34
Castle Solar Solar 40 n/a 2020 Apr 2024 1 Customer program:UT Sch 32
Horseshoe Solar Solar 75 n/a 2020 Apr 2024 Customer program:UT Sch 34
Elektron Solar Solar 80 n/a 2020 Apr 2024 Customer program:UT Sch 34
Oregon Institute of Tech.BESS Battery Storage n/a 2 n/a(owned) Mar 2025 OR HB 2193(2015)
Rock River Wind Wind 50 n/a n/a(owned) Sep 2024 Repowering of existing site
Cedar Creek Wind Wind 151.8 n/a 2022 Mar 2024 2020 AS RFP
Anticline Wind Wind 190 n/a 2022 Dec 2024 2020 AS RFP
Boswell Wind Wind 100.5 n/a 2022 Dec 2024 2020 AS RFP
Cedar Springs Wind IV Wind 320 n/a 2022 Jan 2025 2020 AS RFP
Rock Creek Wind I Wind 350.4 n/a n/a(owned) Dec 2024 2020 AS RFP
Rock Creek Wind II Wind 400 n/a n/a(owned) Sep 2025 2020 AS RFP
Green River Energy Center Solar+Battery 400 400 2022 May 2026 2020 AS RFP:amended to increase
storage capacity in 2023
Faraday Solar and Storage Solar+Battery 525 150 2023 Sep 2025 Customer program:UT Sch 34
Homshadow Solar Solar 300 n/a 2023 Jun 2025 Customer program:OR Sch 272
Dominguez Grid Battery Storage n/a 200 2024 Jun 2026 Negotiated after 2022 AS RFP
Enterprise Storage Battery Storage n/a 80 2024 Jun 2026 Negotiated after 2022 AS RFP
Escalante BESS Battery Storage n/a 80 2024 Jun 2026 Negotiated after 2022 AS RFP
Granite Mountain BESS East Battery Storage n/a 80 2024 Jun 2026 Negotiated after 2022 AS RFP
Iron Springs BESS Battery Storage n/a 80 2024 Jun 2026 Negotiated after 2022 AS RFP
Oregon Comm.Solar(aggregate) Solar 38.8 n/a various various Oregon Community Solar Program
Total 3,301 1,072
PacifiCorp issued and will issue multiple requests for proposals (RFP) to secure resources or
transact on various energy and environmental attribute products. Table 3.7 summarizes recent RFP
activities.
Table 3.7-PacifiCor 's Requests for Proposal Activity
RFP RFP Objective Status Issued Completed
Renewable energy credits(Purchase) Excess system Ongoing Based on Ongoing
RECs specific need
Renewable energy credits(Purchase) California Ongoing Based on Ongoing
compliance needs specific need
Short-term Market(Sales) System balancing Ongoing Based on Ongoing
specific need
Seeking resources
consistent to the Expected Expected
2024 Utah Renewables Community RFP Community Clean Ongoing November October
Energy Act(Utah 2024 2025
Code 54-17-901 to-
909
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PACIFICORP—2025 IRP CHAPTER 3—PLANNING ENVIRONMENT
2022 All-Source REP
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).
2025 All-Source RFP
PacifiCorp will seek to file the 2025 All Source REP ("2025AS REP") 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,26 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.
26 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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PACIEICORP—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:I
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 Jr
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:
' 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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PACIEICORP-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(GATT).
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.
2 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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PACIEICORP-2025 IRP 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 - 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 * Shirley Basin
Wyoming. Anticline 0.
Br Aeolus
_ ��,= ,
• D2A single-circuit 500-kV line
completed October 2020 and energized November 2020.
• D3A 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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PACIEICORP—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 O A I E W A r W PacifiCorp to more efficiently dispatch system resources,
Midpoint improve performance of the transmission system (i.e.,
E Borah reduce line losses), improve reliability, and enable access
Cedar Hil Populu: to a diverse range of new resource alternatives over the
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(132H) 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
83

PACIEICORP-2025 IRP CHAPTER 4-TRANSMISSION
132H 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
84

PACIEICORP-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 PIa
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
85

PACIEICORP—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:
Report suggest that well-
• Bridger system expansion is like considered transmission
Gateway West. accessupgrades, capable of lower giving LSEs
o Southeast Idaho to southwest Utahst
greater . 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 like natural gasprices.
Energy Gateway Segment H
alternatives.
• Western Governors' Association Transmission Task Force Report
Examined the transmission needed to
deliver the largely remote generation F The Task Force observes
resources contemplated by the Clean and continuetransmission
Diversified Energy Advisory Committee. ' provide
This effort built upon the transmission value even as - •
rk
previously modeled by the Seams Steering conditions change. For transmission originally .example,to
Group-Western Interconnection and L6,
the site of a now obsolete
included transmission necessary to support a power plant continues to be
range of resource scenarios, including high used since a new power plant is
efficiency, high renewables and high often constructed
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 "After analyzing_ _ steady-state
_stressed of
Gateway (both Gateway West andone cas_ .
Gateway South) were listed as necessary toorous
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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PACIEICORP—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 ••- most
insight into where congestion is occurring and heavily loaded WECC path in the
assess the cost of that congestion. The Energy Usage ' '
ath is
Gateway segments were included in the analyses7currentl interest of _r of •ue to the
requests
that support these studies, alleviating several high
transmission service . 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
s http://www.oatioasis.com/ppw/index.html
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PACIEICORP-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 more than 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 memorandums of understanding (MOU) to explore potential joint-
development opportunities with Idaho Power Company on its Boardman-to-Hemingway (B2H)
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 balancing
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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 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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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 D1, 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
VI A. SHINGT0N
411
M O N TA N A
McNary ,--.., Wallula
Boardman •`'"y
OGON \ IDAHO
s _ C A 7[W A
HertiinEway —�_Y W E s T W Y O M I N G
Midpoint
Captain)axis 0 Borah D,� SAiey WiA ley B
� Basin
cedar Hill Populus r Aeolus
Anticline D.:
<.g
r I Terminal `r
CALIFORNIA cuuee �li Oquirrh so`�
o u l i Cl F Py
NEVADA Mona 6��
COLORADO
PacihCorp retail service area 5isued
New transmission lines. ��� U I -i
500 kV minimum voltage Red Butte
345 kV minimum voltage
230 kV minimum voltage
• Existing substation
O New substation
A R I Z 0 N A NEW MEXICO
� J
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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PACIEICORP—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 • Placed in-service:May 2013
• Status:right-of-way acquisition underway
Oquirrh-Terminal 345 kV double circuit 14 mi , Scheduled in-service:2024
(DI) New 230 kV single circuit • Status:permitting underway
Windstar-Aeolus Re-built 230 kV single 59 mi . Scheduled in-service:December 2024
circuit
(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
J,fforts to Maximize Existing System Capa
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
nouhbound 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.
4 http://www.caiso.com/Documents/EDAM-Fact-Sheet.pdf
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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 PI
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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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 a line 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 P1 (N-1)
contingency events for the loss of the Treasureton—Franklin 138 kV line.
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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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PACIFICORP-2025 IRP CHAPTER 5-RELIABILITY AND RESILIENCY
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.
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 history 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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PACIFICORP—2025 IRP CHAPTER 5—RELIABILITY AND RESILIENCY
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. 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 Summary
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 Medium 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 Medium 10-49 hours Low <10 hours
' WECC.Western Assessment of Resource Adequacy 2024.Available online:htWs:Hfeature.wecc.or /g wara/
(accessed 12/18/2024)
2 WECC.WARA 2024 Demand-at-Risk Hours by Subregion.Available online at:htt2s://www.wecc.org/wecc-
document/17071 (Accessed 12/18/2024)
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PACIFICORP-2025 IRP CHAPTER 5-RELIABILITY AND RESILIENCY
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 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 because 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 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 increase 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.
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NERC Long-Term Reliability Assessment (LTRA)
Resources
As part of the regional reliability assessment to support the 2025 IRP, PacifiCorp reviewed and
incorporated leamings from the NERC LTRA, published in December 2024.3 The NERC LTRA
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 Subregion 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.
3 NERC.2024 Long-Term Reliability Assessment.December 2024.Available online at:
hllps://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%20Term%2OReliabili . %20
Assessment 2024.pdf(accessed 12/18/2024)
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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%- 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% 14.7% 14.5% 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�:
Prospective Reserve Margin(%) 38.6% 40.1% 38.2% 31.1% 26.7% 20.4% 16.80/c 9.2% 4.9% 0.04:
Reference Margin Level(5�) 11.0% 10.8% 12.0% 11.7% 10.2% 10.1% 9.9% 9.71.o 19.8", 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(q,) 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 these metrics. The 2029 Adequacy Assessment is based on the
2021 Northwest Power Plan, discussed below, with updates for expected changes through 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
4 Northwest Power and Conservation Council.Pacific Northwest Power Supply Adequacy Assessment for 2029.
August 2024.Available online at:https://www.nwcouncil.or,g/fs/18853/2024-4.pdf(accessed 12/18/2024)
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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 EnergyVaR97.5 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. 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 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, and resource-
specific performance. For example, wind and solar contributions incorporate a resource's output
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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).
If a WRAP Participant chooses to exit the program,a two-year exit period applies. Current WRAP
Participants have until October 31 st,2025,to exit the program without being subject to a financially
binding season.
PacifiCorp is currently participating in WRAP and is working with the Western Power Pool to
address 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 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 I't 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
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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
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
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may be more representative of future conditions than earlier conditions. As a result,reliability and
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 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. 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
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modify runoff patterns impacting hydro generation but is not expected to impact dam safety at
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.5 Some broad impacts anticipated from climate change are noted below:6
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.
5 Climate change impacts on the energy system: a review of trends and gaps.Cronin,J.,Anandarajah,G.&Dessens,
0. 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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• Rising sea levels: could damage offshore wind farm infrastructure.
Solar Energy
• Changes in mean temperatures: increased global temperatures could reduce cell
efficiency.
• Changes in solar irradiation, dirt, snow,precipitation: 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.
ildfire Risk Mitigati
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.7
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.
Irransmission-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 several 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.
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PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Introduction
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
summarized in Appendix A (Load Forecast). 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
annual growth rate (CAGR) of 1.67 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 1 2034
11,318 11,270 11,425 11,553 11,690 11,844 12,104 12,193 12,363 12,575
2035 2036 2037 2038 2039 2040 2041 2042 2043
Syste 12,819 13,134 13,404 13,693 13,978 14,279 14,581 15,008 15,237 15,518
Existing Resource
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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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Table 6.2 — Coal-Fired Plants
PacifiCorp Nameplate
Plant Percentage State Capacity End of Coal-fired Operation
Share (%) rnBV)
Cols
3 10 Montana 74 2025 (Transfer capacity to unit 4)
Colstrip 4 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 Wyonning 99 2028 (Gas conversion option)
Dave Johnston 2 100 Wyoming 106 2028 (Gas conversion option)
Dave Johnston 3 100 Wyoming 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
Jim Bridger 4 67 Wyoming 351
Naughton 1 100 Wyoming 156 2025 (Gas conversion option)
Naughton 2 100 Wyoming 201 2025 (Gas conversion option)
Wyodak So Wyoming 268
TOTAL—Coal 4,533
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PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
*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 State 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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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
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 ill
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 11 WY 20
TB Flats 1-2 WY 500
Foote Creek 114V 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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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
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 -
Ore on 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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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Table 6.7—Solar Qualifying Facilities, Oregon
Oregon Qualifying Facilities
Resource Solar Capacity(MVO Storage Capacity(MVO
7 We Solar 1 -
Adams 10 -
Antelope Creek Solar 2 -
Bear Creek 10 -
Black Cap lI 8 -
Blackwell Creek Solar* 1 -
Bly 8 -
Buckaroo Solar 1* 3 -
Buckaroo Solar 2* 3 -
Can onville Solar I* 1 -
Can onville Solar 2* 2 -
Chapman Creek Solar* 3 -
Cherry Creek Solar* 0.4 -
Chiloquin Solar 10 -
Elbe 10 -
Goodling Conmufity Solar* 1 -
Green Solar* 3 -
Hay Creek Solar* 0.6 -
Klarmth Falls Solar 1 0.8 -
Klamath Falls Solar 2 3 -
Linkville Solar* 3 -
Merrill 10 -
Norwest Energy 2(Ne 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 Hill) 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 -
Hot Rock Solar 2* 3 -
Pine Grove Solar 1 -
Round Lake Solar 1 -
Skysol 55 -
Solorize Rogue* 0.1 -
Sunset Ridge Solar 2 -
Tumbleweed 10 -
Tutuiilla Solar* 2 -
Wallowa Coup 0.4 -
Wbisky 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 -
Buckhom 3 -
CedarValle 3 -
Enterprise 80 -
Escalante I 80 -
Escalante II 80 -
Escalante III 80 -
Ewauna 1 -
Ewauna R 3 -
Granite Mountain-East 80 -
Granite Mountain-West 50
GranitePeak 3 -
GreenAle 2 -
Iron Springs 80 -
Laho 3 -
Milford 2 3
Milford Flat 3
Pavant 50 -
Pavant II 50 -
Quichapa I 3
Quichapa II 3
Quichapa III 3
Red Hill 80
South Wford 3
SunEI 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)
Sage I 20 Sage II 20 Sage III 18 -
Sweetwater 80 -
TOTAL—Wyoming Wyondng 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.
Biomass/Biogas
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 Appendix L (Distributed Generation Study).
Table 6.10—Distributed generation Customers and Ca aci
FuelI= Solar Wind Gas' Hydro Mixed'
Nameplate(kW) 772,160 847 784 965 1,233
Capacity(percentage of total) 99.51% 0.11% 0.10% 0.12% 0.16%
Number of customers 86,449 192 3 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
Dominguez 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
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
can include flexible generation, spinning reserves, and voltage control. PacifiCorp-owned
hydroelectric plants are in California,Idaho,Montana, Oregon,Washington,Wyoming, and Utah.
The amount of electricity available from hydroelectric plants is dependent upon several 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 Other UT 20.5
West-Owned
NONE-
Bend Other OR 1
Big Fork Other MT 4.6
Swift 1 2i 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
Qualifting Facilities F
F Various CA 9.4
F Various ID 22.7
F Various OR 40
F Various UT 2.2
F Various WA 2.9
Mid-Columbia JColurnbia WA 170
Total QF 247
Total Hydroelectric off F 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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PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
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-out 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.
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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. Like 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, PacifiCorp 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 Appendix D (Demand-Side Management Resources).
'The historical effects of previous energy efficiency savings are captured in the load forecast before the modeling for
new energy efficiency.
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PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Table 6.13 —Existing DSM Resource Summary
Program Energy Savings or Included as
Description Capacity at Generator Existing Resources for
2025-2045 Period
Residential/small
commercial air 135 MW summery 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(<I 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)Z 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.
I 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(Public Utility Commission of Oregon).
See Appendix M,stakeholder feedback form#26(Vote Solar).
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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 do. i 00
O y
Q 3,000 00
i
2,500 i
2,000
i6
1,500
E
v 1,000
500
0
�Oo �i 0C l^ l I l5 ti� l� l�O ti� ti� l°' gQ 1` 3I 3� 3� �� 30 gA 3b �-I ,z R^ �l .5
�O l f 1O 1 O 10 �O 1 O 1 O �O �O 1 O 1 O _O 1 O LO �O �O �O �O 4O 4O 'O ro 'f �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.
127

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 '
600 - - - -
'iiiii iiii fill
400 -
200
111 1 iiiiiiiiiiiiiiiii
iiii 1111 MUM 111111111111111111111111111......11111111111111111111
oti oti�O oti^ oti� oti� o'�° o'�� o o o o o o°�'
ti ti ti " ti ti ti ti ti ti ti ti ti ti ti ti ti ti ' ti ti
:WS:ale �PMVIM��C Qualifying Facilities iHydro
ind Solar Demand Response +Net Position
Capacity Load and Resource Balance
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 use 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).
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
128

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
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 economic 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 currently. 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
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 and 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
129

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
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)
zo�� 20�6 202� zo?� 2029 zo3o 2o3r 20�2 zo3� 2o�F ro3� 2036 20�� zo38 2039 2�o z�r 2�2 2oF� 2� z�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.
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:
130

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
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 renewable, or other line items.
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#12(Utah Association of Energy Users).
131

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.14 -- Summer Peak-System Capacity Loads and Resources without Resource
Additions
2025 2026 2027 2030 2031 203,
Coal 3,960 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 3,294 3,469 3,469 3,469 3,469 3,469 3,469
Hydroelectric 76 76 76 76 76 76 76 76 76 76
Wind 587 613 596 578 561 534 503 487 470 453
Solar 342 499 487 475 463 452 440 428 416 404
Other Renewable 46 45 44 42 41 40 39 37 36 35
Storage 1 939 925 909 894 879 865 849 834 819
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 405 394 383 372 361 351 340 328 314 301
Demand Response 451 446 440 452 450 443 429 423 431 425
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (274) (1,440) (1,361) (1,096) (902) (631) (476) (421) (380) (277)
Fast ID fisting Resources 8,578 8,433 8,452 8,479 8,504 8,540 8,611 8,603 8,592 8,632
Load 7,746 7,655 7,781 7,919 8,068 8,234 8,447 8,609 8,528 8,700
Distributed Generation (157) (143) (186) (234) (285) (341) (400) (458) (321) (354)
Energy Efficiency (91) (141) (206) (274) (349) (428) (520) (631) (696) (801)
Fast Total obligation 7,498 7,372 7,388 7,412 7,433 7,465 7,527 7,520 7,511 7,545
Planning Reserve Margin(14.4%) 1,080 1,062 1,064 1,067 1,070 1,075 1,084 1,083 1,082 1,087
Fast Obligation+Reserves 8,578 8,433 8,452 8,479 8,504 8,540 8,611 8,603 8,592 8,632
Fast Position 0 0 0 0 0 0 0 0 0 0
Available Market Purchases 500 500 500 0 0 0 0 0 0 0
Coal 133 133 133 133 133 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 74 72 70 67 65 63 61 59 57 54
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 232 226 215 209 200 194 187 179 174 170
Demand Response 60 59 58 57 57 56 55 54 54 53
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 274 1,440 1,361 1,096 902 631 476 421 380 277
West Ddsting Resources 2,271 3,426 3,330 3,054 2,846 2,431 2,260 2,192 2,141 2,028
Load 3,778 3,812 3,905 3,967 4,032 4,103 4,239 4,255 4,288 4,376
Distributed Generation (49) (54) (75) (99) (124) (152) (182) (213) (132) (148)
Energy Efficiency (67) (94) (135) (178) (220) (263) (318) (359) (389) (431)
West Total obligation 3,662 3,664 3,695 3,690 3,688 3,688 3,738 3,684 3,767 3,798
Planning Reserve Margin(14.4%) 527 528 532 531 531 531 538 530 542 547
West Obligation+Reserves 4,189 4,192 4,227 4,222 4,219 4,219 4,277 4,214 4,309 4,345
West Position (1,918) (766) (898) (1,168) (1,373) (1,788) (2,010 (2,022) (2,168) (2,317)
Available Market Purchases 2,603 2,603 2,603 0 0 0 0 0 0 0
Total Resources 10,849 11,859 11,782 11,533 11,349 10,971 10,871 10,795 10,734 10,660
Obligation 11,160 11,036 11,084 11,102 11,121 11,153 11,265 11,203 11,278 11,343
Planning Reserves(14.4%) 1,607 1,589 1,596 1,599 1,601 1,606 1,622 1,613 1,624 1,633
Obligation+Reserves 12,767 12,625 12,680 12,701 12,723 12,759 12,887 12,817 12,902 12,977
System Position (1,918) (766) (898) (1,168) (1,373) (1,788) (2,016) (2,022) (2,168) (2,317)
Available Market Purchases 3,103 3,103 3,103 0 0 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 1,918 766 898 0 0 0 0 0 0 0
NetSurplus/(Deficit) 0 0 0 (1,168) (1,373) (1,788) (2,016) (2,022) (2,168) (2,317)
132

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 2,432 2,432 2,432
Gas 3,469 3,469 3,469 3,469 3,469 3,469 3,469 3,469 3,322 3,322 3,322
Hydroelectric 76 76 76 76 76 76 76 76 76 76 76
Wind 437 421 404 387 371 355 308 293 278 263 249
Solar 392 381 340 329 319 308 297 286 276 243 233
Other Renewable 33 32 31 12 11 10 10 9 9 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 291 269 221 212 203 192 184 176 169 162 155
Demand Response 422 401 402 398 400 406 398 375 376 389 351
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers (161) 0 0 0 0 0 0 0 0 0 0
East Existing Resources 8,690 8,763 8,643 8,569 8,519 8,472 8,383 8,310 7,622 7,564 7,472
Load 8,893 9,150 9,349 9,567 9,774 9,993 10,214 10,478 10,693 10,891 11,097
Distributed Generation (385) (415) (445) (474) (503) (529) (557) (584) (609) (635) (660)
Energy Efficiency (911) (983) (1,112) (1,227) (1,325) (1,407) (1,501) (1,482) (1,547) (1,570) (1,588)
Fast Total obligation 7,596 7,752 7,792 7,865 7,946 8,057 8,156 8,413 8,536 8,686 8,848
Planning Reserve Margin(14.4%) 1,094 1,116 1,122 1,133 1,144 1,160 1,174 1,211 1,229 1,251 1,274
Fast Obligation+Reserves 8,690 8,869 8,914 8,998 9,090 9,217 9,330 9,624 9,766 9,937 10,123
Fast Position 0 (105) (271) (429) (571) (745) (947) (1,314) (2,144) (2,373) (2,650)
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 52 50 48 46 44 41 39 37 35 33 31
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 165 160 142 138 132 128 124 120 101 97 95
Demand Response 52 51 51 50 49 48 48 47 46 45 44
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers 161 0 0 0 0 0 0 0 0 0 0
West Existing Resources 1,902 1,731 1,708 1,700 1,689 1,681 1,651 1,644 1,621 1,613 1,608
Load 4,475 4,577 4,692 4,807 4,927 5,049 5,173 5,376 5,430 5,553 5,680
Distributed Generation (163) (177) (192) (206) (221) (234) (249) (263) (277) (290) (304)
New Energy Efficiency (471) (515) (571) (603) (634) (661) (691) (774) (591) (599) (612)
West Total obligation 3,841 3,885 3,929 3,998 4,073 4,154 4,233 4,340 4,562 4,663 4,764
Planning Reserve Margin(14.4%) 553 559 566 576 586 598 609 625 657 671 686
West Obligation+Res erves 4,394 4,444 4,495 4,574 4,659 4,752 4,842 4,965 5,219 5,334 5,450
West Position (2,492) (2,713) (2,787) (2,874) (2,970) (3,072) (3,191) (3,321) (3,598) (3,721) (3,842)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Total Resources 10,592 10,494 10,351 10,269 10,209 10,152 10,034 9,954 9,243 9,178 9,080
Obligation 11,438 11,637 11,721 11,863 12,019 12,211 12,388 12,753 13,099 13,349 13,612
Planning Reserves(14.4%) 1,647 1,676 1,688 1,708 1,731 1,758 1,784 1,836 1,886 1,922 1,960
Obligation+Res erves 13,085 13,313 13,409 13,572 13,750 13,969 14,172 14,589 14,985 15,272 15,573
System Position (2,492) (2,818) (3,058) (3,303) (3,541) (3,817) (4,138) (4,635) (5,742) (6,094) (6,493)
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) (2,492) (2,818) (3,058) (3,303) (3,541) (3,817) (4,138) (4,635) (5,742) (6,094) (6,493)
133

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.15-Winter Peak System Capacity Loads and Resources without
Resource Additions
2025 2026 2027 2030 2031 2032
Coal 4,147 3,734 3,734 3,499 3,185 3,015 3,015 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 1,837 1,957 1,892 1,829 1,766 1,657 1,523 1,463 1,404 1,346
Solar 38 104 101 98 95 92 89 85 82 79
Other Renewable 41 39 38 37 35 34 33 32 30 29
Storage 1 621 606 591 576 561 546 531 516 500
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 186 181 176 171 166 161 156 149 140 124
Demand Response 119 118 118 128 129 128 121 120 128 127
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (1,600) (1,600) (1,600) (1,600) (1,600) (1,600) (1,600) (1,585) (1,353) (1,118)
East Ddsting Resources 7,804 8,523 8,433 8,120 7,911 7,608 7,442 7,369 7,522 7,662
Load 5,898 5,911 6,036 6,164 6,278 6,408 6,569 6,706 6,899 7,084
Distributed Generation (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Energy Efficiency (75) (118) (157) (197) (239) (283) (331) (388) (450) (513)
Fast Total obligation 5,821 5,790 5,876 5,963 6,033 6,119 6,231 6,309 6,440 6,560
Planning Reserve Margin(16.8%) 978 973 987 1,002 1,014 1,028 1,047 1,060 1,082 1,102
Fast Obligation+Res erves 6,799 6,763 6,863 6,964 7,047 7,147 7,278 7,369 7,522 7,662
Fast Position 1,005 1,760 1,570 1,156 864 461 164 0 0 0
Available Market Purchases 500 500 500 0 0 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 62 59 57 55 53 51 49 47 45
Solar 1 1 1 1 1 1 0 0 0 0
Other Renewable 0 0 0 0 0 0 0 0 0 0
Storage 2 2 2 2 2 2 2 2 2 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 70 69 62 61 58 57 57 56 56 56
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 1,600 1,600 1,600 1,585 1,353 1,118
West Existing Resources 3,345 3,342 3,333 3,330 3,325 3,174 3,171 3,153 2,919 2,679
Load 3,511 3,571 3,640 3,701 3,741 3,805 3,904 3,981 4,068 4,160
Distributed Generation (0) (0) (1) (1) (1) (1) (1) (2) (2) (2)
Energy Efficiency (52) (65) (118) (173) (229) (286) (345) (401) (457) (511)
West Total obligation 3,459 3,506 3,521 3,527 3,511 3,517 3,558 3,578 3,609 3,647
Planning Reserve Margin(16.8%) 581 589 591 593 590 591 598 601 606 613
West Obligation+Reserves 4,041 4,095 4,112 4,120 4,101 4,108 4,156 4,180 4,215 4,259
West Position (696) (753) (780) (790) (776) (934) (985) (1,027) (1,297) (1,581)
Available Market Purchases 2,603 2,603 2,603 0 0 0 0 0 0 0
Total Resources 11,149 11,865 11,766 11,450 11,235 10,783 10,613 10,522 10,441 10,341
Obligation 9,281 9,296 9,397 9,490 9,544 9,636 9,789 9,888 10,049 10,207
Planning Reserves(16.8%) 1,336 1,339 1,353 1,367 1,374 1,388 1,410 1,424 1,447 1,470
Obligation+Reserves 10,617 10,635 10,750 10,857 10,918 11,024 11,199 11,312 11,497 11,677
System Position 532 1,230 1,016 594 317 (241) (586) (789) (1,056) (1,336)
Available Market Purchases 3,103 3,103 3,103 0 0 0 0 0 0 0
Uncommitted FOTs to meet remaining Need 0 0 0 0 0 0 0 0 0 0
Net Surplus/(Deficit) 532 1,230 1,016 594 317 (241) (586) (789) (1,056) (1,336)
134

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Table 6.15 (cont.)-Winter Peak System Capacity Loads and Resources without
Resource Additions
V& z� A; 2043
Coal 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 2,503 2,503 2,503
Gas 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,378 3,378 3,378
Hydroelectric 33 33 33 33 33 33 33 33 33 33 33
Wind 1,285 1,226 1,168 1,107 1,049 990 850 797 744 689 636
Solar 76 73 70 67 64 61 58 55 52 42 39
Other Renewable 28 26 25 9 8 8 7 7 6 6 0
Storage 485 470 455 440 425 410 395 379 365 350 334
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 120 112 99 94 90 86 82 78 75 71 67
Demand Response 128 117 121 121 125 132 129 117 121 132 109
Sale 0 0 0 0 0 0 0 0 0 0 0
Transfers (919) (674) (414) (137) 0 0 0 0 0 0 0
East Existing Resources 7,778 7,925 8,097 8,275 8,336 8,262 8,096 8,008 7,276 7,204 7,101
Load 7,248 7,421 7,645 7,863 8,087 8,287 8,466 8,705 8,909 9,134 9,224
Distributed Generation (11) (11) (12) (13) (13) (14) (14) (14) (15) (15) (16)
Energy Efficiency (579) (624) (700) (766) (826) (886) (954) (973) (1,022) (1,049) (1,077)
East Total obligation 6,659 6,786 6,932 7,084 7,248 7,387 7,498 7,717 7,872 8,070 8,131
Planning Reserve Margin(16.8%) 959 977 998 1,020 1,044 1,064 1,080 1,111 1,134 1,162 1,171
Fast Obligation+Reserves 7,618 7,763 7,931 8,105 8,292 8,451 8,578 8,828 9,005 9,232 9,302
East Position 160 163 166 170 44 (189) (482) (820) (1,729) (2,028) (2,201)
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 42 40 38 36 34 32 30 28 25 23 21
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 54 53 53 51 51 50 50 50 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
Transfers 919 674 414 137 0 0 0 0 0 0 0
West Existing Resources 2,478 2,229 1,967 1,687 1,546 1,544 1,541 1,539 1,536 1,534 1,531
Load 4,232 4,334 4,471 4,605 4,720 4,832 4,959 5,143 5,253 5,374 5,365
Distributed Generation (2) (3) (3) (3) (3) (3) (3) (4) (4) (4) (4)
Energy Efficiency (568) (624) (668) (714) (760) (819) (858) (900) (786) (803) (826)
West Total obligation 3,662 3,707 3,800 3,888 3,957 4,010 4,097 4,239 4,463 4,567 4,535
Planning Reserve Margin(16.8%) 615 623 638 653 665 674 688 712 750 767 762
West Obligation+Reserves 4,277 4,330 4,438 4,541 4,622 4,684 4,786 4,952 5,212 5,334 5,297
West Position (1,799) (2,100) (2,471) (2,854) (3,075) (3,140) (3,245) (3,413) (3,676) (3,801) (3,766)
Available Market Purchases 0 0 0 0 0 0 0 0 0 0 0
Total Resources 10,255 10,155 10,064 9,962 9,882 9,806 9,637 9,547 8,812 8,737 8,632
Obligation 10,321 10,493 10,732 10,973 11,205 11,398 11,596 11,957 12,334 12,637 12,666
Planning Reserves(16.8%) 1,486 1,511 1,545 1,580 1,614 1,641 1,670 1,722 1,776 1,820 1,824
Obligation+Res erves 11,807 12,003 12,278 12,553 12,819 13,039 13,265 13,678 14,110 14,456 14,490
System Position (1,552) (1,849) (2,214) (2,591) (2,937) (3,233) (3,628) (4,132) (5,298) (5,719) (5,858)
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) (1,552) (1,849) (2,214) (2,591) (2,937) (3,233) (3,628) (4,132) (5,298) (5,719) (5,858)
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
135

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
to meet capacity needs. The market availability assumptions used for portfolio modeling are
discussed further in Chapter 7 (Resource Options).
Figure 6.4—Summer System Capacity Position Trend
16,000
14,000
12,000 14.4%Reserves
10,000
y
C�
8,000
6,000 East Existing Resources
4,000
2,000
West Existing Resources
0
West Existing Resources East Existing Resources
Uncommitted FOTs to meet remaining Need tObligation+Reserves
f Obligation
136

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
Figure 6.5—Winter System Capacity Position Trend
16,000
14,000
12,000 ■
■
r—■—J
10,000 16.8%Re
8,000
an
6,000
East Existing Resources
4,000
2,000
West Existing Resources
0
41
—West Existing Resources East Existing Resources
—Uncommitted FOTs to meet remaining Need t Obligation+Reserves
--*—Obligation
137

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Figure 6.6—East Summer Capacity Position Trend
11,000
10,000
9,000
8,000 14.4%Reserves {
7,000
w 6,000
5,000 East Existing Resources
4,000
3,000
2,000
1,000
0
East Existing Resources East-Uncommitted FOTs to meet remaining Need
(East Obligation+Reserves (East Total obligation
138

PACIFICORP—2025 IRP CHAPTER 6—LOAD AND RESOURCE BALANCE
Figure 6.7 —West Summer Capacity Position Trend
11,000
10,000
9,000
8,000
7,000
6,000
3 5,000
14.4%Reserves
4,000 1
3,000
2,000
West Existing Resources
1,000
0
West Existing Resources West-Uncommitted FOTs to meet remaining need
t West Obligation+Reserves ——West Total obligation
139

PACIFICORP-2025 IRP CHAPTER 6-LOAD AND RESOURCE BALANCE
140

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 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.
• PLEXOS 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.
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.
'https:Hatb.nrel.gov/electricity/2024/index
141

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
Supply-Side Resources
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
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 supply-side resource 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 supply-side resource 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, &2xl.
■ 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
• 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
z https:Hatb.nrel.gov/electricity/2024/definitions#scenarios
s https:Hatb.nrel.gov/electricity/2024/definitions#scenarios
142

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
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)
o Adjustments for advanced technology innovation scenario.
• Nuclear'
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 supply-side resource table, 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 20207 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.
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).
s 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 AE02020.pdf
143

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
Most of the supply-side resource options rely on the ATB and EIA reports. Some resources
contained in the supply-side resource table are not listed in the ATB, but were developed through
other reports, 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:'
• 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.
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
144

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
• 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
report), "2022 Grid Energy Storage Technology Cost and Performance Assessment,"" and the
Hydrogen and Fuel Cell Technologies Office's "Multi-Year Program Plan."I2
• 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.14
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:15
• 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.
10 https:Hliftoff.energy.gov/
11 https://www.energy.gov/sites/default/files/2022-
09/2022%20Grid%20Energy%20 Storage%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/19009_h2 production cost pem_electrolysi
s 2019.pdVStatus=Master
14 See Appendix M,stakeholder feedback form#49(Utah Association of Energy Users).
15 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,LLC).
145

PACIFICORP-2025 IRP CHAPTER 7—RESOURCE OPTIONS
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
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.16 For solar, hourly
solar irradiance and weather data was extracted from a Vaisala satellite irradiance dataset" and
configured in a PVMyst model18 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.19
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).
Natrium Demonstration Project
PacifiCorp's 2025 IRP includes the Natrium® advanced nuclear demonstration project: an 840
megawatt thermal pool-type sodium fast reactor that contains a compact and simple safety
envelope and a molten salt energy storage system which enables the plant to vary its supply of
energy to the grid, up to 500 megawatts electric net, providing both firm and flexible emissions-
free energy. The reactor operates near atmospheric pressure, circulating sodium through its core
16 European Centre for Medium-Range Weather Forecasts.https://www.ecmwf int/en/forecasts/dataset/ecmwf-
reanalysis-v5
1'Vaisala.https://www.vaisala.com/
18 Myst.https://www.pvsyst.com/
"Bureau of Ocean Energy Management.https://www.boem.gov/renewable-energy/state-activities/Oregon
146

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
with pumps. The design includes reliable inherent and passive safety features including near
atmospheric operating pressures, always-on passive air cooling and inherent reactivity feedback.
At this time, the specific cost and performance assumptions for the Natrium® advanced nuclear
demonstration project are confidential and are not summarized in the supply-side resource table.
TerraPower and PacifiCorp remain committed to bringing the Natrium technology to market to
enhance the company's ability to serve its customers, meet growing demand and ensure a reliable
and resilient energy future. PacifiCorp is also committed to protecting customers from first-of-a-
kind (FORK) technology risk and FOAK program and construction costs. The Company is
implementing an innovative commercial energy acquisition structure that allows Natrium benefits
to flow to customers while ensuring those customers are not burdened with FOAK technology cost
and risk. This commercial structure is in the final stages of development and the details are
confidential at this time.
The Natrium advanced nuclear demonstration project has been named Kemmerer Power Station
Unit 1 (KU1)which is planned to be built near the Naughton Power Plant. KU1 is currently in the
design and licensing phase. TerraPower submitted the Construction Permit Application to the US
Nuclear Regulatory Commission (US NRC) in March 2024. The US NRC has published their
review schedule and anticipates the Preliminary Safety Analysis Report and Environmental Report
to be approved by August 2026, and the Construction Permit Application to be approved by
December 2026. This approval will allow the beginning of construction of the Nuclear Island. An
Operating License is also required. TerraPower anticipates the Operating License Application to
be submitted in September 2027 and achieving commercial operations the fall of 2031.
On June 10, 2024, TerraPower broke ground for the Natrium reactor demonstration project with
construction of the sodium test and fill facility commencing first. On January 14, 2025, the State
of Wyoming Industrial Siting Council (ISC) approved TerraPower's permit for construction and
operational activities on the Natrium plant that are not under jurisdiction of the US NRC. This
approval allows for the construction of non-nuclear facilities, including the energy island portion
of the Natrium plant that houses the molten salt energy storage tanks and turbines.
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 supply-side resource 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 EIA20 report are applied in PLEXOS. Total resource cost
attributes for supply-side resource options are based on estimates of the first-year, real-levelized
20 https://www.eia. ovg /analysis/studies/powen2lants/capitalcost/pdf/capital cost AE02025.pdf
147

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
costs for resources, stated in June 2024 dollars.21,22 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
m�Kdditional Attributes and Variable O&M, Total Cost and
Fixed 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 supply-side resource table 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).
22 The supply-side resource table was made publicly available during the 2025 IRP public input meeting series and
discussed extensively as it developed.https://www.pacificorp.com/energy/inte,grated-resource-plan/support.html
148

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.2 -2025 Thermal Supply-Side Resources, Characteristics and Costs (2024$)
cbanete'ties casts
Fnctio.V.,
O&M
Net Resource Tab] asset Base Fra<tbn t'ar Adi-W by Fraction Fined
Elevation Capacity A-iabtTty h plet.e.btie. '1 Life Capital \'ar O&\1 O&V Capaciry _ad O&\I O&\I De.aitio.
F.el R..00rrc De.rri tioo (-4FSL) ('%M Year Tv ) ()-) (SlkR) (S/$1\41) cn.'.Paed C1.... (SIM- 1 CapitaSred Coat(S1kS1�
;'-fuel 1-xa1 CombustoaEg;w,rmrwebkbiofisel,with SCRS_J how fuel tanL 0 20 1 2025 2.5 2027 a 30 52,131 $6.93 -11, 91°. 1 S42.82 3'. $14.59
Natarat Gaz SCCT A-o with SCR 0 SO 2025 35 2028 40 $2,613 $7.40 I 87°. 99% $12.42 3% $32.46
\-.1 Gas SCCT Aero x4,with SCR 0 211 2025 3.5 2028 40 T1,789 ! $5.92 1 87o. 98% $9.93 3% S32.46
N seat Gas SCCT Frame-F.1.with SCR 0 233 2025 5.0 2030 40 $1.387 j S7.75 j 100 99% $27.92 j 3% S12.13
Nunnat Gas CCCT Dry'H-,iXl,DF,with SCR 0 649 2025 5.0 1 2030 ! 40 51,839 52.70 0°. 100% $
42.44 f 0% 512.06
N._ Gas CCCT -1r,2X1,DF.with SCR 0 1,227 2025 5.0 ! 2030 40 21,553 52.28 0°. IOOSb $35.18 0% SI1.89
Nennal Gas CCCT Dry'Fr,M,DF,with SCR f adding 95%CCS w sees CCCT IxI 0 565 2025 5.0 2030 s +40 23,429 25.32 0°o IOOSo 577.07 OY. 565.26
Nanaal Gas CCCT 'H',2X1,DF,with SCR+A fa add'i g 95%CCS to rcw CCCT 2x1 0 ! 1085 2025 5.0 1 2030 ! +40 S2,846 ! $4.83 0. 100% Saw OX $65.09
Naaa.1 Gaz Irtemal Cambustias Engine,renewable bi,fi,L with SCR&24-hour fitel tank+A for CT Browat6ekl construction 0 20 2025 25 1 2027 30 S1.918 $6.24 1 74°. 1 91% $42.82 3% $14.59
Nanaat Gas SCCT A-o,with SCR for CT Brownfield conswctba 0 50 2025 3.5 1 2029 40 $2,352 S6.66 87°. 99% S12.42 3% S32.46
I
Nanaal Gas SCCT Aero x4,avth SCR+pfiu CT Brow�eld construction 0 ! 211 2025 3.5 1 2028 40 21,610 $5.33 87'. 99% S9.93 3% S32.46
Nanaal Gas SCCT Feame"F x1,with SCR+A for CT B--&Id coasnnction 0 1 233 2025 5.0 2030 40 $1.248 $698 100% I 99% $27.92 ) 3% $12.13
Nannat Gas CCCT Dry'FI',IXl,DF,with SCR+Afor CT Brownfield constr-ton 0 ! 619 2025 5.0 2030 40 $1,655 1 S2.13 07. 100% S42.44 0% $12.09
Natural Gaz CCCT -H%2X1,DF,with SCR+A for CT Browr�eld coeatruction 0 1.227 I 2025 S.0 2030 40 S1 39B 52.05 0°ii 100% 1 $33.18 1 0% $11.89
Natural Gas CCCT Dsy-1r.IXI,DF,with SCR+A far adding 957s CCS to new-CCCT 1x1+A fi.CT Bmw•ddd emsteoction 0 565 2025 5.0 2030 40 S3,086 j S4.78 1 OY. 100% $77.07 1 0% S65.28
N-1 Gas CCCT Dry W.2X1,DF,with SCR+A for adding 95^.CCS to now CCCT 2x1+A fee Cr Eno-field caosteactrna 0 I 1.085 2025 5.0 2030 40 S2,561 I S4.34 i 0% 100% $62.99 j 0% $65.08
Hydrogen SCCT Feme T'xL with SCR+Afor 100°..Idydrogm btmmg capabiiy 0 233 2023 5.0 2030 40 21,393 38.91 ! 100% 99% $27.92 3% $13.95
Hydrogen CCCT Dry'H',IXI,DF,with SCR+A fix 100°/.Hydrogen btanm¢capab3n 0 649 2025 5.0 1 2030 40 S2,115 S3.11 1 O% ]00% $42.44 0% $13.89
Hydrogm CCCT Dry DF.with SCR+A For1W/.Hydrogen bixnag-pkik, 0 L227 1 2025 5.0 2030 40 $1,786 $2.62 0% ]00% $35.18 0% $13.67
Hyckogm SCCT Fetme'F xL with SCR+A for Hydrogen storage,careen,80 ben,24 hone 0 233 2025 5.0 i 2030 40 $Z586 ! S8.18 i 100% 997E 535.12 3% $27.13
Hydrogen CCCT Thy'li',1X1,DF,with SCR+p f Hydrogen storage,caveen.BO bar,24 hors 0 ! 649 2023 3.0 130 40 Vfi38 ! S3.13 0% 100% S49.64 0% $27.09
H dr m CCCT 'H',2X1,DF,with SCR+A for H en s-a e,caveeo,80 bar,24 ho- 0 1,227 2023 5.0 203o 40 52,752 S2.70 0% 100% 1 542.38 0% $26.89
Hydrogen SCCr Feame"F al,with SCR+A for Hydrogen s-age,tanks,500 bar,24 ban 0 233 2025 5.0 1 2030 ! 40 T2,098 j S8.32 100% 99% S40.78 1 3% S27.13
Hydrogen CCCT Dry'FI',1X1,DF,with SCR+A for Hydrogen storage,bdcs,500 bar,24 horn 0 ! 649 2025 5.0 ! 2030 ! 40 $2,550 ! T3.27 0% I 100% $55.30 95e 527.06
H tr en CCCT 1T',2X1,DF,wtln SCR+p f H dro-s e,tacks,500 bar,24 hour 0 ! 1-227 2025 5.0 2030 40 S2,264 SIBS 1 0% 100% 548.04 � 0% $26.89
Nasal Gas CCCT Dry"Ir.1X1,DF,with SCR Adva-ed Tecboology Case+A adve aced techtnlogy case.CCCT 1x1 0 ! 649 i 2025 1 5.0 I 2030 +40 S1,832 j S2.68 1 0% 100% I S41.33 � 0% i $12.09
Normal Gas CCCT D y W.2X1,DF,with SCR,Advanced Techoobgy Case+A advanced technology case,CCCT 2,1 0 ! 1227 1 2025 I 5.0 I 2030 ! +40 S1,518 $2.23 j ! 0% 100% 534.07 I 07G $11.89
Nauat Gas CCCT Dry'F1',1XL DF,with SCR,Advmeed Technology Case+A edvaneed tec600b®•eau,CCCT 1.1 with 95°.CCS 0 ! 565 2025 5.0 ! 2030 ! +40 T3,261 ! T5.03 0% 100% S72.60 OX $6326
Natural Gas CCCT W,2X1,DF,with SCR Advanced T Case+A advanced t case,CCCT 2,1 with 95°.CCS 0 1085 2025 5.0 2030 +40 %637 14.49 1 0% 100% S57.74 0% S65.08
Hydrogen Electrolyaer,Proton Exchange Membrane(PEN),30.000 kgrday -119 2025 5.0 2030 ! 40 5561 1 523.91 1 +0% 0.00 $10.28 1 100% $32.46
Coal CCSD sx Johnson a(costs m post retrofit basis) 5,54I -85 2027 5.0 2032 30 23.501 f 11.40 1 0% 0% 5277.68 0% ! $53.20
Coal CCS Hester 1-3(costs m post retrofit basis) 6,429 -297 2027 ! 5.0 2032 ! 30 22,931 ! $9.73 1 0°s 0% $235.36 0% $53.20
Coal CCS Huntington 1&2(cons m post retrofit basis) 6,933 -233 2027 5.0 2032 30 $2,951 $9.63 V 0% $242.12 0% $53.20
Coal CCS J-Bddger 3&4(costs no p-s rmofn basis) 7.513 -174 2025 5.0 1 2030 30 $2,598 $10.57 1 0°. 0% $254.91 ( 0% $53.20
Coal CCS 1t'rodak cols on s«tro&basis) 4.448 -69 2027 5.0 1 2032 30 S3,304 1 $11.69 w 0% $309-51 ! 0% ! $5310
Nuclear Small ModWm Rencor a Adsanced Re-tor,Modrate Tevhoobgy Case N/A 600 2030 5.0 2035 60 59.662 • S9.74 v 0% 597.42 0% $17.00
Nuclear Smal Modular React--Adcarced Reactor,Adsmced TecEoob •Case N/A 600 2030 4.0 2034 60 56,368 $8.74 0°. 0% f84.53 0% f12.00
Nwdear Smae\loddar Reactor or Adva-ed Reactor,Mocierae Tecboobgy Case+A formscleas integrated thermal storage NIA ! 750 2030 5.0 1 2035 60 $10.628 1 S10.72 1 0 0% $107.16 i 0% S17.00
Nuclear SmaO-% dolm Reactor a Advanced Reactor,Ad-d Technology Case+A fee noelear 6t,grat,d thermal smog, N A 1 750 2030 4.0 1 2034 1 60 $7 005 ! 59.61 0°. 0% $92.98 0% $12.00
Nuclear Large Light N ater React-,Moderate Tech-IM Case N.4 2.000 2030 7.0 1 2037 60 $7,563 $9.38 0.. 0% $12536 i 0% $10.00
NurJea Ear a L' [Water Reactor,Advanced T Case N A 2 000 2030 5.0 2035 60 26 5 ! 57.88 09-. 90.
Geothemal Near Field Eahmha-ed eotMma]$ -EG NA 707 3025 3.0 2028 30 S7,593 er i.FOM 0% 0% $194.00 6% $125.09
GmE.w Near Field Fnhmheoced Geo&=WSystems(NF-EGS +A Adsanoed Geoshamel TecLrwlo Case NA 707 2025 3.0 2028 I 30 S5949 `kd lade FOM 1 0% 0% SI73.90 I 6% I 5125.09
149

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.3 -2025 Non-Thermal Supply-Side Resources, Characteristics and Costs (2024$)23
Chanete�ati,
Fnction\'ar
O&M
Nat Rswvca Total Asset Base Fraction\'ar Adjusted by Fncriov Fined
e.ratba Covmsercial Lie O&M CapacOy O&3l De
-MMOMFuel Timers) Opentiov fear (v-rs) ) Capinf ed ChavBes Capitalved Cost
Sorage Li-Ina 4-bo.,20 MW N/A 20 1 2025 ! LO 2026 ':� 20 $1,748 1 Ltchded in FOM:� 0°a - 0°° $4505 0°° S29.94
Storage:gel 4-hoar,200 MW N/A i 200 I -5 2 0 2027 i 20 $1,499 lrc!uded a FOM i 0% 0% � $38 77 i 0% $25.66
Storage: Li-Ion,4-ham,200 MW+A Double D-noa,Li-loo,4-hour,200MW N/A 200 i M25 2.0 1 2027 20 S2,557 !I_W d a FOM. 0% ! 0% S69.78 0% $46.19
I I I ! I ! I
Storage: oa Li-Ion,4-h ,1000 MW N/A 1.000 2025 3.0 2028 20 S1,459 !WAdeda FOM 0% ! 0% I S36.92 I 0% S25.66
Storage Ora*Battery,4-hoa,1000 MW N/A I 1,000 I 2025 3.0 I .28 50 S2.021 1lncbbdede FOMI 0% j 0% 1 S50.51 0% $0.19
Storage Gravhv Batt ,M.,1000 MW+A Double Dmat " ,4-hour,1000MW NIA 1,000 2025 3.0 2028 50 $3 006 !I.W d a FOM! 0% ! 0% ! $90.92 0% $035
Storage Adiabatic CAES,500 MW,4000 MWh N/A 500 2025 3.0 2028 30 S3,754 S2.60 50% 1 0% ! 319.20 42% $49.31
Storage 100-ho.4-Ai N/A 200 I 2028 2.0 100 L 1
0 3 9% f17L06
2Storage Pmped Hydro,Two New Revirs,4-hw N/A 400 2025 S 0 $2,9 $0.58 0%
1 0% i 520.20 45% I S149.21
Storage Pumped Hydro,Two New Reservoirs,10-how N/A 400 I 2025 5.0 1 2030 100 S4,159 S0.58 1 0% 1 0% i S20.20 45% S207.95
Storage Pumped Hydro,One Yew Reserow 4-h- N/A ' 400 i 2025 i 5.0 2030 ' 100 $2,883 $0.58 1 0% 1 0% j 520.20 45% 1144.16
Storage Pumped Hydro,Ove New Res irs 10-ho. N/A i 400 I 2025 I 5.0 i 2030 1 100 S3,537 1 S0.58 1 0% i 0% ! $2020 45% f176.87
Storage Pr-ped Thermal Energy Storage.10-hoa N/A I 100 1 2026 i 5.0 2031 ( 60 36,174 30.70 BW 1 O% S2.00 04 $60.00
Stoat a dThamal Ea« Stor e,24-hoa N/A SO 2026 5.0 ! 2031 60 $11,525 f0.70 OK ! OK ! $1.00 OK f60.00
Solar PV,20 MW,Cess 1-10 by bemdon 20 1 2025 i 3.0 2028 25 21,965 iocbded in FOM 0% j 0% $18.16 12% $39.29
Solar PV,200 MW,a-1-10 breeion � 200 1 2025 ! 3.0 I 2028 � 25 51,217 iochded in FOM 0% 1 0% ! 520.52 ! 12% $24.33
Solar PV,20 MW,Class 1-10+A Ads d Sofa Technoogy Case by location 20 1 2025 ! 3.0 i 2029 25 $1.932 ioduded a FOM 0°0 0°ro 217.24 12X $37.33
Sol. PV,200 MW,Clara 1-10+A Ad-ed Sol.Technology Case b.�loeation 200 1 2025 i 3.0 I 2028 ' 25 $1135 ioc!odrd toFOO I 0°° - 0°° $19.47 1 12% $23.11
Wind Wed Cl-l-10,20 MW b.-locariov 20 2023 3.0 i 2028 30 52,355 edudedm FOYl 0°° 0°° 336.79 33% f63.57
Wed Wed Class l-6,200 MW 1.-location j 200 1 2025 j 5.0 j 2030 j 30 S1,421 hmluded in FOM 1 0°a 0°° $31.65 1 35% f63.57
Wad Wed Class 7,200 MW L.location 200 I 2025 5.0 I 130 30 S1,492 mdud:dm FOM! 0°a 0" S31.65 35% S63.57
Wind O&hore,Wmd Class l2 0 1 200 2027 S.0 ! 2032 1 30 58,341 lctdudedeFOM1 0°° 0°.: 569.26 35% f169.16
Wind Wind Class l-10,20 MW+A Ads-ced Ovshare Wed Techoology Case bsl«anon 20 ! 2025 ! 3 1 2028 30 S2,434 Ikdded.FOM I, 0% 1 0% I $34.87 35% SW58
Wmd R"vd Class 1-6,200 MW+A pfianced Onshore Wed TerLwbgy Can by location 1 200 2023 i 3 j 2030 i 30 11,354 included a FOM j 0% 0% J!J S28.45 35X $60.58
Wind Wind Clms 7.200 MW+A Advanced Ovshme Wmd Tech-logy Case by locati- ' 200 1 2025 i 5 i 2030 ' 30 S1,422 ecludedm FOM 0% i 0% 1 328.45 35% 560.58
Wmd Offshore,Wed Class 12+A Adsmced Offshore Wind Tec-b Case 0 200 1 2027 5 2032 1 30 011 Iioduded.FOMI 0% 0% I 3.21 33% 12L92
Assured co-located
21 See Appendix M, stakeholder feedback form#49(Utah Association of Energy Users)
150

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.4-2025 Thermal Supply-Side Resources, Operating Characteristics and Environmental Data (2024S)
Operating Characteristics
Average Fall Load R"ores
Heat Rate(HH\' Consumed S02 NOa 139 CO2
Fuel Resource Description B Egiriercy R R(%) (GaVAMI) (Ibs )
Biofuel Internal Combustion Eugene,renewable biofuel,With SCR S 24-hour fuel tank $295 41 13°o 2.50°% 5-0o. '-"1 0.00152 0.02000 0.000 117
Natural Gas SCCT Aero,with SCR 9,447 36.12% 2"90% 3.9°-6 2Z0 0.00150 0.00750 0 000 117
Natural Gas SCCT Aero xi:with SCR 9,447 36.12% 2.90% 3.9% 27.0 0.00150 0.00750 1 0.000 117
Natural Gas SCCT Frame"F"xl,with SCR 9,717 35.12% 2.70% 3.9% 25.4 0.00150 0.00750 0.000 117
Natural Gas CCCT Dry Ir.M.OF,with SCR 6,040 1 56.491/, 2.501/, 3.8% 210.0 MOM I 0.00750 0.000 117
Natural Gm CCCT Dry"H",2X1,DF,with SCR 6.122 55.74% 2.50% 3.8% 210.0 0.00150 0.00750 U00 117
Natural Gas CCCT Dry"H",IXI,DF,with SCR+A for adding 95%CCS to new CCCT lxl 6,743 53.17% 2501/o 3.8% 323.4 0.00150 0.00563 0.000 6
Natural Gas CCCT Dry"fl",2X1,DF,with SCR+A for adding 95%CCS to new CCCT 2x1 6,843 52.466/6 2.50% 3.8% 323.4 0.00150 0.00563 0.000 1 6
Natural G. Internal Combustion Engine,renewable biofuel,with SCR&24-hour fuel tank+A for CT Brownfield construction U95 41.13% 1 2.50% 5.0% 27.1 1 0.00152 0.02131 0.000 117
Natural Gas SCCT Aero,with SCR+A for CT Brownfield construction 9,447 36.12% 1 2.90% 3.9% 27.0 1 0.00150 1 0.00799 0.000 117
Normal Gas SCCT Aero x4,with SCR+A for CT Brownfield construction 9,447 36.12% 2.900% 3.90% 27.0 0.00150 1 0.00799 0.000 117
Natural G. SCCT Frame'F"al.with SCR+A for CT Brownfield construction 9.717 1 35.12% 2.70% 3.9% 28.4 0.00150 1 0.00799 0.000 117
Natural Gas CCCT Dry'Ir.M.DF,with SCR+A for CT Brownfield coastnrction 6,040 i 56.49% 2.50% 3.8% 210.0 0.00150 0.00799 0.000 117
Natural G. CCCT Dry"H",2XI,DF,with SCR+A for CT Brownfield construction 6,122 55.74% 1 2.500% 3.8% 210.0 0.00150 1 0.00799 0.000 117
Natural Gas CCCT Dry-W.IXI,DF,wih SCR+A for adding 95%CCS to new CCCT lxl+A for CT Browufield construction 6.743 53.17% 1 250% 3.8% 323.4 0.00150 0.00599 0-000 6
Natural Gas CCCT Dry W.2X1,DF,with SCR+A for adding 95%CCS to new CCCT 2xl+A for CT Brownfield construction 6,843 52.46% 1 2.50% 3.8% 323.4 0.00150 0.00599 0.000 1 6
Hydrogen SCCT Frame"F'al.with SCR+Afar 1001/oI-Iydrogea burning capability 9,717 • 33.12% 2.70% 3.90% 28.4 1 0.00000 0.00750 0.000 0
Hydrogen CCCT Dry"H",IXI,DF,with SCR+Afor 1001/,Hydrogen burning capability 6,040 1 56.49% 2.500% 1 3.80% 210.0 0.00000 0.00750 0.000 0
Hydrogen CCCT Dry"H",2XI,DF,with SCR+A for 1001/,Hydrogen burning capability 6,122 I 55.74% 2.50% 1 3.80% 210.0 0.00000 0.00750 0.000 0
Hydrogen SCCT Frame"F xl,with SCR+A for Hydrogen storage,cavern,80 bar,24 hour 9,717 I 35.12% 2.75% 1 3.90% 28.4 0.00196 0.00946 0.002 0
Hydrogen CCCT Dry"H",IXI,DF,with SCR+A for Hydrogen storage,cavern.80 bar,24 hour 6,040 56.49% 2.55% j 3.80% 210.0 0.00196 1 0.00946 0.002 0
Hydrogen CCCT Dry"H",2XI,DF,with SCR+A for Hydrogen storage,cavern,80 bar,24 honu 6,122 55.74% 1 2.55% 3.80% 210.0 1 0.00196 1 0.00946 0.002 0
Hydrogen SCCT Frame"F'al,with SCR+A for Hydrogen storage,talcs,500 bar,24 horn 9,717 35.12% 2.75% 3.901h 28.4 1 0.00196 1 0.00946 0.002 0
Hydrogen CCCT Dry"H",IXI,DF,with SCR+A for Hydrogen storage,tanks,500 bar,24 hour 6,040 56.49% 1 2.55% 3.80% 210.0 0.00196 0.00946 0.002 0
Hydrogen I CCCT Dry W,2X1,DF,with SCR+A for Hydrogen storage,tanks,500 bar,24 hour 6,122 i 55.74% 2.554'0 1 3.80°h 210.0 0.00196 1 0.00946 0.002 0
Natural Gaz CCCTDry"H",IXI,DF,with SCR,Advanced Technology Case+A advanced technology case,CCCT Ixl 6,040 56.49% 2.50% 1 3.8% 210.0 0.00150 1 0.00750 0.000 117
Natural Gas CCCT Dry"H",2XI,DF,with SCR,Advanced Technology Case+A advanced technology case.CCCT 2xl 6,122 1 55.74% 2.50 1 3.8% 210.0 0.00150 1 0.00750 0.000 117
Normal Gas CCCT Dry"H',IXI,DF,with SCR Advanced Technology Case+A advanced technology case,CCCT Ixl with 95%CCS 6,743 53.17% 2.50% 1 3.8% 323.4 0.00150 1 0.00563 0.000 6
Natural Gas CCCT Dry"11",2XI,DF,with SCR Advanced Technology Case+A advanced technology case,CCCT 2xl with 95%CCS 6,843 52.46% 1 2.50% 3.8% 323.4 i 0-00150 0.00563 0.000 6
Hydrogen Electrolyzes,Prota n Exchange Membrane(PEM),50,000 kg�day N/A 79.13% I.50% 1.5% 45.7 1 0.00000 0.00000 0.000 0
Coal CCS Dave Johnston 4(costs on post retrofit basis) 14.795 23.06% I. 7.50% 750% 186.0 1 10.00000 0.07100 1 0.304 1 10
Coal CCS Hunter 1-3(costs on post retrofit basis) 14,011 24.35% 7.50% 7.50% 186.0 1000000 0.07100 0.304 1 10
Coal CCS Huntington 1&2(costs on post retrofit basis) 13,662 i 24.99% 7.500% 1 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 10.000010 0.07100 0304 10
Coal CCS Wyodak(costs on post retrofit basis) 16.653 20.491% 7.50% 1 7.50% 186.0 M00000 1 0.07100 0304 10
Sudear Small.Modular Reactor or Advanced Reactor,Moderate Terlmology Case 9,180 37% 2% 5% 720.0 0.00000 0.00000 0.000 0
Nucear Small Modular Reactor or Advanced Reactor,Advanced Technology Case 9,190 37% I 2°/, 5% 7201. i 0.0000, 0.00000 1 0.000 � 0
Nuclear Small Moddar Reactor or Advanced Reactor,Moderate Technology Case+A f unclear integrated thermal storage 12,626 37.17% 1 2A01/o 5.0% 720.0 i 0 00000 0.00000 1 0.000 0
Nuclear Small Modular Reactor or Advanced Reactor,Advanced Technology Case+A for nuclear integrated thermal storage 12,626 i 37.17% 200% 1 5.0% 720.0 0-00000 1 0.00000 0.000 0
Nuclear Large Light Water Reactor,Moderate Technology Case 10.497 I 33% 2% 5% 720.0 0.00000 1 0.00000 0.000 0
Nuclear Large Light Water Reactor,Advanced Technology Case 10.497 33% 2% 5% 720.0 0.00000 0.00000 0.000 1 0
Geothermal Near Field F,h.,L..Med Geothermal System(NF-EGS)B' N/A N/A ]0°/, 10% 510.0 da da da W.
Geothermal Near Field Fnhanhan ed Geothermal System(NF-EGS)Binary+A Advanced Geothermal Technology Case N/A N/A 10.00% 10.00% 510.0 1 da da da 1 da
151

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 Water
Heat Rate(HM' Consented S02 NOx Hg CO2
Fuel Resource Description Bta/KR'h) Efficiency EFOR(% POR(%) (CanM-h) (lbs/'1C1IBm) (lbs(Mu) (lbs/NBIBto)
Storages Li-Ion,4-hour,20 MW na 85°-0 10°o included in CF na 0.00000 0.00000 0.000 0
Storages Li-Ion,4-hour,100 MW n'a 85% 1% included in CF n4 0.00000 0.00000 1 0.000 0
Storage Li-Ion,4-hour,200 MW+A Doubk Duration,Li-Ion.4-hour,200MW da 1 85.00% j 1.00% included in CF n4 1 0.00000 ' 0.00000 0.000 0
i � I
Storage Li-Ion,4-hour,1000 MW da i 85% 1.0% 1 included in CF n4 0.00000 i 0.00000 0.000 0
Storage Gravity Battery,4-how,1000 MW da 83% 1.0% included in CF da 0.00000 0.00000 0.000 0
Storage Gravity Battery,4-hour,1000 MW+A Double Duration,Gravity,4-hour,1000MW da 83.00% 1.00% included in CF da 0.00000 0-00000 0.000 0
Storage Adiabatic CAES,500 MW,4000 MWh n4 63% L l% 11°8 da 000000 0.000010 0.000 0
Storage 100-how Iron Air da i 43°/. 1.0% included in CF 0.0 0.00000 0.00000 0.000 0
Storage Pumped Hydro,Two New Reservoirs,4-hour da 80% j 2.01% I 4.00io da 000000 0.00000 0.000 0
Storage Pumped Hydro,Two New Reservoirs,10-hour da 80% 2.0% 4.0% da 0-00000 0.00000 1 0.000 1 0
Storage Pumped Hydro,One New Reservoir,4-hour da 80% 2.0% 1 4.0% da 0.00000 0.00000 0.000 0
Storage Pumped Hydro,One New Reservoir,10-hour da 80% 2.0% 1 4.0% da 0.00000 0.00000 0.000 0
Storage Pumped Thermal Energy Storage,10-hour da 55% 2.0% 3.00% ds 1 0.00000 0.00000 0.000 0
Storage Pumped Thermal Energy Storage,24-how da 55% 2 0°io 3-0% da 0.00000 0.000010 0.000 0-
Sol. PV,20 MW,Class 1-I0 NIA by location 1 Included with CF 1 Lxhrded witlr CF da da n'a nda da
Solar PV,200 MW,Class 1-10 N/A by location 1 Included with CF Included with CF n4 da da I da I da
Solar PV,20 MW,Class 1-10+A Advanced Solar Technology Case N/A by location Included with CF Included with CF da 1 da da nda I da
Solar PV,200 MW,Class 1-10+A Advanced Solar Technology Case N/A by location 1 Included with CF I Included with CF n4 da da da W.
Wind Wind Class 1-10,20 MW NIA by location 1 Included with CF I Included with CF da da da da da
Wind Wind Class 1-6,200 MW NIA I by location 1 Included with CF' Included with CF da da i da da da
Wind Wind Class 7,200 MW N/A by location 1 Included with CF Included with CF n4 da da I ds I da
Wind Offshore,Wind Class 12 N/A I max CF:47% Included with CFI Included with CF da da I da 1 da da
Wind Wind Class 1-10,20 MW+A Advanced Onshore Wmd Technology Case N/A I by location j Included with CFI Included with CF da da Wit da da
Wind Wind Class 1-6,200 MW+A Advanced Onshore Wind Technology Case N/A I by location Included with CF Included with CF We We da We da
Wind Wind Class 7,200 MW+A Advanced Onshore Wind Technology Case NIA I by location 1 Included with CF Included with CF da da da da da
Wind Offshore,Wind Class 12+A Advanced Offshore Wind Technology Case I MA _CF 47°0 1 Included with CF f Included with CF i da da da da n/a
Assumed co-located
152

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.6-2025 IRP Thermal Supply-Side Resources, Additional Attributes and Fixed O&M (2024$)
Addiw..l Arrr.Mtea Frted O&M
Taal F.
Px.�me.t .A.-I O&M Toral Fined Taal F.. Cost
E4vatia ilhTaal ED-Afi.. Fata(wa raO Capes!' G61M C Capital'vad Gw Ttarpon O&M CatC-d
12esoarce Deu Mdeled DtP on Yr) Y-JIMM
Iarwoel Combusum E.&,revewabk b.ofueL wih SCR&24 haatal tmik Y's 0 S 2130.94 S 14.59; 6.890% $147.83 92.500o S42.32 162% $1.12 S0.00 S4394 $191.77 $23.67
SMA-wdh SCR N. 0 I2,612.90'',S 3246! 6A01% $16139 310P. $I2A2 2.62% $032 f0.D0 $12.74 f174.13 $6024
SMA-x4,wdh SCR No 0 11,78933!S 3146' 6-104% f11110 ! 350094 f9.93 162% f026 f0-00 ! SI0.19 $121.40 $4199
6CC[Frame Fxl.wih SCR Y. 0 I 1.3%.93 I 11.13! 6.100% f85.34 33.00% f2792 162% f013 WOOf18.65 fIN.00 f39.43
Goshen Y. 2.814 I 1.400.79 I 11.13' 6.100% 566.19 33.00% 32791 1.62% S0.73 f%.20 S124.85 f11109 f73.00
Wasatch F- Yes 4.225 S 1.3710' I 12.13 6.100% S84.50 33.00% $2792 2.62% S0.73 S1472 f/3.38 f117.87 f44.23
W' East Y. 6,130 f 1.373.05 I 12.13 6.100% 584.50 73.00% 227.92 2.62% $0.73 125.80 I f54.45 S138,95 S48.07
CCCTDry'H'.IXI,DF,wih SCR Y. 0 !f 1,839.1 S 12." 6.233% f113.38 78.00% 543.44 2.61% fl.11 f9.00 S43.55 S158,93 S23.36
Goshen Y. 2,814 S 1,857.39 f 12.08 6.233% f116.S2 78.00% 54144 2.62% fl.11 S6034 S103.89 522041 f32.36
WwachRmt Y. 4,225 f 1,82 a S 1209 6233% S11413 7&00% S41d4 2.62% fl.11 $925 S5211 S167.04 S24.45
W ' Eau Y. 6.130 f 1,820Al!f 1108 6133% S11413 � 78.00% S4144 2.62% fL11 $1633 15918 1174.11 S2549
CCCT Dry'H',2X1,DR v8h SCR Y. 0 f 1,55326 f 1189 j 6236X S97 5] 78 00% 53538 162% f0-92 f0-00 53610 f133.6] f1956
Goshen Y. 2,814 S 1,566.]9 f 1L89 6134X f98.54 78.00X 535.18 2.62% S0.92 f61.16 $9'716 S19510 S28.66
Wasatch Frm Y. 4125 S 1,337.73 i S IL89 6134% S%.60 78.005. 535.18 2.63% f0.92 f938 545.48 f1/2.08 f20.79
W' Ewt Yea 6.130 S 1.537.73!S 11.99. 6234% S%.60 78.004. 533.18 2.62% f0.92 116.55 152.65 f14926 521.84
CCCT 7r,IXl,DF,wA SCR+efar 95%CCSmaw CCCT IxI No 0 S 342936 $
6528' 6239% 5218.03 78.00Ya 577.07 5.51% tdr S0.00 i S8134 f299.31 143.81
CCCT Dry 7C,2Xl,DF,wehfCR+e6a edd'oB%%CCS roaew CCCT 2x1 No 0 S 2,816.02 S 65.091 6211% f181.68 ! 78.00Sh $6299 5.51% 13.49 $0.00 $66.48 I749.16 $36.32
Iotmd Coabanoa Eogoe,rmewabk bidd,ah SCR+A for Cr B-.fiddemma8m No 0 S 191763;S 14591 6191% $133.16 3100% S4212 1.62% SI.l1 fO.W H394 f177.10 $61.26
SCCr A-m&SCR+ef CT B-.,&Hcmm 4m No 0 S 235L52 S 32.46! 6.102% f145A7 33.00% S1242 1.62% f032 50.00 $12.74 $15911 $54.73
SCCT Aao.4.wih SCR+Af CT lk-dW cmN em No 0 S 1.610.42 S ... 6.101% $100.30 ! 33.00% 39.93 2.62% $0,26 $010 $10.19 $11049 $38.22
SCCf Frame'F'xl.w*h SCR+efa CT Bso»s dd-nm Y. 0 S 114813 S 12.13 6100% $76.99 33.OMi 517.92 2.62% $0.73 $0.00 S28.65 S105,53 $36.51
Goshen-BsoadrJd No 3.81/ S t,260.71 i S 12.13 6101Y. S77.64 33.00% 237.92 2.62% $0.73 f%10 ! $124.85 f101,50 $7005
Wunrh Fran-&owddd Yes 4,215 S 1,235.75 S 12.13 6101Y. 576.12 33.00°o 527.92 2.62% f0.73 I14.71 H3.38 $I19.50 f41.31
W Ewt-Browddd Yes 6130 f t 3.75 I 11.13 6100% $76.12 33.00°o $27.92 2.62% S0.73 325.80 SMAS S130.57 1 .17
CCCTDry-W,IXI.DF,wih SCR+efa Cr Bw-fiM rmmerim Yes 0 1f 1.655.10�$ 12.09 6234% $103.93 7500°-o f4144 2.62Y. f1.11 1,00 1-51 S147AS S2158
Goshen-B-fid No 2,811 f 1,671.65 f 12.08!. 6.234% f104.% 7&W. S4144 ! 2.62% fLll S60.34 $103.99 S20915 S30.57
Wasach Frta-Ea�>add Yes 6,115 f I,63655 S 1108 6234•. S10290 7800°. S42 2.62% SIAI $923 S5241 SIS3.71 S22.79
W Ewt-Brow�eld Y. 6,130 !f 1,63855!S 11.08' 6234'. S10290 7800°. S42.44 2.67K fLll S1633 S5918 S16178 S23A2
CCCT Dry'H',2Xl,DF,wvh SCR+df CC BroxnfieH censor Eoa Y. 0 f 1,39793f IL89! 6234°. 587.89 78.00°o S35.18 2.R% f0.92 f0.00 f36.10 f123.99 fI8.15
G.Shm-B-.fidd No Z914 S 1.411.91 f 11.99 6.234% 588.76 78.00°o S35.18 2.62% S0.92 S61.16 S9726 SI86.02 S27.22
W-&Fsa Ik..6dd Y. 4,225 S 1.383.95 S 11.99 6.234'. S87.01 78.W f33.18 2.1 f0.92 S9.38 S45.49 S132.50 S19.39
W'ymirB E--B.-&A Y.
6,130 S 1.383.95 S 11.99 6.234°. f87.02 78.00°-o S35.18 162% f0.92 $16.35 S52.65 SIMA7 $20.44
CCCT Dry 7C,IXI,DF.wih SCR+d6r edd'og 95%CCS to vew CCCT lxl+dfa CT BrowdeN cmWomm No 0 S 3,086A4 f 65.28! 6.2J7. $I%.67 78.004. $77.07 5.54% $4.27 50.00 SH1.34 5278.00 $10.69
CCCT N,2X1,DF,MSC
95K CCS to very CCCT LI+eSa Cr BrawdrN cmwomm No 0 S 2,561A2 S 65.09!. 6.2J2o. $16195 78.00% $6299 3.34% f3.49 50.00 566.48 f230A3 533.72
SCCr Frame'F"xl,with SCR+e6r1 den No 0 f 1.599.%;f 13.95 56053'. S%.18 33.00X 527.92 2.62% f0.77 S0.0o $28.65 S118.83 $41.11
CCCT' 'H'.IXI,DF,wib SCR+eta IOOS.H No 0 f 1.I14.e5if 13.89 5604% $119.29 ' 79.00% $42.44 2.62% i $1.11 $0.00 $43.55 S162.85 $23.83
CCCT Dq 71',2Xl,DF,wib SCR+efa IOM.H No 0 S 1.7%.25 S 13.67' 5,604% $100.37 78.00Sh $35.18 2.62% $0.92 $0.00 536A0 $13647 S20.05
SCCT Frame'F'xl.aih SCR+A forth dso moor ernav,60 ba,24 has No 0 ;S 2,58513;S 27.13! 9.271% 1242,26 33.00% 135.12 2.62% f0.92 $0.00 S36.04 $278,30 $%2]
CCCf 7I'IXI DF,wih SCR+eforH tro mu ,cawg80 bar,24 h- No 0 !$ 3039.01!S His 9.254°. 5283.M 7&00% $49.64 2.62% f1.30 50.00 550.94 f334.59 f4&97
CCCT
7I',2X1.DF.wih SCR+efaH tro mu awn 80 bar.2l lna No 0 S 275227 S 26.89!. 9163•. 1257.43 79.00% $4238 2.62% $1.11 f0.00 343.49 S300.93 S44.04
SCCT F-'F'xl.wih SCR+A faH e.rmksc 500 bar,24 hda No 0 S 2,09'7.BI:S 27.13 9155% $I%.67 33.00% S40.78 2.62% S1.07 50.00 311.85 S23931 382.51
CCCT I)rv'H',IXI,DF,wih SCR+e6r tro mu e.rooks,3006a,Td has No 0 !S 1,31991!f 2708 9'_45°. f23814 78.00% $5330 1.61% f143 f0.00 SS6.75 f19499 $43.17
CCCT I)ry'H',2Xl,DF.wih SCR+e6a ogm storage,racks,5006a,Za hoa No 0 S 1364.16 S 2689 9350?: f21191 78.00% S48.04 1.61% S126 fO.W 21930 f26112 f3823
CCCT Du'H',IXI,DF.w&SCR Advanced Techaobgy Case+a ad-d tecLool'�'use,CCCC W No 0 S 1,831.63!S 1208. 6233% S11492 7&00% S4133 2.62% SLOB W. S4141 S15733 S2102
CCCT R,2Xl,DF.wih SCR Adwmed Techoobgy Case+e adsaoced tecJmobG case,CCCC hI No 0 !S 1,517.89!f 11.99 i 6234% S95.36 78.00°ro $3/.07 2.63% $0.89 $0.00 SA96 S13032 SM07
CCCTDsy-W XI,DF.w.SCR Adaamed Techoobgy Case+ea&-,d tec)mology case.CCCT W.95%CCS No 0 f 3.260.98'S 65.28! 6133% f207.32 78.00% S72.60 5.54% S4.02 S0.00 576.63 f11194 Ulm%
CCCT Dry'H'.2XI.DF.wiM SCR AAerced Techwbgy Cae+ea&-dtechmbgycae,CCCT 2xl,95%CCS No 0 f 2,637.12 f 65.08! 6234% f168.46 78.00°a f5774 5.34% f3.21 f0.00 360.94 S229A0 53337
Hydrogrn pcekcr wilh CCCT Dry 71'.3X1.DF ad ckctroyxa Y. 0 !S 2.859.50!S 44.94 i 4.170% S12107 9 00% S60.95 0.00% f0.00 $0,00 S60.95 f18103 S21.20
jr
Proton Ex Mevbrmc (PE. ,50.000 No 0 S 560.99!f 32.461 4.170% S24,75 97 00°o MIS 0.00% 1 S0.0D $0.00 $10.28 f35.03 S4.12
A CCS Do c Jobum 4 cosh m raro6 ham No 5,541 f 3,500.76 $ 53.20 i 6147% f229.12 85.00% S277.66 5.54% S15.38 S0 00 t $293.06 $522.19 $70.13
A CCS Hmta]-3 coos trard bash No 6,029 S 2,%L20;f 53.201 6451% $19381 8500% $235.36 5.51% 513.01 50.00 5246.39 f40211 $59.39
A CCS 1&2 costsm retrd bay No 6.933 S 2,%140;S 532 .00 0: 6A51% $19313 85 % $242.12 5.54% 513.41 560.I0.DI 111.13 S449.36 35
e CC53m 3&a canm retrdba� Y. 7.513 .00 f 2.59839 S 5320 6A54% $171A3 85 % $254.91 5.51% 514.12 $0.00 S269.03 S440A6 MAI
e CCSW (cosum sand bans No 4446 S 350425:S 5320i 6A47% S229.35 85.00% S30931 5.54% $17.15 $0.00 $326.65 f556.00 574.6]
Smaf MoAda Rea7oraAdeaaed Reactor,MOdewre Terhmbgy C- Y. N/A i$ 9,662.09 i f MOD 5.013K S488.02 93.00% $97.42 9.42% $9.18 $0.00 � $106.6D 5394.62 172..
Goshen Y. 2,814 $ 9,85733 $ 17.00 5012°. $497.76 93.00% $97.42 9.42% $9.18 $0.00 $106.60 S604.36 $74.19
W-6 Fra4 Y. 4,225 I 9.95533 j$ MOD: 5 042°'° $497.76 ': 93.00% Sr-42 9.42% $9.18 $0.00 j $106.60 $60436 $74.19
l4'-Eaa Y. 6,130 !I 9,WA7 1 S 17 00 5 oJ2°'a S483.13 93.00% S97.42 9.42% $9-13 S0-00 S106.60 S58913 f72.39
Small Modular Rmna a Adwaced Reac4a,Adsmced TecEmbgy Case No N/A S 6,36823!S 12W 50J_'°'a S32L69 93.00% S9453 9.42% $79] so DoS9149 S414.18 f50.84
Smd MoAda Ractor a Ad•mced Rweta,Modmau Tedmbw Case+a fm m1=imepaed*-d stooge No N/A f1.3%]0 S 1700 5042•. f536.74 93.00% SI07.16 9.42% SI0.10 S0.00 I S11726 S654.00 S802H
Sorel ModderRmctoraAdsaaed Reactor,Adaaaed Tahmb Case+efor oukaa Ihesmel stor a No NIA I 7.003.03!S 1200 5.042X f353.80 93.004. 392.98 9.42% f8.76 $0.00 S101.74 f455.54 555.93
Lase Li$t Weko R-az \9odc.ar TvcMdogy Casc No N/A !f 7,162.87!f 1000 5.042% S381.82 93.00% S125.36 9.42% S11.81 50.00 I f137.17 S518.99 S63.71
Lagc Lift W'aer Rcxtor.Ad.mrccd Tcclrrobgy G:< No N/A f 6,265.25 f 900 5.092% f316.35 93.004. 590.26 9.42% f8.51 50.00 f%.76 1415.1] i $50.95
Ica Field EdmdmxcdGmOaamd Syst®(NF-EGS)Biury Yw N/A f 7,593.%�f ]2509 6.262X 5483.11 8000% S194.00 0.97% S1.69 S0.D0 f195.69 f679,00 f%.89
6aud�ea OR Y. 497 f 8,883.86 f 12509 6262X S%4.14 8000% S194.00 0.97% S1.69 S0.00 f195.69 f759,83 f10842
Wasach Frmt Y. 6325 f 7,591% f 125.09! 6262% 148331 8000% f194-00 0.87% S1.69 S0.00 f195.69 f67900 f96.A9
•e 6x ccs asuBadao mexsdog rodtmb era ccs eom as oppatuB rn.agterilure my,at t&opemdm tithe eaiuoB malresaa«.
153

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.7-2025 IRP Non-Thermal Supply-Side Resources, Additional Attributes and Fixed O&M (2024$)
Additi-I At Imp Faod OAM
FaYoeut MNI.4uvual O/M Total Frsed Total Fsed Total Fired
Ek-io. Told D...W.n Fapor(nal pvTwl CaWciR' ORM Cay+airi OR\I Cop Cap Cwvealed
Resource Desc*d" (AFBL) Cop Factor (S/kW-Yr) (ShW-Yr)
Pt',20 MW,Class 1-10 Y. br location S 1.964.64!S 39.29 6.861% $13749 2-33°. S1c 16 137% S0.25 S1841 S155.90 $65.11
Po dNosh Coati Yes 19 S 2.082.51 S 392 6.861% S14558 1 2479'. $1816 1.37% S0.25 SI871 S163.99 � S76.45
S.W-OR Yes 497 3$ 2.180.75 S 3929 6.861°. $152.32 j 29.29'. $18.16 1.37% S0.25 $19.41 $170.73 I S6634
Wda`x'a. Y. 2.353 S 2.003.93 j S 39.291 6.861°. S140.19 j 25.96°° S18.16 1.37% S0.25 S18.41 S158.60 S69.74
Goshrn Yes 2.814 S 1:99418 S 39291 6.861°. $138.84 2779'. $18.16 1.37% S025 S1841 S15715 564.59
R'asatch Frost Y. I 4.225 $ 1,964.64 S 3929 6.861°. $137.49 j 29.00'. $18.16 j 1.37% $0.25 $19.41 5155.90 1 $61.38
R's Eau Y. 6,130 S 1,964.64 S 3929 j 6.861°. S137.49 1 27.41. SIB.l6 1.37% 50.25 S18.41 S155.90 S64.79
P\'.'00 MR',Class 1-10 Yes bybcatim j S 1,216.55 S 2433. 6861°. 585A4 27.33'. 520.52 137X SD28 $20.80 $105.93 $4424
PoNmid NoM Coast Yes 19 i S 1189.55 S 2433 6.661°. 590.15 24.49. 520.52 1.37% 30.28 320.80 5110.94 $51.72
S.,.6-OR Yes 497 S 1,35037 S 2433 6861°. S94.32 j 29.29'. S20.52 137% 5028 320.80 f115.12 $H.87
l\'aea tt'ele Y. 2J53 S 1,2A0.88 $ 2133 6.861°. f86.81 25.96. $20.52 1.37X 3018 S20.80 5107.60 $4732
Goshev Y. 2,814 ?$ 1128.72 S 2/33 6.661°. 585.97 27.79'. 520.52 137% 5028 S20.80 S106.77 S43.96
\t'asa<ch Frog Y. 4.225 'S 1.216-53�S 2433 j 6661°. S95.I4 ' 29.00'. $20.52 � 1.37X S028 S20.80 S105.93 $4171
R'. Eon Yes 6130 S 1.216.55 S 2433 6.561°. 585.14 27.47'. S20.52 1.37% 1 S018 S20.60 $105.93 1 $44.02
Pe.20 Mtt',Clans 1-10-A Advanced Sohn TKh U oob Case No by br d.1 3 1,83212 S 3733' 6 862% 7 3$12829 23'. S1724 137% S024 WAS S143 76 S60-88
P\'.200 MR Chu,I.10+A Adsaeced Solar Technob Case No bcatiov 1 S 1,134.56 S 23.11' 6.862'. $79.44 27.33'. $19.47 1.37X 3017 $19.74 $99.18 591.43
tl bd Ctasz 1-10,20 MW Yo by bd. S 2,554.58 S 63.57 6292'-. f164.73 1 M.07'. 538.79 /39X I $1.70 540.19 S205.22 $80.60
Portlmd NoM Coast Y. I 19 `S 2,835.59 1 S 63.57 6292% f 18242 24.91'. $38.79 1.39% 31.70 S40.49 f222.90 5102.14
S..d-OR Yes 497 `:.S 3,O14.41 S 63.57 6292% 5193.67 25.18'° 538.79 4.39% 31.70 590.49 f234.15 $106.14
W' R'da Yes 2.353 i S 2,6MJ711 S 63.57 6292% S171-16 1 23.13% $38.79 439% $170 S4049 S21165 S104A6
Goshev Yes 3,811 S 2,605.b8I S 63.57 6292% $167.95 3426% 538.79 4.39% 51.70 S40.49 121.14 1-41
\j"asazch Frost Yes 4125 ;$ 3,580.131 S 63.57 6292% $166.30 33.69. 538.79 4.39X 51.70 540.49 f206.63 570.06
Wso®g Eon Yes 1 6,130 S 2,303.491 S 63.57 6292% S161.52 33,2r. S38.79 4.39% $1.70 S40.49 f202.01 S69.41
Wid Class 1-6,200 MW Yes by bca8vm S 1,421.101S 63.57 6.316% 593.77 34.37'. $31.65 4.39X 31.39 S33.04 f126.81 192.12
Ponlmid NoM Coast Y. 19 1$
1.577.43 j S 63.57 6.316% $103.63 37.62% $31.65 4.39% '1.39 $33.04 S136.68 $41 A7
S.,d-OR Y. I 497 S 1.676.90 j S 63.57 6.316% 5109.93 34.06% S31.65 4.39% S1.39 S33.04 S142.97 S47.92
Walla Wok Yes 2353 S 1.477.95 S 63.57 6.316% $97,36 32.59% $31.65 4.39% $1.39 $33.04 $130.40 $45.68
Goshen Y. 2.814 S 1.449.53 S 63.57 6.316% S95.57 30.28% $31.65 4.3W. S1.39 $33.04 S128.61 $43.49
tt'asatch Front Yes 4,225 S 1.435.32 f 63.57 6.316% f94.67 30.42'b $31.65 4.39% $1.39 S33.04 S127.71 $47.93
R'.o®gEast Y. 6,130 i$
1,392.68'S 63.57 6316% 591.98 j 4115% $31.65 43W.. S139 $33.04 $125.02 $34.60
Wi..d Class 7.200 MW No by bastion S 1.491.73 S 63.57 6.313% S98.19 34.3T 531.61 4.39°-. 51.39 S33.04 S13123 S43.59
Offih.,wad Ch.12 Yea 0 4 S 8,340.57 S 169.16 5202% f442 68 31.54'. f69.26 4.39°. SS 04 $72.30 S514.98 $196.38
S.W-OR Y. 497 1$
9,841.87 S 169.16 S202X 5520.77 j 48.94. f69.26 4.39% $3.04 S72.30 $593.07 $138.33
Wbd Cl -10.20 MVP+A Advanced O..h-VV dT Ca« No bastion i S 2.43426 S 60.58 6292% SI56.98 1 29,07'. 539.87 41. $1.53 S36.40 S193.37 $75.95
Wbd Clml-6,200 MW+A Advmcrd Onshore Wbd7 Case No kmdim S 1,354.17 S 60.58 6316% S99.36 34.37'. 528.15 439% $115 $29.70 1 1I19.06 1 $39.54
Wi.d Coss 7,200 MW+A Adv dOvsh-W d TddM Case No brim?S 1,421.511 S 60.58 6.313X 393.56 34.37'. 528.45 4.39% $125 529.70 SI23.27 540.94
06ihme,Wod Ch-12+AAdcmced OBhwe WbdT-%. Cam No 0 S 6,01,05 S 12192 4.&I% f296-90 1 84.43% $6321 1 439% S278 S6599 I S36199 1 $4906
154

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.8-2025 IRP Storage Supply-Side Resources, Additional Attributes and Fixed O&M (2024$)
.Odditbval At bores F..d O&M
total Feed
Parmeot A.eWul .m TWl F." Total Feed (:oa
Ekrativ. total Deo.oEtiov Factor(real Pa5"ee.t CaWcin Storage O&N Capitamed CapMwE O&M Cost Co.....d
Resavece Desr"tiov M.dded UtP Cost leretred) (S -Yr) Fvaer E W-Yr F.-d- -Y W-Yr) &%M
L:1_4-hot/,20 MV No NIA $ 1.747.61';S 29.94 5354°• S91.1' 166". BY• 545.05 145.15 514011 S960I
;i-Ioq 4-hov,2W M1Y1 Yes N/A if 1.497.99iS 25A61 5.354°a 58157 166'°: SY: 536.77 OW% EO.W 538.77 5120.34 562 J2
Padmd Na C.- Ya � 19 f 1.59777 j S 2566 ii 1311•c 58638 166'° 8<•.o $3917 0.00% WOO f3&77 5125.15 i 585.72
Sa OR Y. 497 f 1.617.731,S 2566 33<J•s I8799 166'• 8<•.: f38.77 000% S000 338.77 f12&75 � $86.82
R'i W'i Y. 3,353 f 151183 j f 3566 j 5354% 58398 16.6'O Sw.e $38.T/ O.W% 50.00 f3&77 1122.74 I61.97
Gosh. Y. 3,81/ f 152].85 j S 35.66 5354% 583.18 16.677• SY. f38.77 O.W% 5000 338.77 113L94 I 583.52
11'mp<h Root Y. 4.225 f 1.342.83;f 2366 4.432% 369.83 16.67s: 85°: f38.77 O.W% SO.W $38,77 f108.60 574.38
1S'yaos8 Emt Y. 6130 f 1482.91 f 25.66 4.432% $67.16 16.67s: 85•.: f38.77 0.00% 50.00 $38.77 f105.93 f72.55
Li-Ion 4-hot/.200 MW+d Doobk Duafim Li-1-4-b-,2001Wt Y. N/A S 2,556.571S 46.19i 5355% $13938 1 33.33'. BS°.
NW'a wrh FEnssvt , . 369.7788 0..0 f00...00 $69.79 3209.16 $71.63
Paded Path Ct/ Ye 19 S 2,W.97 S 46.19 5 1141.5 33335: S69 0 f00 S69.79 3217.37 $74.44
S15 Sp OR Y. 197 S 2,76L10 $ 4619 535 3 3% $6978 0.00% 5000 $6919 1220.11 37531
Wi W Ye 2353 419 535 f978 OW% 50 $6978 321327 I7301
S S 5 1 3
Goa Vc 19 5.355% 542. 33335: 85% $6978 O.W% $000 S6978 3211.90 $72.57W
Y. 4.225 S 2,633.2 S 4619 4.413% 1932 3333 % $69.78 O.W% 500 $69,78 $189.10 $64,76
Y. 1130 12,SM 071 S
46.19 4.453% $11C76 33.33% 95% $69.78 O.W% 5000 $69,78 $184.54 56120
U-1-4-hot/.10WMWt No N/A f 1,459.30'S 25.66 5356% $79.55 16.6Ah 95% $36.92 0.00% IB.W $36.92 SI16.47 $79.77
Gtmyy Bettor.4 hoa.1000 MW Yes N/A f 2.120.99 i 1 0.19 i 2.916% 151.94 16.67% i 13% f50.51 000% SO.W 550.51 5109.45 I74.97
W-6 F- Y. 4.225 f 2.081.62 f 0.19 2.916% 560.71 16.67% i 83% f30.31 000% $0.00 530.51 f111.22 I76.19
Gm' ,4-hoa,IOW MVl+A DabkD Men ,4-how,100MAW No N/A if 3.006.34:f 0.35� 3.916% f87.68 33.33% I 83% f90.93 548% f4.98 S95.90 f183.38 562.87
4_w C.AES,SW MW,4000 biW'h N. N/A if 3,754.W!f 69.3. 4281% f163.09 ! 3333% 12 $19.20 000!n WOO $1920 518229 56243
IW-hot/hen Ah Yes N/A j f 2,729.67 f 171.06 4.591% f13188 3&07% d3% f21.04 261% SOSS 52139 f154.47 S58b4
P..L od. Coop Y. 19 $
2:993.45 f 17LW 5.184% 5168.06 30.07% j 13% f21.0/ 62•b f055 52139 SI89.65 S72W
11-6 F- Yes 4,M f 2,81L36 S 171.06 4581% fO&O 30.07% 43% f2L0/ 2.62% f053 321.59 113623 fW.07
Paoped Hydro,two New Resawhs.1-1- No N/A f 2,984.23!f 149.21 3.121% .7.79 16AI 80% f2020 2.62% 50.53 520.73 f118.52 581.18
Pwped Hydro.Twro New Resavahs.10-hot/ Y. N/A if 4,158.90if 20713 3.121% f13629 41.67% 80% 37A10 2.62% f0.53 220.73 f137.02 I43.02
P .. .North Coca Ya 19 f 4.408.44�f 207.95i 3,121% f144.08 41.:;% .0% -.20 262% SO.53 22013 f164.81 WAS
Sa.haa OR Yes 497 f 4,491.61 f 207.95 3.121% SU&7 41.fi7% BOY. S2020 262% US 52013 $167.40 $45.86
Goshen Yes � 207.95 3.121% 513 f1.0 38.69 11.fi7: f2010 2 62• 505 f3073 3159.61 f437
, 6X
1-h Fr Y. 4,2 4,2 97 465 0•b 3
52010 _'6_'% 1053 320.73 5136.70 S37.45
tYyovptg Fort Y. 6.130 f 4.117.31 S 207.95 2583% f111.61 41.1% BOSh $2010 262eo 30.53 120.73 5133.41 $3629
Forged Hydro.Oae New Resmai.4-boor No N/A f 2.883.24�5 149.16: 3.131% 594.49 .6.67% BO% $20,20 262% 50.53 $20.73 f115.21 I78.91
ed Hydro.Oa New Resmvh.l0-boQ No N/A f 3,537.41 S 176.87! 3.121% f113,92 41.67% 80% $20,20 262'. 50.53 $20.73 f136.65 f37.44
ed Thnvvl Evc St ,10-M1oa No N/A f 6173.76iS 60.W 3.361% f209.52 35.18% ! 53% 32.W 262•: SO.05 $2.05 5211.57 568.06
ed Th Eoc S .24-hot/ No N/A f 11,525.17:S 60.00 3362% f399A9 i 3SA9% I 55% SLOO 1 3-.. $0.01 S1.6I 1390.51 f125.63
-A-d ro krated
155

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.9-2025 IRP Thermal Su 1 -Side Resources,Variable O&M, Total Cost and Credits (2024$)
viable O&\I
Total
Reso Total Faed
OAM Rem . Tax CeedBs Cost wkY Pc C.1.4 Tax
.Ik dFeel O&M Capiak d Cqi k d coal ($M%I)UTC /rrCCeedit.C."(ykW-
)baavea ( appkw)
Iotaeel C-mbs600 Easeoe,renewable biafud,aih SCR&'_l-hom furl tasJ. f 337.85 S6.93 14.39% 1 $1.00 $389.44 S389.44 S191 77
SCCT A-arch SCR f 53.04 S7.40 1439% S107 f12L75 S121.75 S17413
SCCT Aerox4,wilh SCR Is 5104 $5.92 I 14.39% $0.95 $101.81 SI01.81
'Fast 1 ' $121.40
SCOT FmFxl,wih SCR $ 456 f775 14.3 $11.112 f11M.6 $102.86 $114.00
5 7 439% 3 37.12 $13712 f211.04Gosh. S 52
W 557 $77 14.39% S1.12 $0837
W 510837 f127.87
f7. 51S 47.47 75 14.39% 51.12 04.40
S104.40 I $139.95
CCCT Dry Ir.IXI.DF.with SCR S 33.91 j S2.70 j 14.39% I $0.39 $60.26 - $60.26 I S158.93
Gosh. $ 34.65{ $170 j 1439% 1 f039 $70.00 - $70.00 I S220.41
Wawch From S 34.741 $2.70 1 14.39% $0.39 $6227 - $62.27 $167.04
W Eat S 30.051 $2.70 14.39% $0.39 S58.62 f5&62 I f174.11
"CCCT Dry rC 28 2X1,DF,with SCR S 3437 i f2 1439% S0.33 $56.54 - $56.54 $133.67
Gosh. S 35.12 f2.28 j 14.39% S0.33 S66.39 - f66.39 I f195.80
R'asmch From S 3511 j f118 1439% SO33 S58.61 - f58.61 f142.08
wyomkg Eat S 30.45' f2.28 14.39% S0.33 S54.90 $54.90 $149.26
CCCT' ,1X1,DF,aiah SCR+p6a 95%CCS to new CCCT Ix!
S 37.86i f5.32 11.52% i S0.61 587.60 S87.60 f299.37
CCCT "H",SX3,DF,with SCR+p( 95%CCSto oew CC CT 2.1 S 38.421 $4.83 11,52% f0.56 S80.12 f90.12 1 S248.I6
I...d Comb 6.Eogoe,rercwabk bkfblL wtb SCR+p far CT IkOVA&Mcoms--Con f 46.57' $6.24 14.39% $0.90 $114.97 $114.97 i $177.10
SCCI Ac aih SCR+A 6x CT B-.fidd cemmtoc- f 53.041 $666 1439% $096 $115.39 $11539 1 $15921
SCCT A-.4.aih SCR+A f«CT&owdidd eo W-d- S 53b41 $5.33 14.39% $0.77 S97.36 $9736 f110.49
SCCT F-'F'xl,ailh SCR+A f«CT Browidd coos-6- f 5456l, 56.98 14.39% $1.00 $99.05 - f99.05 I f105.53
.wdsd Gosh.-Bd S 5423' $6.99 j 14.39% $1.00 $13126 - $13226 I S20150
R'asach From-Br-fi W S 5419 1 $6.98 14.39% SI.00 S103.60 - S103.60 I SI19.50
R' Fxn-Brown6dd $ 53M $6.99 1 14.39% $I.00 $107.05 S107.05 I $130.57
CCCTDry'TI",IXI,DF.wih SCR+AWs CTBrow."d ..b.-dm S 33.91 $2.43 j 14.39% $0.35 $58.28 - S58.28 I S147.48
Gosh.-Brow'd S 34.01 1 $143 1 1439% 1 $0.95 $67.36 - $67.36 I $208.85
W-ch From-Broxv6dd S 34.121 $2.43 14.39% 1 $0.35 $59.69 - f59.69 f155.71
W Eau-&-fidd S 34.121 f2.43 14.39% ! $0.35 $60.72 f60.72 f162.78
CCCTD.y'W,2X1,DF_aih SCR+Af«CTBma G6dca-se tiou S 34371 f105 14.39% $0.30 $54.87 - f54.87 f123.99
Gosh.-Brox Id S 34.48 j f2.05 14.39% S0.30 S64.05 - f64.05 f186.02
W.-h From-Bmx,ddd S 34581 f2.05 1439% SO30 S56.32 - f56.32 $132.50
Wy-g Eau-B-f.1d S 34.59 S2.05 i 14.39% S0.30 S57.37 $57.37 f139.67
CCCT 'H",1X1,DF,xih SCR�Afix addO 95a'.CCS to-w CCCT Ixt+pf CC&owdkN camaecgan S 37.86 f4.78 11.52% S0.55 S83.88 f63.88 ! f378.OD
CCCT "li".2X1,DF_xw SCR-ef« 95•.CCSmrca-CCCT 2cl+p f.CT Browa6dd cmm tie S 38.421 f4.34 IL52% 50.50 $76.99 576.99 $230.43
SCCT Frame'F xl,Mffi SCR-Af I00%Hydrog.babg cVW, f 54.56 $9.91 14.39% 1 $1.28 $105.86 $105.86 $118.83
CCCT N,1X1,DF,aeh SCR+p(100°aH dro. f 3391� f3.11 1439% S0.45 $61.30 $61.30 $162.95
CCCT 'li',2XI,DF,with SCR+A.100^iHydrog.bwt®gcapabLr S 3437' f3.62 I 14.39% 1 $0.38 557.42 $57.42 i $136.97
SCOT Frame'F al,aAh SCR+Af«H -a ante,80 ba,24 hot $ 5456 $819 1439% $1.18 $160.19 $160.19 S27830
COLT N,1X1,DF,with SCR+p6rH u e,cavt.,806w,24how S 33911 f3.13 14.39% $0.45 S86.46 f86A6 $334.59
CCCT 'fl",2X1,DF,with SCR+pf Hydros.u«age.cavme.BO ba,24 ho« S 3437 f170 j
149% 2 $B1.51 f8L51 f300.93
SCCTF-*Fxl,aihSCR+Af«H s .I.d..500ba,24h« S 5456 f632 143% $146.59 $146.59 I S238.51
CCCT '1 1211.DF.wdh SCR+A f«Hyd,.s-u«ase,tad,.1.W 24 b- S 33.91 f f3.27 14.39% 1 $0.47 $80.83 f80.83 S294.99
CCCT 'H",2X1,DF,with SCR+A f«Hvdso.u e,reel,,500 bm,24 hoe $ 3437. $185 1439% 1 fOAI $75.86 $75.86 $26122
CCCT ,lXl,DF,with SCR Adsaoced Tedmobgy Case+e advmred tahnobgy cae,CCCT I:1 S 33.91 f2.68 I 14.39% 50.39 $60.00 S60.00 I $157.33
CCCT 'H".2X3,DF,wah SCR Adsmced Tedwo Case+padvaocM taboo case,CCC72xl S 3437 f2.23 14.39% 50.32 556.00 f56.00 f130.32
CCCT 'H",1X1,DF,web SCR Adsx-ed Tech-o Ca A edvmced case,CCCT lx1.95'e CCS S 37.961 f5.03 11.52% $0.58 S85.02 $95.02 f283.94
CCCTSCR Ad%a ed Taheolop Case+A adv ed are,CCCT 2xl.95'`.CCS S 31.411 $4.49 11.52% ! 50.52 S77.00 f77.00 S229.40
H aih CCCT 'f(',2X1,DF-d deck S 50.00 0.00% 50.00 S2120 f 4.85 S2120 SI82.03
Ekckdyrzer,Prot-L-U.a Memba-(PEN),50.000 kgldsy S 1 S23.91 0.00% i S0.00 S28.03 S (0.96) S28.03 S35.03
CCS Dave Toh-von 4 coos- t r-8 basis S I1I.40 ! 11.52% ! S1.31 S82.84 S 160.13 S 7. 'S 48710
CCS HMter 1-3 costs a rxaa6t bass $ $9.73 1132% 1 $1.12 $7024 S 160A3 $ 9. f 565.96
CCS 3Ineliegt-1&.2(colts-you rmafitbais) $ $9.63 11.52% $1.11 $71.09 S (160.13)�S (89.04)jf (562.B2
CCS2 B' 3&4 costs- reach best S $10.57 11.52% $122 S70.90 S 160.13 S 923'f 554.00
CCS wyodak(costs-postr &base) $ - S11.69 11.52% i $1.35 $87.70 S (160.13)S (72.43)f (459.1
S. ModdaReactor«Adv-cedReect«,Mad-TvJ..I yCase S - f9.74 j 0.00% f0.00 $82.73 $ (20.29) $62.M 1 f448.80
Gosh. S - f9.74 0.00% $0.00 583.93 $ (20.29)� $6164 ! $458.27
R mach Front S - 1 S9.74 0.00% $0.00 $93.93 S (2129) $61.- -3.88
1\'�-,East $ I $9.74 0.00% ' $0.00 $92.13 $ .29 $59.95 $429.73
S.dlbdw React««Ad-d React«.Advaeced Terbnb Case f f8.74 j 0.00% $0.00 $59.58 S (22.29 $37.29 1 $259.26
SmeB\fodul.Rcacmr«Adv-cedR.mar,ModermeT Case+p 6ca -cte themd $ f10.72 0.00% f0.00 $90.99 S 0.29 $70.71 $508.18
Sma lodulwReactor«Ad-ed Reactor,Ad,-MdT.h-bgy Case+p{or usdezr msegrated m,md stage $ 1 $9.61 0.00% 1 $0.00 .1.53 S .29 f43.24 f300.62
La r Light Waa React«,Mod,ate Tech-b_Case S $9.38 0.00% 50.00 573.09 f 0.29 552.80 f374.94
Lw e1' W-Rawl«.Adv.ced Tedmdo Case $ f7.88 O.00X 50.00 S58.83 S .29 536.55 f237.87
New Field Edwdw!ced Geothermal System(NF-EGS)Buwy S - 1 50.00 0.00% 1 50.. S96.89 S R3.46)1 573.43 ' f514.59
S-d-OR f0.00 0.00% S0.00 S108A2 (23.46)1 f84.96 f595.43
Wwh Fm S96 11 . . . 89 S (25+77)1 $71.12 1 $498.40
-6 f«CCS bstaatbn M Moist g cod Mots u for CCS cons and operakog chwactaisikc ody,na the,peak.. flk a is*W cod reso«ce.
156

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.10-2025 IRP Non-Thermal Supply-Side Resources, Variable O&M, Total Cost and Credits (2024$)
Credits
Total
Tax Credits Resource
(S/DIWh) Cost with Total Fixed
(ITC PTC/ITC Cost rrith Tax
Total Resource Cost already Credits Credit(S/kW-
Resource Description S/MWh) applied) (S/I%Mh) yr)
PV,20 M*North
0 $65.11 S (25.15). $39.96 S95.69
Portlst $76.45 S (25.15) $5130 € S110.04
Southern OR $66.54 S (25.15) $4139 s S 106.20
Walla Walla $69.74 S (25.15) $44.59 S 101.40
Goshen $64.59 S (25.15) $39.44 S96.03
Wasatch Front $61.38 $ (27.63) $33.75 $85.73
Wyoming East $64.79 S 7.63 $37.16 $89.42
PV,200 MW,Class 1-10 $44.24 S (25.15) $19.09 S45.72
Portland North Coast $51.72 S (25.15) $26.57 S56.99
Southern OR S44.87 S (25.15) $19.72 S50.59
Walla Walla 54732 S (25.15) $22.17 S50.41
Goshen S43.86 S (25.15)' $18.71 S45.54
Wasatch Front S41.71 $ (27.63) $14.08 $35.76
Wyoming East W-02 S (27.63) $16.40 1 $39.46
PV,20 MW;Class 1-10+A Advanced Solar Technology Case $60.88 $ (27.63)' $33.25 $79.62
PV,200 MW,Class 1-10+A Advanced Solar Technology Case S41.42 S (27.63) $13.80 $33.03
Wind Class l-10,20MV1' $80.60 S (23.46) $57.14 S145.49
Portland North Coast $102.14 S (23.46) $78.68 S171.70
Southern OR $106.14 S (23.46) $82.68 S182.40
Walla Walla $104.46 S (23.46) $81.00 S164.12
Goshen $69.45 S (23.46) $45.99 S138.03
Wasatch Front $70.08 S (25.77) S4431 S130.77
Wyoming East $69.41 S (25.77) $43.64 S127.01
Wind Class l-6.200MW $42.12 S (23.46) $18.66 S56.18
Portland North Coast $41.47 S (23.46) $18.01 S59.36
Southern OR $47.92 S (23.46) $24.46 € S72.97
Walla Walla $45.68 S (23.46) $2222 S63.43
Goshen S48.49 S (23.46)' $25.03 S6638
Wasatch Front S47.93 S (25.77) $22.16 S59.04
Wyoming East $34.60 $ (25.77)i $8.83 S31.90
Wind Class 7,200 MW 543.59 $ (23.46) $20.13 $60.59
Offshore,Wind Class 12 $18638 S (32.72) $18638 i $514.98
Southern OR $138.33 $ (24.88) $138.33 ! $593.07
Wind Class 1-10,20 MW+A Advanced Onshore Wind Technology Case $75.95 S 25.7 $50.18 $127.76
Wind Class 1-6,200 MW+A Advanced Onshore Wind Technology Case $39.54 S (25.77) $13.77 S41.47
Wind Class 7,200 MW+A Advanced Onshore Wind Technology Case 540.94 S (25.77) $15.17 S45.68
Offshore;Wind Class 12+A Advanced Offshore Wind Technology Case S49.06 S I 1 74 S49.06 $362.89
157

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.11 -2025 IRP Storage Supply-Side Resources,Variable O&M, Total Cost and Credits (2024$)
Variable O&M Credits
Tax Credits
(S/1 M) Total Fixed
(ITC Costvrith
0&:1I already Tax Credit
Resource Description ($/11IR''h) applied) ($&W-yr)
Ion:4-hour,20 MW1 S0.00 S (32.40) $140.22
Ion,4-hour,200 MW1 S0.00 S (27.77) $120.34
Portland North Coast S0.00 S (29.44) $125.15
Southern OR S0.00 S (29.99) $126.75
Walla Walla S0.00 S (28.61) $122.74
Goshen S0.00 S (28.33) $121.94
Wasatch Front S0.00 S (38.14) $108.60
Wyoming East S0.00 S (36.66) $105.93
Ion:4-hour,200 MW+A Double Duration.Li-Ion.4-hour,20OMW1 S0.00 S (23.69) $209.16
Portland North Coast S0.00 S (25.11) $217.37
Southern OR S0.00 S (25.59) $220.11
Walla Walla $0.00 S (24.40) $213.27
Goshen $0.00 S (24.17) $211.90
Wasatch Front $0.00 S (32.54) $189.10
Wyoming East $0.00 S (31.27) $184.54
Ion,4-hour,1000 MW1 $0.00 S (27.05) $116.47
Gravity Battery,4-hour,1000 VIW $0.00 S (33.10) $109.45
Wasatch Front $0.00 S (34.09) $111.22
Gravity Battery,4-hour,1000 MW+A Double Duration,Gravity,4-hour,1000MW $0.00 S (24.62) $183.58
Adiabatic CAES,500 MW,4000 MWh $2.60 S (27.92) $182.29
100-hour Iron Air $0.00 S (37.40) $154.47
Portland North Coast $0.00 S (29.72) $189.65
Wasatch Front $0.00 S (38.52) $158.22
Pumped Hydro,Two New Reservoirs,4-hour $0.58 S (33.01) $118.52
Pumped Hydro,Two New Reservoirs,10-hour $0.58 S (18.40) $157.02
Portland North Coast $0.58 S (19.51) $164.81
Southern OR $0-58 S (19.87) S167-40
Goshen $0.58 S (18.77) $159.61
Wasatch Front $0.58 S (25.28) $136.70
Wyoming East $0-58 S (24.30) $132.41
Pumped Hydro,One New Reservoir,4-hour $0.58 S (31.89) $115.21
Pumped Hydro,One New Reservoir,10-hour $0.58 S (15.65) $136.65
Pumped Thermal Energy Storage,10-hour $0.70 S (34.12) $211.57
Pumped Thermal Energy Storage,24-hour $0.70 S (63.70) $390.51
1A;;n d-4-txd
158

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Table 7.12 - Glossary of Terms Used in the Supply-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).
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.
159

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Term Description
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 (Ibs/TBtu) Expected permitted level of mercury emissions in pounds per trillion
Btu of heat input.
CO2 (Ibs/MMBtu) Pounds of carbon dioxide (CO2) emitted per million Btu of heat input.
Table 7.13 - Glossary of Acronyms Used in Chapter 7
Acronyms 1V 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
CCUS Carbon Capture,Utilization and Storage
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 ff)/ 15 degrees Celsius (°C), Pressure= 14.7 psia/1.013
bar
Li-Ion Lithium Ion
LFP Lithium Iron Phosphate (sub-chemistry of lithium-ion)
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
160

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
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
scenari024, there is a resource row for that scenario.
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 engines,
that are assumed to burn a liquid renewable biofuel like biodiesel or renewable diesel.Each engine
is rated nominally at 5.6 MW with a net capacity of 21.4 MW.,,25 It is presented in the IRP as a 20
MW resource to meet Oregon's regulatory requirements for distributed generation resources,
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 fuel
tanks.26
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
to reduce the inlet air temperature in warmer seasons to increase the CT output. Each CT is also
24 https:Hatb.nrel.gov/electricity/2024/definitions#scenarios
21 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_AE02020.pdf
26 See Appendix M,stakeholder feedback form#59(Renewable Northwest).
161

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
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."27
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."28 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."29
Natural Gas, CCCT "H", 2x1, DF, with SCR—This is "a pair of Model H, dual-fuel CTs in a
2x2x1 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."30
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."31 The 95%option was chosen because that is the most economic option
available in the NREL ATB that meets the EPA I I I 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.
Hydrogen, 4 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
21 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
28 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_AE02020.pdf
"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.cia.gov/analysis/studies/powerplants/capitalcost/pdf/capital_cost_AE02025.pdf
30 Ibid 17
31 2024 ATB Excel Workbook,available at https:Hatb.nrel.gov/electricity/2024/data.
162

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
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 105-106 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."32 In addition to the Pathways to Commercial Liftoff. Clean
Hydrogen (Clean Hydrogen Liftoff Report), the Hydrogen and Fuel Cell Technologies Office
Multi-Year Program Plan33 was used for cost and technical data.
Hydrogen, a 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. ,34
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."35 Data from the DOE Hydrogen and Fuel Cells Program Record36 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 95 percent of the carbon dioxide and would provide reductions in
other emissions.37
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.
32 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,hM2s:Hliftoff.energy.goy/wp-content/uploads/2023/05/20230523-Pathways-to-
Commercial-Liftoff-Clean-Hrogen.pdf
33 Hydrogen and Fuel Cell Technologies Office Multi-Year Program Plan,Dr. Sunita Satyapal,U.S.Department of
Energy,https://www.enerjzy.jzov/eere/fuelcells/h.>�gen-and-fuel-cell-technologies-office-multi-year-pro rg am-plan
34 ibid 20
35 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.
hLtps://www.nrel.gov/docs/fy24osti/87625.pdf,
36 David Peterson,James Vickers,Dan DeSantis,Hydrogen Production Cost From PEM Electrolysis—2019,
February 3,2020,
hllps://www.hydrogen.energy.aov/docs/hydrog_enprogramlibraries/pdfs/l9009 h2 production cost pem electrolysi
s 2019.pdf?Status=Master
37 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 are included because that size was the lowest cost per
kWh in the 2023 IRP. The air storage reservoir is an engineered tank. "Adiabatic" conserves heat
during storage and discharge and 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."38
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
38 hlWs:Hformenergy.com/technology/battery-technology
164

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 report39 ("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.
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.
39 Abdalla Abou-Jaoude,Levi M Larsen,Nahuel Guaita,Ishita Trivedi,Frederick Joseck,and Christopher Lohse,
Idaho National Laboratory;Edward Hoffinan and Nicolas Stauf£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,
hiips:HinldilzitallibrM.inl.gov/sites/sti/sti/Sort 107010.pdf
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Geothermal, Near Field Enhanced Geothermal System (NF-EGS) Binary— This is the ATB
geothermal plant utilizing a 175°C thermal resource with 1.5 km wells and production well flow
rates of 60 kg/s.40
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 supply-side resource table. 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 supply-side resource table 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 IRPs 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 ATB forecast
indicates that 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.
ao 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).
166

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Figure 7.1 —History of Supply-side Resource PV Cost & Forecast
History of SSR Utah PV Costs & Forecast
adjusted for inflation
$2,400 -
$2,200 —
$2,000 —
v
N
ry $1,800
V b
Y $1,600
w
a $1,40006
$1,200
Q �
♦ 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 ° 2018 IRP UT ••0••2019 IRP UT —O—2021 IRP UT
-0- 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 supply-side resource table 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 ATB forecast indicates that 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.
167

PACIEICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Figure 7.2—History of Supply-side Resource Wind Costs & Forecast
History of SSR Onshore Wind Costs & Forecast
$2,300 adjusted for inflation
$2,100
Y
v $1,900
o
$1,700 /
0
$1,500 \
U
C° ~$1,300
$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 ••i••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 supply-side resource table 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 IRPs 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.
168

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Figure 7.3—History of Battery Energy Storage System Costs & Forecast
History of SSR Battery Energy Storage System Costs & Forecast
adjusted for inflation
$1,200
Y
N
N $1,000
N
N
O A ❑••
to EL.•••O. O.
CU -I]...ND
cn $600
M �•?� ��
�•..E3...0
Ln O.
Ln
W $400
Mco
$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
••43••2019 IRP Li-ion NCM —C- 2021 IRP Li-ion NCM
—41- 2021 IRP Li-ion NCM (Utility Scale)---e —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.
169

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.
Comparison of Lazard's Levelized Cost of Energy Analysis-Version 17 (LCOE+ 17)41 and
NREL's 2024 ATB42
Lazard's LCOE+ 17 and the NREL ATB both inform stakeholders about the economic viability of
different energy sources, but they differ in scope, methodology, and the specifics of their cost
assumptions. Each report is assumed to use a consistent but distinct methodology across all
technologies, with technology specific nuances treated fairly. Table 7.14 provides a side-by-side
comparison of pertinent information in the two reports.
Lazard's LCOE+ 17 cost assumptions are based on a standardized financial model with fixed debt
and equity costs. The analysis assumes 60% debt at an 8% interest rate and 40% equity at a 12%
cost, resulting in an after-tax weighted average cost of capital (WACC) of 7.7%.
NREL's ATB offers a range of financial assumption options to reflect different market conditions
and provide a more comprehensive view of potential costs.
Table 7.14—Comparison of Lazard LCOE+ and NREL ATB
Lazard LCOE+ 17 NREL ATB
Levelized Cost of Energy Historic Ranges &Averages Historic and future
(LCOE) "Technology Advancement
Scenarios" options
Levelized Cost of Storage Yes No
LCOS
Levelized Cost of Hydrogen Yes No
LCOH
Finance Assumptions No Yes
Tax Credits Yes Optional
Capital Cost Yes, but not clearly defined "Capital Expenditure"
CAPEX
Construction Cost Assumed to be included Yes
Overnight Capital Cost No Yes
Grid Connection Cost Not clear Yes
Construction Finance Factor No Yes
Construction Cashflow Curve No No
Weighted Average Cost of Yes Yes
Capital
Fixed O&M (FOM) Yes Yes
Variable O&M (VOM) Yes Yes
Capacity Factor CF Yes Yes
Facility Net Power Capacity Yes Yes
Heat Rate I Yes Yes
ai Lazard Levelized Cost of Energy+,June 2024,https://www.lazard.com/media/xemfeyOk/lazards-Icoeplus june-
2024-_vf.pdf
az https:Hatb.nrel.gov/electricity/2024/index
170

PACIFICORP-2025 IRP CHAPTER 7-RESOURCE OPTIONS
Construction Time Yes Yes
Design Life Yes Yes
Energy Storage Duration Yes Yes
Energy Storage Round Trip Yes Yes
Efficiency RTE
Energy Storage Degradation Yes Included in FOM
Regional Resolution Level Regional markets, including Select cites in each state,per
CAISO but not WECC referenced reports
Regional Adjustment Factors No Included in referenced reports
Effective Load Carrying Yes No
Capability ELCC) Analysis
Demolition Costs No No
Outage Rates, Forced and Assumed to be included in Assumed to be included in
Planned CF CF
References or Bibliography No I Yes
The costs reported by Lazard and NREL can differ due to variations in their methodologies and
assumptions. Lazard's LCOE+ 17 tends to provide a more standardized comparison across
technologies,which can be useful for high-level decision-making.In contrast,NREL's ATB offers
a more detailed and nuanced view, considering different scenarios and market conditions.
Reasons for Cost Differences:
• Methodological Differences: Lazard uses a fixed financial model, while NREL
incorporates a range of scenarios and assumptions, leading to different cost estimates.
• Scope of Analysis: Lazard focuses on a high-level comparison of technologies, whereas
NREL provides detailed data for specific scenarios and market conditions.
• Financial Assumptions: Differences in debt and equity costs, as well as WACC, can lead
to variations in the reported costs.
• Technology Assumptions: NREL's ATB includes projections for future technology
advancements, which can result in lower cost estimates compared to Lazard's more
conservative approach.
In summary, while both Lazard's LCOE+ 17 and NREL's ATB provide valuable insights into the
costs of energy technologies, their differences in scope, methodology, and assumptions can lead
to varying cost estimates. Understanding these differences is crucial for stakeholders to make
informed decisions about energy investments.
FDemand-Side Resource
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
171

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
the size,type, location and cost of demand-side resources.43 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.44 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).
• 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).
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 several 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.
" The 2025 Conservation Potential Study is available on PacifiCorp's IRP Support & Studies web page:
www.pacificorp.com/energy/integrated-resource-plan/support.html.
as 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(Public Utilities Commission of Oregon).
See Appendix M,stakeholder feedback form#36(Sierra Club).
See Appendix M,stakeholder feedback form#45(Utah Clean Energy).
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Table 7.15—Demandft-ResonseExistingand Planned Pro rams
State Existingor 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 7.16 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.45 Potential shown is incremental
to the existing DSM resources identified in Table 7.17. 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 7.16—Demand Response Pro ram Attributes West Control Area,46*
Or Summer Winter
Average Average
20-Year Levelized 20-Year Levelized
Potential Cost Potential Cost
roduct M $/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
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
as The CPA can be found at:www.pacificorp.com/energy/integrated-resource-plan/support.html.
46 Demand response resources derived from the demand response RFP are not included to protect confidential 3ra
party pricing information.
173

PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
Table 7.17—Demand Response Pro ram Attributes East Control Area,47*
Summer Winter
Levelized
20-Year Cost 20-Year Levelized
Potential ($/kW- Potential Cost
Product M r)]t (MW) ($/kW-yr)
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 1 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).
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, Wyoming48
• Measure:
— 120 residential measures
— 146 commercial measures
— 105 industrial measures
— 19 irrigation measures
• Facility type:49
— 18 residential facility types
— 28 commercial facility types
— 30 industrial facility types
47 Demand response resources derived from the demand response RFP are not included to protect confidential 3'
party pricing information.
48 Oregon's DSM potential was assessed in a separate study commissioned by the Energy Trust of Oregon.
49 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.
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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
— 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.50 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
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.sl
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
so The identified technical potential represents the cumulative impact of DSM measure installations in the 20r'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.
51 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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PACIFICORP—2025 IRP CHAPTER 7—RESOURCE OPTIONS
resource supply curves. Table 7.18 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.
Table 7.18—2045 Total Cumulative Energy Efficiency Potential by
Cost Bundle Category (MWh)
7Bundle California Idaho Oregon Utah Washington Wyoming
Cooling Measures 34,469 42,040 609,077 1,282,306 102,772 108,946
Heating Measures 28,535 75,471 870,110 751,888 197,253 122,268
Summer Measures 68,513 119,447 1,292,227 1,244,883 366,577 221,926
Winter Measures 221 14,417 103,548 221,229 3,524 347,464
Zero Cost Temperature
Dependent Measures 18,360 84,725 295,605 1,550,447 127,775 84,371
Zero Cost Non-
Temperature
Dependent Measures 33,056 260,493 1,224,970 3,470,030 376,187 626,797
Cost credits afforded to DSM energy efficiency resources include the following:
• A state-specific transmission and distribution investment deferral cost credit (Table 7.19)
• Stochastic risk reduction credit.52
• Northwest Power Act 10-percent credit(Oregon and Washington resources only).53
52 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.
53 The formula for calculating the $/MWh Power Act credit is: (Bundle price - ((First year MWh savings x market
value x 10%) + (First year MWh savings x T&D deferral x 10%))/First year MWh savings. The levelized forward
electricity price for the Mid-Columbia market is used as the proxy market value.
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Table 7.19—State-specific Transmission and Distribution Credits (2024$)
Transmission Distribution
State Deferral Value Deferral Value 4Total
($/kW-year) ($/kW-year)
California $5.83 $11.23 . 6
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
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.
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
Chapter 8 (Modeling and Portfolio Evaluation).
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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. "QY 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 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 several months in advance of the summer and winter seasons.
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 if the seller attests the capacity is surplus to its needs and the resource is registered in
the program, it is unclear how much capacity of that sort is likely to be available, particularly as
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.
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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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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
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.I
• 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(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.
1 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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kntroduction
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.
As addressed in public input meetings and stakeholder feedback forms, the subject of modeling
for portfolio evaluation is highly technical. PacifiCorp consults regularly with the provider of the
PLEXOS optimization modeling software as these methods are developed. Interested parties are
encouraged to review publicly available materials(including recordings)from the 2025 IRP public
input meeting series for additional context and information.2
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 Chapter 9 (Modeling
and Portfolio Selection Results).
Key Changes Since the 2023 IRP
The 2025 IRP public meeting inputs series encompassed many key advancements in modeling and
evaluation strategy, many driven by stakeholder input. These changes are described in detail later
in this chapter. These enhancements are in addition to standard updates applicable to core data
such as load and price forecasting. Each change has been incorporated into the company's
engagement strategy via public input meetings and stakeholder feedback.'
In the 2025 IRP:
• Portfolios must achieve regional and system WRAP compliance.
• Existing thermal units can operate indefinitely with ongoing maintenance.
• IRA Tax Credits are extended through the model horizon(21 years).4
• Jurisdictional portfolios are used to integrate final portfolios.
o States are only able to impact the disposition of resources in which they have an
active share.
o Resource additions are considered situs and must be able to serve requirements in
their associated jurisdiction.
• Improved granularity and reliability evaluation.
• No federal CO2 policy adder is assumed in the expected case.
• Transmission representation now includes a distinct bubble for the Wasatch Front.
2 For discussion of public materials and feedback,see also Appendix C(Public Input Process),Appendix M
(Stakeholder Feedback Forms),and public meeting materials publicly available at
https://www.pacificorp.com/energy/integrated-resource-plan/public-input-process.html.
I See also Appendix C(Public Input Process),Appendix M(Stakeholder Feedback Forms),and public meeting
materials publicly available at https://www.pacificorp.com/energy/integrated-resource-plan/public-input-
process.html.
a The value of production tax credits(PTCs)is reduced in the last five years of the study horizon,to better represent
the value of resource additions in the latter half of the horizon. See Appendix M,stakeholder feedback form#63
(Utah Clean Energy)for additional discussion.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
• A new price-policy variation("MR", medium gas price with at-risk federal regulation)
has been added to account for changing expectations for future federal policy.
• No market purchases are allowed in peak hours on the five days with the highest peak
load in each month, market purchases are allowed up to transmission limits in all other
hours.
• The stochastic analysis incorporates wide-ranging historical volatility in renewable
shapes, thermal outages, load, market prices, and hydro availability.
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 tools, 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.6
5 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).
6 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
loads,Key Planning Assumptions and Uncertainties 2/'
Including ST hourly
\,
fuel costs,granularity definitions,operating portfolio
constraints,reserve requirements, 1 dispatch
L weather year data,etc. �� \, /� Report 3
LT Expansion ST Model
Plan
hourly
shortfalls by
bubble
PreferredPortfolio i i
Iterative � '
Selected on a least-cost le2st-risk basis from Optimization
competing portfolios 6Create LT
Calculate 4
Model with ST granularity
adjustment
drivers
Process new
selection
drivers(riles,
Action Plan scenarios)
5
The portfolio development process in the 2025 IRP is an iterative process, whereby PacifiCorp
completes initial LT capacity expansion modeling runs for each portfolio. Portfolios are evaluated
for cost, reliability and compliance using the ST model, dispatch focused, modeling results. Data
regarding resource value and unserved energy quantities from the ST 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 LT capacity expansion model
has produced a portfolio that demonstrates no unserved energy in the ST dispatch model run, and
then for several phases thereafter,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 ST 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 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 ST model. The ST model performs an hourly
dispatch of the portfolio.
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.
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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
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
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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 ♦ Increase Fixed Cost ♦ Less likely to pick resource
output in IT Model output in 5T Model
IF Energy value of a resource's < Energy value of a resource's ♦ Decrease Fixed Cost ♦ More likely to pick
output in LT Model output in ST Model resource
This iterative process was conducted 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 blocks. 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 with the adjusted load file. If the portfolio selected in phase I 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
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(a deterministic run 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. This process
leads to a portfolio that is reliable on a deterministic hourly basis. 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 Analysis
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 as a guide to volatility and stochastic
relationships. These conditions, including weather patterns, thermal outages, fuel and market
prices, hydro generation, and wind and solar generation profiles, are mapped to historical dates
underlying PacifiCorp's chaotic normal load forecast.PacifiCorp has 18 distinct years of historical
data and ran each portfolio using each specific historical year for all years of the 21-year horizon.
The reported stochastic results are based on fifty randomized combinations of the forecasted results
based on each historical year. In each of the fifty draws, one historical data year is drawn for each
of the years of the IRP study horizon (2025-2045). For example, one draw could include 2025
results based on 2006 weather conditions, 2026 results based on 2015 weather conditions, and
2027 results based on 2020 weather conditions. The same randomized historical year draws are
used for all portfolios so that all portfolios can be examined on a comparable stochastic basis.
Probabilistic analysis therefore depends upon draws from actual historical variance, which is both
more volatile and realistic than prior parameterized variance, improving the verisimilitude of
outcomes. The results from these runs are used to calculate a risk adjustment which is combined
with ST model system costs to achieve a risk-adjusted PVRR to guide portfolio selection.
Responsive to stakeholder feedback, and like consideration made in past IRPs, cases eligible to
become the preferred portfolio which report the possibility of significant end-effects are further
evaluated to determine if a portfolio represents significant long-term costs or risks compared to
other eligible portfolios.
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, and CO2 emissions data
as an indicator of risks associated with greenhouse gas emissions.
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Vesource Portfolio Development
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
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)7 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
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
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:
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.
I 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 439(Western Resource Advocates).
189

PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Figure 8.3 —Transmission System Model Topology with Major Options
2025 IRP
W ash l n g t o n Chehalis Transmission topology
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A/ Walla Walla j
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BPA NITS MCNary
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Wyoming
Central OR Go on
vrllamette Valley 9 ® Longhorn n® Wyoming North
17-1 C t i
o n ?y 1 Bridger D2,2��
im ....... Wyoming
satnmar NetnlnB .y�g2 BorahPopl D3 D3 W....... ®East
5outn Dal Lake NUT Wyoming ��{
4�t®Trona
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$ Nevada Utah
Clover Mona Colorado Colorado
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IN Generation California 4 Corners
$ RM
© Purchase/Sale Markets Mead
® Contracts/Exchanges INarryallenl N e y M e=I c o
F► PacifiCorp Transmission Rights �1(\
F--I- Transmission Capacity Options
*—► Boardman to Hemingway'� Palo Verde
N Internal Capacity Integration Option $
a
O Arizona
This map is for general reference only regarding IRP topology.
PacifiCorp is reevaluating the timing and needs analysis underlying 132H 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.9,10
"Interconnection" requires modifications, additions, or upgrades to physically and electrically
connect a generating facility to the transmission system. Which requirements apply can be
9 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).
to 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.
191

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.I I
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
" See Appendix M,stakeholder feedback form 417(Public Utilities Commission of Oregon)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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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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 Options12,13
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 land 2 2025 12026 1 2027 2028 2029 2030 12031 1 20321 2033 12034 12035 1 2036 1 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 2028 1 2029 2030 12031 12032 12033 12034 12035 12036 12037 12038 1 2.039 12040 12041 2042 2043 2044 2045
Coal 2028 Retired
Dave Johnston 202-1 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 20M 2045
Coal 2028thru 2045
_ _ _ _ _ _ _ _ _ _ _ _ _ _
Cofire-2030/2039111(d) Dual Fuel - - - - - - - - Gas - - - - - -
CoalCCS+SCR 2032 CCS+45Q 4�2-32044
Hunterl-3 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041Coal 2028 thru 2045 - -Cofire Alt.Fuel-2030/2039111(d DualFuel - Alt.Fuel-
CoalCCS+SCR 2032 CCS+45Q Huntington 1-2 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041Coal 2028thru 2045 - -Cofire Alt.Fuel-2030/2039111)d DualFuel - Alt.Fuel-CoalCCS+SCR2032 I CCS+45Q I CCS -
Key Default/current operation ri
CCS
Retirement Option Alternative Fuel
Gas conversion option Assumed retired
12 While 11 l(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 based on the cost of biodiesel,which results in a dispatch price of over$400/MWh
(2024$).
f3 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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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
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 Options14
Chehalis 2025 2026 2027 2028 12029 1 2030 1 2031 2032 2033 2034 2035 2036 2037 1 2038 1 2039 1 2040 2041 2042 2043 2044 2045
Gas-2028 thru 2045
Cofire/non-emitting 2030
Currant Creek 2025 2026 1 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 1 2043 2044 2045
Gas-2028 thru 2045
_
Hermiston 112 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 1 2042 1 2043 2044 2045
Gas-2028 thru 2039/Alt.Fuel
Jim Bridger Units 1 and 2 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 1 2025 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 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
_ _ ]2040
Nau hton Units land 2 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2041 2042 2043 2044 2045
Gas-2026 thru 2045as _ _ _Naughton Unit3 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2041 2042 2043 2044 2045
Gas-2028 thru 2045 _ _Gadsby Steam 1-3 2025 202 22027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2041 2042 2043 2044 2045
Gas 2028thru 2045Gadsby Crs 4-6 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 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 Management
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.
"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 lh to advance options for potential implementation by 2030.
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
Wind and Solar Resources
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.
• 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
195

PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
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.
From a modeling perspective,it is not feasible to incorporate all 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 1st 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 6.38 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.15 PVRR
figures reported in the 2025 IRP are reported in 2024 dollars.
15 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 111(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.16 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 PaciflCorp 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 2021.17 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 2024.18
16 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).
17 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).
18 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://apps.ecology.wa.gov/publications/documents/2302066.pdf(Accessed 11/8/2024).
197

PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Figure 8.4 —CO2 Prices Modeled by Price-Policy Scenario
WA CCA CO2
$340 (ChehaUs)
$320 — —231RP(M)
$300 ---231RP(H)
$280
$260 t 251RP SCGHG
$240 25 IRP HH
$220 —
`p �� _ MCA CO2
$180
o $160
Z
$140 i
$120 _
$100 r r_ .
Sao
$fio
$40
$20 — — — — — — — —
otia oti`' oti6 oti� oti° ory9 0'�° 031 o3ti o3� o'�°' o'�`' 0'�6 03� 03° 0'�9 oa° oat oati oar oa°' cAy
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
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 PaciflCorp'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.19 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 AURORAxmp20 (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
19 The September 2024 OFPC prompt month is November 2024;October 2024 would be traded as"balance of
month"when the OFPC is released.
20 AURORAxmp is a proprietary production cost simulation model,developed by Energy Exemplar,LLC.
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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.21 The increased cost calculated for coal pricing was developed by evaluating the
percentage difference in the average annual gas prices at Henry Hub between the medium and high
cases. Annual percentage differences were then applied to each coal plant's coal supply price over
the 21-year horizon.
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
Ai erage of Palo Verde and Mid-C(Flat) Henry Hub
$120 $14
$110 $13
$100 $12
$90 i Sll
$� S10
.ta. a S9
$70 8 Ls
$60
e, $50 $6
$40 ss
$20 $2
$10 $1
so _ so
M uY 10 n 00 eT O .-. N nn y vi O P- ee T O Ny M O h O r W a, O .• N M < h O r` 00 T O N
0
0 0 0 0 0 0
•••••\fgaa 3,1CO2(jfar MI) .....Sfpa_JSCO2(Sep 2022)
- - -Lgas OCD2(Sep 2022) 1fPa-00O2(SeP 2022) .....Ivfedim(Afar SKl) -bfedium(5p 2112'7
-Hgas HCO2(Sep 2022) -Sigas_SCO2(Sep 20M 1 -Low(Sep 2022) High(S.P 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.
Sl 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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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.
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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 resource table). In
initial jurisdictional runs, small generator and local battery resources are limited based on the load
in each transmission bubble, due to the assumption these are sized to serve local load so as not to
require transmission investment.
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.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
Each run of the ST model produces an optimized dispatch of a 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 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 and the typical range
of outcomes across each month. For stochastic modeling in the 2025 IRP, alternative inputs are
used that reflect conditions analogous to actual results in a specific historical year. Stochastic
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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.
Appendix H (Stochastics) discusses the methodology for developing the stochastic inputs for the
2025 IRP.
Stochastic Conditions
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, using historical data based on 2015, 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, random 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
• 5th,901h and 951h percentile PVRR
• Standard deviation
• Risk-adjustment
• Energy Not Served(ENS)
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 COZ emission costs for any scenarios that include a COZ 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.
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5a' and 95th Percentile PVRR
The 51h and 95th percentile PVRRs are also reported from the 18 results drawn from the ST runs
under 18 distinct stochastic conditions. 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 51h
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 50 random draws of the 18 runs under stochastic conditions. 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 50 random draws 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 random draws 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.
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 Syste
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 AdequacX
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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 Serge 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
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
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2021 IRP, market purchases were restricted compared to past IRPs, as described in Chapter 7
(Resource Options).
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 PVRR, 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 Portfolio Selection
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
emissions results can be used to differentiate portfolios that might be closely ranked on a risk-
adjusted PVRR basis.
Case Definitions
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.
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o Integrated Portfolios incorporate 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
• Sensitivity Cases
Additional portfolio detail can be found in Appendix I (Capacity Expansion Results).
Initial Portfolios
Informed by the public-input process, the initial cases explore significant interactions among
retirement options including the potential to convert coal units to natural gas or biodiesel
operations, install carbon-capture equipment on coal-fired facilities, and retire units during the
study horizon. 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.
Jurisdictional Definitions and Modeling
As discussed above, distinct requirements exist for various jurisdictions, and some of these
requires conflict. As a result, initial portfolio modeling is used to separate the requirements as
described below, allowing for the development of optimal portfolios of resources to meet
jurisdictional needs.
Compared to Oregon and Washington, modeling for Utah/Idaho/Wyoming/California (UIWC) is
more focused on least-cost resource selection regardless of fuel type. UIWC resources must meet
the Western Resource Adequacy Program (WRAP)requirements for this jurisdiction. As a result,
the only modeling constraint for this jurisdiction is one which combines load and requires the
model to select enough total resources (including existing resources under current allocation
protocols) to meet WRAP planning requirements. All resources are eligible for inclusion in these
states and this requirement.
All Washington resource selections are analyzed and optimized assuming the SCGHG price-
policy scenario, as required under RCW 19.280.030 for clean energy planning.
Oregon initial portfolios model compliance with House Bill 2021. Oregon participates in existing
coal-fired resources through 2029 and existing gas-fired resources (including the gas conversions
of Naughton 1 and 2 in 2026 and the endogenously selected conversion of Dave Johnston Units 3
and 4 in 2029)through 2039. Emissions allocated to Oregon from existing resources are calculated
based on Oregon's current share of the resources and the appropriate Oregon DEQ emissions
factors. Like other jurisdictions, Oregon must be WRAP compliant. PLEXOS models face
challenges meeting annual emissions constraints due to the need to model slices of time in each
different model (as described earlier in this chapter). This has been addressed by assessing a
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shadow price on Oregon allocated emissions as a model driver to ensure HB 2021 compliance is
achieved. The shadow price is not reported from the model as a cost to customers, but is instead
used to impose a penalty on the model if Oregon allocated resources emit CO2-E. This price drives
the model to reduce emissions (and generation) and select additional resources to meet Oregon
load. Compliance for Oregon is measured by determining whether there is enough Oregon-
allocated generation to meet Oregon load on an annual basis while also having emissions below
the Oregon required thresholds.
Five price-policy scenarios were evaluated in this IRP:
• MN: Medium natural gas/No federal CO2regulations
• MR: Medium natural gas/current federal CO2 regulations under Section 111 of the Clean
Air Act.
• LN: Low natural gas/No federal CO2 regulations.
• HH: High natural gas/High CO2 cost applied to all generators (updated CO2 forecast,
starting 2030)with no other federal CO2 regulations.
• SC: Medium natural gas/Social cost of greenhouse gases (starting immediately) from
Washington docket U-190730 with no other federal CO2 regulations.
Table 8.4 provides the price-policy case definitions for the 2025 IRP. Additional information,
including coal unit retirement assumptions, are provided for each case in Appendix I (Capacity
Expansion Results).
Table 8.4—Price-Policy Case Definitions
Price- Existing Coal(') 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, offshore wind, storage, natural gas, transmission, DSM,
purchases and sales,etc.
In all five price-policy 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. This cost is incremental to the CO2 cost included
in each price-policy scenario. Where applicable, the price-policy scenarios above represent CO2
as a cost applicable to all emitting resources,based on the direct emissions associated with the fuel
consumed by each generator.
The 2023 IRP included a medium natural gas/medium CO2 (MM)price-policy scenario. The MM
price-policy scenario, which was the price-policy included in the 2023 IRP preferred portfolio,
was excluded from the 2025 IRP. In the 2023 IRP, the MM price-policy was included as a proxy
to represent potential future federal CO2 regulations. For the 2025 IRP the MR price-policy
scenario, which was not included in the 2023 IRP, encompasses federal CO2 regulations. This
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price-policy scenario was added in response to the final CO2 regulations issued by EPA on April
25,2024,which apply to new natural gas-fired combustion turbines and existing coal,oil, and gas-
fired steam turbines.
All portfolios consider variations in retirement timing, the impact of regional haze compliance
operating limits and options for gas conversion or CCS 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
efer 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 convert to gas by January 1, 2032
Offshore Wind Counterfactual to the Preferred -
Portfolio selection: Offshore
wind must be selected
No Forward Technology No nuclear, hydrogen storage, -
100-hour storage or biodiesel
peaking
Geothermal Counterfactual to the Preferred -
Portfolio selection:
Geothermal must be selected
Hunter Retire Require all Hunter units to -
retire no later than 1/l/2030
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
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
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 were not a commercially viable
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option. This variant was analyzed twice, once using the MN price-policy scenario and once using
the MR price-policy scenario.
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 CCS 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 all portfolios 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.
No Forward Technology
In this variant all nuclear, hydrogen storage, 100-hour battery, and biodiesel peaking resources
are removed from the preferred portfolio and the portfolio is re-optimized without these resource
options. The removal of 100-hour battery as an option in this variant is in response to stakeholder
request.22 The purpose of this variant is to evaluate the cost and risk impacts of limited new
resource types becoming available in the future.
Geothermal Counterfactual
Like the offshore wind case, advanced geothermal units are available for selection in all
portfolios in Central Oregon and Southern Utah starting in 2027. These resources require
transmission upgrades to be enabled. Pursuant to stakeholder interest23, as geothermal is not
selected for the Preferred Portfolio, a minimum of 707 MW of geothermal resource must be built
22 See Appendix M,stakeholder feedback form#55(Utah Division of Public Utilities).
23 See Appendix M,stakeholder feedback form#56(Utah Clean Energy).
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in Central Oregon or Southern Utah. This counterfactual is used to assess system impacts and the
magnitude of costs associated with geothermal and its associated transmission requirements.
Hunter Retire
Responsive to stakeholder interest, a variant is considered that forces all three Hunter coal units
to cease all operations by 2030.24 This variant forces the retirement of the Hunter Plant in any
year from 2028 to 2030. The purpose of this variant is to assess the impact on cost and emissions
when Hunter is precluded from continued operation.
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 for environmental compliance. 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
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. Hunter and Huntington, which are not eligible for gas
conversion,were eligible for alternative fuel conversion but were not forced to convert.
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
za See Appendix M,stakeholder feedback form#53 (Sierra Club).
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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, identified as 1)"UIWC"for Utah,Idaho,Wyoming and California,2) "OR"
for Oregon and 3) "WA" for Washington. 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. Given concerns related to the availability of transmission on
an hourly basis between the West and East sides of PacifiCorp's system, the selection of proxy
resources on the West is determined jointly by the Oregon and Washington initial jurisdictional
portfolios, and the selection of proxy resources on the East is determined by the initial
jurisdictional UIWC portfolio. Accordingly, only the jurisdictional portfolios that determine the
selection of a given resource are eligible to participate in that resource.
Table 8.6—Portfolio Integration Resource Example
Jnrisidiction Fixed Share Initial Portfolio Selection(1IR) Total Allocation(AIR)
Oregon 7500 1>0 112
Washington 25% 60 :-
Total 1000/0 1 0
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.
The initial integration step has the potential to result in compliance shortfalls, as a portion of the
resources that were identified for compliance may be shared with other jurisdictions. Thus, the
final step of the integration process is to identify and remedy any such shortfalls in energy and
capacity compliance.
Washington Portfolios
The integrated preferred portfolio reflects Washington customer energy and capacity needs and
the CETA clean energy standards from 2030 onwards. The final integrated portfolio presents a
CETA-compliant path towards the production of a quantity of clean megawatt hours that meets
Washington's retail sales on an annual basis, as described in further detail in Appendix O
(Washington's Clean Energy Action Plan). This CETA-compliant portfolio is a starting point for
the analysis that will be provided in the forthcoming 2025 Clean Energy Implementation Plan
(CEIP), expected to be filed with the Washington Utilities and Transportation Commission in
October 2025.
The focus of this IRP filing is to present an integrated preferred portfolio that meets all state-
specific requirements. As described in this chapter and further in Appendix Othe 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. The following scenarios and sensitivities required by
Washington rule are also included.
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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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-
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 the IRP
analysis reflects impacts related to climate change and 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
PacifiCorp identified a variety of sensitivities outlined in Table 8.7 and discussed further in
Chapter 9.
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PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
Table 8.7—Sensitivi Case Definitions
1 0 A=d
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 CCS Allows CCS to be selected at additional coal units
Business as Usual Portfolio if no state requirements existed
Business Plan First 3 years are aligned with the current business plan
Load Sensitivities
The 2025 IRP includes several sensitivities related to load forecast assumptions. Figure 8.6
provides a comparison of load by year for each case, including the base assumption for
comparison. Definitions for all sensitivities are then discussed individually,below.
Figure 8.6—Load and Private Generation Sensitivity Assumptions
25,000
23,000
21,000
19,000
17,000
3 15,000
13,000 or
11,000
9,000
o ' tK
ZrV oti^ oti�Zr';q o")o o'*j o'� o") o'� o'� o")�O o'' Z'� Z' cP° o�� c K Z11K ZtK
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
Base Case High PG Low PG High
Low 1-in-20 Weather High DC
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.
213

PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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 based on median load conditions (exceedance in 10 of 20
years) is replaced with a higher load forecast based on peaks that reflect an expected 1 in 20 year
exceedance level. The preferred portfolio is re-optimized with this new load forecast to evaluate
the cost and risk impacts of higher peak loads.
High Private Generation
In this sensitivity the base load forecast is replaced with a new load forecast incorporating high
private generation adoption 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
adoption.
Low Private Generation
In this sensitivity the base load forecast is replaced with a new load forecast incorporating low
private generation adoption 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
adoption.
Large-Metered Load Growth
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 this future. A variety of transmission upgrades are necessary
to meet the significant load increases contemplated in this sensitivity, including B2H. This
portfolio uses the same integration process as the preferred portfolio to address any state
compliance shortfalls.
Low-Cost Renewables
This sensitivity assumes high IRA/IIJA adoption results in significant cost reductions for
PTC/ITC eligible resources, making them more likely to displace 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 the availability of lower
cost renewables 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 CCS
214

PACIFICORP—2025 IRP CHAPTER 8—MODELING AND PORTFOLIO EVALUATION
This sensitivity allows CCS to be selected at Wyodak, Hunter Units 1-3, Huntington Units 1 and
2, and Dave Johnston Unit 4, in addition to the option of CCS at Jim Bridger Units 3 and 4. ,
This sensitivity relies on the assumption that it is feasible to complete installations at all of these
units 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 CCS were a commercially viable option at more than one coal site
before 2032.
Business As Usual" (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 set so that
coal plants retire no earlier than assumed in the 2017 IRP Update except to the extent that
updated commitments or requirements supersede the older assumptions. The portfolio is
otherwise fully endogenous. 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
The unconstrained integrated MN case does not select new resources in the first three
years,please refer to the Preferred Portfolio for results.
In the 2025 IRP, this case has the same assumptions as the integrated preferred portfolio. 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.
15 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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PACIFICORP-2025 IRP CHAPTER 8-MODELING AND PORTFOLIO EVALUATION
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PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
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 includes 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 builds upon 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 forthcoming RFPs 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 NatriumTM
demonstration project, anticipated to achieve online status by the end of 2031. Over the
planning horizon,the 2025 IRP preferred portfolio includes 3,782 MW of new wind,and 5,912
MW of new solar, of which 1,147 MW is small-scale.
• 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, and additional upgrades that increase transfer and interconnection capability on the
west side of PacifiCorp's system.
• 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 were converted to natural gas where the option was
available.
• In the 2025 IRP, four factors related to emitting resources drive a reduction in CO2 emissions
after 2025. These factors are retirements (minority-owned units and Dave Johnston 3),
additional natural gas conversions (Naughton I and 2 and Dave Johnston I and 2), reduced
capacity factors at existing coal and natural gas facilities(influenced by additions of renewable
resources and energy storage), 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 because 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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PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
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. As illustrated in Figure 9.1, the final
preferred portfolio selection is informed by all relevant modeling results.
Figure 9.1 —Portfolio Integration and Selection Workflow
Full Jurisdictional Portfolios Oregon Each jurisdictional
(for all variants) Washington portfolio is a full system
UIWC optimization assuming the
constraints and requirements
of the jurisdiction-
1\a Offshore
No ase ind
N 3as Offshore
Nucl Base Wind Offshore
Wind
J
Integration Process
Integration follows a linear
series of steps designed to allocate and
preserve each jurisdictions'selections
while mitigating overbuild.
Geothermal Base
No Nuclear
Offshore
Wmd No Fora ai i
Tech
Once integrated,all
Variant portfolios and the base
Evaluate Integrated Portfolios case are evaluated for relative cost,
— — emissions,reliability,risk metrics and
final compliance.
d ,�oA
The preferred portfolio is selected as the
Preferred Portfolio Selection best of all eligible cases.
This chapter also presents discussion of Oregon's compliance position in the preferred portfolio.
218

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Results of resource portfolio cost and risk analysis from each step are presented in the following
discussion of PacifiCorp's portfolio evaluation processes. Stochastic analysis is also discussed in
Volume II, Appendix H (Stochastics).
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 Oregon MN initial jurisdictional run to show 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 was selected for integration.
In Table 9.1, phase 17 was selected as the Oregon initial portfolio for inclusion in the MN
integrated portfolio. This selection takes into consideration the PVRR of$26,298 million, and the
stream of unnerved energy costs that led to a total cost of$0 and had no unserved energy after
2027. Other phases which were considered were phase 11, phase 15, and phase 5, however the
higher PVRR of phases 15 and 5,and the fact that phase 17 was more WRAP compliant than phase
11 led to phase 17 being selected.
Table 9.1 —Iterative phases of Oregon MN portfolio
Phase Jurisdiction Ace-Policy 21 Year PVRR Unserved Energy Cost
OR Medium Gas, No CO' 26,108 1
1 OR Medium Gas, No CO2 26,809 0
OR Medium Gas, No CO2 26,314 0
OR Medium Gas, No CO2 26,353 1
OR Medium Gas, No CO2 26,405
OR Medium Gas, No CO2 26,372
6 OR Medium Gas, No CO2 26,370 1
7 OR Medium Gas, No CO2 26,343
8 OR Medium Gas, No CO2 26,442 1
9 OR Medium Gas, No CO2 26,365
10 OR Medium Gas, No CO2 26,498
11 OR MediLun Gas, No CO2 26,298
12 OR Medium Gas, No CO2 26,461 1
13 OR Medium Gas, No CO2 26,366
14 OR Medium Gas,No CO2 26,447 1
15 OR Medium Gas,No CO2 26,361
16 OR Medium Gas,No CO2 26,388
17 OR Medium Gas,No CO2 26,298
18 OR Medium Gas,No CO21 26,463 1
19 OR Medium Gas,No CO21 27,058
219

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
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 I, 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.
Jurisdictional Shares of the Preferred Port
Table 9.2 through Table 9.4 present each jurisdiction's assumed share of total preferred portfolio
resources as contained in the integrated preferred portfolio. These shares are based on the results
of full jurisdictional portfolios that reflect planning requirements specific to the different
jurisdictions, as discussed in the next section. For more information about how jurisdictional
portfolios are determined, refer to Chapter 8.
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PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.2 —Oregon Sharer,z,3
OR Shares by Resource Type and Year,Installed NIW
Installed Capacity,MW
Resource 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Nuclear - - - - - - - 130 - - - - - - - - - - - - - 130
Renewable Peaking - - - - - - - - - - - - - - 19 - 4 18 40
DSM-Energy Efficiency - 97 101 107 114 115 110 113 108 109 111 110 106 102 116 123 107 114 9, 90 2,044
DSM-Demand Response - 0 48 16 7 - 1 3 3 11 - 11 4 23 4 - 9 8 153
Renewable-Wind - 16 445 939 - 1 - 22 260 30 131 28 0 282 37 15 72 2,278
Renewable-Utility Solar - 167 135 1,268 136 180 302 169 10 - 1 0 0 416 78 9 - 148 56 3,074
Renewable-Small Scale Solar - - - 320 2 18 26 21 30 132 0 309 - - 110 143 36 1,147
Renewable-Battery,<8 hour - 1 280 100 128 - 119 39 210 20 47 - 46 - 107 55 - - - - 1,152
Renewable-Battery,24+hour - - - - - 272 88 - - - - - 7 79 33 934 102 210 397 192 353 2,667
Potential Solar Acceleration 794 (794)
Table 9.3 —Washington Share4
Installed Capacity,MW
Resource 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 204 Total
Nuclear - - - - - - 32 - - - - - - - - - - - - - 32
Renewable Peaking - - - - - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency - 0 13 16 15 17 18 18 19 19 20 19 19 15 14 12 11 11 10 8 7 280
DSM-Demand Response - 0 - 15 2 2 - - - - - 8 - 6 1 1 1 - 1 - 14 51
Renewable-Wind - - - 5 148 313 - - - 7 87 10 44 9 0 94 12 - 5 - 24 758
Renewable-Utility Solar - - - 56 45 423 45 60 101 56 3 - 0 0 139 26 3 - - 49 19 1,025
Renewable-Small Scale Solar - - - - - - - - - - - - 0 - - - - - - - - 0
Renewable-Battery,<8 hour - - - 865 114 168 - - - - - - - 129 67 7 12 - 5 - - 1,367
Renewable-Battery,24+hour - - - - - 238 3 3 4 3 4 4 4 4 4 4 4 5 5 5 5 298
Potential Solar Acceleration 212 (212)
' See Appendix M,stakeholder feedback form#49(Utah Association of Energy Users).
2 While the 2025 IRP preferred portfolio indicates that a largely just-in-time strategy is the most economic means of achieving compliance with Oregon's clean energy
compliance requirements,PacifiCorp's 2025 CEP will evaluate other alternatives like the potential accelerated compliance indicated in Table 9.2.For more details,
please refer to Appendix P(Oregon Clean Energy Update)
s Planned Energy efficiency and demand response selections in 2025 and 2026 are not presented in Tables 9.2 through 9.4.
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PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.4—Utah, Idaho, Wyoming, and California Share
UTWC Shares by Resource Type and Year,Installed AM
Installed Capacity,MW
Resource 2025 12026 12027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Nuclear - - - - - - - 338 - - - - - - - - - - - - - 338
Renewable Peaking - - - - - - - - - - - - - - - - -
DSM-Energy Efficiency - 0 99 103 117 130 196 163 167 168 170 185 218 193 177 172 170 197 114 106 86 2,931
DSM-Demand Response - 1 - 2 111 99 - - - - 2 112 - - 0 57 106 19 26 30 566
Renewable-Wind - - 200 200 344 - - - - 0 - - - - - - - - 744
Renewable-Utility Solar - - - - 668 - - - - 0 - - - - - - 668
Renewable-Small Scale Solar - - - - - - - - - - - - - - - - - - -
Renewable-Battery,<8 hour - 1 - 27 - - - - - - 0 - - - - 713 - 459 733 1,933
Renewable-Battery,24+hour - - - - - 1 - - - - - - - - 104 - - - 105
Full Jurisdictional Portfolios
Each jurisdiction's resource selections begin with a view of the entire system as optimized under that jurisdiction's particular constraints.
These idealized views of the system allow each jurisdiction's preferred resource selections to be identified. These portfolios are referred to as
the `full jurisdictional portfolios' and show the selections prior to integration.
The following portfolios shown in Table 9.5 through Table 9.7 report the entirety of each jurisdictional portfolio's selections when planning
for the entire system, which were then integrated into the preferred portfolio. This same integration process is used to develop integrated
portfolios specific to each variant and price-policy scenario, and the preferred portfolio is selected based on the results for the integrated
portfolios.
4 While the 2025 IRP preferred portfolio indicates that a largely just-in-time strategy is the most economic means of achieving CETA compliance,PacifiCorp's 2025
CEIP will evaluate other alternatives like the potential accelerated compliance indicated in Table 9.3.For more details,please refer to Appendix O(Washington Clean
Energy Action Plan)
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PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.5—Oregon Full Jurisdictional Portfolio
'Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 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 - - - - - - - - - M283
- - - -
Gas-Peaking
_ _ _ _ _ _ _ _Nuclear - - - 500 - 500
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _Renewable Peaking - - - - - - - 19 4 184l
DSM-Energy Efficiency 92 89 201 209 220 237 306 280 283 280 300 309 333 303 291 266 286 252 230 189 5,239
DSM-Demand Response 18 2 53 17 9 53 5 1 3 3 11 259 15 23 4 100 9 50 25 710
Renewable-Wind - 21 260 1,066 100 51 29 347 40 175 37 376 50 20 96 2,668
Renewable-Small Scale Wind - - - - - - - - - -
Renewable-Utility Solar 122 99 1,871 19 220 315 225 13 554 104 12 197 75 3,826
Renewable-Small Scale Solar 320 2 18 26 21 30 132 309 110 143 36 1,147
Renewable-Geothermal
_ _ _ _ _ _
Renewable-Battery,<8 hour - 876 255 228 31 119 39 210 20 83 104 100 314 58 2 2,439
Renewable-Battery,8-23 hour _ _ _ 17 224 _ _ 241
_ _ _ _ _ _ _ _ _ _ _
Renewable-Battery,24+hour 134 59 4 752 128 341 59 1,477
- - - - - - - - - - - - - -
Other Renewable - -
Storage-Other _ - - - 1
_ _ _ _ _ _ _ _ _ _ _
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) (1,387) (1,949)
- - - - - - - - - - - - - - - - - -
Coal-CCS 526 (526) 0
- - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions - 46 687 - (418) 315
Gas Plant Retirements - - - (79) (79)
Retire-Hydro
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Refire-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-QF - (47) (3) (50)
Expire-Other - s20 (20) 500
Total 1 110 1 153 1 201 1 1,026 523 1 3,444 1 302 1 1,193 1 664 1 765 1 713 1 575 1 667 1 795 1 1,008 1 2,084 1 249 1 (140) 581 387 1 (18)
223

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
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 1 2028 1 2029 1 2030 1 2031 1 2032 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 - - - - - - - - - - - -
Gas-Peaking
_ _ _ _ _ _ _ _ _ :2900316
_ _ _ _ _ _ _ _ _ _ _
Nuclear - - - - 500 - - 500
Renewable Peaking - - - - - - - - -
DSM-Energy Efficiency 92 89 224 235 215 234 289 287 291 323 356 324 304 293 278 302 268 234 186 5,430
DSM-Demand Response 18 2 2 197 5 17 43 17 24 8 5 331 31 27 107 834
Renewable-Wind 1,607 260 1 - - 1,868
Renewable-Small Scale Wind - - - - - - - - - - -
Renewable-Utility Solar 201 138 463 1,437 770 527 418 772 249 100 1 1 5,076
Renewable-Small Scale Solar
- - - - - - - - - - - - - - - - - - - - - -
Renewable-Geothermal -
Renewable-Battery,<8 hour 38 856 232 1,376 - - - 129 67 66 129 149 646 170 1,357 5,215
Renewable-Battery,8-23 hour
- - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery,24+hour
- - - - - - - - - - - - - - - - - - - - - -
Other Renewable
Storage-Other - - - - -
Existing Unit Changes
Coal Plant Retirements-Minority Owned (82) (33) (123) (148) - - (386)
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Coal Plant Retirements (906) - - (906)
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Coal Plant Ceases as Coal (357) (205) (2,679) (3,241)
- - - - - - - - - - - - - - - - - -
Coal-CCS 526 (526) 0
- - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions - 311 205 1,979 (330) - - (448) 1,717
Gas Plant Retirements - - - -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Hydro -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Non-Thermal (3) 0(32) (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 - s20 � (2�00) 500
Total 1 110 1 418 264 1 548 1 2,074 1 1,669 1 1,447 1,558 1 818 1 705 1 1,088 1 615 1 356 1 439 1 395 1 367 1 14 1 782 1 898 1 198 656
224

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.7—Utah, Idaho, Wyoming, California (UIWC) Full Jurisdictional Portfolio
'Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,MW
Resource 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 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 1 2045 Total
Expansion Options
Gas-CCCT - - - - - - - - - - - - -
Gas-Peaking
Nuclear - - - 500 - - 500
Renewable Peaking - - - - - - -
DSM-Energy Efficiency 92 89 164 170 182 196 270 236 247 251 261 286 312 284 278 257 252 283 216 200 165 4,691
DSM-Demand Response 18 2 2 7 112 99 5 39 115 3 4 70 106 43 30 32 687
Renewable-Wind - - - 306 684 344 - - 1,334
Renewable-Small Scale Wind - - - - - - - - - - - -
Renewable-Utility Solar - - 153 12 79 668 31 123 133 3 - - 2 - 65 1,269
Renewable-Small Scale Solar
- - - - - - - - - - - - - - - - - - - - - -
Renewable-Geothermal - -
Renewable-Battery,<8 hour - - 193 71 224 - 85 171 4 474 249 140 469 713 896 1,097 733 5,519
Renewable-Battery,8-23 hour
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Renewable-Battery,24+hour 104 104
- - - - - - - - - - - - - - - - - - - -
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 5
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Coal-Gas Conversions - 251 144 - - (156) 239
Gas Plant Retirements _- - -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Retire-Hydro
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Refire-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-QF - (47) (5) (52)
Expire-Other - s20 I 1:::(2::Ol) 500
Total 110 1 358 1 164 1 263 1 394 1 974 1 1,172 1 736 1 278 1 371 1 484 1 499 1 331 1 729 1 527 1 403 1 393 1 1,206 1 426 1 1,157 910
225

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
226

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Pie 2025 IRPTreferred Portfolio
The preferred portfolio is selected from among all of the variant and price-policy portfolios after
integration. 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 9.2 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 are scheduled to 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 fall 2031. By the end of 2032, the preferred portfolio
includes 2,408 MW of energy storage resources, including 605 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 3,782 MW of new wind and 5,912 MW of new
solar.
Figure 9.2—2025 IRP Preferred Portfolio (All Resources)
45000
40000
35000
30000
25000
20000
15000 IEEE
10000 0 __. _
5000 ■soon
' ck`h
?V CIV
■Coal ■Converted Gas ■Gas ■Hydrogen Storage Peaker
z Renev.able Peaking m QF Hydro z Nuclear
e Hydro Storage m Battery Solar ■Wind
■Geothermal ■Energy Efficiency ■Demand Response 0 Nff-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.
New since the 2023 IRP, the 2025 IRP preferred portfolio includes a number of smaller
incremental upgrades to enhance transfer capability, including lines between southern Utah and
the Wasatch Front in Utah, Walla Walla and Yakima in Washington, Walla Walla and Deschutes
County in Oregon, and Summer Lake and Deschutes County in Oregon.
227

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. Eight out of the fourteen transmission
selections are expected to increase interconnection capability only,while the other six transmission
selections provide both interconnection capability and increased transfer capability among the
transmission areas modeled in the IRP. 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
]Export Import Interconnect Build I-estinent Build
2626 Utah South-Wasatch Front:138 kV reinforcement#1 250 1 250 250 30 100% Utah South Wasatch Front
2028 Cluster 1 Area 11:Willamette Valley 0 1 0 199 14 100% n/a n/a
Cluster 1 Area 14:Summer Lake 400 400 400 111 100% Summer Lake Hemingway
Cluster 1/2/3:Walla Walla 0 0 393 328 100% n/a n/a
Serial queue:Central Oregon 0 0 152 4 100% n/a n/a
Sc iaVCluster 1/2:Yakima 0 0 628 64 100% n/a n/a
Utah South-Wasatch Front:138 kV reinforcement#2 200 200 200 12 100% Utah South Wasatch Front
2029 Cluster 2 Area 23:Willamette Valley 0 0 393 2 100% n/a n/a
2030 Cluster 2 Area 19:Sumner Lake to Central Oregon 500 kV 1,500 1,500 670 1,283 100% Summer Lake Central OR
Walla Walla-Yakima 230 kV 400 400 400 142 100% walla Walla Yakima
2031 Serial through Cluster 1 Area 13:Southern Oregon 0 0 231 42 100% n/a n/a
2032 Cluster 1 Area 12:Southern Oregon 0 0 300 303 100% n/a n/a
2033 Cluster 2 Area 18:Central Oregon 500 kV Substation 0 0 518 372 100% n/a n/a
2039 Walla Walla-Central Oregon 500 kV 1,500 1,4,2500 670 1,463 100% Walla wawa Central OR
Grand Total 4,250 50 5,41 4,169
l 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 some project-specific timing and costs.
New Solar Resources
The 2025 IRP preferred portfolio includes 2,092 MW of new utility scale solar by the end of 2030,
3,822 MW by the end of 2035, and 4,765 MW by the end of 2045. Additionally, the 2025 IRP
preferred portfolio includes 320 MW of new small scale solar by the end of 2030, 417 MW by the
end of 2035, and 1,157 MW by the end of 2045. These cumulative totals are shown in Figure 9.3.
Figure 9.3—2025 IRP Preferred Portfolio New Solar Capacity
10,000
8,000 -------------------------- —
6,000 �,----------'.---
4,000 -
�' --
U 2,000 J. — —
0 — �e
10 4
�251RP =251RPOR =25 IRP WA O25 IRP UIWC ———2023 IRP Update ---23IRP
228

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
New Wind Resources
As shown in Figure 9.4, PacifiCorp's 2025 IRP preferred portfolio includes 2,267 MW of new
wind generation by the end of 2030, 2,988 MW by the end of 2035, and 3,782 MW of cumulative
new wind by the end of 2045. Of note, all wind selections are utility scale.
Figure 9.4—2025 IRP Preferred Portfolio New Wind Capacity
10,000 ---------------
8,000
6,000 1 —
4,000
----� i
0
�251RP =251RPOR 025IRPWA O25 IRP UIWC ---2023 IRP Update ---23IRP
New Storage Resources
New storage resources in the 2025 IRP preferred portfolio are summarized in Figure 9.5 and 9.X.
The 2025 IRP preferred portfolio includes 1,684 MW of new 4-hour storage resources by the end
of 2030, 2,072 MW by the end of 2035 and 4,451 MW by the end of 2045. Additionally,the 2025
IRP preferred portfolio includes 511 MW of storage with at least 24 hours duration by the end of
2030 and growing to 616 MW by 2035 and 3,073 MW by 2045. Cumulative storage selections,
inclusive of both short and long duration resources, total 7,524 MW by 2045.
Figure 9.5—2025 IRP Preferred Portfolio New 4-Hour Storage Capacity',2
10,000
8,000 — ---------------
6,000 i
./
U � /
2,000
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
251RP =251RPOR 025IRPWA O25 IRP UIWC ---2023 IRP 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 categorized as new storage capacity in the 2025 IRP.
2 The 2023 IRP and 2023 IRP Update totals shown in Figure 9.5 include a minimal amount of intermediate duration
storage.
229

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.6—2025 IRP Preferred Portfolio New 24+Hour Storage Capacity'
6,000
4,000
M FP
.Z
2,000
u
0
'4h '4b ,4� ,y4� ^? h0 ,yam ,yti y'h ,yb yh ,ybn hb hQ O ♦ ,�c4 ti 'h v h
,yc� rV ,v ,vcl"
■25 IRP 025 IRP OR 025IRP WA 025 IRP UIWC
'The 2025 IRP preferred portfolio also includes 41 MW of renewable peaking resources by the end of the planning
horizon.
New Nuclear Resources
The 2025 IRP includes new advanced nuclear as part of its least-cost,least-risk preferred portfolio.
As shown in Figure 9.7, the 500 MW advanced nuclear NatriumTM demonstration project is
currently scheduled to come online by fall 2031.
Figure 9.7—2025 IRP New Nuclear'
2,000
1,500 -------------------
1,000
JI
U 500 r--+J.
Nh IP C� Mh
�o ryo �o ryo �o ryo �o ryo �o ryo �o ryo �o ryo �o ryo �o ryo �o ryo �o
25IRP =25IRPOR =251RPWA O25 IRP UIWC ---2023 IRP Update ---23IRP
'While the 500 MW advanced nuclear NatriumTM demonstration project is currently scheduled to come online by
the fall of 2031,the PLEXOS model works best with beginning of year start dates for expansion candidates,so a
start date of l/1/2032 was assumed for the NatriumTM demonstration project in modeling.
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 9.8 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
230

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
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, thus lowering the commercial forecast.5
Figure 9.8 —Load Forecast Comparison between Recent IRPs (Before Incremental Energy
Efficiency Savings)
Forecasted Annual System Load Forecasted Annual System Coincident Peak
(G«°h) (AM
120,000 18,000
100,000 16,000
14,000
80,000 12,000
60,000 10,000
8,000
40,000 6,000
20,000 4,000
2,000
0 0 _
W a O '+ N M I O�NO NO NONO NO MO MO MO MO MO MO MO MO MO MO M ee N G g NOO NO OFN OWN OON O
N N . . . . . . N N N N N N N N . . . . F, NN N N NOM1 NM NM MM M YMl M M1M WM aM N MOf
1^1 (V N N
—2025 MP }2023 W —2025 MP --o—2023 MP
DSM resources continue to play a key role in PacifiCorp's resource mix. The chart to the left in
Figure 9.9 compares total energy efficiency capacity savings in the 2025 IRP preferred portfolio
relative to the 2023 IRP preferred portfolio. Cumulative capacity of energy efficiency programs in
the 2025 IRP preferred portfolio totals 5,436 MW 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 9.9 compares
cumulative demand response program capacity in the 2025 IRP preferred portfolio relative to the
2023 IRP preferred portfolio and does not include capacity from existing programs. The 2025 IRP
has a cumulative capacity of demand response programs totaling 515 MW by 2040. By year-end
2045, the 2025 IRP preferred portfolio has a cumulative capacity of demand response programs
totaling 789 MW.
5 A different approach is needed to protect existing customers from sizeable resource and transmission infrastructure
investment costs associated with certain new large loads. Consequently,these loads fall outside of the traditional
planning process. Should those loads materialize,we are working with certain large customers to ensure they can
bring sufficient resources and are prepared to pay for the incremental transmission upgrades required to serve them.
231

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.9—2025 IRP Preferred Portfolio Energy Efficiency and Demand Response Capacity
Energy Efficiency Demand Response
6,000 1,500 —
4,000 — 1,000
2,000 $�� 500 ����=%mot=:_---�
gS fnn
—
U ...was f
0 00110M -
0 --
171 1 1 1 1 1
N ti ti ti ti ti N ti ti N N ti ti N ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti N ti 4 N ti N
25 IRP =25 IRP OR 25 IRP =25 IRP OR
025IRPWA 025 IRP UIWC O25 IRP WA 025 IRP UIWC
---2023 IRP Update ---23IRP ---2023 IRP Update ---23IRP
'Energy efficiency and demand response in the 2023 IRP began escalating two years prior to when escalation begins
in the 2025 IRP preferred portfolio. Cumulative energy efficiency and demand response in 2045 in the 2025 IRP
preferred portfolio is similar to cumulative energy efficiency and demand response by 2042 in the 2023 IRP,the end
of the planning horizon.
Wholesale Power Market Prices and Purchases
Figure 9.11 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 9.11 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.
Market transactions in the 2025 IRP are purely economic as market purchases do not contribute to
capacity like they did in the 2023 IRP and 2023 IRP Update.In the 2023 IRP and 2023 IRP Update,
market purchases were limited to 1,000 MW in the winter and 500 MW in the summer. For the
2025 IRP, economic market purchases for energy could be made up to transmission limits, but
market purchases were not allowed on the top five load days during peak hours in peak seasons
and could never be used for capacity. Refer to Chapter 5: Reliability and Resiliency for additional
details.
Figure 9.10—2025 IRP Preferred Portfolio Market Purchases
Summer Market Purchases Winter Market Purchases
1200 1200
900 900 ----------------------- -
---- --
600 � 600
300
0 30 0 0 r_.�� LaLLJ-1
d � � � d
2025 IRP Energy 2023 IRP Energy 2025 IRP Energy 2023 IRP Energy
----25 IRP Capacity Limit ----23 IRP Sunnier Lmrit ----25 IRP Capacity Limit ----23 IRP Winter Lmrit
232

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.11 -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) $12
S120
$10
$too
Ss
♦ i' 56
$60 ♦
54 ��
$40
$2
$20
g SO n c n ro o o N m a n o N oo a o m a n
$0
r r o N r N r N o 0 o N r o 0
N N N N N N N N N N N N t 20251RP(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-fuel plants have been an important contributor to 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
have enabled the company to reduce fuel consumption,associated costs and emissions,and instead
buy increasingly low-cost 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 9.12, the 2025 IRP
converts 562 MW of coal-fueled generation to natural gas fueled, exits PacifiCorp's share in 386
MW of minority-owned coal, and also assumes retirements of 220 MW at Dave Johnston and 156
MW of Naughton gas conversion by the end of the study horizon. Jim Bridger Units 3 and 4
convert to carbon capture in 2030 and operate during the 12 years of tax credit eligibility, retiring
in 2043. The balance of the coal units continues to operate through the end of the study horizon.
Fi ure 9.12-2025 IRP Preferred Portfolio Thermal Resources
10,000 -
8,000
6,000
4,000
2,000
0
,yo ,yo ryo ryo ,tio ,tio �o ryo ryo ,yo ryo ,yo ryo ryo ryo ryo ryo �o �o �o �o
Coal Coal-CCUS Gas-Steam Gas-CT/CCCT ---2023 IRP 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. Also shown in Table 9.9 are
233

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
the coal unit changes which are projected to occur if necessary to comply with the current U.S.
Environmental Protection Agency (EPA) greenhouse gas (GHG) emissions regulation under
Section 111(d) of the Clean Air Act. 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.6
Table 9.9-2025 IRP Coal Resource Results
Majority-Owned Co
2025 IRP Retirement Year 2023 IRP Retirement Year
unit Selected w/o 111(d)Regulation Selected w/111(d)Regulation As Selected
Dave Johnston 1&2 Not retired(Gas conversion 2029) No change 2028
Dave Johnston 3 2027(Clean air compliance) No change 2027(Clean air compliance)
Dave Johnston 4 Not retired Not retired(Gas conversion 2030) 2039
Hunter 1 Not retired 2032 2031
Hunter 2&3 Not retired Not retired(Alt.fuel conv.2030) 2032
Huntington 1&2 Not retired Not retired(Alt.fuel conv.2030) 2032
Jim Bridger 1&2 Not retired(Gas conversion 2024) No change 2037(Gas conversion 2024)
Jim Bridger 3&4 2042(CCS conversion 2030) No change 2037(Gas conversion 2030)
Naughton 1 2042(Gas conversion 2026) No change 2036(Gas conversion 2026)
Naughton 2 Not retired(Gas conversion 2026) No change 2036(Gas conversion 2026)
Wyodak Not retired 2032 2039
only-Owu
2025 IRP Retirement Year 2023 IRP Retirement Year
Udt 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 1 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, new battery storage resources,
transmission, and Regional Haze compliance that capitalizes on flexibility.
The chart on the top in Figure 9.13 compares projected annual CO2e emissions across the 2025
IRP and the 2023 IRP preferred portfolios and is inclusive of emissions attributed to market
purchases. In the current 2025 IRP preferred portfolio, emissions are generally higher than
projected in the 2023 IRP. This relative increase is primarily the result of two differences in
modeling assumptions. In the 2023 IRP, a medium CO2 price was included in the expected price-
'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.
234

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
policy scenario used to forecast emissions.No CO2 price was included in the dispatch of the 2025
IRP preferred portfolio used to forecast emissions.The 2023 IRP also modeled the EPA's proposed
implementation of the Ozone Transport Rule as a significant dispatch target on emissions. No
dispatch target was included in the expected price-policy scenario used to forecast emissions in
the 2025 IRP. The MR (medium gas price with at-risk federal regulation) price-policy scenario
accounts for the effects of possible federal policy,and the portfolio optimized and dispatched under
the MR price-policy scenario is a better comparison to the 2023 IRP preferred portfolio.
The difference in emissions between the 2023 IRP and the 2025 IRP is also partly due to an
increase in unspecified market purchases, which are assigned a default emission factor of 0.428
MT CO2e/MWh. This default factor, often established by state regulations and widely used in
GHG compliance reporting across multiple states, remains constant throughout the planning
period. However, energy industry experts believe the market is trending toward lower emissions
as renewable energy and storage capacity expand. As more renewables enter the market, overall
emissions are expected to decline, translating to a lower emission factor. PacifiCorp is actively
engaging with states to discuss updating this default emission factor to better reflect the market's
transition to cleaner energy. Finally, the difference in emissions from the 2023 IRP 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 factor. 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.
The bottom chart in Figure 9.13 presents historical data and assigns emissions to unspecified
market purchases at a rate of 0.428 metric tons CO2 equivalent per MWh—with no credit to market
sales. It also accounts for emissions from specified purchases. The graph shows that system CO2e
emissions have declined by approximately 45%in 2025,75%in 2030,and 77%in 2040,compared
to a 2005 baseline of 54.6 million metric tons. In the final five years of the planning horizon,
emissions increase moderately due to the factors outlined above.
235

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.13—2025 IRP Preferred Portfolio CO2 Emissions and PacifiCorp CO2 Equivalent
Emissions Trajectory'
IRP CO2e Emissions Comparison
30
25
o"
20
r_
0
F
`' 15
° 10
5
0
in rD n 00 M O -4 N M R in (0 r- Co M O c1 N M R 47
N N N N N co co M M M co co co M M V V V V V V
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
■2025 IRP CO2e 2023 IRP CO2e
PacifiCorp CO2e Emissions Trajectory
60
100%
50
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30
o v
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111111111
0 0 0 0 0 N N N N N M M M M M
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
PacifiCorp Emissions(Million MT) 2005 Base Emission ......%Reduction from 2005 Base
1 PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2023 from owned facilities,specified sources
and unspecified sources.2024 emissions were not forecasted in the 2025 IRP and therefore reflect the forecast from the 2023 IRP
Update.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.
236

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Renewable Portfolio Standards
Figure 9.14 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 Interjurisdictional 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 at various points 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.
Although not depicted in Figure 9.14, 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.
237

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.14—Annual State RPS Compliance Forecast
800 California RPS
b 600 +
H
C. 400
W 200
04 0
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a 150,000
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238

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Oregon HB 2021 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. For more information on Oregon's planning requirements and
the compliance position of the preferred portfolio,refer to Volume II, Appendix P (Oregon Clean
Energy Update).
Capacity and Energy
Figure 9.15 and Figure 9.16 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 dispatch under
base price curve assumptions. Renewable capacity and generation reflect categorization by
technology type and not disposition of renewable energy attributes for regulatory compliance
requirements.7 On an energy basis, coal generation drops below 20 percent in 2030 and remains
below 15 percent through the end of the planning period. On a capacity basis, coal resources drop
below 10 percent by the end of the planning period. 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 PacifiCorpIRP 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'sIRP preferred portfolio energy mix includes owned resources and purchases from third parties.
239

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1' ,

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 shows jurisdictional resource selections of PacifiCorp's 2025 IRP preferred
portfolio. Table 9.12 and Table 9.13 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 9.14 and Table 9.15 report line-item detail of PacifiCorp's peak load and resource
capacity balance for winter, including preferred portfolio resources, over the 21-year horizon.
241

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
242

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 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Expansion Options
Gas-CCCT - - - - - - - - - -
Gas-Peaking
Nuclear - - 500 500
Renewable Peaking 19 4 18 41
DSM-Energy Efficiency 92 89 209 220 239 261 329 291 E299 295 299 315 347 314 293 301 303 315 238 205 182 5,436
DSM-Demand Response 18 2 63 21 120 99 5 3 3 21 112 18 5 24 61 106 29 26 52 789
Renewable-Wind 21 1 794 1 1,452 344 1 1 29 347 40 1 175 37 376 1 50 20 96 1 3,782
Renewable-Small Scale Wind -
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ I _ _ _
Renewable-Utility Solar 222 180 1,690 849 240 403 225 13 1 554 104 12 197 75 4,765
Renewable-Small Scale Solar - 320 2 18 26 21 30 132 309 110 143 36 1,147
Renewable-Geothermal
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Renewable-Battery,<8 hour 1,146 242 296 119 39 210 20 47 175 67 113 67 713 5 459 733 4,451
Renewable-Battery,8-23 hour
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Renewable-Battery,24+how 511 91 3 4 3 4 4 11 83 37 939 107 319 402 197 358 3,073
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) 0
Coal-Gas Conversions -357 205 (156) 406
- - - - - - - - - - - - - - - - -
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-QF - (47) (3) (50)
Expire-Other 520 (20) '00
otal 1 110 4fi4 209 1,417 1 1,353 1 4,229 1 1,505 1 1,177 1 772 1 783 1 716 1 559 1 546 1 904 1 956 1 1,857 1 331 1 1,453 1 (31)1 994 1 1,530
243

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.11 —Preferred Portfolio with Jurisdictional Resource Selections
histalled Capacity,MW
Resource 2025 2026 2027 2028 1 2029 2030 2031 1 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Gas-CCCT - - - - - - - - - - - - - - - - - - - - - -
Gas-Pealing - - - - - - - - - - - - - - - - - - - - -
Nuclear - - - - - - - 500 - - - - - - - - - - - - - 500
OR - - - - - - - 130 - - - - - - - - - - - - - 130
WA - - - - - - - 32 - - - - - - - - - - - 32
UIWC - - - - - - - 338 - - - - - - - - - - - - 338
Renewable Peaking - - - - - - 19 - 4 18 41
OR - - - - - - - - - - - - - - - - 19 - 4 - 18 40
WA - -
UIWC - -
DSM-Energy Efficiency 92 89 209 220 239 261 329 291 299 295 299 315 347 314 293 301 303 315 238 205 182 5,255
OR - - 97 101 107 114 115 110 113 108 109 ill 110 106 102 116 123 107 114 92 90 2,044
WA - 0 13 16 15 17 18 18 19 19 20 19 19 15 14 12 11 11 10 8 7 280
UIWC - 0 99 1 103 1 117 130 196 1 163 167 168 170 185 219 193 177 172 170 197 114 106 1 86 2,931
DSM-Demand Response 18 2 - 63 21 120 99 5 1 3 3 21 112 18 5 24 61 106 29 26 52 769
OR - 0 - 48 16 7 - 5 1 3 3 11 - 11 4 23 4 1 - 9 - 8 153
WA - 0 - 15 2 2 - - - - - 8 - 6 1 1 1 - 1 - 141 51
UIWC - 1 - - 2 ill 99 - - - - 2 112 - - 0 57 106 19 26 30 566
Renewable-Wind - - - 21 794 1,452 344 1 - 29 347 40 175 37 - 376 50 - 20 - 96 3,782
OR - - - 16 445 939 - 11 22 260 1 30 131 28 0 282 37 - 15 - 72 2,278
WA - - - 1 5 1 148 313 - - - 7 87 10 44 9 0 94 12 - 5 - 24 758
UIWC - - - - 200 200 344 - - - - - 0 - - - - - - - - 744
Renewable-Small Scale Wind - - - - - - - - - - - - - - - - - - - - - -
Renewable-Utility Solar - - - 222 180 1,690 849 240 403 225 13 - 1 - 554 104 12 - - 197 1 75 4,765
OR - - - 167 135 1,268 136 180 302 169 10 - 0 0 416 78 9 - - 148 56 3,074
WA - - - 56 45 423 45 60 101 1 56 3 - 01 01 139 26 3 - - 49 19 1,025
UIWC - - - - - - 668 - - - - - 0 - - - - - - - - 668
Renewable-Small Scale Solar - - - - - 320 1 2 1 18 26 21 30 132 - 309 - - 110 - - 143 36 1,147
OR - - - - - 320 2 18 26 21 30 132 0 309 - - 110 - - 143 36 1,147
RL - - - - - - - 0 - - - 0
UIWC
Renewable-Geothermal - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery,<8hour - - - 1,146 242 296 - 119 39 210 20 47 - 175 67 113 67 713 5 459 733 4,451
OR - - 1 280 100 128 - 119 39 1 2101 20 47 1 46 1 - 1071 55 - - - - 1,152
WA - - 1 8651 1141 168 - - - - - - - 129 67 7 12 - 5 - - 1,367
UIWC - - 1 - 27 - - - - - - - 0 - - - - 713 - 459 733 1 1,933
Renewable-Battery,8-23 hour - - - - - - - - - - - - - - - - - - - - - -
Renewable-Battery,24+hour - - - - - 511 91 3 4 3 4 4 11 83 37 939 107 319 402 197 358 3,073
OR - - - - - 272 88 - - - - - 7 79 33 934 102 210 397 192 353 2,667
WA - - - - - 238 3 3 4 3 4 4 4 4 4 4 4 5 5 5 5 298
UIWC - - - - - 1 - - - - - - - - - - - 104 - - - 105
Other Renewable - - - - - - - - - - - - - - - - - - - - - -
Storage-Other - - - - - - - - - - - - - - - - - - - - - -
244

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.12-Preferred Portfolio Summer Capacity Load and Resource Balance(2025-2034)
2025 2027 2030 2032
Coal 3,960 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 3,294 3,469 3,469 3,469 3,469 3,469 3,469
Hydroelectric 76 76 76 76 76 76 76 76 76 76
Wind 587 613 596 578 561 534 503 487 470 453
Solar 342 499 487 475 463 452 440 428 416 404
Other Renewable 46 45 44 42 41 40 39 37 36 35
Storage 1 939 925 909 894 879 865 849 834 819
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 405 394 383 372 361 351 340 328 314 301
Demand Response 451 446 440 452 450 443 429 423 431 425
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (281) (1,447) (1,369) (1,105) (973) 0 0 0 0 0
East Existing Resources 8,571 8,426 8,443 8,470 8,433 9,171 9,087 9,024 8,973 8,909
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 0 35 68 124 121 119 117
Solar 0 0 0 0 0 0 151 147 143 139
Storage 0 0 2 2 25 27 27 27 26 26
Nuclear 0 0 0 0 0 0 0 457 454 452
Demand Response 7 7 7 7 8 80 151 149 146 143
East Planned Resources 7 7 9 9 70 177 455 903 891 879
East Total Resources 8,578 8,433 8,452 8,479 8,504 9,348 9,542 9,927 9,863 9,788
Load 7,746 7,655 7,781 7,919 8,068 8,234 8,447 8,609 8,528 8,700
Distributed Generation (157) (143) (186) (234) (285) (341) (400) (458) (321) (354)
Energy Efficiency (91) (141) (206) (274) (349) (428) (520) (631) (696) (801)
East Total obligation 7,498 7,372 7,388 7,412 7,433 7,465 7,527 7,520 7,511 7,545
East Reserve Margin 14.4% 14.4% 14.4% 14.4% 14.4% 25.2% 26.8% 32.0% 31.3% 29.7%
Coal 133 133 133 133 133 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 74 72 70 67 65 63 61 59 57 54
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 232 226 215 209 200 194 187 179 174 170
Demand Response 60 59 58 57 57 56 55 54 54 53
Sale 0 0 0 0 0 0 0 0 0 0
Transfers 281 1,447 1,369 1,105 973 0 0 0 0 0
West Existing Resources 2,277 3,433 3,339 3,063 2,916 1,800 1,784 1,771 1,761 1,751
Additional Proxy/Short-Term Purchases 1,910 757 885 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 2 67 202 201 201 200 202
Solar 0 0 0 117 205 1,185 1,231 1,306 1,446 1,496
Storage 0 0 1 839 982 1,684 1,759 1,828 1,841 1,969
Nuclear 0 0 0 0 0 0 0 0 0 0
Demand Response 2 2 2 2 2 2 2 2 2 2
West Planned Resources 1,911 759 889 960 1,255 3,072 3,193 3,336 3,488 3,668
West Total Resources 4,189 4,192 4,227 4,022 4,171 4,872 4,977 5,107 5,249 5,419
Load 3,778 3,812 3,905 3,967 4,032 4,103 4,239 4,255 4,288 4,376
Distributed Generation (49) (54) (75) (99) (124) (152) (182) (213) (132) (148)
Energy Efficiency (67) (94) (135) (178) (220) (263) (318) (359) (389) (431)
West Total obligation 3,662 3,664 3,695 3,690 3,688 3,688 3,738 3,684 3,767 3,798
West Reserve Margin 14.4% 14.4% 14.4% 9.0% 13.1% 32.1% 33.1% 38.6% 39.4% 42.7%
Total Resources 12,767 12,625 12,680 12,501 12,675 14,220 14,518 15,034 15,113 15,207
Obligation 11,160 11,036 11,084 11,102 11,121 11,153 11,265 11,203 11,278 11,343
Planning Reserves(14.4%) 1,607 1,589 1,596 1,599 1,601 1,606 1,622 1,613 1,624 1,633
Obligation+Reserves 12,767 12,625 12,680 12,701 12,723 12,759 12,887 12,817 12,902 12,977
System Position 0 0 0 (199) (48) 1,461 1,631 2,217 2,211 2,231
Reserve Margin 14.4% 14.4% 14.4% 12.6% 14.0% 27.5% 28.9% 34.2% 34.0% 34.1%
245

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.13-Preferred Portfolio Summer Capacity Load and Resource Balance(2036-2045)
2042 2
Coal 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,926 2,432 2,432 2,432
Gas 3,469 3,469 3,469 3,469 3,469 3,469 3,469 3,469 3,322 3,322 3,322
Hydroelectric 76 76 76 76 76 76 76 76 76 76 76
Wind 437 421 404 387 371 355 308 293 278 263 2,49
Solar 392 381 340 329 319 308 297 286 276 243 233
Other Renewable 33 32 31 12 11 10 10 9 9 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 291 269 221 212 203 192 184 176 169 162 155
Demand Response 422 401 402 398 400 406 398 375 376 389 351
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 8,851 8,763 8,643 8,569 8,519 8,472 8,383 8,310 7,622 7,564 7,472
Additional Proxy/Short-Term Purch- 0 0 0 0 0 0 64 0 672 628 475
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 115 112 110 108 106 104 101 99 97 95 92
Solar 135 131 127 123 120 116 ill 107 104 100 96
Storage 26 25 25 25 24 24 23 592 581 858 1,289
Nuclear 450 447 445 442 440 437 435 432 430 427 426
Demand Response 141 138 197 193 189 186 209 253 257 264 270
East Planned Resources 868 856 907 895 882 869 947 1,487 2,144 2,373 2,650
East Total Resources 9,719 9,620 9,550 9,464 9,401 9,340 9,330 9,797 9,766 9,937 10,123
Load 8,893 9,150 9,349 9,567 9,774 9,993 10,214 10,478 10,693 10,891 11,097
Distributed Generation (385) (415) (445) (474) (503) (529) (557) (584) (609) (635) (660)
Energy Efficiency (911) (983) (1,112) (1,227) (1,325) (1,407) (1,501) (1,482) (1,547) (1,570) (1,588)
East Total obligation 7,596 7,752 7,792 7,865 7,946 8,057 8,156 8,413 8,536 8,686 8,848
East Reserve Margin 27.9% 24.1% 22.6% 20.3% 18.3% 15.9% 14.4% 16.5% 14.4% 14.4% 14.4%
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 52 50 48 46 44 41 39 37 35 33 31
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 165 160 142 138 132 128 124 120 101 97 95
Demand Response 52 51 51 50 49 48 48 47 46 45 44
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 1,741 1,731 1,708 1,700 1,689 1,681 1,651 1,644 1,621 1,613 1,608
Additional Proxy/Short-Term Purchase 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 238 241 259 262 261 299 303 302 303 302 310
Solar 1,455 1,446 1,383 1,431 1,553 1,510 1,470 1,387 1,307 1,314 1,255
Storage 1,966 1,980 1,971 2,144 2,200 3,176 3,299 3,487 3,863 4,035 4,365
Nuclear 0 0 0 0 0 0 0 0 0 0 0
Demand Response 2 3 3 3 3 3 3 3 3 3 8
West Phoned Resources 3,660 3,670 3,616 3,840 4,016 4,988 5,075 5,179 5,476 5,654 5,938
West Total Resources 5,401 5,401 5,325 5,540 5,705 6,668 6,727 6,823 7,097 7,267 7,545
Load 4,475 4,577 4,692 4,807 4,927 5,049 5,173 5,376 5,430 5,553 5,680
Distributed Generation (163) (177) (192) (206) (221) (234) (249) (263) (277) (290) (304)
Energy Efficiency (471) (515) (571) (603) (634) (661) (691) (774) (591) (599) (612)
West Total obligation 3,841 3,885 3,929 3,998 4,073 4,154 4,233 4,340 4,562 4,663 4,764
West Reserve Margin 40.6% 39.0% 35.5% 38.6% 40.1% 60.5% 58.9% 57.2% 55.6% 55.9% 58.4%
Total Resources 15,120 15,021 14,875 15,003 15,106 16,009 16,057 16,620 16,863 17,205 17,668
Obligation 11,438 11,637 11,721 11,863 12,019 12,211 12,388 12,753 13,099 13,349 13,612
Planning Reserves(14.4%) 1,647 1,676 1,688 1,708 1,731 1,758 1,784 1,836 1,886 1,922 1,960
Obligation+Reserves 13,085 13,313 13,409 13,572 13,750 13,969 14,172 14,589 14,985 15,272 15,573
System Position 2,036 1,709 1,465 1,432 1,357 2,040 1,885 2,031 1,878 1,933 2,095
Reserve Margin 32.2% 29.1% 26.9% 26.5% 25.7% 31.1% 29.6% 30.3% 28.7% 28.9% 29.8%
246

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.14-Preferred Portfolio Winter Capacity Load and Resource Balance (2025-2034)
2025 2027 2030 2032
Coal 4,147 3,734 3,734 3,499 3,185 3,015 3,015 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 1,837 1,957 1,892 1,829 1,766 1,657 1,523 1,463 1,404 1,346
Solar 38 104 101 98 95 92 89 85 82 79
Other Renewable 41 39 38 37 35 34 33 32 30 29
Storage 1 621 606 591 576 561 546 531 516 500
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 186 181 176 171 166 161 156 149 140 124
Demand Response 119 118 118 128 129 128 121 120 128 127
Sale 0 0 0 0 0 0 0 0 0 0
Transfers (1,600) (1,600) (1,600) (1,226) (930) 0 0 0 0 0
East Existing Resources 7,804 8,523 8,433 8,495 8,581 9,208 9,042 8,954 8,875 8,780
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 0 90 175 316 306 297 287
Solar 0 0 0 0 0 0 39 37 36 35
Storage 0 0 1 1 17 18 18 18 18 17
Nuclear 0 0 0 0 0 0 0 403 401 398
Demand Response 0 0 0 0 0 0 0 0 0 0
East Planned Resources 0 0 2 2 109 196 374 767 754 740
East Total Resources 7,804 8,523 8,435 8,496 8,689 9,404 9,417 9,722 9,629 9,520
Load 5,898 5,911 6,036 6,164 6,278 6,408 6,569 6,706 6,899 7,084
Distributed Generation (1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Energy Efficiency (75) (118) (157) (197) (239) (283) (331) (388) (450) (513)
East Total obligation 5,821 5,790 5,876 5,963 6,033 6,119 6,231 6,309 6,440 6,560
East Reserve Margin 34.1% 47.2% 43.5% 42.5% 44.0% 53.7% 51.1% 54.1% 49.5% 45.1%
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 62 59 57 55 53 51 49 47 45
Solar 1 1 1 1 1 1 0 0 0 0
Other Renewable 0 0 0 0 0 0 0 0 0 0
Storage 2 2 2 2 2 2 2 2 2 0
Purchase 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 70 69 62 61 58 57 57 56 56 56
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 1,226 930 0 0 0 0 0
West Existing Resources 3,345 3,342 3,333 2,956 2,655 1,574 1,571 1,568 1,566 1,561
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 2 67 201 201 200 199 202
Solar 0 0 0 30 52 299 309 326 359 368
Storage 0 0 1 1,091 1,276 2,037 2,104 2,193 2,206 2,369
Nuclear 0 0 0 0 0 0 0 0 0 0
Demand Response 0 0 0 41 51 56 55 58 58 59
West Planned Resources 0 0 2 1,164 1,446 2,594 2,669 2,776 2,821 2,997
West Total Resources 3,345 3,342 3,335 4,120 4,101 4,168 4,240 4,344 4,387 4,559
Load 3,511 3,571 3,640 3,701 3,741 3,805 3,904 3,981 4,068 4,160
Distributed Generation (0) (0) (1) (1) (1) (1) (1) (2) (2) (2)
Energy Efficiency (52) (65) (118) (173) (229) (286) (345) (401) (457) (511)
West Total obligation 3,459 3,506 3,521 3,527 3,511 3,517 3,558 3,578 3,609 3,647
West Reserve Margin -3.3% -4.7% -5.3% 16.8% 16.8% 18.5% 19.2% 21.4% 21.5% 25.0%
Total Resources 11,149 11,865 11,769 12,616 12,790 13,572 13,657 14,066 14,016 14,079
Obligation 9,281 9,296 9,397 9,490 9,544 9,636 9,789 9,888 10,049 10,207
Planning Reserves(16.8%) 1,559 1,562 1,579 1,594 1,603 1,619 1,645 1,661 1,688 1,715
Obligation+Reserves 10,840 10,858 10,975 11,084 11,147 11,255 11,434 11,549 11,738 11,922
System Position 309 1,008 794 1,532 1,643 2,317 2,223 2,517 2,278 2,157
Reserve Margin 20.1% 27.6% 25.2% 32.9% 34.0% 40.8% 39.5% 42.3% 39.5% 37.9%
247

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.15-Preferred Portfolio Winter Capacity Load and Resource Balance (2035-2045)
2042
Coal 3,015 3,015 3,015 3,015 3,015 3,015 3,015 3,015 2,503 2,503 2,503
Gas 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,527 3,378 3,378 3,378
Hydroelectric 33 33 33 33 33 33 33 33 33 33 33
Wind 1,285 1,226 1,168 1,107 1,049 990 850 797 744 689 636
Solar 76 73 70 67 64 61 58 55 52 42 39
Other Renewable 28 26 25 9 8 8 7 7 6 6 0
Storage 485 470 455 440 425 410 395 379 365 350 334
Purchase 0 0 0 0 0 0 0 0 0 0 0
Qualifying Facilities 120 112 99 94 90 86 82 78 75 71 67
Demand Response 128 117 121 121 125 132 129 117 121 132 109
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 8,697 8,600 8,511 8,412 8,336 8,262 8,096 8,008 7,276 7,204 7,101
Additional Proxy/Short-Term Parch- 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 278 268 259 250 240 231 221 212 202 193 183
Solar 33 32 31 30 28 27 26 25 23 22 21
Storage 17 16 16 16 15 15 14 370 360 499 711
Nuclear 396 394 392 389 387 384 381 379 377 374 372
Demand Response 0 0 0 0 0 0 0 0 0 0 1
East Planned Resources 727 713 700 687 673 660 645 988 965 1,091 1,291
East Total Resources 9,423 9,313 9,212 9,099 9,009 8,921 8,742 8,996 8,241 8,294 8,392
Load 7,248 7,421 7,645 7,863 8,087 8,287 8,466 8,705 8,909 9,134 9,224
Distributed Generation (11) (11) (12) (13) (13) (14) (14) (14) (15) (15) (16)
Energy Efficiency (579) (624) (700) (766) (826) (886) (954) (973) (1,022) (1,049) (1,077)
East Total obligation 6,659 6,786 6,932 7,084 7,248 7,387 7,498 7,717 7,872 8,070 8,131
East Reserve Margin 41.5% 37.2% 32.9% 28.4% 24.3% 20.8% 16.6% 16.6% 4.7% 2.8% 3.2%
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 42 40 38 36 34 32 30 28 25 23 21
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 54 53 53 51 51 50 50 50 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
Transfers 0 0 0 0 0 0 0 0 0 0 0
West Existing Resources 1,559 1,555 1,552 1,550 1,546 1,544 1,541 1,539 1,536 1,534 1,531
Additional Proxy/Short-Term Purchase 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 237 241 258 261 260 298 301 300 301 300 308
Solar 355 349 331 339 363 348 333 309 286 280 260
Storage 2,362 2,379 2,362 2,558 2,619 3,606 3,732 3,910 4,279 4,439 4,761
Nuclear 0 0 0 0 0 0 0 0 0 0 0
Demand Response 60 67 66 73 75 82 83 82 85 84 87
West Phoned Resources 3,013 3,036 3,018 3,231 3,317 4,334 4,450 4,601 4,951 5,103 5,417
West Total Resources 4,572 4,591 4,570 4,781 4,863 5,878 5,991 6,140 6,488 6,636 6,948
Load 4,232 4,334 4,471 4,605 4,720 4,832 4,959 5,143 5,253 5,374 5,365
Distributed Generation (2) (3) (3) (3) (3) (3) (3) (4) (4) (4) (4)
Energy Efficiency (568) (624) (668) (714) (760) (819) (858) (900) (786) (803) (826)
West Total obligation 3,662 3,707 3,800 3,888 3,957 4,010 4,097 4,239 4,463 4,567 4,535
West Reserve Margin 24.9% 23.9% 20.3% 23.0% 22.9% 46.6% 46.2% 44.8% 45.4% 45.3% 53.2%
Total Resources 13,995 13,904 13,782 13,880 13,872 14,799 14,732 15,136 14,729 14,930 15,340
Obligation 10,321 10,493 10,732 10,973 11,205 11,398 11,596 11,957 12,334 12,637 12,666
Planning Reserves(16.8%) 1,486 1,511 1,545 1,580 1,614 1,641 1,670 1,722 1,776 1,820 1,824
Obligation+Reserves 11,807 12,003 12,278 12,553 12,819 13,039 13,265 13,678 14,110 14,456 14,490
System Position 2,188 1,901 1,505 1,327 1,053 1,760 1,467 1,458 618 474 850
Reserve Margin 35.6% 32.5% 28.4% 26.5% 23.8% 29.8% 27.1% 26.6% 19.4% 18.1% 21.1%
248

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Integrated Portfolio Resource Comparisons by Technology and Year
Table 9.16 through Table 9.28 report the incremental capacity of each technology type for each integrated portfolio and integrated variant
portfolio. Table 9.29 through Table 9.32 report the capacity of coal generating units that are retired, converted to natural gas fueling, or
augmented with carbon capture technology. Table 9.33 summarizes how full jurisdictional studies were identified for each variant and price-
policy scenario. Full jurisdictional studies are only modified and endogenously developed to the extent the variant relates to resources that
can be selected for that jurisdiction. As a result,the Oregon and Washington full jurisdictional portfolios are not modified in the variants that
examine coal resource alternatives. Similarly,Washington requires planning under the social cost of greenhouse gases, so its full jurisdictional
portfolio is not modified under other price-policy scenarios. Those variants related to clean resources in which all jurisdictions can participate
have full jurisdictional portfolios for each jurisdiction.
Table 9.16—New Gas'
Study Installed capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 U08k 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - - - - - - - - - - - -
MR Base - - -
MN-No CCS
MN-No Nuclear - -
MN-No Coal 2032
MN-Offshore Wind - -
MN-No Forward Technology
MN-Geothermal - - -
MN-Hunter Retire 99 - 99
LN Basc - 496 496
HH Base - -
SC Base'Positive values indicate installed capacity in the first full year of operation.
249

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.17 - Nuclear'
Installed Capacity,AI\`'
Study 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - - - - 500 - - - - - - - - - - 500
MR Base - 500 500
MN-No CCS 500 500
MN-No Nuclear - - - - -
MN-No Coal 2032 500 500
MN-Offshore Wind - - - 500 - 500
MN-No Forward Tecluiology
MN-Geothermal - - - 500 - 500
MN-Hunter Retire 500 500
LN Base - - - - 500 - - - - 500
HH Base 500 - - 500
SC Base - - - - - 500 - - - - 500
'Positive values indicate installed capacity in the first full year of operation.
Table 9.18—Renewable Peaking'
7Base
udy Installed Capacity,bIW
2025 2 2027 2028 2029 2030 2031 ;2032 2633 2034 2035 2036 2037 2038 2039 2040 2041 2042 2"3 2044 2045 ToW- - - - 19 - 4 Is 41
- 19 4 18 41
19 4 18 41
ear - - - - - - - -
MN-No Coal 2032 19 4 18 41
MN-Offshore Wind -
MN-No Forward Teclmology
MN-Geothermal - - - - - -
MN-Hunter Retire - 19 4 18 41
LN Base - - - - - -
HH Base - 19 4 18 41
SC Base - - - - - - -'Positive values indicate installed capacity in the first full year of operation.
250

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.19—DSM—Energy Efficiency
Study Installed Capacity,11IW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base 92 89 209 220 239 261 329 291 299 295 299 315 347 314 293 301 303 315 238 205 182 5,436
MR Base 92 89 209 221 231 256 329 313 326 315 318 326 369 335 313 308 304 315 254 224 209 5,656
MN-No CCS 92 89 207 218 229 253 326 287 284 282 294 300 333 312 292 289 304 315 260 232 219 5,417
MN-No Nuclear 92 89 210 220 237 256 331 314 310 299 299 314 324 267 283 251 286 299 282 261 220 5,444
MN-No Coal 2032 92 89 210 221 231 251 319 304 308 298 309 325 347 314 293 299 304 315 270 246 220 5,565
MN-Offshore Wind 92 89 1 209 219 1 240 1 260 331 292 306 294 299 322 345 314 310 301 303 314 222 1 218 182 5,462
MN-No Forward Technology 92 89 210 220 237 256 331 315 310 301 301 315 324 267 283 251 286 299 282 247 219 1 5,435
MN-Geothermal 92 89 207 217 227 245 306 298 303 293 313 320 354 335 313 308 305 314 270 259 218 5,586
MN-Hunter Retire 92 89 219 232 243 265 332 306 310 307 312 328 358 326 306 301 304 315 258 224 209 5,636
LN Base 92 89 207 223 236 257 325 288 300 289 311 318 343 309 322 305 302 291 272 244 217 5,540
HH Base 92 89 211 223 237 257 309 295 300 289 309 315 347 326 305 302 305 316 259 252 230 5,568
SC Base 92 89 211 226 241 263 329 293 314 305 318 325 357 325 320 308 305 315 270 260 219 5,685
Table 9.20—DSM—Demand Response
Study Installed Capacity,XIW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base 1S 2 - 63 21 120 99 5 1 3 3 21 112 18 5 24 61 106 29 26 52 789
MR Base 18 2 63 19 16 3 5 1 5 3 19 323 18 5 24 114 34 34 25 205 936
MN-No CCS 18 2 63 19 34 187 5 1 3 3 21 93 18 5 25 6 176 30 26 50 785
MN-No Nuclear 18 2 - 63 20 136 13 8 26 79 32 4 70 14 151 24 46 31 12 102 48 899
MN-No Coal 2032 18 2 63 19 16 - 5 1 3 3 19 328 18 5 25 5 146 33 27 51 787
MN-Offshore Wind 18 2 - 63 20 1 206 21 8 10 4 4 1 110 29 5 1 11 8 166 30 31 50 796
MN-No Forward Technology 18 2 63 21 131 13 10 26 77 35 6 70 13 151 24 45 31 12 102 57 907
MN-Geothermal 18 2 - 60 20 16 - 8 - 7 5 7 - 13 10 26 450 29 8 7 103 789
MN-Hunter Retire 18 2 63 19 211 14 5 1 3 3 23 113 18 129 25 7 147 29 30 87 947
IN Base 18 2 - 63 19 75 149 7 2 4 4 14 110 14 5 24 124 - 8 80 51 773
HH Base 18 2 63 22 13 - 5 1 3 3 19 - 18 8 24 5 463 15 157 30 869
SC Base 18 2 2 64 28 191 14 5 1 1 1 18 11 108 18 10 24 6 150 12 1 50 46 779
251

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.21 —Utility Scale Wind'
Study Installed C'apacitw,\I1V
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - 21 794 1.452 344 1 - 29 347 40 175 37 - 376 50 - 20 - 96 3,782
MR Base 21 694 1,931 200 382 100 129 447 40 175 37 376 50 20 - 96 4,698
MN-No CCS 21 594 1,252 276 1 - 29 347 40 175 37 376 50 20 - 96 3,314
MN-No Nuclear - 500 1,728 300 301 302 322 380 292 2 - - - - - 4,127
MN-No Coal 2032 21 594 2,914 - 1 - 29 347 40 175 37 376 50 20 96 4,700
MN-Offshore Wind 100 100 762 630 400 1 1,000 98 100 100 - - 353 95 - 162 3,901
MN-No Forward Technology - - 694 1,482 1 302 301 22 294 1 53 176 1 38 1 367 1 91 1 1 147 3,968
MN-Geothermal 594 402 200 1 2 - 169 204 185 89 360 62 38 - 19 2,325
MN-Hunter Retire 21 894 1,842 340 1 29 347 40 175 37 376 50 20 96 4,268
LN Base - 594 1,265 594 2 - 24 369 1 176 38 - 365 90 3 - 150 3,671
HH Base 21 1,214 2,677 - 2 29 349 40 175 37 376 50 20 96 5,086
SC Base 20 1,614 1,353 352 1 - 65 293 237 114 26 29 423 47 11 196 1 4,781
'Positive values indicate installed capacity in the first full year of operation.
Table 9.22 —Small Scale Wind'
Study Installed Capacity,NnV,
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - - - - - - - - - - - - - - - - - - - -
MR Base
MN-No CCS
MN-No Nuclear - - - - - -
MN-No Coal 2032
MN-Offshore Wind - -
MN-No Forward Technology
MN-Geothermal - - - - - - - - - - - -
MN-Hunter Retire -
LN Base - - - - - - - - -
HH Base -
SC Base - - - - - - - - - - - - - - - - -'Positive values indicate installed capacity in the first full year of operation.
252

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.23 -Utility Solar'
Study Installed Capacity,11 W
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - - 222 180 1,690 849 240 403 225 13 - 1 - 554 104 12 - 197 75 4.765
MR Base - 222 180 1,690 863 934 420 467 213 133 1 - 554 104 12 - - 197 75 6,065
MN-No CCS 222 180 1,690 614 240 403 225 13 - 1 554 104 12 - 197 75 4,530
MN-No Nuclear - - 656 - 1,444 962 299 326 395 456 391 1 - - - - - 22 108 5,060
MN-No Coal 2032 222 180 1,690 494 635 545 792 114 100 1 554 104 12 197 75 5,715
MN-Offshore Wind - 103 237 1 205 1 1,382 885 1 249 104 1 100 100 1 100 1 103 392 1 444 100 - 116 26 4,646
MN-No Forward Technology - 119 13 - 1,968 962jt4
316 49 - 1 d27
577 85 34 239 111 5,021
MN-Geothermal - - 29 505 1 1,168 200 199 103 - 2 82 229 211 - 333 104 3,705
MN-Hunter Retire - - 222 180 2,352 1,173 225 13 - 1 554 104 12 197 75 5,751
LN Base - 200 138 1,761 517 230 7 - 1 570 93 61 - 44 110 4,369
HH Base - 222 181 1,813 1,904 360 196 1 554 104 12 197 75 6,956
SC Base - 22 381 144 2,005 1,259 206 1 225 90 1 471 115 - 288 92 6,034
'Positive values indicate installed capacity in the first full year of operation.
Table 9.24-Small Scale Solar'
Study Installed Capacity,hIW
2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
�1N Base - 320 1S '6 21 30 132 - 309 - - 110 - - 143 36 1,147
MR Base - 320 2 18 26 21 30 132 - 309 110 143 36 1,147
MN-No CCS 320 2 18 26 21 30 132 - 309 110 143 36 1,147
MN-No Nuclear - - - - 320 2 18 26 21 26 53 - 307 49 153 10 126 36 1,147
MN-No Coal 2032 - 320 2 18 26 21 30 132 - 309 110 143 36 1,147
MN-Offshore Wind - - - - 416 - - - - - - 24 29 114 142 - 36 250 26 1,037
MN-No Forward Technology - 320 2 18 26 21 30 127 - 307 1 - - 117 - 35 108 36 1,147
MN-Geothermal - - - - 304 - 11 29 17 23 17 15 201 331 13 21 - 35 18 26 1,061
MN-Hunter Retire - 320 2 18 26 21 30 132 - 309 - 110 - 143 1 36 1 1,147
LN Base - - - - - 320 2 18 26 21 31 153 - 306 - 97 - 35 101 36 1,146
HH Base - - 320 2 18 26 21 30 132 - 309 110 - 143 1 36 1 1,147
SC Base - - 320 2 19 26 23 24 20 9 312 42 170 - 56 1 26 1 1,049
'Positive values indicate installed capacity in the first full year of operation.
253

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.25—Geothermal
Study Installed Capacity,DIN
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 1 2037 2038 2039 1 2040 2041 2042 2043 2044 2045 Total
MN Base - - - - - - -
MR Base - - - - - - - - - - - - -
MN-No CCS - - - -
MN-No Nuclear - - - - - - - - - - -
MN-No Coal 2032 -
MN-Offshore Wind - - - - - - - - - - - - - -
MN-No Forward Technology -
MN-Geothermal - - 403 304 - 707
MN-Hunter Retire - -
LN Base - - - - - - - - - - - - - - - -
HH Base I - -
SC Base I - - - - - - - -'Positive values indicate installed capacity in the first full year of operation.
Table 9.26—Battery, <8 hour 1
Installed Capacity,MW
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2 339 2040 2041 2042 2043 2044 2045 Total
1\4N Base 1.146 24' 296 119 39 210 20 47 175 67 113 67 713 5 459 733 4.451
MR Base - - 1,156 215 438 - 119 39 210 20 47 27 175 67 113 582 33 5 305 324 3,875
MN-No CCS 2 1,146 215 299 - 119 39 210 20 47 - 175 188 113 67 115 5 758 - 3,518
MN-No Nuclear 16 1,399 109 462 - 274 39 209 34 72 313 130 6 937 159 - 605 10 602 5,376
MN-No Coal 2032 1.145 215 565 - 119 39 210 20 47 - 175 67 113 67 152 5 416 18 3.373
MN-Offshore Wind 7 2,291 527 528 - 149 131 46 54 2 251 113 1,454 211 675 1 768 82 834 8.123
MN-No Forward Technology 1.349 179 316 6 182 41 279 30 83 333 186 112 1,322 272 287 444 251 605 6,277
MN-Geothermal 1,048 184 650 - 241 4 203 37 70 - 179 37 1,437 473 - 104 53 449 5,169
MN-Hunter Retire 4 1,145 215 836 119 39 210 20 47 41 175 67 113 67 129 5 109 185 3,526
LNBase - 1,252 220 609 - 99 39 209 23 82 - 239 67 1,126 1,060 - 272 12 1,437 6,746
HH Base 2 L146 302 1.383 - 119 39 210 20 47 - 175 67 113 67 5 - - 3,695
SC Base 2,147 329 484 - 175 7 194 2 23 - 286 121 1,095 138 245 192 237 531 6,206
'Positive values indicate installed capacity in the first full year of operation.
254

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.27—Battery, 8-23 hour'
Study Installed Capacity,Nr%V
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 1 2035 2036 1 2037 2038 2039 1 2040 2041 1 2042 2043 2044 1 2045 jTotalMN Base - - - - - - - - - - - - - - - - - - -
MR BaseMN-No CCS 1
MN-No Nuclear - - - -
MN-No Coal 2032
MN-Offshore Wind 1 - - 1
MN-No Forward Technology
MN-Geothermal -
MN-Hunter Retire
LN Base - - - -
HH Base 1 - I
SC Base - - - - - - - - -'Positive values indicate installed capacity in the first full year of operation.
Table 9.28—Battery, 24+hour I
Study Installed Capacity,MW
In 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - - - �11 91 3 4 3 4 4 11 83 37 939 107 319 402 197 358 3.073
MR Base 510 91 3 4 3 4 4 175 83 37 939 107 510 401 197 455 3,523
MN-No CCS 511 91 3 4 3 4 4 11 83 37 939 107 261 402 197 358 3,015
MN-No Nuclear - 191 2 3 3 3 3 3 114 3 3 186 78 233 168 118 4 1,115
MN-No Coal 2032 510 91 3 4 3 4 4 33 83 37 939 107 390 401 197 358 3,164
MN-Offshore Wind - 1,577 20 23 23 22 25 26 24 27 28 127 34 142 96 30 34 2,258
MN-No Fonvard Technology -
MN-Geothermal - 85 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 1 13 1 84 1 85 1 316 1 174 1 88 1 855
MN-Hunter Retire 837 91 3 4 3 4 4 123 83 146 939 107 455 401 197 537 3,934
LN Base - 271 95 4 4 3 4 4 17 38 40 132 26 215 137 159 16 1,165
HH Base 511 91 3 4 3 4 4 11 83 37 939 107 641 402 197 598 3.635
SC Base - - - 1,410 107 19 19 18 20 1 21 69 22 34 141 141 442 219 169 94 2,945
'Positive values indicate installed capacity in the first full year of operation.
255

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.29—Majority Owned Coal Retirements'
Study Installed Capacity,XINV
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 1 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - - (220) - - - - - - - - - - - - - - - (220)
MR Base - - - (220) - (686) - - - - - - - (906)
MN-No CCS (220) - (220)
MN-No Nuclew - - - (220) - - - - - - - - (220)
MN-No Coal 2032 (220) (686) 906
MN-Offshore Wind - - - (220) - - - - - - - - (220)
MN-No Forward Technology (220) (220)
MN-Geothernial - (220) - - - - - - (220)
MN-Hunter Retire (220) - (1,158) (1,378)
LN Base - (220) - - - - - - (220)
HH Base (220) (268) - (488)
SC Base - - - (488) - - - - (269) - - (757)
'Negative values indicate retirement of coal capacity.
Table 9.30—Carbon Capture and Sequestration Selections
in Installed Capacity,MW
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
h1N Base - - - - 526 - - - - - - (526) 0
MR Base - 526 (526) 0
MN-No CCS - -
MN-No Nuclear - - 526 - - - - - - - - - - 526
MN-No Coal 2032 -
MN-Offshore Wind - - 526 - - - - - - - 526) - 0
MN-No Forward Technology - 526 - - 526
MN-Geothermal - - - - 526 - - - - - - - - - - 526) - - - 0
MN-Hunter Retire - - 526 - (526) - 0
IN Base - - - - - 526 - - - - - - - - - - 526) - - - 0
HH Base - 526 - - (526) 0
SC Base - - - - - 526 - - - - - - - - - - - - - - - 526
256

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.31 —Coal to Gas Conversion Selections
Study Installed Capacity,XINV
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
MN Base - 357 - - 205 - - - - - - - - - - - - - (156) - - 406
MR Base - 357 205 1,979 - - - - - (156) - 2,385
MN-No CCS - 357 205 (403) - 159
MN-No Nuclear - 357 - 205 - - - - - - - - 562
MN-No Coal 2032 - 357 205 2,679 - - - (156) - 3,085
MN-Offshore Wind - 357 - 205 - - - - - - - - (156) - - 406
MN-No Forward Technology - 357 205 - - - 562
MN-Geothermal - 357 - - 205 - - - - - - - - - - - - 562
MN-Hunter Retire - 357 205 - - 562
LN Base - 357 - - 205 - - - - - - - - - - - - 562
HH Base - 357 205 599 (269) - - 892
SC Base - 357 - - 205 330 - - - - - - - - (99) - - 793
Table 9.32 —Gas Retirements'
stuck Installed Capacity,XIW
2025 2026 2 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2 2043 2044 2045 Total
MN Base - - - - - - - - - - - - - - - - - -
MR Base - - - -
MN-No CCS
MN-No Nuclear - - - - - - -
MN-No Coal 2032
MN-Offshore Wind - - - - - -
MN-No Forward Technology
MN-Geothermal - - - - - -
MN-Hunter Retire
LN Base - - - - - - -
HH Base
SC Base - - - 167) - - - - - - - - (16;
'Only reports retirements of existing gas plants.
257

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
258

PACIFICORP-2025 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 7
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. Consequently, 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. As discussed in Chapter 8, some of the studies below were able to fulfill the requirements
of another study and are noted as such. Table 9.33 summarizes the jurisdictional studies which
were integrated for each of the variants and price-policy scenarios.Variants evaluating technology
that is available in all jurisdictions have jurisdictional portfolios developed for each jurisdiction.
Where a jurisdiction does not use the applicable technology or assumptions under consideration in
the variant, selections for that jurisdiction are held constant at their base scenario. For example,
neither Oregon nor Washington participates in coal-fired resources over the long term, so studies
that evaluate alternative decisions for coal-fired resources hold Oregon and Washington
jurisdictional results constant. Similarly, Washington requires that the SCGHG price-policy
scenario be used for planning, so Washington selections under SCGHG are integrated regardless
of the price-policy scenario under consideration.
Table 9.33 —Jurisdictional Studies for Variants and Price-Policy Scenarios
1
7L\.IR -
ase Base Base \fN price-policy scenario
se ✓ yIR price-poficy scenario
se ✓ J LN price-policy scenario
HE - Base ✓ J HH price-policy scenario
SC - Base ✓ ✓ Base SCGHG price-police scenario
\o coal units are able to select CCS
,FN - No CCS technolog-v
_A.11 coal must retire or convert b-,-
'F\ - No Coal 2032 :anuary 1. 2032
Require all Hunter units to retire no
MTN - Hunter Retire later than 1 1 2030
\o nuclear resources are eligible for
�fN - No Nuclear
✓ (SC) selection
J (SC) Counterfactual to preferred portfolio
\FN - O fshore Wind selection
\o nuclear,hydrogen or 100-hour
\FN - No Fom-ard Technolog ✓ {SC} storage, or biodiesel pealing
✓ J (SC) Counterfactual to preferred portfolio
\FN - Geothennal selection
MN - All Coal End of Life Same as No CCS Continue 2025 coal technology
�FN - \o Ne«- Gas Same as Preferred Portfoho \o ne«- gas resources allo-wed
Same as No Coal 2032 All coal must be converted to natural
\FN - Force All Gas Conversions gas ,where available
259

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.34 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. As in previous IRPs,
model results can indicate the need to examine costs and risks beyond the model horizon.
End effects were applied to all portfolios run under the MN price-policy for a 5-year period after
the study horizon, results of which can be seen in this table. The specific trends that led to this
examination can be found in the discussion of individual cases below.
Table 9.34-Integrated Portfolios Under Medium Gas/Zero CO2
ST Value Risk Adjusted With End Effects CO2 Emissions
Total CO2
Change from Change From Emissions, Change From
Lowest Cost Lowest Cost Change from 2025-2045 Lowest
PVRR Portfolio Stochastic Portfolio Lowest (Thousand Endssion
Case-MNjillikL $m ($ Rank PVRR ($m Rank PVRR $m) Portfolio Rank Tans Portfolio Rank
Integmted Base MN 27,233 $171 4 27,618 $106 2 34,663 $0 Ed 317,054 109,082 9
Integrated No CCS MN 28,345 $1,283 6 28,886 $1,374 6 35,768 $1,105 6 386,023 178:051 3
Integrated No Nuclear MN 28,878 $1,816 29,301 $1,789 8 36,457 $1,794 1 7 320,486 112,515 10
Integmted No Coal Post 2032 MN 28,438 $1,376 7 29,235 $1,723 7 36,751 $2,088 1 8 215,237 7,265 3
Integmted Offshore Wind MN 34,645 $7,583 35,127 $7,615 13 42,917 $8,255 31Q,014 102,043 7
Integmted No Future Tech MN 29,110 $2,048 10 29,534 $2,022 10 36,946 $2,284 330,034 122,063
Integrated CeothennalMN 29,208 $2,146 li 29,946 $2,434 11 37,188 $2,525 310,138 102,167 8
Integrated Hunter Retire MN 27,062 $0 1 27,765 $253 3 34,960 $297 269,208 61,237 6
Integrated Base MR 27,176 $114 3 27,913 $401 4 35,385 $723 5 207,971 0 1
Integrated No CCS MR 28,581 $1,519 8 29,374 $1,862 9 36,896 $2,233 9 213,302 5,331 2
late grated Base LN 27,785 $723 5 27,970 $458 5 35,167 $504 4 340,068 132,096 12
Integmted Base HH 27,119 $57 2 27,512 $0 1 34,714 $51 2 238,450 30,479 4
Integrated Base SC 29,787 $2,725 12 30,088 $2,575 12 37,904 $3,242 12 257,126 49,155 5
Table 9.35, below, summarizes the cost and risk results of the variant studies under conditions
represented by the LN (low gas price/zero CO2)price-policy scenario.
Table 9.35-Inte rated Portfolios Under Low Gas/Zero CO2
ST Value CO2 Emissions
Total CO2 qW
Change from Emissions, Change from
Lowest Cost 2025-2045 Lowest
PVRR Portfolio (Thousand Emission
Case -LN ($m) ($m) Rank Tons) JL Portfolio Rank
Integrated Base LN 25,113 $498 4 315,803 54,380 10
Integrated Base MN 25,226 $611 5 334,470 73,047 12
Integrated No CCS MN 25,847 $1,232 8 361,938 100,514 13
Integrated No Nuclear MN 28,638 $4,023 12 315,004 53,580 9
Integrated No Coal Post 2032 MN 25,428 $814 6 261,423 0 4
Integrated Offshore Wind MN 37,505 $12,890 13 299,472 38,049 7
Integrated No Future Tech MN 26,507 $1,892 9 326,791 65,368 11
Integrated Geothermal MN 26,936 $2,322 10 300,704 39,281 8
Integrated Hunter Retire MN 24,959 $344 2 273,675 12,251 6
Integrated Base MR 24,615 $0 1 254,697 (6,726)
Integrated No CCS MR 25,580 $965 7 261,242 (181)
Integrated Base HH 24,990 $375 3 248,840 (12,584)
Integrated Base SC 27,805 $3,190 11 1 270,860 9,437
Table 9.36 summarizes the cost and risk results of the variant studies under conditions represented
by the HH (high gas price/high CO2)price-policy scenario.
260

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.36-Integrated Portfolios Under High Gas and Coal/High CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2025-2045 Lowest
PVRR Portfolio (Thousand Emission
Case -HH ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base HH 31,498 $0 1 174,521 444 2
Integrated Base MN 34,498 $3,000 8 232,976 58,900 13
Integrated No CCS MN 35,762 $4,264 11 219,378 45,302 12
Integrated No Nuclear MN 35,275 $3,777 10 202,255 28,178 10
Integrated No Coal Post 2032 MN 33,052 $1,553 4 179,879 5,803 4
Integrated Offshore Wind MN 45,727 $14,228 13 194,780 20,703 8
Integrated No Future Tech MN 35,902 $4,404 12 207,187 33,110 11
Integrated Geothermal MN 35,247 $3,749 189,861 15,785 7
Integrated Hunter Retire MN 31,973 $475 179,948 5,871 5
Integrated Base MR 31,796 $297 180,431 6,355 6
Integrated No CCS MR 33,110 $1,612 5 178,538 4,461 3
Integrated Base LN 33,995 $2,496 6 201,609 27,532 9
Integrated Base SC 34,207 $2,709 7 174,077 0 1
Table 9.37 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.
261

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.37-Integrated Portfolios Under Medium Gas/ Social Cost of CO2
ST Value CO2 Emissions
Total CO2
Change from Emissions, Change from
Lowest Cost 2025-2045 Lowest
PVRR Portfolio (Thousand Emission
Case -SC ($m) ($m) Rank Tons) Portfolio Rank
Integrated Base SC 40,268 $2,628 7 103,326 3,072 3
Integrated Base MN 40,882 $3,242 8 117,244 16,990 9
Integrated No CCS MN 41,851 $4,210 11 120,282 20,028 12
Integrated No Nuclear MN 38,899 $1,258 4 115,060 14,806 8
Integrated No Coal Post 2032 MN 39,186 $1,545 105,996 5,742 5
Integrated Offshore Wind MN 51,719 $14,079 13 110,124 9,870 7
Integrated No Future Tech MN 41,797 $4,157 10 117,608 17,354 10
Integrated Geothermal MN 40,942 $3,302 9 106,062 5,808 6
Integrated Hunter Retire MN 38,034 $394 101,094 840 2
Integrated Base MR 38,708 $1,067 3 117,634 17,380 11
Integrated No CCS MR 39,227 $1,586 6 104,731 4,477 4
Integrated Base LN 42,873 $5,232 12 157,891 57,637 13
Integrated Base HH 37,640 $0 1 100,254 0 1
Integrated Portfolios Under Medium Gas/Federal Regulation (MR)
Three variant cases examined compliance under the current language in EPA 111(d): the base MR
case,the MR No CCS case, and the No Coal Post-2032 case. Details for each MR case is included
with the discussions of the integrated portfolio results below.
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 found not to be commercially viable at this
location. As Jim Bridger 3 and 4 run as coal in this case, the No CCS variant serves as the "All
Coal End of Life"variant as well.
Figure 9.17 shows the cumulative (at left) and incremental (at right) portfolio changes when CCS
at Jim Bridger 3 and 4 is not allowed on the system starting in 2030. 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.
Over the course of the horizon, fewer proxy resources are built. There is reduction of 469 MW of
wind, 236 MW of solar and 989 MW of battery, with battery reductions occurring in 2042 and
2045.
262

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.17- Increase/(Decrease in Proxy Resources with No CCS
Cumulative Changes Incremental Portfolio Changes
800
1.000
600
500 ���������■■■�1 400
�'' ---■
(1.00D) (200)
(1.500) (400)
(2.000) - (600)
(2.500) (800)
^h tib ryn ryW rq ,y0 ,rye P 11 1, ,yh `0 ,y 1*1 ,yq O � N P yh h ,1b n * q ,y0 41 ,yry ,y^t 1", ,yh ,yb ,y ,ytb ,yq�1?$N 1'y y 1P
ti 1O NO h h� NO NO NO N h ti� NO NO 'YO h ti$ti�ti�N�'V�'Va M�^�i ^�^�i '��HO '�O ti0 HO 'VO �O tV 'VO tV 'L� tV tV ^r ^SY�'�
■Cosl ■Gas ■QF •Hydro -Coal -G. •QF •Hydro
■Nudear ■Hy
dro Storage ■Baaery S.I.■ -Nadm •Hydro Storage -Battey •Solar
•Wind •Geothermal ■Energy Effidmry ■Demmdllmpoose •Wind Geothermal •Energy Effid-cy -D—dRespm
•Covvrned Gas Hydrogen Storage Pecker •Renewable Peaking •Convened Gas Hydrogen Storage Pecker Rw ble Peaking
Figure 9.18 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 the 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$1.076 billion 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 9.18-Increase/(Decrease)in System Costs with No CCS
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,000
$2,000
$500 $1,076
$0 _ $1,500 —
NOMINEE $1,000
($500) $500
($1,000)
$0
($1,500)
($2,000) ($500) tt
($2,500) - ($1,000)
n rn o N v c a o N ($1,500)
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
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
No Nuclear Variant
This variant does not allow the NatriumTM demonstration nuclear project to be selected as a
resource option in 2032. Additionally,this variant does not allow any proxy nuclear to be selected
as a potential replacement for the NatriumTM project. The analysis explores the potential costs and
benefits of replacement resource options should the nuclear projects prove unviable.
Figure 9.19 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. The variant
case does not select small renewable peaking resources and reduces 100-hour battery selection by
1,955 MW. The No Nuclear portfolio does add an additional 923 MW of 4-hour storage, 347 MW
263

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
of wind, 296 MW of solar, and 120 MW of DSM. This study also keeps the CCS at Jim Bridger
and Naughton 1 gas conversion through the end of the study horizon.
Figure 9.19-Increase/(Decrease)in Proxy Resources with No Nuclear
Cumulative Changes Incremental Portfolio Changes
3,000 1.500
2,500
2.000 ! 1,000
1,500 p —'
500
y 0 , �..■..■....'.' 1101--
—Emil—
■'' '
A (500) 1
(I.000) — I (500)
(1,500) — —
(2,000)
N'D W N4i H �� ,,,N ,.th ,yb ,y'7 ,,,b �� �4 ,yq O N 'h Ph '7 Nb n N4 Q ,yb �n 14 �Q ,GPN GPI CPy
No No No ti ti No No No i l No No No No ti l 4 li 11 NP No N6 4 N1 �O N° N° N° N° N° No No No No N N N N N
■Coal ■Gas ■QF ■Hydro ■Coal ■Gas ■QF ■Hydro
•Nodes ■Hydro Storage ■Battery ■Solar •Nndear •Hydro Storage Battey •Solar
W,ad •Geothermal •Enagy Efficiency •D®sod Resp-. .Wind .Geothermal •Energy Effideacy ■Demand Response
Con as vened G t Hydrogen Storage Peaker •Renewable Pealdng t.Converted Gas Hydrogen Storage Peaks Renewable Peaking
Figure 9.20 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 the 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 $1.794 billion increase in costs compared to the preferred portfolio.
Given that no costs associated with the NatriumTM demonstration project are included in modeling,
the increase in costs reflects the loss of all energy and PTC benefits associated with the project.
As seen in Figure 9.20 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.
Figure 9.20-Increase/(Decrease)in System Costs with No Nuclear
Annual Change in Cost by Line Item Net Difference In Total System Cost
$600 —
$ $2,000
500 —
$400 $1,800 ---
$1,600
— t�11 $1,400 —�
$1,200
$100 '
$0 — — —— t�tttt� $$800$600
($100) $600
($200) $400
($300) $200
($400) $0
. . . . . C. � N� � � � ($200)
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 M m...
O O O O O O O O O O O O O O O O O O O O O O O O O O
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
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
264

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. Because all units eligible for gas conversion
either convert to gas or retire early, this study also serves as the "Force Gas Conversion"variant.
Figure 9.21 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 additional energy efficiency and
demand response, over 2,200 MW of additional wind and solar, and a shift in storage from 4-hour
to long duration.
Figure 9.21 -Increase/(Decrease)in Proxy Resources with No Coal Post-2032
Cumulative Changes Incremental Portfolio Changes
6,000 5,000
5.000 4,000 —
4.000 3.000
2.000 ^�
000 zG z,000
1.000 1,000
(1,0DO)
O !IIIII 1111111 •
(2,000) I (1,000)
( (2,000)
4.000)
(5,oD0) —
tiy ,;1 „1N „1^5 1, „th ,yb ,yam N „tq o - N 'h h ryh ,yb ti 4 q „14 ^i 'S P h
ti� ti� ti ti ti rv� � ti� �' �ti`Y ti`P,�eP tie4�ti`P ti� � ti� ti�ti�ti� ti° ti� ti° ti� ti° �° ti� �° do ,yc4'ti`P ti`F ticF,ycF ti`Y
Coal G. ■QF -Hydro ■Ca G. ■QF ■Hydm
■Nudes •Hydro Storage -Bwary S.I.• ■N-dear ■Hydro Storage ■Battery ■Solar
•Wind •Geothermal -Eaergy Efficiency -Demmd Response ■Wind -Geothermal ■Energy Effid—y ■De dResponse
—av•C dGas -Hydrogen Storage Peaker Renewable Peaing -Cmverted Gas -Hydroga Storage Peaker Ree ble Peaing
Figure 9.22 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 the 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 converted to gas by 2032, the
resulting portfolio has a $2.088 billion increase in costs compared to the preferred portfolio.
As seen in Figure 9.22 below, the system cost increase exceeds the impact of 45Q tax credits and
CCS capital cost. Additionally, this case has higher levels of market purchases and has higher
proxy resource costs in nearly all years of the study horizon.
Figure 9.22 -Increase/(Decrease)in System Costs with No Coal Post-2032
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,500
$2,500 $2,088-
$1,000 $2,000
$0 � — $1,000
($500) $500
($1,000) $0
($1,500) ($500)
($2,000) ($1,000)
OI ($1,500)
O O O N O O O N N N N N N N N N N N N N ON N N N
O O O O O O O O O O O O O O O O O O O O O O O O O O
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
265

PACIFICORP—2025 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 9.23 shows the cumulative (at left) and incremental (at right) portfolio changes when
offshore wind is forced into the portfolio in 2033. A positive value indicates an increase in
resources and a negative value indicates a decrease when a resource is reduced or eliminated. The
portfolio selects and additional 120 total MW of wind, 3,760 MW of 4-hour storage and 35 MW
of additional DSM. These increased selections are partially offset by a reduction of 132 MW of
solar and 812 MW of 100-hour storage. Retirements are the same between the studies.
Figure 9.23 - Increase/(Decrease in Proxy Resources with Offshore Wind
Cumulative Changes Incremental Portfolio Changes
z
a,000 ,DDO
3,500 1,500
3,000 —
2,500 I,000
2,000 500
N _
m 1,500 MIN
500 (500)
,..■■■.■�����(SOD) (1,000)
(1.000)
tih eyb ti� ti4 tiQ h0 ,y♦ hti eh ,yP h b M� b ,yq O ♦ N NCY h h h ,` n ,yro Q „t0 ,y♦ hry ^1h „tb ^1h ^16 ,y ,Ib ,'I O ♦ ry M h
,� ^O NO ,� ry0 NO NO NO r0 1 101 NOh NO 4h'O tiCY 14 11 ti�11 4 4b 11 ee0 11 ry0 ry0 ry0 ry0 ry0 ry0 ^Oi ry0 '�O ry0 tiCP ryCY tiCP tiCP ry ryCY
.Coal G. •QF •Hydro •Coal G. •QF -Hydro
■Nudwr ■Hydro Stange ■Bmn y M. •Nude. •Hydro Storage •Battery S.I.•
■Wiod -Geoth—d ME—gy Effid—y ■D--dRespo •Wiud •Geoth,mal •Energy Effiday •De dRespa
•Ca--d Gas Hydrogen Storage Peak, Rw ble Peaking C—ve dGas Hydrogw Storage Peaktt Rwewable Peaking
Figure 9.24 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 the 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 $8.255 billion
increase in costs compared to the preferred portfolio.
As seen in Figure 9.24 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.
266

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.24-Increase/(Decrease)in System Costs with Offshore Wind
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,600
$1,400 $ ,000 ---
$8,000 __-
$1,200 $7,000 -
$1,000 $6,000 $8,255
$800 $5,000
$600 $4,000
$400 $3,000
($200) $0
($1,000)
N N N N N V V V V V 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
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
No Forward Technology
This variant does not allow the NatriumTM demonstration nuclear project, hydrogen storage, 100-
hour battery or small biodiesel peaking units to be selected as resource options. The analysis
explores the potential costs and benefits of replacement resource options should these technologies
not become commercially viable during the assumed time frame as modeled.
Figure 9.25 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. The variant
case selects 120 MW of additional DSM, 187 MW of additional wind and 254 additional MW of
solar. The model replaces the 3,073 MW of 100-hour storage with 1,826 MW of 4-hour storage
and also does not retire CCS at Jim Bridger or the Naughton 1 gas conversion.
Figure 9.25-Increase/(Decrease)in Proxy Resources with No Forward Technology
Cumulative Changes Incremental Portfolio Changes
1.500 1,000
800
1 000 600
500 111 .
200
(1 0DO)
(600)
(1,500)
(8m
C2.000) a y e �Ay a (1,000) by
�O Off~OWN O OAP O�h Orb Off^O O CSO�~C5~C5�CSP CSh Sh O~b Sr O~�OryQ OHO Off`O�ry O��Orb O�y Orb Off^OPT O�Q OO CP`CYti Cp CAP�y
ti � '� h ti ti N ti ti ry ti ti ti ti ti h ti '� N '� N '� N ti ti ti N N h h h ti h ti ti ti ti
■Coal G. -QF •Hydro ■Coal •Gas •QF -Hydro
■Nadear ■Hydro Storage -Battery S.I.• •Nud— -Hydro Storage •Battery ■Solar
•Wind -Gmth-1 •Energy Etricimey ■Demend Respmse •Wind •Geothermal .E—gy Effrdmcy •D® dRe%p
•C_wa dGas -Hydrogen Storage Peaks -RenewablePdd.g -Convened G. Hydrogen Storage Peaker Renewable Peaki-g
Figure 9.26 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions, when forward technologies are removed from the portfolio. The graph on the left
shows annual changes in cost by category and the graph on the 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 forward technology is removed from the portfolio, the
resulting portfolio has a $2.284 billion increase in costs compared to the preferred portfolio,
somewhat higher than the impact of removing NatriumTM alone as shown in Figure 9.20.
As seen in Figure 9.26 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
267

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
in proxy resource costs in the final years of the study horizon, the need for early investment
overcomes these later potential savings.
Figure 9.26—Increase/(Decrease) in System Costs with No Forward Technology
Annual Change in Cost by Line Item Net Difference In Total System Cost
$800
$zsoo $2,284
$600
$400 $2,000
$zoo , $1,500
$o ---� —�, $1,000
($zoo) ' $500
($400) $0
($600)
($500)
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 V V V V a a a a V 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
■Coal&Gas Fixed -Coal&C Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment -Net Cost/(Benefit) ---Cumulative PVRR(d)
Force Geothermal
Since geothermal 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 geothermal resource.
Figure 9.27 shows the cumulative (at left) and incremental (at right) portfolio changes when
geothermal is forced into the portfolio by 2028. A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated.The geothermal
study does not retire the Naughton 1 gas conversion. Additionally, the firm capacity more than
700 MW of geothermal reduces the need for other renewable resources. Over 2,500 MW of wind
and solar are removed, as well as over 2,200 MW of long duration storage. 719 MW of 4-hour
storage is selected in the geothermal study.
Fi ure 9.27- Increase/(Decrease) in Proxy Resources with Geothermal
Cumulative Changes Incremental Portfolio Changes
2,000 1.500
1.000 t,000 .
0 MENNEN M 0
(2,000) P7 MML
(soo)
(3,ODO) (1,000)
(4.000) (1,500)
(5.ODO) (2.000)
Sy Orb S^S°'� �O Off~OWN O��Orb O�h Orb Off^O��O��CYO CP~CP~CPS'CPa CPh Oryh O~b Sr O~�Sr OHO Off` �ry O�� roc O�y Orb Off^O��O�Q CPO CY`CP~CPS'CP'CPy
tY ^i tY ti ti � ti ti ti ti ti ti ti N H ti ti ti H ti ti ti N h ti ti N h N W � ti ti h ti ti h ^i ti ti ti ti
■Coat -Gas -QF -Hydm ■Coal ■Gas ■QF -Hydm
■Nadear ■Hydro Storage -Battery -Solar ■Nod— ■Hydro St«age ■Battery S.I.■
■Wind -Gmthermal -Energy Efficimey -Demmd Respmse •Wind -Geothermal -Energy Efftd—y •D--dRespme
■C_we dGas -Hydrogen Storage Peaks Renewable Peaking •C—ed Gas -Hydrogen Storage Pecker Renewable Peaking
Figure 9.28 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions, when geothermal is forced into the various jurisdictional portfolios. The graph on
the left shows annual changes in cost by category and the graph on the 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 geothermal is forced into the portfolio, the
resulting portfolio has a $2.525 billion increase in costs compared to the preferred portfolio.
268

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
As seen in Figure 9.28 below, these increases come primarily from increased costs of the
geothermal compared to the lower costs of the renewable resources that were replaced by the
geothermal.
Figure 9.28 -Increase/(Decrease)in System Costs with Geothermal
Annual Change in Cost by Line Item Net Difference In Total System Cost
$800 $3,000 $2,525
$600 $2,500 -----
$400 $2,000 —
$20 �I Ill fl '''. $I,500
$
0 $1,000 —
($200) $500 —
($400) — $0
ro r a o N m a v, rc m a o N v ($500)
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 V V a a a V
....O O O O O O O O O O O V O O V O O V O O O O O 8.
O
■Coal&Gas Fixed •Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
Force Hunter Retirement
Responsive to stakeholder request, PacifiCorp performed a variant analysis exploring what the
impact of an early retirement of the Hunter plant would be on the portfolio. In this variant,all units
at Hunter were required to retire by 2030. The analysis explores the potential costs and benefits of
replacing the Hunter plant with resources selected in the UIWC jurisdictional portfolio when
Hunter is not available. Additional consideration of Utah regulations would be necessary before
the company would be able to move forward with implementing this variant.
Figure 9.29 shows the cumulative(at left)and incremental(at right)portfolio changes when Hunter
is forced to retire 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 Hunter study does not retire the
Naughton 1 gas conversion. The loss of 1,100 MW of firm capacity in 2030 leads to the selection
of over 1,100 MW of wind and solar, coupled with 866 MW of additional storage in 2030. By the
end of the study horizon, the model selects 99 MW of new gas, an additional 355 MW of energy
efficiency and demand response, and over 1,400 MW of new renewables. Total battery selection
over the horizon stays the same but has a shift from 4-hour to 100-hour storage.
Figure 9.29-Increase/(Decrease)in Proxy Resources with Hunter Retirement
Cumulative Changes Incremental Portfolio Changes
3.500 2,500
3.000 2.000
2.500 1,500
2.000 3
1,500
m 1.000 y 500 —
500
(1(000) 111111111111' (1,000)
(1,500)
11 yb en 17 H 1 h1 M� 'yy 7p h ,,,b , 4 q o , 1 n h h ryb n * al �O �;1 1 �Q'GF s,CFI GY 4,
ti ti� ti� ti ti� ti� ti� ti� � � ti ti� ti� ti� ti ti`4'ti`Y ti`Y ti`4 ti`4�ti`4 ti��O ti��O ti�H� ti° � ti° � � ti° � �v rv� ti ti ti ti ti ti
■Coal G. ■QF ■Hydm ■Cod G. -QF •Hydro
■Nadem ■Hydro Stage ■Bent y S.I.■ •N•d— -Hydro Storage -Battery •Sda
•Wtad •Gmthettnd •E—gy Effid—y •D®end Response •Wind •Gmthermd -Energy Efficiency ■D--dResp—
•C—wM Gas Hydrogm Storage Peaker •Renewable Peakng •0.,erc d Gas Hydrogen Storage Peaker Renewable Peaking
269

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.30 summarizes changes in system costs,based on ST model results using MN price-policy
assumptions, when Hunter is forced to retire in 2030. The graph on the left shows annual changes
in cost by category and the graph on the 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 Hunter is forced to retire in 2030,the resulting portfolio has a$297 million increase
in costs compared to the preferred portfolio.
As seen in Figure 9.30 below, these increases come primarily from the additional proxy resource
costs associated with replacing the Hunter plant in 2030.
Figure 9.30-Increase/(Decrease)in System Costs with Hunter Retirement
Annual Change in Cost by Line Item Net Difference In Total System Cost
$500 $350 $297—,�
$400 MEN $300
$300 MEN $250
$200 ,,,,,., $ 0
$100 $15150
$0 —EMEME $100
($100) $50
($200) MMEMINIMENIMEMEN
MMEMMM $0
($300) ($50)
($400) ($100) —'
NG r O O N V D n a O N ($150)
N N N N a
O O N N O N O O N O N
O O O O O O O O O O O O O O O O O O O O O O O O O O
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulatme PVRR(d)
MR Portfolio
The MR portfolio evaluates resource selections assuming EPA 111(d) rules remain in effect
through the study horizon. This portfolio limits new gas capacity factors and requires either
installation of CCS, gas conversion, or retirement of existing coal units by 2032. The purpose of
this study is to evaluate a path PacifiCorp would pursue for long-term compliance with this rule.
Figure 9.31 shows the cumulative (at left) and incremental (at right) portfolio changes between a
medium price, no carbon tax future and a medium price, 111(d) compliance future. A positive
value indicates an increase in resources and a negative value indicates a decrease when a resource
is reduced or eliminated. In an MR future, all plants that are eligible to convert from using coal to
using a different fuel type do. Wyodak and Hunter 1 both retire in 2032. This reduction in coal
capacity and the significantly lower capacity factor of converted units leads to an additional 1,299
MW of solar, 916 MW of wind and 369 MW of DSM. The portfolio also selects 451 MW of
additional 100-hour battery, while removing 575 MW of 4-hour storage.
270

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.31 - Increase/(Decrease in Proxy Resources with MR
Cumulative Changes Incremental Portfolio Changes
6 000 3:Oo0
5.000
2.000
4.000
3,000 I,OoO
2,000
(4.Oo0) (3,000)
1 tib * ti� h 'y0 'ham „f'y ,y'ti ^,b ^fh „* ,y 1*1 „Iq o � 'y h yh h ,yb n ,y4 q ,11 41 ^fly vfM „", ,yh „" ,y ^1*1 ^'q Cp~
ti ry0 NO h ry0 NO NO ^O 10 t0 ry0 NO NO ry0 r0 ryCY'ryGD`ryGY`NG�`ry�ryC1' N�ry0 N�ry ti�ry0 ry0 ry0 ry0 ry0 ry0 ^O ry0 ^O ry0 ry ry ry ry ry
■Cosl ■Gas ■QF •Hydro -Coal -G. •QF •Hydro
■Nudes ■Hydro Storage ■Battery S.I.■ -Nad— •Hydro Storage -Bay •Solar
•Wind Geothermall ■Energy Effi
mvate dmy ■Demmditmpoose •Wtvd Geothermal •Energyllffid-cy -Demand Response
-Cd Gas Hydrogen Storage Peak' •Renewable Peaking •Cmvated Gas Hydrogm Storage Peaker Renewable Peaking
Figure 9.32 summarizes changes in system costs, based on ST model results operating MN price
policy portfolio under the MN price policy assumptions. The graph on the left shows annual
changes in cost by category and the graph on the 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 MR portfolio is operating under the MN price policy,the resulting portfolio
has a $723 million increase in costs compared to the preferred portfolio.
Figure 9.32 - Increase/(Decrease)in System Costs of MR Portfolio Operating Under MN
Annual Change in Cost by Line Item Net Difference In Total System Cost
$800
$800
$600 $700 $723
$400 $600
$500 /
$200 $400$300
($200) $100 `
$0
($400) ($100) —
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d ($200)
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
■Coal&Gas Fixed ■Coal&.Gas Variable ■PI'OXy Re50Ul'Ce COS[g 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
MR No CCS
The MR No CCS portfolio evaluates what changes would occur to the MR portfolio if CCS at Jim
Bridger were to prove to not be a viable option for EPA 111(d) compliance. This portfolio limits
new gas capacity factors and requires either gas conversion, or retirement of existing coal units by
2032, precluding CCS selections. The purpose of this study is to evaluate the path PacifiCorp
would take to be compliant with this rule in the absence of CCS at Bridger.
Figure 9.33 shows the cumulative (at left) and incremental (at right) portfolio changes between a
medium price, no carbon tax future and a medium price, 111(d) compliance future. A positive
value indicates an increase in resources and a negative value indicates a decrease when a resource
is reduced or eliminated. Jim Bridger 3 and 4 gas convert in lieu of installing CCS and does not
retire Naughton 1 gas conversion. Hunter 1 retires in 2031 instead of 2032. Keeping the Jim
Bridger and Naughton units leads to lower proxy resource selections across all generating types.
The portfolio reduces wind by 55 MW,DSM by 378 MW and solar by 561 MW.Battery selections
remain cumulatively the same with a shift from 24-hour battery to 4-hour battery.
271

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.33 - Increase/(Decrease in Proxy Resources with MR No CCS vs. MR
Cumulative Changes Incremental Portfolio Changes
2.500 zsoo
2.000 2,1
1.500
L 00 ''••�..■■ 1.500
5
m oo --- ...■■■■�,,,, l,aao c
(1,500) ,' ■■ , — ■—
two) (soo)
(z,
(2,500)
1 ryb eye ry4 h 1'0 'ham my 11 1, „th ,hb "i „t4 ,,,q o � ry P h h „rb n * q „t0 ,yr ^try 11 vtb ,yh „tb ,y 1*1 ,yq��f$ry
'� ry� ry� h ry� ry� ry� ry� N ^�i '�� ry� ry� ry� h ry$'��ry�ry�'��'�� ry�ry ry�ry '��ry� '�� ry� ry� ryq ry� 'V ry� rV ry� ry ry
■Cosl ■Gas ■QF •Hydro •Coal -G. •QF •Hydro
■Nudm ■Hydro Storage ■Banery ■Solar :coal
•Hydro Storage -Battery •Solar
•Wind •Geothermal ■Energy Effidmy ■Dmmd Rmpmse •Wind Geothermal •Energy Effeimey �D—dResp-.
.Cmvrned Gas Hydrogen Storage Pecker •Renewable Pealvg •Converted Gas Hydrogm Storage Peaker Renewable Peaking
Figure 9.34 summarizes changes in system costs,based on ST model results using MR 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 the 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$1.507 billion increase
in costs compared to the MR portfolio with CCS.
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 9.34-Increase/(Decrease in System Costs with MR No CCS vs. MR
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,000 $1,507
——— $2,00
$500 $1,500
($500) $500
($1,000) $o
($1,500) ($500) TO --
($
2,000) ($1,000)
N N N N N m m m m a a a a a a ($1,500)
■Coal&Gas Fixed ■Coal&Gas Variable ■Proxy Resource Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
HH Portfolio
The HH portfolio evaluates what selections would be made under high future costs, including gas,
market, and coal. This portfolio integrated Oregon selections under HH, UIWC selections under
HH and Washington selections under SC. The purpose of this study is to evaluate the selections
PacifiCorp would make if a high-cost future was most likely.
Figure 9.35 shows the cumulative (at left) and incremental (at right) portfolio changes between a
medium price, no carbon tax future and a high price future. A positive value indicates an increase
in resources and a negative value indicates a decrease when a resource is reduced or eliminated.
The HH Portfolio selects Dave Johnston 4 and Hunter 2 to convert from coal to a different fuel in
2030. The HH also retires Hunter 2 in 2033. The model increases brownfield renewable selections
by 2007 MW and selects 562 additional MW of 100-hour storage. There is a reduction in 4-hour
272

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
storage of 757 MW, however all selections of additional 4-hour storage occur in 2030 in the HH
run. An additional 208 MW of DSM is also selected.
Figure 9.35- Increase/(Decrease in Proxy Resources with HH
Cumulative Changes Incremental Portfolio Changes
5.000 _ 3,500
3,000
4.000
2,500
3,000 2000
2,000 .b 1,500
1000 1.000
500
( ) ' (500)
(2,000)
eyh tib * ti� hQ 'h0 'ham 1" 11 1, ,yh 1'* "i ,yQ O � ti P h h 1" n ry4 Q �O 41 1ry ,y^1 1b ,h ,1 ,y M� 1" O � ti P '^�
ti 1O NO h ^i0 NO NO NO N h MO NO NO rY0 h h$ti�ti�N�ti�ti� MS,ry N�ry ti�HO ti� 'VO HO 'VO HO 'V 1O ^O ry0 ry�^�^�^r6 ^�'y�
■coal G. ■QF •Hydro •Coal G. •QF :Hydro
■Nudem ■Hy
dro Stmage ■Battery ■Sohn •Node: •Hydro Storage -Bay •Sdar
•Wind •Geothermal ■Encgy Effid—y •Demand R.Wp •Wind .Geothermal •Energy Efficimcy mDemmd Respmse
•Cmv d Gas .Hydrogen Storage Peaker -Renewable Peaking Cmvened Gas Hydrogm Storage Peaker Renewable Peaking
Figure 9.36 summarizes changes in system costs, based on ST model results operating HH price
policy portfolio under the MN price policy assumptions. The graph on the left shows annual
changes in cost by category and the graph on the 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 HH portfolio is operating under the MN price policy,the resulting portfolio
has a $51 million increase in costs compared to the preferred portfolio.
Figure 9.36-Increase/(Decrease) in System Costs of HH Portfolio Operating Under MN
Annual Change in Cost by Line Item Net Difference In Total System Cost
$500 $300
$400
$300 $200
$200 $100
$1$00 — —,,■■������ $0 $51
($100) — ($100)
($200) ———($300) ($200)
($400) — ($300)
.., . m o o ($400) �.
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 y
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
■Coal&Gas Fixed ■Coal&Gas Variable ■P1'OXy ReaOtffCe COSTS 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Cost/(Benefit) ---Cumulative PVRR(d)
273

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
LN Portfolio
The LN portfolio evaluates what selections would be made under low future costs, including gas
and market with no CO2 tax adder. This portfolio integrated Oregon selections under LN, UIWC
selections under LN and Washington selections under SC. The purpose of this study is to evaluate
the selections PacifiCorp would make if a low-cost future was most likely.
Figure 9.37 shows the cumulative (at left) and incremental (at right) portfolio changes between a
medium price, no carbon tax future and a low-price future. A positive value indicates an increase
in resources and a negative value indicates a decrease when a resource is reduced or eliminated.
The LN portfolio delays the retirement of the Jim Bridger CCS conversions one year and does not
retire Naughton 1. The LN does select 496 MW of new gas peaking units in 2045 in place of the
41 MW of renewable peaking in the preferred portfolio. There is an increase of 91 MW of DSM,
and a reduction of 508 MW of new renewable generation. The model selects and additional 389
MW of storage, swapping 100-hour for 4-hour battery.
Figure 9.37- Increase/(Decrease in Proxy Resources with LN
Cumulative Changes Incremental Portfolio Changes
2.000 1,500
1.500 1.000
1,000500 � 500 --- —■' � '
O y
0 ME MMMMIMMMM. , E y (500)
(1,000) (1,500) —
(1.500)
ryy ryp ryn tiW ryq h0 ry♦ 11ry n1n 1P 1" '* "n 11q yq O ♦ N h h h 1" n ry4 Q MO ,y♦ M~ nay roo- 1" 01 M 1*1 1" O ♦ ti M h
ti ti� ti� ti ti� ti� ti� ti� ti ti ti� ti ti� tr tr ti`3 ti`4 ti`Y N`Y,�c4�ti$ ti�rO ti�ti° tisr ti� ti° ti� rr° ti� ti� t8 ti� r8 ,v0 ,�cP ryc4'ti`fi ticY,�c4p,�cY
■coal G. •QF •Hydro •Coal G. •QF oHydro
■Nudear ■Hydro Storage ■Battery ■Solar .Nudear •Hydro Storage .Battery S.I..
■Wand •Geothermal ■Energy Effidmcy ■Demmd Rmpmse •Wtnd •Geothermal •Energy Effidmcy De dResponse
•Cen—d Gas •Hydrogen Storage Pecker Renewable Peaking •Convened Gas Hydrogen Storage Pecker Rmewble Peaking
Figure 9.38 summarizes changes in system costs, based on ST model results operating LN price
policy portfolio under the MN price policy assumptions. The graph on the left shows annual
changes in cost by category and the graph on the 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 LN portfolio is operating under the MN price policy, the resulting portfolio
has a $504 million increase in costs compared to the preferred portfolio.
Figure 9.38-Increase/(Decrease) in System Costs of LN Portfolio Operating Under MN
Annual Change in Cost by Line Item Net Difference In Total System Cost
$200 $600
$150 $504�.
$500
$$50 $400
$0 11 111.T
$300
($50) $200
($100) $100
($150)
($200) $0
($250) ($100)
($200)
O O O O O O O O O O O O O O O O O O O O O O O O O O
■Coal 8!.G95 Fixed ■Coal.$Gas Variable ■PI'OXy Re501n'Ce Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Costl(Benefit) ---Cumulative PVRR(d)
274

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
SCGHG Portfolio
The SCGHG portfolio evaluates what selections would be made under a Social Cost of Greenhouse
Gas future. This portfolio integrated all jurisdiction's selections under SCGHG. The purpose of
this study is to evaluate the selections PacifiCorp would make if an SCGHG future was most likely.
Figure 9.39 shows the cumulative (at left) and incremental (at right) portfolio changes between a
medium price, no carbon tax future and an SCGHG future. A positive value indicates an increase
in resources and a negative value indicates a decrease when a resource is reduced or eliminated.
The SCGHG portfolio does not retire the Jim Bridger CCS conversions or Naughton 1 but does
retire Wyodak in 2028 and the Dave Johnston 1 gas conversion in 2043.Additionally,the SCGHG
case chooses gas conversion at Dave Johnston 4 and allows it to continue through the 21-year
horizon and does not retire Naughton 1. The SCGHG case selects an additional 999 MW of utility
scale wind, 1,269 MW of utility scale solar, 1,756 MW of 4-hour battery and 240 MW of DSM.
The portfolio reduces small scale solar selections by 101 MW and 100-hour storage by 126 MW.
Figure 9.39- Increase/(Decrease in Proxy Resources with SCGHG
Cumulative Changes Incremental Portfolio Changes
6,000 2,000
s,000 1500
4,000
I,000
3,000
m 2.000 500
(l,000)
(500)
(2,000) p.000>
,11 1" ryn tiW 10, „f0 'h♦ ,�1N ,yr'f „1P ,ryh ,'* 'ry „1W ♦ N h h h r1b n ,q4 Q ^f0 ^f♦ 1" 11 1", „1h „b ,.1f ^fib 1" O ♦ ^1 ? '^�
ti ti� ti� ti ti� ti� ti� ti� ti ti ti� ti ti� rr rr ti`Y ti`Y ti`Y N`Y,b�ti$ ti�rO ti�ti° tis'ti� ti° ti� rr° ti� ti� rO ti� r8 rv0 ,�cP ryc4'ti`fi ticY,�c4p,�cY
.Coal G. -QF -Hydro •Coal G. -QF -Hydro
■Nadear ■Hydro Storage ■Batery ■Solar -Nadear -Hydro Storage -Battery S.I.-
■What -Genthermal ■Energy Effid—y ■Demand R.Vp -Wind -Geothermal -Energy Effidency -Demaodltespmw
•Cen—d Gas -Hydrogen Storage Pecker Renewabk Pinking -Convened Gas Hydrogm Storage Peaker Renewable Pealing
Figure 9.40 summarizes changes in system costs, based on ST model results operating SCGHG
price policy portfolio under the MN price policy assumptions. The graph on the left shows annual
changes in cost by category and the graph on the 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 SCGHG portfolio is operating under the MN price policy, the resulting
portfolio has a $3.242 billion increase in costs compared to the preferred portfolio.
Figure 9.40-Increase/(Decrease)in System Costs of SCGHG Portfolio Operating Under MN
Annual Change in Cost by Line Item Net Difference In Total System Cost
$1,000 $3,500
$3,242
$800 --___
$3,000
$600 $2,500
$00 — 11 I $2,00 --
$200 $1,500
$0 $1,000
($200) M Eli $500
($400) $0
($500)
O O O O O O O O O O O O O O O O O O O O O O O O O O
■Coal&Gas Fixed ■Coal.$Gas Variable ■PI'OXy Re501n'Ce Costs 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
■Emissions ■Net Market Transactions■Transmission
■Risk Adjustment —Net Costl(Benefit) ---Cumulative PVRR(d)
275

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Additional Sensitivity Analysis
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. It is assumed that state level compliance would still be required to be met in
these sensitivities; Oregon would still need to reduce emissions, and Washington would need to
meet CETA targets. These sensitivity cases are also useful as "bookend" analysis to aid in
understanding how PacifiCorp'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.1 lists additional sensitivity studies to be performed for the 2025 IRP. To isolate the impact
of a given planning assumption, all sensitivity cases are evaluated in comparison to the preferred
portfolio.
Table S.1—Summary of Additional Sensitivity Cases
Sensitivity 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
7highest load
High Distributed Generation Assumes lower load due to high Distributed Generation adoption
Low Distributed Generation Assumes higher load due to low Distributed 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 additional coal units
Business as Usual Portfolio if no state requirements existed
Business Plan8 First 3 years are aligned with the current business plan
High Load Growth
The High Load Growth sensitivity evaluates what selections would be made if load growth were
higher than projected. The purpose of this study is to identify potential additional resource needs
if load grows faster than anticipated.
Figure 9.41 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and high load growth. A positive value indicates an increase in resources and
a negative value indicates a decrease when a resource is reduced or eliminated. The high load
growth portfolio does not retire Naughton 1 but does retire Naughton 2 in 2045. The higher load
growth leads to an additional 319 MW of DSM, 160 MW of wind, and 435 MW of solar. There is
a total reduction of 137 MW of storage, with 329 fewer MW of 4-hour storage offset by 100 MW
of 8-hour and 92 MW of 100-hour storage.
8 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.
276

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.41 -Increase/(Decrease in Proxy Resources with High Load Growth
Cumulative Changes Incremental Portfolio Changes
800
1,800
1,600 600 —
1,400
400
1,200
p 800 '
^' 600 ■ ■
400 �(200)
4 2.0 `sm (400)
(200)
` (600)
(400) (S00)
rNh hb N� * 1 h0 M1 Mh 1 Mh „tb „tn 1101
O ti h h h „rb n 4 q ,50 hN hh „, „th „tb hry „t4 hq o N h
ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryo ryc�'ryc�'ryc�'ryc�'^cY^cp' ry�NO N'�N'�ry�ryo No No No No NO ^o No NO ry0 ^Cp rycv'ryc�'NCB'ryd ryC�'
■coal ■Gas ■QF ■Hydro ■Coal ■Gas ■QF •Hydro
■Nucleaz ■Hydro S[orage ■Battery ■Solar ■Nuclear ■Hydro Storage ■Battery ■Solo
■Wind •Geothermal ■Energy Efficiency ■Demand Response •Wind •Geothermal •Energy Efficiency a Demand Response
■Converted Gas .Hydrogen Storage Peaker a Renewable Peaking a Converted Gas .Hydrogen Storage Peaker Renewable Peaking
Low Load Growth
The Low Load Growth sensitivity evaluates what selections would be made if load growth were
higher than projected. The purpose of this study is to identify which resources might be economic
if load grows more slowly than anticipated.
Figure 9.42 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and high load growth. A positive value indicates an increase in resources and
a negative value indicates a decrease when a resource is reduced or eliminated. The low load
growth portfolio does not retire Naughton 1. Due to the lower need, the portfolio selects 1,566
MW less wind, 2,440 MW less solar and 425 MW less storage, with a reduction in 100-hour
storage offset by additional 4-hour storage. The portfolio does select an additional 125 MW of
DSM.
Figure 9.42 -Increase/(Decrease in Proxy Resources with Low Load Growth
Cumulative Changes Incremental Portfolio Changes
2,000 1,000
1,000 500
,d(1,000) U11111111111
G• 1
1
y N (500) I
A(2,000) �
(3,000)
(4,000) (1,500) —
(5,000) -
1 hb 1 * 1 MO 1 1 1 1' nth 1" h1 ry4 nt1 O ` N ^� y. h h b n 4 q ho ,�� „rN Mh hp „th „tb h" „t4 „tq S 1;' 1k�^� y IP
ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ryCY ryCY'ryC�`ryCF rycY ryc�' ryS�ry�ry�NSr NSr ry0 ry0 NO NO ry0 ry0 ry0 ry0 ry0 ry0 ryCY ry ry ry ryCY'ry
■coal ■Gas ■QF is Hydro ■Coal G. ■QF ■Hydro
■Nucleaz ■Hydro Storage ■Battery
■Solar :Nu I— is Hydro Storage ■Battery ■Soler
■Wind •Geothermal ■Energy Efficiency ■Demand Response •Wind •Geothermal ■Energy Efficiency ■Demand Response
•Converted Gas .Hydrogen Storage Peaker a Renewable Peaking .ConVerted Gas .Hydrogen Storage Peaker Renewable Peaking
1-in-20 Peak Load Growth
The 1-in-20 Peak Load Growth sensitivity evaluates what selections would be made if load growth
were higher than projected. The purpose of this study is to identify potential additional resource
needs if peak load is higher than anticipated.
Figure 9.43 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and higher 1-20 peak loads.A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated. The 1-20 peak
277

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
load portfolio retires the Jim Bridger CCS conversions 1 year later and does not retire Naughton
1. The higher peak loads lead to an additional 317 MW of DSM and 431 MW of additional solar.
There is a reduction of 222 MW of wind and 385 MW of storage.
Figure 9.43 - Increase/(Decrease)in Proxy Resources with 1-in-20 Load Growth
Cumulative Changes Incremental Portfolio Changes
2,000 ,500
1,000
1,500
1,000
500
■�'�_ ,
500 ■■-■■■■■■■■■■■
(500)
0 , I .
ENEEME■E.■• 40,000)
(500) (1,500)
(1,000) (2,001)
N Nb NN * ", ,y'h 1, „, „�b 1 1P 1 1b 1n 14 1Q O N "t h
NO NO NO NO NO NO NO NO NO NO NO NO NO NO NO N$N$N$N$NCY NCP NO NO NO NO'N�NO NO NO NO NO NO NO NO NO NO N�N�N�N�N�N�
■Coal ■Gas ■QF -Hydro ■Coal ■Gas ■QF ■Hydro
■Nucl— ■Hydro Storage ■Battery
■Solar ■Nuclear ■Hydro Storage ■Battery ■Solar
■Wind -Geothermal ■Energy Efficiency ■Demand Response •Wind -Geothermal ■Enetgy Efficiency ■Demand Response
■Converted Gas -Hydrogen Storage Pecker Renewable Peaking -Converted Gas -Hydrogen Storage Pecker Renewable Peaking
High Distributed Generation Growth
The High Distributed Generation Growth sensitivity evaluates what selections would be made if
distributed generation growth were higher than projected (and load was lower as a result). The
purpose of this study is to identify which resources would be economic if load is lower than
anticipated.
Figure 9.44 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and high load growth. A positive value indicates an increase in resources and
a negative value indicates a decrease when a resource is reduced or eliminated.The high distributed
generation growth portfolio selects an additional 269 MW of DSM. The portfolio reduces
renewable resources by 4,078 MW and storage resources by 135 MW over the course of the 21-
year horizon.
Fi ure 9.44- Increase/(Decrease) in Proxy Resources with High Distributed Generation
Cumulative Changes Incremental Portfolio Changes
2,000 1,000
U00 500
�'■■��' tt ■ ■■■ ■
a, (soo) ■
(z,000)
(3 000) (1.000)
(4.000) (1,500)
(5,000) - (2.000)
l y ONb S^a LSr Orb O"h ONb O*^ 11 ONQ CYO S,1P 1P CPa CFh ONh ONb St ONE Sr OHO Off`OWN O��Oho-O�y Orb O*^ ,O�Q a CY`CPN CPS' r 41
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 ^i N N N N
■Coal -Gas -QF -Hydro ■Coal G. ■QF -Hydro
■Nadear •Hydro Storage -Battery -Solar ■Nod— ■Hydro St«age ■Ba m ■Sd.
■Wind •Geothermal -Energy Efficieacy -Demand Respmse •Wind -Geothermal •Energy Effideocy -D--dResp—.
■Converted Gas •Hydrogen Storage Peaks -Renewable Peaking •Convrred Gas -Hydrog-Stage Pecker Renewable Peaking
Low Distributed Generation Growth
The low distributed generation growth sensitivity evaluates what selections would be made if
distributed generation growth were lower than projected. The purpose of this study is to identify
potential additional resource needs if distributed generation growth is lower than anticipated.
278

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.45 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and high load growth. A positive value indicates an increase in resources and
a negative value indicates a decrease when a resource is reduced or eliminated. The low distributed
generation portfolio does not retire Naughton 1. The higher load need leads to 349 additional MW
of DSM and 471 MW of solar. There is a reduction of 15 MW of wind and 351 MW of 4-hour
storage partially offset by an additional 40 MW of 100-hour storage.
Figure 9.45-Increase/(Decrease)in Proxy Resources with Low Distributed Generation
Cumulative Changes Incremental Portfolio Changes
1,400 600
1,200 400
1,000
r� 800
LG 600
400
200
0 1111111111 I �q ■
(200)
��
C-- —� (400)
(200)
( (600)
400)
(600) (800)
ray tib N� ticb tiq „tb „th .,b M� �cb ,�q O ^ 'y h ^h ryb ti 4 A „, „th ,yb ,yn „tW „, O N "i h
ry0 ry0 ry0 ry0 ry0 �O ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 ry0 tiCY tiCY tiCY tiCY rycY rycY' ry0 NO NO NSA ryS�ry0 ry0 NO NO ry0 NO ry0 ry0 NO ry0 NCp rycP,�cP,�cP ryd'ryCP
■coal ■Gas ■QF ■Hydro ■Coal ■Gas -QF ■Hydro
■Nuclear ■Hydro Storage ■Battery ■Solar ■Nuclear ■Hydro Storage ■Battery ■Solar
■Wind •Geothermal ■Energy Efficiency ■Demand Response ■Wind •Geothermal •Energy Efficiency ■Demand Response
■Converted Gas -Hydrogen Storage Peaker -Renewable Peaking •Converted Gas -Hydrogen Storage Peaker-Renewable Peeking
Large-Metered Load Growth
The large-metered load growth sensitivity evaluates what selections of both resources and
transmission would be required to serve all large-metered load that could potentially come online
in PacifiCorp service territory. The purpose of this study is to identify which resources might be
needed if the system had to serve all of these large-metered loads.
Figure 9.46 shows the cumulative (at left) and incremental (at right) portfolio changes between
normal load growth and high load growth. A positive value indicates an increase in resources and
a negative value indicates a decrease when a resource is reduced or eliminated. This sensitivity
selects 2,354 MW of gas peaking units,an additional 3,872 MW of utility scale wind,an additional
5,993 MW of utility scale solar and 9,650 MW of additional storage. In 2038, the large-metered
load growth portfolio retires 804 MW of existing thermal units that were not retired in the preferred
portfolio. In addition to significant resource additions, serving large-metered load requires
significant transmission investments. Table 9.38 shows the transmission required in the large-
metered load growth study.
279

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
Table 9.38—Large-metered Load Transmission Selections
Line Year Selected
INC 132H2 Hemingway>Longhom-2033 2033
INC BorahPop>Hemingway 2037 Segment E 2037
INC BorahPop>Wasatch Front 2035 D3.2 2044
INC BorahPop>Wasatch Front 2035 D3.3 2035
INC Bridger>BorahPop 2032 2032
INC Bridger>BorahPop 2035 D3.2 2044
INC Bridger>Wyoming East 2032 D2.2 2032
INC Goshen>NUT 2035 lb 2035
INC NUT>Goshen 2029 2029
INC NUT>Wasatch Front 2029 2029
INC NUT>Wasatch Front 2030 2C7 3C6 2030
INC Portland North Coast>Willamette Valley 2037 2037
INC Portland North Coast>Yakima 2029 2029
INC Utah South>Wasatch Front 2028B 2028
INC Utah South>Wasatch Front 2029 2029
INC Utah South>Wasatch Front 2035 2035
INC Willamette Valley>Central OR 2032 2032
INC Willamette Valley>Southern OR 2036 2036
INC Wyoming East>BorahPop 2035 D3.3 2035
INC Wyoming East>Bridger 2032 2032
INC Wyoming East>Clover 2035 GWS2 2044
Figure 9.46- Increase/(Decrease in Proxy Resources with Large-metered Load Growth
Cumulative Changes Incremental Portfolio Changes
25.000 10,00o
g,000
20,000
6,000
I5,000
4,000
b
N 10,000
5.000 —' 2.0000 �_1�1.- Elm
p (2,000)
(5,000) (4.000)
h b n 4 A n)11 ,y♦ 11, „1", h1, ,slh n* 1 11 hq o ♦ N ^� P h h vb n * tiQ nt0 n1♦ hry n1'1 1, nth ntb 1 h4 ", o ♦ ti M h
ti�ti�ti�ti�tis'ti° ti� ti� �° �° �° �° ti� �° �° ti$ ♦
ti�ti�ti�ti$ti$ ti�ti� ti�ti� ti� ti� ti° ti� ti° ti� ti� ti ti� ti do tie4'ti`p ti`P ti`p ti�ti`Y
■Coal -Gas -QF -Hydm ■Coal -Gas -QF -Hydro
■Nudes ■Hydro Storage -Battery •Soles ■Nodes ■Hydro Storage ■Battery -Solar
■Wind -Geothermal ■Energy Effisdmy ■De dResponse -Wind -Geothermal •Energy Effid-.y -D®-d ReWp e
•Cowerted Gas -Hydrogm Storage Peaker Renewable Peaking -Cm we dGas Hydrogen Storage Peaker Renewable Pealing
Low-Cost Renewables
The low-cost renewables sensitivity evaluates what selections would be made if renewable
resources were lower cost than the current modeling expectations. The purpose of this study is to
identify potential additional resources if the company were able to take advantage of all tax credits
and assumes advantageous financing to complete projects.
Figure 9.47 shows the cumulative(at left) and incremental(at right)portfolio changes between the
preferred portfolio and a portfolio acquiring resources on the advantageous basis described above.
A positive value indicates an increase in resources and a negative value indicates a decrease when
280

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
a resource is reduced or eliminated. The low-cost renewables portfolio selects 199 MW less wind,
but 7,187 MW of additional utility scale solar. The model also selects 950 more MW of short and
medium duration storage,but 2,549 MW less 100-hour battery. Of note,coal plants which are able
to endogenously retire throughout the horizon convert to alternate fuels but do not retire under this
sensitivity.
Fi ure 9.47- Increase/(Decrease)in Proxy Resources with Low-Cost Renewables
Cumulative Changes Incremental Portfolio Changes
10,000 6,000
5,000
8•000 4,000
6,000 3,000
4 000 2,00
2,000
1.0000 —■■ _ —_
(4.000) (4.000)
(6.000)
O N h h ryh b n 4 ti hti ,1 ,stb ,yn „1 ,yQ O � '� "t P h
ti ti� ti� ry ti� ti° ti� v v v ry ti� ti� ti� v �ti`Y ryd',�c5'tic4�ti`P ,�o eS'tiSr tip'ro0 ti0 ti0 ti0 ,yo ,yo do ,o no ,o no ,yc4'ti`Y,ycP ti`Y,yc4 ti`Y
■Coal G. ■QF -Hydro ■Coal ■Gas ■QF ■Hydm
-Nudes Hydro Storage -Battery •Solar ■Nuclear ■Hydro Storage ■Battery ■Solar
ind •Geot
h
erma
l
-Energy Efficimcy -Demmd Response ■Wind •Geothermal ■Energy Effcimey ■De dRespm.
—we•C dGas •Hydrogm Storage Peal= -Renewable Pealdng •Cmverted Gas -Hydrogen Storage Peaker Renewable P-bng
Low IRA/IIJA Eligibility
The low IRA/IIJA sensitivity evaluates what selections would be made if no resources were ever
eligible for IRA or IIJA credits. The purpose of this study is to identify the impact if tax credits
were not available to any new resources.
Figure 9.48 shows the cumulative(at left) and incremental(at right)portfolio changes between the
low IRA/IIJA portfolio and the preferred portfolio. A positive value indicates an increase in
resources and a negative value indicates a decrease when a resource is reduced or eliminated. The
low IRA/IIJA portfolio includes an additional 627 MW of gas peaking units, and 311 more MW
of DSM. The low IRA/IIJA portfolio also includes a reduction of 3,782 MW of wind and 3,366
MW of solar, as well as 2,382 MW of storage. This sensitivity delays the Bridger CCS retirement
by one year.
Figure 9.48-Increase/(Decrease in Proxy Resources with Low IRA/IIJA Eligibility
Cumulative Changes Incremental Portfolio Changes
2.000
2,000
o —
o (4.000) b 3,000)
( w(z,000>
s.000>
(3.000)
(10.000) (4.000)
(12,000) (5,000)
ryh ry10 4n ry4 ryq y0 ry� Mry 1 P yh hb i �W yq O ry h Nh ryb n ry4 q h0 ^f� Mry y^ yd' Mh Mb *1 �JF it SP CYh
ti ti� ti� ti ti� ti� ti� ti� ti ti ti� ti ti� ti ti ti`3 14 11 ti`Y 4,11p * ° ti�eO 11 1 ti° 4 ti° ti ti° v ti� v � ti ti ti ti ti ti
■Cod G. ■QF -Hydro ■Coal -Gas -QF -Hydro
Nod— ■Hydro Storage ■Battery ■Solar -Nuclear -Hydro Storage -Battery S.I.•
■Wind -Gmth-1 ■Enegy Efficiency ■Demmd Response •Wind -Gmthermd -Energy EBicimcy -D—dResponse
-Convened Gas -Hydrogen Storage Peaker -Renewable Peaking -Convened Gas Hydrogm Storage Peaker Renewable Peaking
281

PACIFICORP—2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
All CCS
The All CCS sensitivity evaluates what selections would change if it were feasible to convert all
units to CCS that would be eligible for conversion. The purpose of this study is to identify the
impact of installing up to 8 CCS units.
Figure 9.49 shows the cumulative(at left) and incremental(at right)portfolio changes between the
base assumption and allowing all CCS. A positive value indicates an increase in resources and a
negative value indicates a decrease when a resource is reduced or eliminated. In this sensitivity,
all eligible units except Wyodak convert to CCS. The lower maximum output means that the
sensitivity selects additional resources, including 391 MW of DSM, 397 MW of additional wind
and 637 more MW of storage. The only significant reduction is 431 MW of solar.
Figure 9.49-Increase/(Decrease)in Proxy Resources with All CCS
Cumulative Changes Incremental Portfolio Changes
soo
2,500
2,000 400
1,500 zoo
500
Y
(500) (400)
(1.000)
(1.500) (600)
9.0m) (gam)
tih ryb ti� ry4 ^o' 11 ,yam 1ti „l^r 1' ,yh „lb ,yn 11
,yq O , 'h h ryh tib ti 4 r4 1 ;' hti 1" ,ya „lh ,stb ^n „1 1 o r ti "t P h
ti� ti� ti� ti ti ti rv� � ti� � �ti`Y ti`P,�eP tie4�ti`P ti� � ti� ti�ti� ti� ti� ti� ti� ti� ti� ry ti��° do ,yc4'ti`P ti`F ticF,ycF ti`Y
Coal G. ■QF -Hydro ■Coal G. ■QF ■Hydm
■Nudear •Hydro Storage -Bm y S.I.• ■N-dear ■Hydro Storage ■Battery ■Solar
•Wind •Geothermal -Energy Efficimcy -Demmd Response ■Wind -Geothermal ■Energy Efficiency ■De dRespm
—av•C dGas i Hydrogm Storage Peaker Renewable Peabng •C—ve dGas -Hydrogen Storage Peaker Renewable Peaking
Business as Usual/Business Plan
The business as usual and business plan sensitivities were able to be covered by the same study.
The business-as-usual study requires that coal retires no earlier than in the 2017 IRP unless
otherwise mandated to do so by law. The business plan study requires that the first three years of
the horizon align with the business plan, and then the model is able to endogenously choose any
outcomes. These studies explicitly require operation and resource selection in the absence of any
state or federal requirements, and the portfolio must be selected only on the basis of economics.
Figure 9.50 shows the cumulative (at left) and incremental (at right)portfolio changes between be
preferred portfolio and a business-as-usual case.A positive value indicates an increase in resources
and a negative value indicates a decrease when a resource is reduced or eliminated. This view
selects significantly fewer resources.In total,there are 9,879 fewer MW chosen,and coal continues
to remain on the system as in the preferred portfolio. This portfolio selects 2,488 MW less wind,
3,496 MW less utility scale solar, 1,147 MW less small scale solar and a total of 1,903 MW less
storage (replacing 100-hour battery with 4-hour battery).
282

PACIFICORP—2025 IRP CHAPTER 9—MODELING AND PORTFOLIO SELECTION RESULTS
Figure 9.50- Increase/(Decrease) in Proxy Resources with
Business Plan/Business as Usual Assumptions
Cumulative Changes Incremental Portfolio Changes
1
2.000 ,000
500
0DO) , (500) MEN NO== F—M 0
'
(4'ODO)
_(1 000)
m(1 500)
ro
(6.000) (2..—)
(S.0o0) (2.500)
(3.000)
(10,000) (3,500)
(12,0D0) (4,000)
Nh If ry N4 „t'� „tti 11 ,yb. ,yh ? ,fin „t01 O � ^, ? ',� 1" 00 ryn 1" 1" „1, „�h „o ,yn 1** ,yq O r N 'h h
rV0 'V 'VO 'CIO 41011101^�I NO MO �R 'VO � 'LJ 41,111'VO ^�^�1�W6 ^r�W� NO NO ti0 N ti MO �i �i �i �l0 ^Oi �l0 N NO 41o,
'V$N$N�^$N�^i�
■Coal G. ■QF ■Hydro -Coal -Gas -QF •Hydro
■Nuclear ■Hydro Storage ■Battery -S.1. -Nucear -Hydro Storage -Battery -Solar
-Wind -Geothermal -Energy Efficiency -Demand Response -Wind Geothermal -Energy Efficiency -Demand Response
-Converted Gas -Hydrogen Storage Peaker -Renewable Peaing .C—erted Gas Hydrogen Storage Peaker Renewable Peaing
Washington Scenarios
As described in Chapter 8, in addition to the information provided throughout the 2025 IRP,
Washington's CETA legislation mandates three key studies for analysis, in addition to the least-
cost, least-risk portfolio developed to meet CETA clean energy standards:
• Alternative Lowest Reasonable Cost
• Maximum Customer Benefit
• Climate Change
This analysis plus additional detail related to Washington requirements is found in Appendix O
(Washington Clean Energy Action Plan)
9 Note: The Washington requirement for a climate change sensitivity,which includes climate change impacts,is met
by the incorporation of climate change considerations into all 2025 IRP studies.
283

PACIFICORP-2025 IRP CHAPTER 9-MODELING AND PORTFOLIO SELECTION RESULTS
284

PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
CHAPTER 10 -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. The action plan
has been shaped by changes in the planning environment, ongoing review and validation, and
stakeholder feedback.
• PacifiCorp's 2025 IRP 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).I
• The 2025 IRP acquisition path analysis provides insight on how changes in the planning
environment might influence future resource procurement activities. Key uncertainties
addressed in the acquisition path analysis include load,private generation, changes in available
resources, and carbon dioxide (CO2) emission polices.
• 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-party power, discusses its hedging practices, and identifies the types of risks borne by
customers and the types of risks borne by shareholders.
Introducti
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.
' 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).
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
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:
• 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 Plan
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 2025 IRP action items by resource category.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Table 10.1 —2025 IRP Action Plan
Action
1. Existing Resource Actions
Item
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:
1 b 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:
• PacifiCorp will continue to evaluate the economic and technical feasibility of carbon capture technology on Jim Bridger
ld Units 3 and 4 to comply with Wyoming's low carbon portfolio standard. The Company is pursuing a front-end engineering
design study as part of compliance with Wyoming's low carbon portfolio standard requirements as a site-specific analysis is
needed to better understand the feasibility of the project.2
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.
2 See Appendix M,stakeholder feedback form#59(Renewables Northwest).
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Natrium"Demonstration Project:
• 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 Public Utility Commission of Oregon 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.
1 g • 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.
Federal Greenhouse Gas Emission Compliance:
li • EPA finalized its regulation for existing coal-fueled steam units under Clean Air Act Section I I l(d) in April 2024,though the
rule has been challenged in the D.C. Circuit.PacifiCorp will continue to update and evaluate alternatives for affected resources
while the legal process continues.
Dave Johnston Units 1 and 2:
1j • PacifiCorp will initiate the process of converting Dave Johnston Units 1 and 2 to natural gas, including obtaining all required
regulatory notices and filings. Natural gas operations are anticipated to commence spring of 2029.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Action
2. New Resource Actions
Item L A
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 initiate with individual jurisdictions the process to issue as appropriate by individual jurisdiction need, one or
more independent Request for Proposals (RFP) to procure resources aligned with the 2025 IRP preferred portfolio that can
2b achieve commercial operations by the end of December 2029.3
• Individual independent jurisdictional RFP filings will include timelines associated with the respective jurisdictions' process.
• Considering the differentiated resource needs by jurisdiction identified in the 2025 IRP, scope and targeted resource needs
may vary by jurisdiction.
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(Public Utility Commission of Oregon).A portion of cost-effective demand response resources identified in the 2025 preferred portfolio in 2025 represent planned
volumes are expected to be acquired through a previously issued demand response RFP soliciting resources identified in the 2013 IRP.PacifiCorp will pursue all cost-
effective demand response resources identified as incremental to existing resources or as an expansion of existing resources offered through approved programs.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Action
Item 3. Transmission Action Items
Local Reinforcement Projects
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.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Action
Item 4. Demand-Side Management(DSM) Action
Energy Efficiency & Demand Response 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
Appendix D in Volume II of the 2025 IRP.
• PacifiCorp will pursue cost-effective energy efficiency resources.
Year First-Year Energy Efficiency (GWh) Annual Capacity (MW)
2025 595 92
2026 573 89
2027 597 209
2028 648 220
a
• 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 and are
incremental to those already included as existing.5
Year Annual Incremental apace
2025 18
2026 2
2027 0
2028 63
a A portion of cost-effective demand response resources identified in the 2025 preferred portfolio in 2025 represent planned volumes are expected to be acquired
through a previously issued demand response RFP soliciting resources identified in the 2013 IRP.PacifiCorp will pursue all cost-effective demand response resources
identified as incremental to existing resources or as an expansion of existing resources offered through approved programs.
5 See Appendix D,Table D.3 for the split out between summer and winter capacity.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
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 may 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.
Renewable Energy Credit Sales:
6b
• Maximize the sale of RECs that are not required to meet state RPS compliance obligations.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Progress on 2023 Action Plan
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.
Figure 10.1 below presents two views of incremental resource changes in the 2025 IRP preferred portfolio. The figure at left reports the
incremental resource additions from the 2025 IRP preferred portfolio, whereas the figure at right illustrates how these selections differ from
the incremental changes in the 2023 IRP preferred portfolio.6,7
Figure 10.1 —Incremental Resources in the 2025 IRP Preferred Portfolio
Incremental Resources in the 2025 IRP Incremental Change from the 2023 IRP
Preferred Portfolio
5000 5000
4000 4000
3000
3000 2000
T 2000 10000 ■_ -■__
000
- 000
-33000
-1000 -4000
do^+ doa' ,�°ryo ti do ti�4 ti 4o.y do,y 4a,y 4ry
,yo do ti� do do ti� 4Y ti, ti� tiV N� ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
■Coal ■Gas ■QF ■Coal ■Gas ■QF
Hydro v Nuclear ■Hydro Storage Hydro Nuclear ■Hydro Storage
■Battery ■Solar ■Wind ■Battery ■Solar ■Wind
■Geothermal ■Energy Efficiency ■Demand Response ■Geothermal ■Energy Efficiency ■Demand Response
■Converted Gas ■Hydrogen Storage Peaker ■Renewable Peaking ■Converted Gas ■Hydrogen Storage Peaker ■Renewable Peaking
6 The timeframe presented in these charts shows only years where expansion resources were selected.
These figures support Wyoming Public Service Commission Guideline E,"Changes in expected resource acquisitions and load growth from that presented in the
utility's previous IRV.A load comparison is provided in Appendix A(Load Forecast),Figure A.1.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
Table 10.2—2023 IRP Action Plan Status Update
Action Item 1. Existing Resource Actions Status
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.
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.
ld natural gas conversion. All required regulatory notices • PacifiCorp ceased coal-fueled operations at Jim
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.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
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.
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
if 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.
• 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.
1 Natrium"Demonstration Proiect: • PacifiCorp continues to work with TerraPower on
g commercial arrangements for offtake from the
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
• PacifiCorp will continue to monitor and report key NatriumTM project and expects to finalize these
TerraPower milestones for development and will make arrangements by the end of 2025.
regulatory filings, as applicable.
• By the end of 2023, PacifiCorp expects to finalize
commercial agreements for the NatriumTM project.
• By Q2 2024, PacifiCorp expects to develop a
community action plan in coordination with community
leaders.
PacifiCorp will continue to monitor key TerraPower
milestones for development and will make regulatory
filings, as applicable, including, but not limited to, a request
for the Public Utility Commission of Oregon 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.
• 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
1h 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
• Based on the Ozone Transport Rule trading program merits, leaving the stay in place.
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 2 2023.
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
Action
Item 2• New Resource Actions Ju _r
Status
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
• 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.
2b 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
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
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
• 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.
2c • 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
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PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
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 RFP 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 Items Status LIN
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 in
Q4 2024
•
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 500 kilovolt transmission line, which is
3c
(132H) Joint Permit Funding Agreement. targeted for a 2027 in-service date.
• 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.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
• 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: For energy efficiency, PacifiCorp achieved the Action Plan
• PacifiCorp will acquire cost-effective energy efficiency target of 543 GWh in 2023 and achieved 96.2%of the 2024
resources targeting annual system energy and capacity target, excluding HERS.
selections from the preferred portfolio as summarized Since the 2023 IRP, PacifiCorp launched demand response
below. PacifiCorp's state-specific processes for programs
ro rams and expanded offeringswithin its existing
4a planning for DSM acquisitions is provided in Appendix rorams. PacifiCorp continues to pursue the incremental
D in Volume II of the 2023 IRP. programs. � p
capacity additions but did not achieve the 2023-24
1st earE�e Emden GWh
2023 543 1 123 incremental capacity,due to the later than anticipated timing
2024 559 1 220
2025 568 1 259 of program effective dates for newly launched demand
2026 628 1 197
response programs.
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
• PacifiCorp will pursue cost-effective demand response
resources targeting annual system capacity selections
from the preferred portfolio as summarized in Appendix
D in Volume II of the 2023 IRP.
Year NIP Annual Incremental Capacity(MW)
2023 72
2024 39
2025 152
2026 109
Action
Item 5. Market Purchases Status
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 Market purchases are made in accordance with the Risk
Intercontinental Exchange, in which the exchange Management Policy and Energy Supply Management Front
provides a competitive price. Office Procedures and Practices and include a mix of the
• Prompt-month,balance-of-month, day-ahead, and hour- transaction types identified in item 5a.
ahead non-brokered bi-lateral transactions.
Action
Item 6. Renewable Energy Credit (REC)Actions Status
70 W
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PACIFICORP-2025 IRP CHAPTER 10—ACTION PLAN
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, state and federal
environmental 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 in Table
10.3, PacifiCorp identifies the planning scenario assumption affecting both short-term (2025-
2034) and long-term(2035-2045) resource strategies.
Acquisition Path Decision Mechanism
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."g 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.
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.
8 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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Table 10.3 —Near-term and Long-term Resource Acquisition Paths
Near-Term Resource Acquisition Strategy Long Term Resource Acquisition
Trigger Event Planning Scenario(s)AL AL (2025-2034) Strategy
2035-2045
Higher sustained load Refer to Chapter 8,Table . A new load forecast incorporating higher than anticipated load • In the long-term acquisition
growth 8.7—Sensitivity Case growth increases load relative to the base forecast. window,slightly fewer incremental
Definitions sensitivity . Through 2030,resource additions would be similar to the resources are required due to
"High Load Growth" preferred portfolio with a small amount of additional wind and additional incremental resources
solar added to the portfolio to meet higher than anticipated shifting into the near-term window
loads. to meet higher than anticipated
• From 2031 through 2034,small amounts of solar,4-hour loads compared to the preferred
battery and DSM resources are added to meet higher than portfolio.
anticipated loads.
Lower sustained load Refer to Chapter 8,Table . A new load forecast incorporating lower than anticipated load • In the long-term acquisition
growth 8.7—Sensitivity Case growth decreases load relative to the base forecast. window,even fewer incremental
Definitions sensitivity"Low . In the near-term acquisition window,far fewer incremental resources are required due to lower
Load Growth". resources are required to meet load compared to the preferred loads compared to the preferred
portfolio. portfolio.
• Through 2034,significant amounts of wind and solar along • From 2035-2045,significant
with moderate amounts of small-scale solar and 100-hour amounts of wind,solar,small-scale
battery fall out of the portfolio while additional 4-hour battery solar and 100-hour battery fall out
is added compared to the preferred portfolio. of the portfolio compared to the
• Fewer incremental transmission options are required to meet preferred portfolio and would not
fewer incremental resources while the timing of some need to be procured.
incremental transmission options is shifted outward compared
to the preferred portfolio.
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Near-Term Resource Acquisition Strategy JL Long Term Resource Acquisition
Trigger Event Planning Scenario(s) (2025-2034) Strategy
2035-2045
Higher sustained Refer to Chapter 8,Table • A new load forecast incorporating higher than anticipated • From 2035-2045,higher private
private generation 8.7—Sensitivity Case private generation adoption decreases load relative to the base generation results in 2,696 MW of
penetration levels Definitions sensitivity forecast. resource additions falling out of the
"High Private Generation" • In response to high private generation adoption,far fewer portfolio compared to the preferred
incremental resource selections are required in the action plan portfolio.
window compared to the preferred portfolio. • On average,far less wind,solar and
• Through 2030,significant amounts of wind,solar,small-scale 100-hour air battery are selected
solar and moderate amounts of 100-hour battery fall out of the while additional 4-hour battery is
preferred portfolio while a significant amount of 4-hour selected in similar amounts
battery is selected. compared to the preferred portfolio.
• Through the remainder of the near-term acquisition window,
resource additions are similar to the preferred portfolio.
• Transmission selections are similar to the preferred portfolio
with the location and timing of incremental transmission
changing depending on incremental resource selections.
Lower sustained Refer to Chapter 8,Table • A new load forecast incorporating lower than anticipated • In the long-term resource
private generation 8.7—Sensitivity Case private generation adoption increases load relative to the base acquisition window,resource
penetration levels Definitions sensitivity"Low forecast. selections are similar to the
Private Generation" • To counteract low private generation adoption,minimal preferred portfolio as lower private
additional resources are required relative to the preferred generation levels cause incremental
portfolio through 2029. resource builds in the near-term
• From 2030 through 2034,moderate amounts of wind and solar acquisition window.
are added to what is selected in the preferred portfolio. • 156 MW of Naughton gas
conversion would remain online
compared to retiring in 2043 in the
preferred portfolio.
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Near-Term Resource Acquisition Strategy Long Term Resource Acquisition
igger Event Planning Scenario(s) (2025-2034) Strategy
IL 2035-2045
Higher than expected Refer to Chapter 8,Table • A new load forecast incorporating higher than anticipated • From 2035-2045,significant
large-metered load 8.7—Sensitivity Case large-metered load growth beginning in 2027 increases load additional resources are required
growth Definitions sensitivity relative to the base forecast. compared to the preferred portfolio
"Large Metered Load • High large-metered load growth results in significant resource including more than 1,000 MW of
Growth" additions compared to the preferred portfolio,including new gas and 5,000 MW of new
significant resource additions in the near-term acquisition renewables.
window.
• By 2028,nearly 10,000 MW of additional resources are
selected compared to the preferred portfolio including
significant amounts of wind,solar,small-scale solar,4-hour
battery and a moderate amount of 8-hour battery.
• By the end of 2034,a significant amount of new gas is added
to the portfolio,along with nearly 4,500 MW of additional
incremental renewable resources.
• Significant transmission investment would be required to serve
new resource additions.
Changes to IRA/IIJA Refer to Chapter 8,Table • High adoption of the IRA/IIJA resulting in lower-than- • From 2035-20445,significant
result in lower-than- 8.7—Sensitivity Case expected new renewable resource costs would result in additional incremental renewable
expected renewable Definitions sensitivity significantly more incremental renewable resource additions resources would be built along with
costs "Low-Cost Renewables" than selected in the preferred portfolio. more incremental transmission.
• Significant incremental wind,solar and 4-hour battery • Thermal resources would run at
additions would result in lower thermal output and less 100- lower capacity factors with some
hour battery storage additions. thermal capacity retiring in the
• Significant transmission investment would be required to serve long-term acquisition window.
new resource additions.
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Near-Term Resource Acquisition Strategy JL Long Term Resource Acquisition
igger Event Planning Scenario(s) (2025-2034) Strategy
2035-2045
Changes to IRA/IIJA Refer to Chapter 8,Table • In the absence of tax credits from the IRA/IIJA resulting in • In the long-term acquisition
result in higher-than- 8.7—Sensitivity Case higher-than-expected renewable resource costs,significant window,additional new gas is built
expected renewable Definitions sensitivity"Low amounts of incremental renewable resource additions would along with a small amount of gas
costs PTC/ITC eligibility" fall out of the portfolio compared to the preferred portfolio. peaking to replace lost renewables
• By 2030, significant wind,solar,small-scale solar and 100- from the preferred portfolio.
hour iron battery would fall out from the portfolio. • Existing thermal resources would
• By the end of 2034,significant additional incremental remain online past retirement dates
renewable capacity falls out of the portfolio while some new selected in the preferred portfolio to
gas is selected. continue providing energy and
• If renewable resources become more expensive in the absence capacity.
of IRA/IIJA benefits,very little capacity would be needed to
replace renewable capacity as thermal resources would run at
higher capacity factors to meet load obligations.
No legislation under Refer to Chapter 8,Table • With only load requirements to meet(no other federal or state • From 2035-2045,significantly
consideration is 8.7—Sensitivity Case requirements),far fewer resources are selected compared to fewer MW are selected compared to
adopted and state Definitions sensitivity the preferred portfolio as existing thermal resources are able to the preferred portfolio including
environmental "Business as Usual"(also run at higher capacity factors and less capacity and energy is less wind,solar,small-scale solar
requirements impacting called the Wyoming needed on the system. and 100-hour battery.
thermal plants are Reference Case). • In the near-term acquisition window,significantly fewer MW • Additional 4-hour battery is added
unwound are selected compared to the preferred portfolio,including less from 2035 through 2045 compared
wind, solar,small-scale solar,4-hour battery and 100-hour to the preferred portfolio,revealing
battery. that in a"business as usual"
• With far fewer new resources compared to the preferred scenario,4-hour batteries remain
portfolio,"business as usual"would require significantly valuable new resource options in
fewer incremental transmission interconnect MW in the near- the absence of other new
term acquisition window. renewables.
Legislation forces all Refer to Chapter 8,Table • With all coal units forced to retire or gas convert by 1/1/2032, • In the long-term acquisition
coal to retire or gas 8.5—Portfolio Variants 2,679 MW of nameplate capacity would convert to natural gas window resource additions are
convert by 2032 variant"No Coal 2032" in 2030.Jim Bridger units 3 and 4 were assumed to not be similar to the preferred portfolio.
allowed to install CCS,and in this case,units 3 and 4 would
convert to natural gas in 2030 instead of retiring.
• By 1/1/2032,686 MW of coal retires.
• Significant additional incremental renewable resources and are
added to the portfolio including wind, solar,4-hour battery and
100-hour battery within the near-term acquisition window.
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Near-Term Resource Acquisition Strategy Long Term Resource Acquisition
Trigger Event Planning Scenario(s) (2025-2034) Strategy
2035-2045
No NatriumTM Refer to Chapter 8,Table • Without the 500 MW NatriumTM demonstration project in • While the type,timing and location
Advanced Nuclear 8.5—Portfolio Variants 2032,moderate amounts of renewable resources are added to of resources change,the amount of
Demonstration Project variant"No Nuclear" the portfolio by 2032. incremental resource additions in
in 2032,and no other • In 2033 and 2034,additional incremental renewable resources the long-term acquisition window
nuclear projects are added to the portfolio. without Natriurn'is similar to the
preferred portfolio.
• Batteries and other renewables
would fall out of the portfolio in
2041 through 2045 as incremental
amounts of these resources are built
earlier to replace Natriurn .
• 682 MW of thermal resources
would remain online in 2043
instead of retiring,including 526
MW of Jim Bridger CCS and 156
MW of Naughton gas conversion.
Technologies such as Refer to Chapter 8,Table • Without nuclear,hydrogen storage, 100-hour battery or • While the type,timing and location
nuclear,hydrogen 8.5—Portfolio Variants biodiesel peaking,nuclear and 100-hour battery selected in the of resources change as is required
storage, 100-hour variant"No Forward preferred portfolio are replaced by a significant amount of 4- by the absence of nuclear and 100-
battery storage and Technology" hour battery and moderate amounts of wind and solar. hour battery,the amount of
biodiesel peaking do • In the near-term acquisition window,the capacity of future incremental resource additions in
not become technology that falls out of the portfolio is greater than the the long-term acquisition window is
commercially viable capacity of incremental resources needed to replace the lost similar to the preferred portfolio.
capacity. • 682 MW of thermal resources
would remain online in 2043
instead of retiring,including 526
MW of Jim Bridger CCS and 156
MW of Naughton gas conversion.
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Near-Term Resource Acquisition Strategy Long Term Resource Acquisition
Trigger Event Planning Scenario(s) (2025-2034) Strategy
2035-2045
Legislation requires the Refer to Chapter 8,Table • By 1/l/2030, 1,158 MW of nameplate coal capacity retires at • From 2035-2045,moderate
Hunter plant to retire 8.5—Portfolio Variants Hunter. amounts of incremental resource
no later than 1/l/2030 variant"Hunter Retire" • To replace the lost Hunter capacity,by 2030,moderate additions would be added to the
amounts of wind and solar would be added to the portfolio, portfolio,including new gas.
including solar at Hunter.Additionally,a significant amount • In 2043, 156 MW of nameplate
of 4-hour battery and moderate amount of 100-hour battery capacity at Naughton 1 running as
would be added to the portfolio. gas remains online through the end
of the planning horizon instead of
retiring as it does in the preferred
portfolio.
No CCS available at Refer to Chapter 8,Table • Incremental resource selections with Jim Bridger CCS • From 2039-2045 fewer 4-hour
Jim Bridger in 2030 8.5—Portfolio Variants unavailable are similar to the preferred portfolio with slight battery resources are selected.
variant"No CCS" changes in the location and timing of incremental resources. • In 2043,247 MW of Naughton gas
• By 1/l/2030, 174 MW of nameplate capacity remains conversion retires without CCS in
available at Jim Bridger without the installation of CCS. the portfolio.
• Moderate amounts of wind and solar,some of which is sited at
Jim Bridger,falls out of the portfolio,along with some 4-hour
battery.
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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 resilient grid operations and statutory
compliance. 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, there may be insufficient potential resource
development deliverable to the jurisdiction with resource need, 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.
As the range of events is unknowable, these potential impacts are represented by broad sensitivity
studies such as those which raise or lower resource availability (such as natrium, carbon capture,
coal, offshore wind) and competition for resources (load, distributed generation, IRA adoption,
DSM). In addition, IRP resource potential availability is informed by an assessment of publicly
available data derived from the cluster study process.
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 the capacity needs.
• Temporarily drop below its planning reserve margin.
• Implement load control initiatives, including calls for load curtailment via existing load
curtailment contracts.
IRP Action an LinkagWo Business Planning
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.
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• Beyond the first three years of the study period, unit retirement assumptions are aligned
with the preferred portfolio.
• All other resources are optimized.
Consequently,please refer to the 2025 IRP preferred portfolio as described in Chapter 9.
ice Procurement Stra
To acquire resources outlined in the 2025 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 if jurisdictional need is warranted. 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 to include but not limited to 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 2025 IRP action plan.
Renewable Resources, Storage Resources, and Dispatchable Resources
PacifiCorp will use 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 Management9
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
9 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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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.
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 June 2025 to solicit resources within its
territory which are 20 MW or smaller and can be commercially operational by December 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 discussed in Appendix P (Oregon Clean Energy
Update) and will be further addressed in PacifiCorp's 2025 Oregon Clean Energy Plan.
Assessment 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 party. 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 1 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. The level of debt imputation associated with long-term
contracts will have an impact on PacifiCorp's credit ratios and credit rating.
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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.
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.
&urpose of
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
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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
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.
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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.
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 fully 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
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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.
317

PACIFICORP-2025 IRP CHAPTER 10-ACTION PLAN
318

2025
Integrated Resource Plan
a
Volume 11 - March 31 , 2025
AM: 44
• :� ice=7:� PAC I F I CO R Pa
i

This 2025 Integrated Resource Plan is based upon the best available information at the time of
preparation. The IRP action plan will be implemented as described herein, but is subject to
change as new information becomes available or as circumstances change. It is PacifiCorp's
intention to revisit and refresh the IRP action plan no less frequently than annually. Any
refreshed IRP action plan will be submitted to the State Commissions for their information.
For more information, contact:
PacifiCorp Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
[e-mail]
www.pacificorp.com

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF CONTENTS - VOLUME II
TABLE OF CONTENTS...............................................................................i
TABLEOF TABLES.................................................................................Vii
TABLEOF FIGURES ................................................................................xi
APPENDIX A - LOAD FORECAST
INTRODUCTION.......................................................................................................................................................1
SUMMARY LOAD FORECAST......................................................................................................................................I
LOADFORECAST ASSUMPTIONS.......................................................................................................................4
REGIONAL ECONOMY BY JURISDICTION....................................................................................................................4
WEATHER..................................................................................................................................................................5
STATISTICALLY ADJUSTED END-USE("SAE")..........................................................................................................7
INDIVIDUAL CUSTOMER FORECAST...........................................................................................................................7
ACTUALLOAD DATA................................................................................................................................................8
SYSTEMLOSSES......................................................................................................................................................10
FORECAST METHODOLOGY OVERVIEW......................................................................................................11
DEMAND-SIDE MANAGEMENT RESOURCES IN THE LOAD FORECAST.......................................................................11
MODELINGOVERVIEW.............................................................................................................................................11
ELECTRIFICATION ADJUSTMENTS............................................................................................................................12
PRIVATEGENERATION.............................................................................................................................................13
SALES FORECAST AT THE CUSTOMER METER..........................................................................................13
STATESUMMARIES..............................................................................................................................................14
OREGON..................................................................................................................................................................14
WASHINGTON..........................................................................................................................................................14
CALIFORNIA............................................................................................................................................................15
UTAH.......................................................................................................................................................................15
IDAHO......................................................................................................................................................................16
ALTERNATIVE LOAD FORECAST SCENARIOS.............................................................................................17
APPENDIX B - REGULATORY COMPLIANCE
INTRODUCTION...........................................................................................................................................19
GENERALCOMPLIANCE............................................................................................................................19
CALIFORNIA............................................................................................................................................................21
ID A H O......................................................................................................................................................................22
OREGON..................................................................................................................................................................22
UTAH.......................................................................................................................................................................22
WASHINGTON..........................................................................................................................................................22
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PACIFICORP—2025 IRP TABLE OF CONTENTS
WYOMING...............................................................................................................................................................23
APPENDIX C - PUBLIC INPUT
PARTICIPANTLIST......................................................................................................................................83
COMMISSIONS..........................................................................................................................................................83
STAKEHOLDERS AND INDUSTRY EXPERTS...............................................................................................................84
GENERAL MEETINGS AND AGENDAS......................................................................................................85
GENERALMEETINGS...............................................................................................................................................85
STAKEHOLDER COMMENTS.....................................................................................................................87
CONTACT INFORMATION..........................................................................................................................87
APPENDIX D - DEMAND-SIDE MANAGEMENT
INTRODUCTION...........................................................................................................................................89
CONSERVATION POTENTIAL ASSESSMENT(CPA)FOR 2025-2044......................................................89
CURRENT DSM PROGRAM OFFERINGS BY STATE...............................................................................90
STATE-SPECIFIC DSM PLANNING PROCESSES......................................................................................92
UTAH,WYOMING,AND IDAHO................................................................................................................................92
WASHINGTON..........................................................................................................................................................92
CALIFORNIA............................................................................................................................................................93
OREGON..................................................................................................................................................................93
PREFERRED PORTFOLIO DSM RESOURCE SELECTIONS....................................................................93
APPENDIX E - GRID ENHANCEMENT
INTRODUCTION...........................................................................................................................................99
REGIONAL ENERGY MARKETS.................................................................................................................................99
Western Energy Imbalance Market....................................................................................................................99
ExtendedDay Ahead Market...........................................................................................................................100
TRANSMISSION NETWORK AND OPERATION ENHANCEMENTS...............................................................................100
Advanced Protective Relays.............................................................................................................................100
DynamicLine Rating.......................................................................................................................................100
Digital Fault Recorders/Phasor Measurement Unit Deployment..................................................................101
Radio Frequency Line Sensors.........................................................................................................................102
TransmissionCFCls........................................................................................................................................102
DISTRIBUTION AUTOMATION AND RELIABILITY....................................................................................................103
Distribution Automation/Fault Location,Isolation and Service Restoration................................................103
DistributionCFCls..........................................................................................................................................103
Distribution Substation Metering.....................................................................................................................104
DISTRIBUTED ENERGY RESOURCES.......................................................................................................................105
EnergyStorage Systems...................................................................................................................................105
DemandResponse............................................................................................................................................106
Dispatchable Customer Storage Resources.....................................................................................................106
TRANSPORTATION ELECTRIFICATION....................................................................................................................107
ADVANCED METERING INFRASTRUCTURE.............................................................................................................108
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PACIFICORP—2025 IRP TABLE OF CONTENTS
OUTAGE MANAGEMENT IMPROVEMENTS..............................................................................................................109
FUTURE GRID ENHANCEMENTS............................................................................................................110
APPENDIX F — FLEXIBLE RESERVE STUDY
Contents
INTRODUCTION.........................................................................................................................................111
OVERVIEW.............................................................................................................................................................112
FLEXIBLE RESOURCE REQUIREMENTS...............................................................................................113
CONTINGENCYRESERVE.......................................................................................................................................114
REGULATIONRESERVE..........................................................................................................................................114
FREQUENCY RESPONSE RESERVE..........................................................................................................................115
BLACK START REQUIREMENTS..............................................................................................................................116
ANCILLARY SERVICES OPERATIONAL DISTINCTIONS............................................................................................116
REGULATION RESERVE DATA INPUTS.................................................................................................117
OVERVIEW.............................................................................................................................................................117
LOADDATA...........................................................................................................................................................118
WINDAND SOLAR DATA.......................................................................................................................................118
NoN-VER DATA...................................................................................................................................................119
REGULATION RESERVE DATA ANALYSIS AND ADJUSTMENT.........................................................119
OVERVIEW.............................................................................................................................................................119
BASE SCHEDULE RAMPING ADJUSTMENT..............................................................................................................120
DATACORRECTIONS.............................................................................................................................................120
REGULATION RESERVE REQUIREMENT METHODOLOGY..............................................................122
OVERVIEW.............................................................................................................................................................122
COMPONENTS OF OPERATING RESERVE METHODOLOGY......................................................................................122
Operating Reserve:Reserve Categories..........................................................................................................122
Planning Reliability Target:Loss of Load Probability....................................................................................123
Balancing Authority ACE Limit:Allowed Deviations......................................................................................124
Regulation Reserve Forecast:Amount Held....................................................................................................125
REGULATION RESERVE FORECAST........................................................................................................................126
Overview..........................................................................................................................................................126
PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS.................................................................131
PORTFOLIO DIVERSITY BENEFIT............................................................................................................................131
EIMDIVERSITY BENEFIT......................................................................................................................................132
FAST-RAMPING RESERVE REQUIREMENTS........................................................................................134
PORTFOLIO REGULATION RESERVE REQUIREMENTS.....................................................................135
REGULATION RESERVE COST................................................................................................................................137
FLEXIBLE RESOURCE NEEDS ASSESSMENT........................................................................................139
OVERVIEW.............................................................................................................................................................139
FORECASTED RESERVE REQUIREMENTS................................................................................................................140
FLEXIBLE RESOURCE SUPPLY FORECAST..............................................................................................................140
FLEXIBLE RESOURCE SUPPLY PLANNING..............................................................................................................143
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PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX G - PLANT WATER CONSUMPTION
STUDYDATA...............................................................................................................................................147
APPENDIX H - STOCHASTICS
INTRODUCTION...................................................................................................................................................149
OVERVIEW............................................................................................................................................................150
STOCHASTIC VARIABLES.................................................................................................................................150
LOAD.....................................................................................................................................................................150
MARKETPRICES....................................................................................................................................................151
HYDROCONDITIONS..............................................................................................................................................152
WIND AND SOLAR OUTPUT....................................................................................................................................153
THERMALOUTAGES..............................................................................................................................................155
CORRELATEDINPUTS.......................................................................................................................................155
APPENDIX I - CAPACITY EXPANSION RESULTS
2025 IRP PORTFOLIO MAPS..............................................................................................................................159
PREFERRED PORTFOLIO.........................................................................................................................................159
2025 IRP PORTFOLIO SUMMARIES.................................................................................................................163
PREFERRED PORTFOLIO.........................................................................................................................................163
..............................................................................................................................................................................163
OREGON FULL JURISDICTIONAL PORTFOLIO..........................................................................................................164
WASHINGTON FULL JURISDICTIONAL PORTFOLIO.................................................................................................165
UTAH,IDAHO,WYOMING,CALIFORNIA(UIWC)FULL JURISDICTIONAL PORTFOLIO............................................166
MNNo CCS..........................................................................................................................................................167
MRNO CCS..........................................................................................................................................................168
NoNUCLEAR.........................................................................................................................................................169
NoCOAL 2032......................................................................................................................................................170
OFFSHOREWIND...................................................................................................................................................171
LN(LOW NATURAL GAS/NO CO2 PROXY)..........................................................................................................172
MR(MEDIUM NATURAL GAS/CURRENT FEDERAL CO2 REGULATIONS) .............................................................173
HH(HIGH NATURAL GAS/HIGH CO2 PROXY).....................................................................................................174
SC(SOCIAL COST OF GREENHOUSE GASES)..........................................................................................................175
APPENDIX K- CAPACITY CONTRIBUTION
INTRODUCTION...................................................................................................................................................177
CFMETHODOLOGY............................................................................................................................................178
CFMETHOD RESULTS........................................................................................................................................180
WRAPMETHODOLOGY.....................................................................................................................................182
WRAPRESULTS....................................................................................................................................................182
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PACIFICORP—2025 IRP TABLE OF CONTENTS
APPENDIX L - DISTRIBUTED GENERATION STUDY
DISTRIBUTED GENERATION BEHIND-THE-METER RESOURCE ASSESSMENT...............................189
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
INTRODUCTION...................................................................................................................................................271
STAKEHOLDER FEEDBACK FORM SUMMARY..........................................................................................271
REQUESTED ADDITIONAL STUDIES..............................................................................................................273
PUBLISHED STAKEHOLDER FEEDBACK FORMS......................................................................................275
APPENDIX N - ENERGY STORAGE POTENTIAL EVALUATION
INTRODUCTION...................................................................................................................................................439
PART 1: GRID SERVICES....................................................................................................................................439
ENERGYVALUE.....................................................................................................................................................440
Background......................................................................................................................................................440
Modeling..........................................................................................................................................................441
OPERATING RESERVE VALUE................................................................................................................................443
Background......................................................................................................................................................443
Modeling..........................................................................................................................................................444
TRANSMISSION AND DISTRIBUTION CAPACITY......................................................................................................445
GENERATION CAPACITY........................................................................................................................................446
Background......................................................................................................................................................446
PART 2:ENERGY STORAGE OPERATING PARAMETERS........................................................................446
PART 3:DISTRIBUTED RESOURCE CONFIGURATION AND APPLICATIONS....................................448
SECONDARYVOLTAGE..........................................................................................................................................448
T&D CAPACITY DEFERRAL...................................................................................................................................449
LONG DURATION ENERGY STORAGE.....................................................................................................................449
APPENDIX O - WASHINGTON CLEAN ENERGY ACTION PLAN
INTRODUCTION...................................................................................................................................................453
KEYFINDINGS.......................................................................................................................................................453
BACKGROUND.......................................................................................................................................................453
ENERGYJUSTICE................................................................................................................................................455
DISTRIBUTIONALJUSTICE......................................................................................................................................456
PROCEDURALJUSTICE...........................................................................................................................................458
RECOGNITIONJUSTICE..........................................................................................................................................459
RESTORATIVEJUSTICE..........................................................................................................................................460
PORTFOLIO DEVELOPMENT...........................................................................................................................461
RESOURCE PORTFOLIO DEVELOPMENT..................................................................................................................461
Portfolio Integration and Resource Allocations..............................................................................................462
ResourceAdequacy..........................................................................................................................................462
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PACIFICORP—2025 IRP TABLE OF CONTENTS
Conservation Potential Assessment.................................................................................................................463
Demand Response and Load Management Programs.....................................................................................464
Distributed Energy Resources..........................................................................................................................464
Transmission....................................................................................................................................................466
Development of a Washington-Compliant Portfolio........................................................................................467
PORTFOLIORESULTS........................................................................................................................................469
WASHINGTONSENSITIVITIES.................................................................................................................................473
CLEANENERGY TARGETS...............................................................................................................................475
CUSTOMERBENEFITS.......................................................................................................................................477
CUSTOMER BENEFIT INDICATORS..........................................................................................................................478
NON-ENERGY BENEFIT AND IMPACTS...................................................................................................................482
IDENTIFYING VULNERABLE POPULATIONS............................................................................................................482
SPECIFICACTIONS.............................................................................................................................................483
SUPPLY-SIDE..........................................................................................................................................................483
DEMAND-SIDE.......................................................................................................................................................483
EnergyEfficiency Actions................................................................................................................................483
Demand Response Actions...............................................................................................................................484
PUBLIC PARTICIPATION PLAN.......................................................................................................................484
ACTIONPLAN.......................................................................................................................................................485
APPENDIX P - OREGON CLEAN ENERGY UPATE
INTRODUCTION...................................................................................................................................................489
KEYFINDINGS .......................................................................................................................................................489
BACKGROUND.......................................................................................................................................................490
PORTFOLIO ASSUMPTIONS.............................................................................................................................491
PORTFOLIO INTEGRATION AND RESOURCE ALLOCATIONS.....................................................................................491
ResourceAdequacy..........................................................................................................................................492
HB 2021 Greenhouse Gas Emissions:Methodology and Assumptions...........................................................492
SMALL-SCALE RENEWABLES.................................................................................................................................496
PORTFOLIORESULTS........................................................................................................................................497
OREGON RESOURCE SELECTIONS..........................................................................................................................497
GREENHOUSE GAS EMISSIONS...............................................................................................................................499
SMALL-SCALE AND COMMUNITY-BASED RENEWABLES.......................................................................................501
TRANSMISSION......................................................................................................................................................501
IMPACTS OF OREGON COMPLIANCE.......................................................................................................................502
ADDITIONAL ACTIONS AND RESOURCES...................................................................................................505
DEMAND-SIDE MANAGEMENT..............................................................................................................................505
EnergyEfficiency.............................................................................................................................................505
DemandResponse............................................................................................................................................506
COMMUNITY-BASED RENEWABLE ENERGY..........................................................................................................506
PilotProgram..................................................................................................................................................507
IRPAnalysis.....................................................................................................................................................508
DISTRIBUTION SYSTEM PLANNING........................................................................................................................509
TRANSPORTATION ELECTRIFICATION....................................................................................................................510
COMMUNITY AND STAKEHOLDER ENGAGEMENT.................................................................................511
ADVISORYGROUPS...............................................................................................................................................511
GENERAL STAKEHOLDER ENGAGEMENT...............................................................................................................512
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PACIFICORP-2025 IRP TABLE OF CONTENTS
COMMUNITY BENEFIT INDICATORS............................................................................................................513
ACTIONPLAN.......................................................................................................................................................515
APPENDIX R - RENEWABLE PORTFOLIO IMPLEMENTATION
PLAN
INTRODUCTION...................................................................................................................................................519
SUMMARY..............................................................................................................................................................520
2025 RENEWABLE PLAN METHODOLOGY AND ASSUMPTIONS...............................................................................520
APPLICABLE REQUIREMENTS.................................................................................................................................521
ANNUALTARGETS..............................................................................................................................................522
OREGON RPS ELIGIBLE RESOURCES...........................................................................................................522
INCREMENTAL COSTS.......................................................................................................................................526
APPENDIX Z - ACRONYMS
vii

PACIFICORP—2025 IRP TABLE OF CONTENTS
TABLE OF TABLES - VOLUME II
APPENDIX A - LOAD FORECAST
TABLE A.1—FORECASTED ANNUAL LOAD,2025 THROUGH 2O34(MEGAWATT-HOURS)...............................................2
TABLE A.2—FORECASTED ANNUAL COINCIDENT PEAK LOAD(MEGAWATTS)AT GENERATION,PRE-DSM.................3
TABLE A.3—ANNUAL LOAD CHANGE:MAY 2024 FORECAST LESS MAY 2022 FORECAST(MEGAWATT-HOURS)AT
GENERATION,PRE-DSM.......................................................................................................................................3
TABLE A.4—ANNUAL COINCIDENT PEAK CHANGE:MAY 2024 FORECAST LESS MAY 2022 FORECAST(MEGAWATTS)
ATGENERATION,PRE-DSM..................................................................................................................................3
TABLE A.5—PROJECTED RANGE OF TEMPERATURE CHANGE IN THE 20205 AND 2050s................................................6
TABLE A.6—WEATHER NORMALIZED JURISDICTIONAL RETAIL SALES 2008 THROUGH 2O23.......................................8
TABLE A.7—NON-COINCIDENT JURISDICTIONAL PEAK 2008 THROUGH 2O23...............................................................9
TABLE A.8—JURISDICTIONAL CONTRIBUTION TO COINCIDENT PEAK 2008 THROUGH 2O23........................................10
TABLE A.9—SYSTEM ANNUAL RETAIL SALES FORECAST 2025 THROUGH 2O34,POST-DSM......................................13
TABLE A.10—FORECASTED RETAIL SALES GROWTH IN OREGON,POST-DSM............................................................14
TABLE A.I I—FORECASTED RETAIL SALES GROWTH IN WASHINGTON,POST-DSM WASHINGTON RETAIL SALES—
MEGAWATT-HOURS(MWH)...............................................................................................................................14
TABLE A.12-FORECASTED RETAIL SALES GROWTH IN CALIFORNIA,POST-DSM.......................................................15
TABLE A.13—FORECASTED RETAIL SALES GROWTH IN UTAH,POST-DSM.................................................................16
TABLE A.14-FORECASTED RETAIL SALES GROWTH IN IDAHO,POST-DSM................................................................16
TABLE A.15—FORECASTED RETAIL SALES GROWTH IN WYOMING,POST-DSM.........................................................17
APPENDIX B - REGULATORY COMPLIANCE
TABLE B.1—INTEGRATED RESOURCE PLANNING STANDARDS AND GUIDELINES SUMMARY BY STATE......................25
TABLE B.2—HANDLING OF PREVIOUS IRP ACKNOWLEDGMENTS AND OTHER IRP REQUIREMENTS...........................30
TABLE B.3—OREGON PUBLIC UTILITY COMMISSION IRP STANDARDS AND GUIDELINES...........................................48
TABLE B.4—UTAH PUBLIC SERVICE COMMISSION IRP STANDARDS AND GUIDELINES...............................................61
TABLE B.5—WASHINGTON CETA STANDARDS,RULES AND GUIDELINES..................................................................68
TABLE B.6—WYOMING PUBLIC SERVICE COMMISSION GUIDELINES...........................................................................82
APPENDIX C - PUBLIC INPUT
APPENDIX D - DEMAND-SIDE MANAGEMENT
TABLE D.1—CURRENT DEMAND RESPONSE AND ENERGY EFFICIENCY PROGRAM SERVICES AND OFFERINGS BY
SECTORAND STATE............................................................................................................................................90
TABLE D.2—CURRENT WATTSMART OUTREACH AND COMMUNICATIONS ACTIVITIES................................................92
TABLE D.3—CUMULATIVE DEMAND RESPONSE RESOURCE SELECTIONS(2025 IRP PREFERRED PORTFOLIO)(MW)..94
TABLE DA—CUMULATIVE ENERGY EFFICIENCY RESOURCE SELECTIONS(2025 IRP PREFERRED PORTFOLIO)..........95
TABLE D.5—FIRST-YEAR ENERGY EFFICIENCY RESOURCE SELECTIONS(2025 IRP PREFERRED PORTFOLIO)..............95
APPENDIX E - GRID ENHANCEMENT
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PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX F - FLEXIBLE RESERVE STUDY
TABLE F.1-PORTFOLIO REGULATION RESERVE REQUIREMENTS..............................................................................113
TABLE F.2-2025 FLEXIBLE RESERVE COSTS AS COMPARED TO 2023 COSTS,$/MWH.............................................113
TABLE F.3-SUMMARY OF STAND-ALONE REGULATION RESERVE REQUIREMENTS..................................................131
TABLE FA-EIM DIVERSITY BENEFIT APPLICATION EXAMPLE................................................................................133
TABLE F.5-2018-2019 RESULTS WITH PORTFOLIO DIVERSITY AND EIM DIVERSITY BENEFITS...............................133
APPENDIX G - PLANT WATER CONSUMPTION
TABLE G.1-PLANT WATER CONSUMPTION WITH ACRE-FEET*PER YEAR...............................................................147
TABLE G.2-PLANT WATER CONSUMPTION BY STATE ACRE-FEET).........................................................................148
TABLE GA-PLANT WATER CONSUMPTION FOR PLANTS LOCATED IN THE UPPER COLORADO RIVER BASIN(ACRE-
FEET).................................................................................................................................................................148
TABLE G.3-PLANT WATER CONSUMPTION BY.........................................................................................................148
APPENDIX H - STOCHASTICS
APPENDIX I - CAPACITY EXPANSION RESULTS
TABLE I.1-PRICE-POLICY CASE DEFINITIONS..........................................................................................................157
TABLE I.2-PORTFOLIO VARIANTS............................................................................................................................157
APPENDIX K- CAPACITY CONTRIBUTION
APPENDIX L - DISTRIBUTED GENERATION STUDY
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
TABLE C.1-STAKEHOLDER FEEDBACK FORM SUMMARY.........................................................................................271
APPENDIX N - ENERGY STORAGE POTENTIAL EVALUATION
APPENDIX O - WASHINGTON CLEAN ENERGY ACTION PLAN
TABLE 0.1-TRANSMISSION SELECTIONS SUPPORTING WASHINGTON RESOURCES1,2...............................................466
TABLE 0.2-INCREMENTAL RESOURCE ADDITIONS FOR WASHINGTON CUSTOMERS,BY RESOURCE ALLOCATION
ASSUMPTION.....................................................................................................................................................471
TABLE 0.3-CLEAN ENERGY INTERIM TARGETS FOR WASHINGTON CUSTOMERS 2026-2029....................................477
TABLE 0.4.-PACIFICORP'S CBI FRAMEWORK.........................................................................................................478
TABLE 0.5-WASHINGTON CLEAN ENERGY ACTION PLAN MATRIX.........................................................................485
IX

PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX P - OREGON CLEAN ENERGY UPATE
TABLEP.1-ASSUMPTIONS........................................................................................................................................493
TABLE P.2-SMALL-SCALE RESOURCE POSITION IN 2030..........................................................................................496
TABLE P.3-INCREMENTAL RESOURCE ADDITIONS FOR OREGON CUSTOMERS,BY RESOURCE ALLOCATION ASSUMPTION
498
TABLE PA-TRANSMISSION SELECTIONS SUPPORTING OREGON RESOURCES1,2.........................................................501
TABLE P.5-COST PER KW OF CBRE PROJECTS AWARDED GRANT FUNDING BY ODOE..........................................508
TABLE P.6-ESTIMATED COSTS REQUIRED TO BREAKEVEN ON CBRE PROJECTS......................................................509
TABLE P.7-INTERIM CBI FRAMEWORK....................................................................................................................514
TABLE P.8-OREGON CLEAN ENERGY PLAN ACTION MATRIX..................................................................................515
APPENDIX R - RENEWABLE PORTFOLIO IMPLEMENTATION
PLAN
TABLE R.1-OREGON RPS TARGET DATA.................................................................................................................522
TABLE R.2-OREGON RPS GENERATING FACILITIES AND RESOURCES.....................................................................523
APPENDIX Z - ACRONYMS
x

PACIFICORP-2025 IRP TABLE OF CONTENTS
TABLE OF FIGURES - VOLUME II
APPENDIX A - LOAD FORECAST
FIGURE A.1-PACIFICORP SYSTEM LOAD FORECAST CHANGE,AT GENERATION,PRE-DSM........................................2
FIGURE A.2-PACIFICORP ANNUAL RETAIL SALES 2008 THROUGH 2O23 AND..............................................................4
FIGURE A.3-PACIFICORP ANNUAL RESIDENTIAL USE PER CUSTOMER 2008 THROUGH 2O23 ......................................5
FIGURE A.4-COMPARISON OF UTAH 5, 10,AND 20-YEAR AVERAGE PEAK PRODUCING TEMPERATURES....................7
FIGURE A.5-LOAD FORECAST SCENARIOS,PRE-DSM................................................................................................18
APPENDIX B - REGULATORY COMPLIANCE
APPENDIX C - PUBLIC INPUT
APPENDIX D - DEMAND-SIDE MANAGEMENT
APPENDIX E - GRID ENHANCEMENT
APPENDIX F - FLEXIBLE RESERVE STUDY
FIGURE F.1 -BASE SCHEDULE RAMPING ADJUSTMENT..............................................................................................120
FIGURE F.2-PROBABILITY OF EXCEEDING ALLOWED DEVIATION.............................................................................125
FIGURE F.3-WIND REGULATION RESERVE REQUIREMENTS BY FORECAST-PACE..................................................127
FIGURE F.4-WIND REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACW..................127
FIGURE F.5-SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACE..................128
FIGURE F.6-SOLAR REGULATION RESERVE REQUIREMENTS BY FORECAST CAPACITY FACTOR-PACW................128
FIGURE F.7-NON-VER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR-PACE.............................129
FIGURE F.8-NON-VER REGULATION RESERVE REQUIREMENTS BY CAPACITY FACTOR-PACW...........................129
FIGURE F.9-STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS-PACE................................................130
FIGURE F.10-STAND-ALONE LOAD REGULATION RESERVE REQUIREMENTS-PACW.............................................130
FIGURE F.11-INCREMENTAL WIND AND SOLAR REGULATION RESERVE COSTS.......................................................139
FIGURE F.12-COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES,EAST BALANCING AUTHORITY AREA
(MW)................................................................................................................................................................143
FIGURE F.13-COMPARISON OF RESERVE REQUIREMENTS AND RESOURCES,WEST BALANCING AUTHORITY AREA
(MW)................................................................................................................................................................143
APPENDIX G - PLANT WATER CONSUMPTION
APPENDIX H - STOCHASTICS
FIGURE H.1-CHAOTIC NORMAL AND HISTORICAL LOAD PATTERNS........................................................................151
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PACIFICORP-2025 IRP TABLE OF CONTENTS
FIGURE H.2-HISTORICAL MARKET PRICE VARIATION.............................................................................................152
FIGURE H.3-HISTORICAL HYDRO VARIATION..........................................................................................................153
FIGURE HA-HISTORICAL VARIATION OF PROXY WIND AND SOLAR RESOURCES....................................................155
FIGURE H.5--HISTORICAL MARKET PRICES VS LOAD,JULY 2023............................................................................156
FIGURE H.6-HISTORICAL MARKET PRICES VS LOAD,OCTOBER 2020......................................................................156
APPENDIX I - CAPACITY EXPANSION RESULTS
APPENDIX K- CAPACITY CONTRIBUTION
FIGURE K.1-CF METHOD CAPACITY CONTRIBUTION VALUES FOR WIND,SOLAR,AND STORAGE..........................181
FIGURE K.2-LOSS OF LOAD EVENT DETAIL.............................................................................................................181
FIGURE K.3-WRAP CONTRIBUTIONS THROUGH TIME-SOLAR..............................................................................184
FIGURE KA-WRAP CONTRIBUTIONS THROUGH TIME-WIND................................................................................185
FIGURE K.5-WRAP CONTRIBUTIONS THROUGH TIME-STORAGE..........................................................................186
APPENDIX L - DISTRIBUTED GENERATION STUDY
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
APPENDIX N - ENERGY STORAGE POTENTIAL EVALUATION
FIGURE N.1 -ENERGY MARGIN BY ENERGY STORAGE ATTRIBUTES..........................................................................442
FIGURE N.2-LONG DURATION STORAGE CHARGING AND DISCHARGING,TARGETS AND OPTIMIZATION................450
APPENDIX O - WASHINGTON CLEAN ENERGY ACTION PLAN
FIGURE 0.1-TENETS OF ENERGY JUSTICE................................................................................................................455
FIGURE 0.2-CPA RESULTS FOR WASHINGTON:CUMULATIVE ACHIEVABLE TECHNICAL POTENTIAL.....................463
FIGURE 0.3-CUMULATIVE NEW DISTRIBUTED GENERATION CAPACITY INSTALLED BY............................................465
FIGURE 0.4-CUMULATIVE NEW CAPACITY INSTALLATIONS BY TECHNOLOGY(MW-AC)........................................466
FIGURE 0.5-CUMULATIVE AND INCREMENTAL PORTFOLIO CHANGES.....................................................................474
FIGURE 0.6-CUMULATIVE AND INCREMENTAL PORTFOLIO CHANGES.....................................................................474
FIGURE 0.7--CLEAN ENERGY INTERIM TARGETS FOR WASHINGTON CUSTOMERS,2025 THROUGH 2O45................476
APPENDIX P - OREGON CLEAN ENERGY UPATE
FIGURE P.1-HB 2021 EMISSIONS TARGETS FOR PACIFICORP...................................................................................492
FIGURE P.2-OREGON GREENHOUSE GAS EMISSIONS RELATIVE TO HB 2021 TARGETS..............................................500
FIGURE P.3-CUMULATIVE AND INCREMENTAL PORTFOLIO CHANGES......................................................................502
FIGURE PA-UIWC PORTFOLIO LESS PREFERRED PORTFOLIO SYSTEM COST..........................................................503
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PACIFICORP-2025 IRP TABLE OF CONTENTS
APPENDIX R. - RENEWABLE PORTFOLIO IMPLEMENTATION
PLAN
APPENDIX Z - ACRONYMS
xiii

PACIFICORP-2025 IRP TABLE OF CONTENTS
XIV

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 primary driver to changes in PacifiCorp's
2025 IRP load forecast are due to the exclusion of specific new large customers who are expected
to provide or pay for the resources and transmission necessary to support their load. These
customers are expected to acquire their own resources; therefore, their loads have been excluded
so that the PLEXOS capacity expansion optimization model does not plan Company resources to
serve them.
The compound annual load growth rate for the 10-year period(2025 through 2034)is 1.28 percent.
Relative to the load forecast prepared for the 2023 IRP, PacifiCorp's 2034 forecast load
requirement decreased in all states other than Washington resulting in PacifiCorp system load
requirement to decline 13.35 percent in 2034. Figure A.1 provides a comparison of the 2025 IRP
and the 2023 IRP load forecasts.
1

PACIFICORP-2025 IRP APPErmix A-LOAD FORECAST
Figure A.1 -PacifiCorp System Load Forecast Change, at Generation, re-DSM
Forecasted Annual System Load Forecasted Annual System Coincident
(GWh) Peak(MW)
120,000 20,000
100,000
80,000
15,000
60,000 10,000
40,000
20,000 5,000
0 0
ti ti ti ti ti ti ti ti ti ti tio��tio�^tio��tio��tio��tio��tio�^tiocl'1P,11o'2'
—2025 IRP t2023IRP 2025 IRP 2023IRP
Table A.1 and Table A.2 show the annual load and coincident peak load forecast when not
reducing load projections to account for new energy efficiency measures.1 Table A.3 and Table
A.4 show the forecast changes relative to the 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 Total OR WA CA UT WY ID
2025 64,414,790 16,114,060 4,545,410 844,170 29,396,700 9,662,750 3,851,700
2026 64,231,880 16,396,610 4,573,810 844,790 28,904,240 9,640,700 3,871,730
2027 65,395,390 16,601,790 4,761,850 844,380 29,627,340 9,666,940 3,893,090
2028 66,504,260 16,824,670 4,957,640 845,780 30,272,410 9,684,200 3,919,560
2029 67,262,990 16,995,130 4,967,740 842,310 30,839,670 9,686,200 3,931,940
2030 68,211,820 17,210,630 4,993,880 841,360 31,535,430 9,681,100 3,949,420
2031 69,249,310 17,432,090 5,018,660 840,620 32,295,080 9,696,570 3,966,290
2032 70,277,070 17,697,980 5,055,940 842,410 32,986,240 9,704,760 3,989,740
2033 71,146,810 17,911,130 5,071,770 839,820 33,621,250 9,700,290 4,002,550
2034 72,221,110 18,187,210 5,100,920 839,770 34,378,540 9,691,460 4,023,210
Compound Annual Growth Rate
2025-34 1.28% 1.35% 1.29% -0.06% 1.75% 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 11,318 2,752 830 146 5,597 1,233 760
2026 11,270 2,769 841 147 5,546 1,211 756
2027 11,425 2,803 880 147 5,631 1,211 753
2028 11,553 2,834 886 148 5,733 1,213 739
2029 11,690 2,869 891 148 5,829 1,214 739
2030 11,844 2,908 895 148 5,936 1,218 740
2031 12,104 3,011 898 148 6,058 1,220 769
2032 12,193 2,993 901 148 6,167 1,218 765
2033 12,363 3,072 933 152 6,229 1,208 770
2034 12,575 3,135 941 152 6,364 1,210 773
or Compound Annual Growth Rate
2025-34 1.18% 1.46% 1.40% 0.44% 1.44% -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 WY ID
2025 (5,390,270) (3,616,260) (155,350) (11,050) (964,520) (412,110) (230,980)
2026 (5,706,540) (4,061,040) (147,950) (8,180) (783,240) (472,540) (233,590)
2027 (7,254,380) (5,159,500) 5,020 (8,800) (1,407,080) (450,000) (234,020)
2028 (10,176,860) (6,621,290) 146,440 (10,700) (2,911,330) (544,910) (235,070)
2029 (10,656,290) (6,957,650) 126,430 (12,850) (3,021,690) (553,770) (236,760)
2030 (10,600,020) (6,855,430) 108,530 (14,430) (2,948,470) (651,450) (238,770)
2031 (11,131,380) (7,389,600) 87,960 (15,980) (2,904,810) (667,550) (241,400)
2032 (11,044,710) (7,462,900) 65,540 (17,550) (2,614,110) (771,970) (243,720)
2033 (11,075,420) (7,508,650) 45,520 (18,880) (2,540,700) (807,980) (244,730)
2034 (11,130,430) (7,554,380) 23,940 (20,350) (2,466,790) (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 WA CA UT Wym
2025 (429) (259) (26) (1) (31) (68) (43)
2026 (488) (284) (30) (1) (27) (94) (52)
2027 (626) (386) (7) (2) (76) (95) (60)
2028 (931) (489) (19) (4) (260) (105) (55)
2029 (992) (618) (36) (9) (194) (77) (59)
2030 (971) (599) (51) (10) (165) (83) (63)
2031 (1,019) (620) (68) (12) (156) (91) (72)
2032 (1,016) (639) (84) (13) (101) (97) (82)
2033 (984) (599) (73) (10) (128) (115) (60)
2034 (937) (575) (85) (11) (83) (121) (62)
3

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
oad 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, 2008 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 2008 through 2023 and
Western Region Employment
Retail Sales and Service Territory Employment
60,000 System Annual Sales Western Region Employment 42.0
59,000
58,000 4 0.0
0
57,000
38.0
56,000
55,000 36.0
54,000 >,
53,000 34.0
52,000 32.0 W
51,000 — —
50,000 30.0
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 2008 through 2023
System Residential Use per Customer
11,000
y
10,500
Q
Q
'27 10,000
40
04
a�
9,500
3
x
9,000
d 8,500
8,000
0(ea
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/westwidesecurereportl-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
Bureau of Reclamation Site Jurisdiction (OF)*
Assumption
2020S I 2050s
Kla=Ritverear 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 commercial data center forecasts within the respective
jurisdictions.
7

PACFICORP—2025 IRP APPENDix A—LOAD FORECAST
Customer forecasts are provided by the customer to PacifiCorp through a regional business
manager("RBM").
Actual Load Data
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 2008 through 2023
System Retail Sales-Megawatt-hours(MWh)*
Year California Idaho Oregon Utah Washington Wyoming System
2008 858,950 3,447,815 13,143,154 22,725,958 4,066,187 9,166,786 53,408,850
2009 821,496 2,990,395 12,992,344 22,160,113 4,035,869 9,224,533 1 52,224,750
2010 835,316 3,482,028 13,049,455 22,581,496 4,036,261 9,623,480 53,608,035
2011 798,656 3,495,853 12,883,008 23,392,972 4,008,345 9,771,921 54,350,755
2012 778,337 3,544,362 12,914,227 23,731,702 4,027,750 9,448,692 54,445,070
2013 767,445 3,573,026 12,960,411 23,799,941 4,038,910 9,514,315 54,654,048
2014 764,480 3,581,617 13,062,897 24,272,779 4,080,862 9,562,888 55,325,523
2015 734,199 3,542,141 13,060,948 24,045,657 4,063,695 9,349,334 54,795,974
2016 746,449 3,503,137 13,205,242 23,696,002 4,014,408 9,190,762 54,356,000
2017 750,570 3,596,265 13,229,888 23,837,915 4,056,911 9,331,995 54,803,545
2018 734,567 3,654,789 13,252,578 24,627,024 4,038,845 9,243,048 55,550,852
2019 737,603 3,529,552 13,226,821 24,542,645 4,036,076 9,318,836 55,391,533
2020 757,481 3,599,853 13,179,461 24,742,370 4,081,180 8,317,875 54,678,220
2021 788,621 3,524,419 13,705,078 25,309,780 4,114,232 8,494,548 55,936,679
2022 785,410 3,661,104 j 13,715,836 25,455,539 4,023,511 8,705,156 56,346,557
2023 755,275 3,573,339 1 13,988,996 25,712,395 3,823,307 8,718,426 56,571,738
Compound Annual Growth Rate
2008-23 -0.85% 0.24% 1 0.42% 0.83% -0.41% -0.33% 0.38%
*System retail sales do not include sales for resale
8

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Table A.7-Non-Coincident Jurisdictional Peak 2008 through 2023
Non-Coincident Peak-Megawatts (MW)*
Year California Idaho Oregon Utah Washington Wyoming System
2008 187 759 2,921 4,479 923 1,339 10,609
2009 193 688 3,121 4,404 917 1,383 10,705
2010 176 777 2,552 4,448 893 1,366 10,213
2011 177 770 2,686 4,596 854 1,404 10,486
2012 159 800 2,550 4,732 797 1,337 10,376
2013 182 814 2,980 5,091 886 1,398 11,351
2014 161 818 2,598 5,024 871 1,360 10,831
2015 157 843 2,598 5,226 837 1,326 10,986
2016 155 848 2,584 5,018 819 1,300 10,724
2017 177 830 2,920 4,932 943 1,354 11,156
2018 158 830 2,608 5,091 849 1,319 10,854
2019 151 793 2,632 5,158 895 1,363 10,993
2020 155 806 2,562 5,336 848 1,271 10,979
2021 149 1 771 1 2,894 1 5,547 938 1,299 11,598
2022 162 833 2,813 5,526 895 1,314 11,543
2023 155 769 2,924 5,431 844 1,324 11,447
Compound Annual Growth Rate
2008-23 -1.24% 1 0.08% 1 0.01% 1 1.29% -0.59% -0.08% 0.51%
*Non-coincident peaks do not include sales for resale
9

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Table A.8-Jurisdictional Contribution to Coincident Peak 2008 through 2023
Coincident Peak-Megawatts (MW)*
Year California Idaho Oregon Utah Washington Wyoming System
2008 171 682 2,521 4,145 728 1,208 9,456
2009 153 517 2,573 4,351 795 987 9,375
2010 144 527 2,442 4,294 757 1,208 9,373
2011 143 549 2,187 4,596 707 1,204 9,387
2012 156 782 2,163 4,731 749 1,225 9,806
2013 156 674 2,407 5,091 797 1,349 10,474
2014 150 630 2,345 5,024 819 1,294 10,263
2015 152 805 2,472 5,081 833 1,259 10,601
2016 139 575 2,462 4,940 817 1,201 10,135
2017 152 593 2,547 4,911 787 1,306 10,296
2018 126 741 2,526 5,037 790 1,295 10,514
2019 122 731 2,276 5,158 761 1,248 10,297
2020 127 603 2,428 5,336 839 1,180 10,515
2021 145 767 12,543 5,319 1839 1,214 10,827
2022 142 730 2,726 5,250 870 1,266 10,984
2023 140 509 2,890 5,196 807 1,223 10,765
Compound Annual Growth Rate
2008-23 -1.33% -1.93% 1 0.92% 1.52% 0.69% 0.08% 0.87%
*Coincident peaks do not include sales for resale
System Losses
Line loss factors are derived using the five-year average of the percent difference between the
annual system load by jurisdiction and the retail sales by jurisdiction. System line losses were
updated to reflect actual losses for the five-year period ending December 31, 2023.
10

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Forecast Methodology Overview
Demand-side Management Resources in the Load Forecast
PacifiCorp models demand-side management(DSM) 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.
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 like 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.
Many 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
11

PACFICORP—2025 IRP APPENDix A—LOAD FORECAST
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
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.'
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
a 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.
12

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
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
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.
Sales Forecast at the Customer Meter
This section provides total system and state-level forecasted retail sales summaries measured at
the customer meter by customer class including load reduction projections from new energy
efficiency measures from the Preferred Portfolio.
Table A.9—System Annual Retail Sales Forecast 2025 through 2034, post-DSM
System Retail Sales—Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 18,192,073 21,909,908 17,371,196 1,435,667 100,845 59,009,688
2026 18,478,238 22,063,280 16,214,788 1,431,485 99,108 58,286,900
2027 18,800,131 22,197,849 16,450,828 1,423,054 97,668 58,969,530
13

PACFICORP-2025 IRP APPENDix A-LOAD FORECAST
2028 19,190,567 22,091,187 16,738,021 1,413,274 96,623 59,529,672
2029 19,491,361 21,871,170 16,772,389 1,401,328 95,019 59,631,266
2030 19,875,324 21,698,175 16,845,920 1,389,305 93,664 59,902,389
2031 20,306,301 21,596,410 16,980,838 1,378,814 92,340 60,354,704
2032 20,772,055 21,432,263 16,902,580 1,365,336 91,412 r6O,563,647
2033 21,157,523 21,190,484 16,787,515 1,350,595 90,171 60,576,289
2034 21,622,660 21,050,123 16,673,196 1,338,528 89,435 60,773,943
Compound Annual Growth Rate
2025-34 1.94% -0.44% -0.45% -0.78% -1.33% 0.33%
State Summaries
Oregon
Table A.10 summarizes Oregon state forecasted retail sales growth by customer class. Growth in
Oregon retail sales are driven by expectations for the residential class.
Table A.10-Forecasted Retail Sales Growth in Oregon, post-DSM
Oregon Retail Sales-Megawatt-hours(MWh
Year 7R7esi7dential Commercial Industrial Irrigation Lighting Total
2025 80 6,715,632 1,367,320 250,920 30,121 14,316,773
2026 61010,181 6,758,288 1,371,878 250,815 29,642 14,420,803
2027 6,051,304 6,729,400 1,341,400 250,332 29,255 14,401,692
2028 6,108,184 6,691,531 1,319,069 249,914 29,049 14,397,746
2029 6,135,339 6,638,809 1,290,269 249,222 28,749 14,342,388
2030 6,193,330 6,589,995 1,270,861 248,611 28,592 14,331,390
2031 6,252,656 6,543,338 1,251,491 247,971 28,479 14,323,935
2032 6,336,181 6,509,261 1,225,849 247,033 28,480 14,346,805
2033 6,412,705 6,464,445 1,194,298 245,438 28,340 14,345,226
2034 6,528,806 6,446,045 1,161,233 244,342 28,298 14,408,725
Compound Annual Growth Rate
2025-34 1.03% -0.45% -1.80% -0.29% -0.69% 0.07%
Washington
Table A.11 summarizes Washington state forecasted retail sales growth by customer class. Growth
in Washington retail sales are driven by expectations for the industrial class.
Table A.11 -Forecasted Retail Sales Growth in Washington,post-DSM Washington Retail
AL Sales-Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 1,617,779 1,529,202 724,050 157,018 3,978 4,032,026
14

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
2026 1,626,189 1,530,187 711,068 156,285 3,985 4,027,715
2027 1,626,300 1,529,021 849,486 155,619 3,985 4,164,411
2028 1,624,874 1,527,690 989,969 154,616 3,997 4,301,146
2029 1,611,783 1,516,912 985,982 153,651 3,985 4,272,314
2030 1,604,064 1,509,197 985,768 152,587 3,985 4,255,601
2031 1,597,678 1,502,852 984,776 151,790 3,985 4,241,082
2032 1,592,476 1,494,420 981,491 150,169 3,997 4,222,553
2033 1,580,259 1,477,848 972,546 148,565 3,985 4,183,203
2034 1,574,975 1,467,106 964,432 147,149 3,985 4,157,648
Compound Annual Growth Rate
2025-34 -0.30% -0.46% 3.24% -0.72% 0.02% 0.34%
California
Table A.12 summarizes California state forecasted sales growth by customer class. Decrease in
California retail sales are driven by expectations for the commercial class.
Table A.12 - Forecasted Retail Sales Growth in California, post-DSM
California Retail Sales-Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 378,690 236,019 52,824 91,016 1,664 760,212
2026 379,100 233,017 52,181 91,302 1,649 757,249
2027 378,764 230,241 51,589 90,842 1,639 753,075
2028 379,366 228,367 51,192 90,209 1,636 750,769
2029 377,307 225,092 50,631 89,407 1,625 744,062
2030 376,535 222,645 50,296 88,589 1,621 739,686
2031 375,811 220,270 49,978 87,753 1,618 735,430
2032 376,378 218,509 49,758 86,776 1,621 733,042
2033 374,716 214,981 49,210 85,561 1,615 726,082
2034 374,457 212,245 48,841 84,488 1,613 721,644
Compound Annual Growth Rate
2025-34 -0.12% -1.17% -0.87% -0.82% -0.340/. -0.58%
Utah
Table A.13 summarizes Utah state forecasted sales growth by customer class. Growth in Utah
retail sales are driven by expectations for the residential class.
15

PACIFICORP-2025 IRP APPENDIX A-LOAD FORECAST
Table A.13 -Forecasted Retail Sales Growth in Utah, post-DSM
Utah Retail Sales-Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 8,376,501 11,476,530 7,286,541 236,606 50,688 27,426,867
2026 8,594,571 11,601,196 6,192,020 233,425 49,770 26,670,982
2027 1 8,874,055 11,787,852 6,332,359 229,689 49,224 27,273,180
2028 9,204,255 11,741,914 6,525,760 225,303 49,038 27,746,270
2029 9,506,156 11,621,980 6,609,541 220,255 48,708 28,006,641
2030 9,849,880 11,532,865 6,729,616 214,774 48,597 28,375,731
2031 10,237,731 11,508,017 6,890,399 210,111 48,532 28,894,792
2032 10,629,198 11,412,798 6,871,721 203,493 48,632 29,165,842
2033 10,968,166 11,270,916 6,831,483 196,715 48,473 29,315,754
2034 11,330,944 11,189,384 6,805,015 j 190,863 48,461 29,564,668
Compound Annual Growth Rate
2025-34 3.41% -0.28% -0.76% -2.36% -0.50% 0.84%
Idaho
Table A.14 summarizes Idaho state forecasted sales growth by customer class. Decrease in Idaho
retail sales are driven by expectations for the commercial class.
Table A.14 - Forecasted Retail Sales Growth in Idaho, post-DSM
Idaho Retail Sales-Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 811,032 557,096 1,587,100 669,538 2,639 3,627,405
2026 815,973 551,568 1,583,461 669,118 2,584 3,622,705
2027 822,198 549,212 1,581,458 666,172 2,502 3,621,543
2028 829,646 547,613 1,580,474 662,984 2,394 3,623,112
2029 829,200 541,094 1,578,348 658,733 2,236 3,609,612
2030 830,437 535,557 1,577,652 654,831 2,058 3,600,534
2031 831,025 528,787 1,576,746 651,325 1,869 3,589,752
2032 834,627 522,879 1,575,943 648,136 1,698 3,583,284
2033 832,920 514,181 1,572,933 644,763 1,545 3,566,342
2034 835,354 508,041 1,570,309 642,274 1,433 3,557,411
Compound Annual Growth Rate
2025-34 0.33% -1.02% 1 -0.12% 1 -0.46% -6.56% -0.22%
Table A.15 summarizes Wyoming state forecasted sales growth by customer class. Decrease in
Wyoming retail sales are driven by expectations for the industrial and commercial classes.
16

PACIFICORP—2025 IRP APPENDIX A—LOAD FORECAST
Table A.15—Forecasted Retail Sales Growth in Wyoming, post-DSM
Wyoming Retail Sale Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Lighting Total
2025 1,055,290 1,395,430 6,353,361 30,568 11,755 8,846,405
2026 1,052,223 1,389,024 6,304,181 30,541 11,476 8,787,446
2027 1,047,511 1,372,121 6,294,536 30,400 11,062 8,755,629
2028 1,044,242 1,354,072 6,271,558 30,247 10,509 8,710,629
2029 1,031,575 1,327,283 6,257,618 30,059 9,714 8,656,249
2030 1,021,079 1,307,918 6,231,727 29,913 8,810 8,599,448
2031 1,011,399 1,293,146 6,227,447 29,865 7,856 8,569,713
2032 1,003,195 1,274,396 6,197,819 29,728 6,984 8,512,122
2033 988,757 1,248,112 6,167,046 2%553 6,213 8,439,681
2034 978,125 1,227,302 6,123,365 29,412 5,644 8,363,848
Compound Annual Growth Rate
2025734 -0.84% -1.42% 1 -0.41% -0.43% -7.83% -0.62%
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.
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).
17

PACFICORP—2025 IRP APPErDrx A-LOAD FORECAST
The 95% prediction interval is calculated at the system level and then allocated to each state and
class based on their contribution to the variability of the system level forecast. The standard error
bands for the jurisdictional peak forecasts were calculated in a similar manner. The final high load
growth scenario includes the optimistic economic forecast and low private generation forecast plus
the monthly energy adder and the monthly peak forecast with the peak adder. The final low load
growth scenario includes the pessimistic economic forecast and high private generation forecast
minus the monthly energy adder and monthly peak forecast minus the peak adder.
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 materializes 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, re-DSM
Base Case High PG Low PG High Low 1-in-20 Weather High DC
25,000
20,000
15,000
10,000
5,000
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
18

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
APPENDIX B - REGULATORY COMPLIANCE
Tntroductio
This appendix describes how PacifiCorp's 2025 Integrated Resource Plan(IRP) complies with (1)
the various state commission IRP standards and guidelines, (2) specific analytical requirements
stemming from acknowledgment orders for the company's 2023 Integrated Resource Plan, and
other ongoing IRP acknowledgement order requirements as applicable, and (3) state commission
IRP requirements stemming from other regulatory proceedings.
Included in this appendix are the following tables:
• Table B.1 - Provides an overview and comparison of the rules in each state for which an IRP
submission is required.' The table is divided into topical subsections as follows:
(a) Source
(b) Filing Requirements
(c) Frequency
(d) Commission Response
(e) Process
(f) Focus
(g) Elements
• Table B.2 - Provides a description of how PacifiCorp addressed the 2023 IRP
acknowledgement order requirements and other commission directives.2
• Table B.3 - Provides an explanation of how this plan addresses each of the items contained in
the Oregon IRP guidelines.
• Table B.4 - Provides an explanation of how this plan addresses each of the items contained in
the Public Service Commission of Utah IRP Standard and Guidelines issued in June 1992.
• Table B.5 - Provides an explanation of how this plan addresses each of the items contained in
the Washington Utilities and Transportation Commission IRP rules issued in RCW 19.280.030
and WAC 480-100-620 through WAC 480-100-630 issued in December 2020.
• Table B.6 - Provides an explanation of how this plan addresses each of the items contained in
the Wyoming Public Service Commission IRP guidelines updated in March 2016.
General Compliance
PacifiCorp prepares the IRP on a biennial basis and files the IRP with state commissions. The
preparation of the IRP is done in an open public process with consultation from all interested parties,
including commissioners and commission staff, customers,and other stakeholders. This open process
' 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.
a"Other commission directives"includes orders relevant to previous IRPs that contain ongoing requirements.
19

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
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 Chapter 2 (Introduction), as well as Appendix C (Public Input).
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 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 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 portfolio analysis
and the results and conclusions drawn from the analysis are described in Chapter 9.
Consistent with the IRP standards and guidelines of Oregon,Utah, and Washington,this includes an
Action Plan in Chapter 10. 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
20

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
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 directed 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) along with 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 CPUC3 and D.23-12-008. On March 7, 2024, PacifiCorp filed its 2023 IRP Supplement (2023
On-Year Supplement to its 2021 IRP) in Docket R.18-07-003. The Plan was approved in Decision
24-12-035, adopted December 19, 2024.
On October 18, 2019, PacifiCorp submitted its 2019 IRP in compliance with D.18-02-018.
On April 6, 2020, the CPUC issued D.20-03-028, which reiterated PacifiCorp's ability to file an
alternative IRP.
On September 1, 2021, PacifiCorp filed its 2021 IRP in Docket R.18-07-003 in compliance with
D.08-05-029.
On November 1, 2022, PacifiCorp filed its 2021 IRP in Docket R.20-05-003 in compliance with
D.18-02-018, D.20-03-028, and D.22-02-004.
The California Public Utilities Commission is anticipated to issue IRP requirements in May 2025,
with the Company's next Alternative IRP filing due November 2025.
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.
3 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).
21

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
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 2025 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 as amended by Order No. 07-047).
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), flexible resource capacity (Order No. 12-013 ), and renewable
portfolio standard planning (HB 3161 ORS 469A.075). Consistent with the earlier guidelines (Order
89-5074), 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.3
provides detail on how this plan addresses each of the requirements.5
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.4 documents how PacifiCorp complies with each of
these standards.
Washington
This IRP is submitted to the Washington Utilities and Transportation Commission (WUTC) in
compliance with its required four-year filing cadence. In its report, the rule requires PacifiCorp to
4 Public Utility Commission of Oregon,Order No. 12-013,Docket No. 1461,January 19,2012.
5 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.
22

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
include: a range of load forecasts; assessments of distributed and supply-side resources, renewable
resource integration, regional generation and transmission, resource adequacy, and comparative
resource evaluation; evaluation of economic, health, and environmental burdens and benefits;
scenarios and sensitivities; and portfolio analysis including the development of a preferred portfolio.
In addition, Washington requires the inclusion of a Clean Energy Action Plan per Washington RCW
19.280.030 and WAC 480-100-620, which is provided as Appendix O (Clean Energy Action Plan).
Table B.5 documents how PacifiCorp complies with each of these standards.
Wyoming
Currently Chapter 3, Section 33 of the Wyoming Public Service Commission rules 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.
In August 2024, the Wyoming Public Service Commission issued a Notice of Technical Conference
and Call for Comments to consider engaging in a rulemaking to determine if additional rule
requirements are necessary to comply with newly enacted Wyoming Statute § 37-2-135 that went
into effect on July 1, 2024, which requires the Commission to review IRP action plans. PacifiCorp is
participating in the public rulemaking process.
Table B.6 documents how PacifiCorp complies with Wyoming guidelines.
23

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
24

PACIFICORP—2023 IRP APPENDIX B—IRP REGULATORY COMPLIANCE
Table B.1 —Integrated Resource Planning Standards and Guidelines Summary by State
MLff"I
Oregon Utah AL Washington Idaho Wyoming
Order No. 07-002,Investigation Docket 90-2035-01 Standards WAC 480-100-620 Content of Order 22299 Wyoming Electric,Gas
into Integrated Resource and Guidelines for Integrated an integrated resource plan. Electric Utility Conservation and Water Utilities,
Planning,January 8,2007,as Resource Planning June 18, Filed 12128120, effective Standards and Practices Chapter 3, Section 33,
amended by Order No.07-047. 1992. 12131120. January 1989. March 21,2016.
Order No. 08-339,Investigation WAC 480-100-625 Integrated
into the Treatment of CO2 Risk resource plan development and
in the Integrated Resource timing.Filed 12128120, effective
Planning Process,June 30, 12131120.
2008.
WAC 480-100-630 Integrated
Order No. 09-041, New Rule resource planning advisory
OAR 860-027-0400, groups.Filed 12128120, effective
implementing Guideline 3, 12131120.
"Plan Filing,Review,and
Updates".
Order No. 12-013,
"Investigation of Matters
related to Electric Vehicle
Charging",January 19,2012
Order No.23-061,
"Reconsideration of Order No.
22-390 Granted in Part;
Reconsideration of Order Nos.
22-446 and 22-477 Denied,
February 24,2023.
25

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Oregon Utah Washington Idaho Wyoming
Least-cost plans must be filed 7n.
o be submitted to Submit a least-cost plan to the Submit Resource Management Each utility serving in
with the Oregon PUC, WUTC every four years, Report on planning status.Also, Wyoming that files and
including a Clean Energy Plan. including a Clean Energy Action file progress reports on IRP in another
Plan.Plan to be developed with conservation,low-income jurisdiction,shall file the
consultation of WUTC staff,and programs,lost opportunities and IRP with the commission.
with public involvement. capability building.
Empor
IRP GuidelinesFrequency
Oregon Utah as ing on daho Wyoming
Plans filed biennially,within File biennially. Unless otherwise ordered by RMR to be filed at least The commission may
two years of its previous IRP the commission,each electric biennially.Conservation require any utility to file an
acknowledgment order.An utility must file an integrated reports to be filed annually. IRP.
annual update to the most resource plan(IRP)with the Low income reports to be filed
recently acknowledged IRP is commission by January 1, at least annually.Lost
required to be filed on or 2021,and every four years Opportunities reports to be
before the one-year thereafter. filed at least annually.
anniversary of the Capability building reports to
acknowledgment order date. At least every two years after be filed at least annually.
While informational only, the utility files its IRP,
utilities may request beginning January 1,2023,the
acknowledgment of proposed utility must file a two-year
changes to the action plan. progress report.
26

PACIFICORP—2023 IRP APPENDIX B—IRP REGULATORY COMPLIANCE
oil I 1 ' fill
Oregon Utah Washington Idaho Wyoming
Least-cost plan(LCP) IRP acknowledged if found to The plan will be considered, Report does not constitute Commission advisory
acknowledged if found to comply comply with standards and with other available pre-approval of proposed staff reviews the IRP as
with standards and guidelines.A guidelines.Prudence reviews information,when evaluating resource acquisitions. directed by the
decision made in the LCP of new resource acquisitions the performance of the utility Commission and drafts
process does not guarantee will occur during rate making in rate proceedings. Idaho sends a short letter a memo to report its
favorable rate-making treatment. proceedings. stating that they accept the findings to the
The OPUC may direct the utility WUTC no longer filing and acknowledge the commission in an open
to revise the IRP or conduct Note,however,that Rate Plan acknowledges IRPs. report as satisfying meeting or technical
additional analysis before an legislation allows pre-approval commission requirements. conference.
acknowledgment order is issued. of near-term resource
investments.
" 1 • W71TOMM
Oregon Utah Washington Idaho Wyoming
raal
public and other utilities Planning process open to the In consultation with WUTC staff, Utilities to work with The review may be
lowed significant public at all stages.IRP develop and implement a public commission staff when conducted in accordance
involvement in the preparation developed in consultation involvement plan. reviewing and updating with guidelines set from time
of the plan,with opportunities with the commission,its RMRs.Regular public to time as conditions
to contribute and receive staff,with ample opportunity PacifiCorp is required to submit a workshops should be warrant.
information.Order 07-002 for public input. work plan for informal commission part of process.
requires that the utility present review not later than 15 months prior The Public Service
IRP results to the Oregon PUC to the due date of the plan. Commission of Wyoming,in
at a public meeting prior to the its Letter Order on
deadline for written public The utility must file its draft IRP with PacifiCorp's 2008 IRP
comments. the commission four months prior to (Docket No.20000-346-EA-
Commission staff and parties the filing of an IRP.(a)The 09)adopted commission
should complete their commission will hear public comment Staff s recommendation to
comments and on the draft IRP at an open meeting expand the review process to
recommendations within six once filed. (b)The utility must file include a technical
months after IRP filing. draft IRP presentation materials at conference,an expanded
Competitive secrets must be least five business days prior to the public comment period,and
protected. open meeting. filing of reply comments.
27

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
7Oregon AL Utah Washington Idaho Wyoming
20jyear plan,with end- 20-year plan with short-term 20-year plan,which describes mix of 20-year plan to meet load Identification of least-
and a short-term (four-year)action plan. resources sufficient to meet current obligations at least-cost, cost/least-risk resources
(two-year)action plan.The Specific actions for the first and future loads and CETA with equal consideration to and discussion of
IRP process should result in two years and anticipated standards at"lowest reasonable" demand side resources.Plan deviations from least-cost
the selection of that mix of actions in the second two cost.Resource cost,market volatility to address risks and resources or resource
options which yields,for years to be detailed.The IRP risks,demand-side resource uncertainties.Emphasis on combinations.
society over the long run,the process should result in the uncertainty,resource dispatchability, clarity,understandability,
best combination of expected selection of the optimal set of ratepayer risks,policy impacts, resource capabilities and
costs and variance of costs. resources given the expected environmental risks,and equitable planning flexibility.
combination of costs,risk and distribution of benefits must be
uncertainty. considered.Utilities must develop a
ten-year clean energy action plan for
implementing RCW 19.405.030
through 19.405.050.
Guidelines
Oregon Utah Washington Idaho Wyoming
Basic elements include: IRP will include: Basic elements: Discuss analyses considered Commission IRP guidelines
• Consistent and comparable • Range of forecasts of • A range of forecasts that including: cover:
resource evaluation. future load growth examine the effect of • Load forecast uncertainties. • Sufficiency of the public
• Risk and uncertainty must be economic forces on the • Changes to existing comment process.
• Evaluation es all present consumption of electricity. resources. • Utilitystrategic goals,
considered. and future resources, g g '
• Least cost planning,consistent • An assessment of • Equal consideration of resource planning goals
p S> including demand side, conservation and load demand and supply 1 side and preferred resource
with the long-run public supply side and market,
interest. on a consistent and management,and policies and resources. portfolio.
• Consistent with Oregon and comparable basis. programs to achieve • Contingencies for • Resource need over the
federal en Ore conservation. upgrading,optioning and near-term and long-term
gyp y • Analysis of the role of • Assessment of a wide range of acquiring resources at planning horizons.
• External costs must be competitive bidding generating technologies. optimum times. • Types of resources
considered,and quantified . A plan for adapting to • Assessment of transmission • Report on existing resource considered.
where possible. OPUC different paths as the system capability and stack,load forecast and • Changes in expected
specifies environmental adders future unfolds. reliability.
(Order No.93-695,Docket additional resource menu. resource acquisitions and
• A cost effectiveness • Evaluation of energy supply load growth from the
UM 424). resources(including previous IRP.
• Multi-state utilities should plan methodology.
p transmission and distribution) • Environmental impacts
their generation and • An evaluation of the using"lowest reasonable cost" considered.
transmission systems on an financial,competitive, criteria. • Market purchase
28

PACIFICORP—2023 IRP APPENDIX B—IRP REGULATORY COMPLIANCE
I .
Oregon Utah Washington M Idaho Wyoming
integrated-system basis. reliability and operational • Resource adequacy metrics. evaluation.
• Construction of resource risks associated with • Energy and nonenergy • Reserve margin analysis.
portfolios over the range of resource options,and how benefits and reductions of • Demand-side
identified risks and the action plan addresses burdens to vulnerable management and
uncertainties. these risks. populations and highly conservation options.
• Portfolio analysis shall include • Definition of how risks are impacted communities;health
fuel transportation and allocated between and environmental benefits,
costs,and risks.
ratepayers and shareholders
transmission requirements. • Long-range plan(10+years).
• Plan includes conservation • Progress report compared to
potential study,demand the previously filed plan.
response resources,environmental costs,and • Clean energy action plan for
distributed generation implementing RCW
technologies. 19.405.030 through
19.405.050.
• Avoided cost filing required • Summary . changes to
within 30 days of modeling methodologies or
acknowledgment. inputs compared to the utility's
• IRP includes a description of previous IRP.
the electric company's plan for • Analysis and summary of
meeting the requirements of
the renewable portfolio avoided costs;list of
standard. nonenergy costs and benefits
and how they accrue.
• Summary of public comments
and utility responses.
29

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Table B.2 —Handling of Previous IRP Acknowledgments and Other IRP Requirements
Reference Requirement or Recommendation 2025 IRP Approach
Order No. 35514 p. 17 •• we encourage the Company to continue As a consequence of changing exogenous risks,new natural gas resources are included
exploring an approach in its IRP process that for selection in the 2025 IRP.
allows for a reasonable and accurate selection
of cost-effective natural gas resources in a
portfolio.
Order No. 35514 p. 17 Finally,we acknowledge the inherent In this cycle,Natrium is anticipated to come online in the fall of 2031 (modeled as
complexities with the Natrium project and 1/l/2032).Consistent with the 2023 IRP,the 2025 IRP includes variant analysis with no
direct the Company to continue to assess the Natrum project as described in Chapters 8 and 9,designed to inform alternative path
risks of technology viability and potential analysis and potential costs and benefits.PacifiCorp continues to evaluate nuclear
delays with Natrium and plan accordingly. resources within the context of an evolving planning environment.
Order 35977 p.3 ...the Company explained that it expects that For the 2025 IRP,PacifiCorp meets these expectations with the inclusion of WRAP
its 2025 IRP will include discussion of the compliance,planning reserve margin and resource requirements as described in
impacts of WRAP compliance and will include Chapters 6,7 and 8.
appropriate modeling of planning reserve
margin and resource requirements.
0 1 1:" no"
Reference Requirement or Recommendation 2025 IRP Approach
Order No.22-178,p. 13 In order to connect new resources to the grid, IRP modeling accounts for cost,location,total transfer capability and resource enabled
it is critical not only that transmission be built, by transmission options. Options are modeled endogenously,and selections are driven
but that the right transmission be built;the primarily by the need to increase interconnection to allow efficient system transfer and
Commission and stakeholders need to have to serve load.In the 2025 IRP,costs,descriptions,and transfer capabilities are defined,
sufficient information to verify that ratepayers and in addition near-term transfer options are rooted in cluster study and queue analysis
are getting the benefits they are paying for at and informed by surplus resource options which allow for transmission costs to be
each stage of development. Going forward, avoided where appropriate.The transmission option modeling strategy was discussed at
we expect PacifiCorp to provide information three public input meetings spanning May 2,2024 through August 15,2024 with
that allows that assessment at the outset.We opportunities for feedback and recommendations.PacifiCorp also responded to
also expect the company to actively encourage stakeholder comments in stakeholder feedback forms during the public input process.'
key stakeholders like Commission Staff and Also,modeling of small scale renewable resources for both the IRP and CEP assumes
consumer advocates to participate and provide there are no accompanying transmission requirements,providing an additional
'See Appendix M,stakeholder feedback form#17(OPUC),stakeholder feedback form#17(OPUC), stakeholder feedback form#40(RNW).
30

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement or Recommendation 2025 IRP Approac
a larger window into its own transmission opportunity to evaluate transmission avoidance beyond the native core functionality of
planning processes. the PLEXOS model. See Chapter 4(Transmission),and Chapter 8(Modeling and
Portfolio Evaluation).
Order No.22-178,p. We expect PacifiCorp to engage in the PacifiCorp,in April 2023,completed an Economic Study Request("ESR"),submitted
15;Appx B p. 1 company's local transmission planning by the Oregon Public Utility Commission("OPUC")Staff to have PacifiCorp evaluate
process as appropriate and to request that the effects of 1.0 GW of Offshore Wind(OSW)generation in southern Oregon,assumed
sufficient information to inform to be interconnected to PacifiCorp's Del Norte substation located in Del Norte,
consideration of offshore wind in future IRPs California.PacifiCorp participated in the Technical Focus Group for the October 2023
is made available in this local transmission Northern California and Southern Oregon Offshore Wind Transmission Study led by
study cycle. Schatz Energy Research Center and is Contributor in the U.S.Department of Energy led
West Coast Offshore Wind Transmission Study,currently underway as of 2025.These
efforts inform both the local transmission plan and transmission modeling options
available to the IRP model.
Order No.22-178,p. PacifiCorp to provide a map of resources in This requirement is met by the preferred portfolio map provided in Appendix I
18;Appx B p. 1 the IRP Executive Summary,which (Capacity Expansion Results).
PacifiCorp agrees to do.
Order No.22-178, In future IRPs or during future RFP processes, Following the completion of the 2021 IRP and in advance of bid submissions in the 2022
Appx B p.2 potential RFP bidders should be given access All-Source RFP,PacifiCorp prepared the requested information and provided it to
to a 12x24 Loss of Load Probability matrix for stakeholders in its January 25,2022,filing in docket UM 2011.Following the
one out of every five years in the IRP planning completion of the 2025 IRP,PacifiCorp will develop comparable information for use in
timeframe. future RFP processes.
Order No.24-073 Direct PacifiCorp to provide specific baseline PacifiCorp anticipates including any available and applicable baseline metrics for its
metrics in the 2025 IRP/CEP to allow for community benefit indicators(CBIs)goals in its forthcoming 2025 Clean Energy Plan.
measured progress towards CBI goals.
Order No.24-073 In the 2025 IRP/CEP,direct PacifiCorp to For the 2025 IRP,Natrium assumptions have been updated to the extent possible as
update Natrium assumptions to reflect actual described in Chapter 7(Resource Options).
events.
31

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
ijthe�
Reference Requirement or Recommendation 2025 IRP Approac
Order No.24-073 In the 2025 IRP/CEP model,PacifiCorp must: 25 IRP,each jurisdiction's resources are optimally selected in compliance with
(1)demonstrate that simultaneous compliance its unique requirements and then integrated into the preferred portfolio.Existing
with all state-level policies is feasible with the resources are assumed to be allocated consistent with what is currently approved in each
least-cost,least-risk Preferred Portfolio and states'rates for cost-allocations.Proxy resource selections,as they are driven by a
with the Preferred Portfolio variants tested in jurisdictions' specific need and obligations,are generally assumed to be situs cost
the IRP under multiple allocations. allocated.Allocation strategies were not used to demonstrate compliance with HB 2021
in the creation of the preferred portfolio.Additional cost-allocation strategies or variants
will be tested in the 2025 CEP.
Order No.24-073 In the 2025 IRP/CEP,PacifiCorp shall include In the 2025 IRP,this requirement is met through the base assumptions of the medium
an analysis of forecasted costs and annual gas price/no carbon price(MN)scenario.PacifiCorp also models other price-policy
emissions of the Preferred Portfolio using only scenarios considering alternative carbon price futures.
actual carbon prices in effect in 2025 through
the 20-year planning horizon.
Order No. 24-073 In the 2025 IRP/CEP,PacifiCorp shall The base or`expected' case assumption in the 2025 IRP for the preferred portfolio and
calculate and report the costs and GHG all variants has no GHG cost adder for Oregon(and system)resource selections or
emissions associated with each portfolio dispatch.Other jurisdictions'modeling requirements include GHG emissions as a cost-
assuming that GHG prices are not reflected in adder for the selection of their resources.Other price policies(as indicated by their
dispatch decisions but still included in names)may have GHG emissions costs which impact dispatch,but these portfolios are
investment and retirement decisions. for analytics and not selectable as the preferred portfolio.
Order No.24-073 In the 2025 IRP/CEP PacifiCorp shall provide The 2025 IRP provides an expanded explanation of resource cost determinations and
an explanation of renewable cost assumptions data sourcing. See Chapter 7(Resource Options).
and a comparison to recent pricing
information from such organizations as
National Renewable Energy Lab and Lazard.
Order No.24-073 In the 2025 IRP/CEP,PacifiCorp shall PacifiCorp updated coal costs and assumptions in September 2024 leveraging the most
confirm that coal generator cost assumptions current future cost and performance estimates available to the company.Any items
reasonably reflect the structure and terms of which are based on generation(fuel,emissions,variable O&M etc.)have been confirmed
any associated fuel supply agreements or fuel with subject matter experts for accuracy.
supply plans.Categorize variable costs that
affect dispatch as variable costs in the model
with as much accuracy as reasonably possible.
32

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i 1 � � 1
Reference Requirement or Recommendation 2025 IRP Approac
Order No.24-073 In the 2025 IRP/CEP PacifiCorp shall report As in the 2023 IRP and 2023 IRP Update,all workpaperlforgranularity/reliability
on steps that the Company took to reduce the adjustments are included in the 2025 IRP workpaper filing. PacifiCorp engaged with
magnitude of reliability and granularity stakeholders regarding granularity/reliability adjustments in five public input meetings
adjustments,how the Company engaged with spanning January 25,2024 through September 25,2024.PacifiCorp also provided
stakeholders on adjustments,and describe the additional detail in response to stakeholder feedback forms.'
methodology and report the resulting
reliability and granularity adjustments by The enhancements of the iterative approach to modeling have led to more efficient
resource.Include any supporting work papers model outcomes.All resources included in jurisdictional portfolios were endogenously
demonstrating the granularity/reliability selected by the model,and the integrated portfolios only include resources selected in the
adjustments in the Data Disk. best of the compliant jurisdictional portfolios.
Order No.24-073 In the 2025 IRP/CEP PacifiCorp shall provide PacifiCorp has been selected for a$3.52 billion conditional DOE federal loan through
an update on PacifiCorp's efforts to secure Project WIRE to support multiple transmission projects across four states,benefiting
Energy Infrastructure Reinvestment(EIR) customers in California,Idaho,Oregon and Utah.'
financing from the DOE Loan Program
Office.Assume EIR financing through the The High IRA adoption sensitivity fulfills the study request in this order.
DOE Loan Program Office in the Preferred
Portfolio or include a variant portfolio that
optimizes resource additions and retirements
under the assumption of EIR financing.
Order No.24-073 Acknowledge updated avoided costs from the PacifiCorp's November 2024 energy efficiency avoided cost submittal in docket UM
2023 IRP planning and direct PacifiCorp to work 1893 included incremental value associated with the need for clean energy resources for
with Staff and Stakeholders to update avoided compliance with HB 2021.PacifiCorp's submittal in response to Staffs proposal for
costs for use in UM 1893 considering HB 2021 qualifying facility avoided costs in docket UM 2000 also includes incremental value
constraints. related to HB 2021.PacifiCorp expects this concept to be further developed in its 2025
CEP,and to continue to evolve as it applied in specific programs and rates.
Order No.24-297 PacifiCorp's next Clean Energy Plan filing must The 2025 IRP,Appendix P includes a near-term action plan to work towards meeting
contain an executable action plan. Oregon states obligations and HB 2021 compliance.This near-term action plan will be
executed upon and/or further refined in the 2025 CEP.
Note that`data disk' is a carry-over from the days of providing physical media,and Pacific is transitioning to refer to public,confidential and highly confidential
workpapers'.
a Refer to Appendix M,stakeholder feedback form#17(OPUC)and stakeholder feedback form#36(Sierra Club).
'PacifiCorp Lands$3.5B Federal Loan for Transmission Projects in Four States I Clearing Up I newsdata.com
33

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement or Recommendation 2025 IRP Approach
HB 3162,ORS IRP includes a description of the electric See Appendix R(Renewable Portfolio Implementation Plan).
469A.075 company's plan for meeting the requirements of
the renewable portfolio standard
i
Reference Requirement or Recommendation 2025 IRP Approach
Docket No. 90-2035-01 The forecasts will be made by jurisdiction and by general class PacifiCorp's load forecast is developed for each jurisdiction and by
p.33-37 and will differentiate energy and capacity requirements.The customer class.Further,this forecast includes off-system wholesale
Company will include in its forecasts all on-system loads and customers for which the Company has a contractual obligation to
those off-system loads which they have a contractual obligation fulfill.To plan for non-firm off-system customer impacts returning to
to fulfill.Non-firm off-system sales are uncertain and should not PacifiCorp's system, 1-year and 3-year option direct access customers
be explicitly incorporated into the load forecast that the utility in Oregon are incorporated into the forecast assuming they will return
then plans to meet.However,the Plan must have some analysis once their opt-out period expires.
of the off-system sales market to assess the impacts such
markets will have on risks associated with different acquisition
strategies.
Docket No. 90-2035-01 Analyses of how various economic and demographic factors, PacifiCorp has evaluated these market conditions to inform a least-
p.33-39 including the prices of electricity and alternative energy sources, cost,least-risk preferred portfolio outcome.Changes to consumer
will affect the consumption of electric energy services,and how behavior are also outlined under the suite of existing demand-side
changes in the number,type and efficiency of end-uses will management,energy efficiency and load forecast projections at the
affect future loads. disposal of the Company.
Docket No. 90-2035-01 An evaluation of all present and future resources,including PacifiCorp has included a wide range of potential resource options
p.33-39 future market opportunities(both demand-side and supply-side), within its supply-side table and has included reasonable cost estimates
on a consistent and comparable basis. for all resource types.Where costs and operating characteristics are
similar,as with different lithium-ion chemistries,the IRP does not
attempt to differentiate.Differences in performance are expected to be
well within the normal range of offers from bidders.Even non-emitting
peaking and nuclear resources are ultimately proxies for their particular
combinations of costs,operating characteristics,and risks.Many types
of risks are expected to evolve over the next few planning cycles
including risks associated with these new technologies,and those
associated with emitting technologies.
34

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement or Recommendation 20 ,5 IRP Approach
Docket No. 90-2035-01 An assessment of all technically feasible and cost-effective PacifiCorp has evaluated all technically feasible and cost-effective
p.33-37 improvements in the efficient use of electricity,including load energy efficiency,conservation,and load management through the
management and conservation. Conservation Potential Assessment to compete with other resources in
the IRP modeling.
Docket No. 90-2035-01 An assessment of all technically feasible generating PacifiCorp has evaluated all known technically feasible generating
p.33-39 technologies including:renewable resources,cogeneration, technologies including renewable resources,cogeneration,and the
power purchases from other sources,and the construction of construction of thermal resources. The IRP does not represent ownership
thermal resources. structures for proxy resources.Procurement for any resource could result
in a Build Transfer Agreement(BTA),Power Purchase Agreement
(PPA),self-build,or other contract structure.
Docket No. 90-2035-01 The resource assessments should include: life expectancy of the The resource assessments include life expectancy of the resources, the
p.33-39 resources,the recognition of whether the resource is recognition of whether the resource is replacing/adding capacity or
replacing/adding capacity or energy,dispatchability,lead-time energy, dispatchability, lead-time requirements, flexibility, and
requirements,flexibility,efficiency of the resource and efficiency of the resource and opportunities for customer participation.
opportunities for customer participation.
Docket No. 90-2035-01 An analysis of the role of competitive bidding for demand-side Demand side resources are evaluated as part of the IRP modeling to
p.33-39 and supply-side resource acquisitions. evaluate overall competitiveness with other resources.
Docket No. 90-2035-01 A 20-year planning horizon. The 2025 IRP covers a 21-year horizon from 2025 through 2045.This
p.33-39 is an exception to the standard coverage requirement of 20 years and
was extended in this cycle to meet a 2045 requirement pertaining to
Washington Docket UE-210829,Order 06.
Docket No. 90-2035-01 A two-year action plan outlining the specific resource decisions This requirement is met in Chapter 10(Action Plan).
p.33-39 intended to implement the integrated resource plan in a manner
consistent with the Company's strategic business plan.
Docket No. 90-2035-01 An action plan outlining the specific resource decisions intended This requirement is met in Chapter 10(Action Plan).
p.33-39 to implement the integrated resource plan in a manner consistent
with the Company's strategic business plan.The action plan will
span a four-year horizon and will describe specific actions to be
taken in the first two years and outline actions anticipated in the
last two years.The action plan will include a status report of the
specific actions contained in the previous action plan.
35

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Referei 6.Requirement or Recommendation 3 2025 IRP Approach
Docket No. 90-2035-01 Load forecasts integrated with resource options in a manner Modeling for the 2025 IRP incorporates multiple load forecasts and
p.33-39 which rationalizes the choice of resources under a variety of price-policy scenarios under which resources compete on an optimized
economic circumstances. basis for the selection of resource options,retirements,unit conversions,
transmission options,market purchases and sales,and other elements.
See Chapters 7, 8 and 9.
Docket No. 90-2035-01 A plan of different resource acquisition paths for different PacifiCorp presents its alternative path analysis in Chapter 10(Action
p.33-39 economic circumstances with a decision mechanism to select Plan).
among and modify these paths as the future unfolds.
Docket No. 90-2035-01 An evaluation of the cost-effectiveness of the resource options PacifiCorp's 2025 IRP evaluates risk via a risk-adjustment metric based
p.33-39 from a variety of perspectives and society as a whole. on stochastic modeling results,provides a set of competitive variant
portfolios,and includes studies assuming a social cost of greenhouse gas
cost-adder as a price-policy scenario.
Docket No. 90-2035-01 An evaluation of the risks associated with various resource PacifiCorp's 2025 IRP evaluates risk via a risk-adjustment metric based
p.33-39 options and how the action plan addresses these risks in the on stochastic modeling results and includes a Business Plan sensitivity.
context of both the Business Plan and the 20-year Integrated The 2025 IRP will be used to inform the Business Plan.
Resource Plan.
Docket No. 90-2035-01 An evaluation of the financial,competitive,reliability,and The 2025 IRP endogenously evaluates the attributes of competing
p.33-39 operational risks associated with various resource options and resource options through its input data,which is reflective of the costs,
how the action plan addresses these risks in the context of both operational characteristics,technology type,location,interconnection
the Business Plan and the 20-year Integrated Resource Plan.The availability and other factors.In addition,the RFP non-price scoring
Company will identify who should bear such risk,the ratepayer process evaluates,in coordination with several independent evaluators
or the stockholder. representing three states,the project and reliability risks and scores these
results accordingly.The assumptions in the Business Plan and 20-year
Integrated Resource Plan are ultimately modified and realized through
actual generating projects that are either owned or under contract and
represent ratepayer risk,not shareholder risk,except to the extent that
the commitments or actions of the Company are deemed imprudent in a
future ratemaking proceeding.During RFP procurements,the terms of
contracts are also reviewed by independent evaluators and are available
and submitted to regulatory staff upon request or by order or statute.
These contracts include performance guarantees to balance the risk
between the project owner and the Company on behalf of ratepayers.
36

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement or Recommendation 2025 IRP Approach
Docket No. 90-2035-01 Considerations permitting flexibility in the planning process so PacifiCorp assesses the potential value of resources against risk and the
p.33-39 that the Company can take advantage of opportunities and can expense of time and resources in the development of its supply side
prevent the premature foreclosure of options. resources.The 2025 IRP public input process included materials and
discussion of supply side resources in six meetings spanning January
2024 through September 2024.Resources were a topic of interest in
numerous stakeholder feedback forms submitted during the 2025 IRP
development process.Refer to Appendix M for a full list of publicly
available feedback and responses.
Docket No. 90-2035-01 An analysis of tradeoffs;for example,between such conditions The 2025 IRP inherently evaluates trade-offs between reliability and
p.33-39 of service as reliability and the acquisition of lowest cost resource cost,as well as operational costs incurred during dispatch as
resources. part of the core functionality of optimization modeling.Additional
analysis is provided in narrative form where salient trade-offs are
indicated in portfolio outcomes. See Chapter 9(Modeling and Portfolio
Selection Results).
Docket No. 90-2035-01 A range,rather than attempts at precise quantification,of Future environmental and safety regulation has an almost unfathomable
p.33-39 estimated external costs which may be intangible,in order to potential range of outcomes,many of which may be contradictory with
show how explicit consideration of them might affect selection other rules or policy goals,as in restrictions on non-emitting resources.
of resource options. The Company will attempt to quantify the What is certain,is that compliance may involve costs dramatically in
magnitude of the externalities,for example,in terms of the excess of even the social cost of greenhouse gases price-policy
amount of emissions released and dollar estimates of the costs of scenario.As an example,coal ash handling and water treatment is only
such externalities. partly related to ongoing operations,but the costs could offset years of
possible operational benefits depending on the circumstances.
Environmental and safety regulation is not limited to fossil fuel
resources,a few very basic examples include:
Very few battery chemistries have significant history in utility-scale
operations,and some examples of fire hazards have been identified.
Wind turbines present risks related to birds and bats.
Cadmium telluride solar panels include two toxic chemicals,which
while significantly less harmful in compound form,do not have well
documented long-term effects.
The above is not intended to be comprehensive-all technologies have
trade-offs and risks though some technologies have more unknown
unknowns than others.The largest externality of which the Company is
currently aware is the impact of greenhouse gases on the climate.A
37

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement or Recommendation 20 ,5 IRP Approach
price-policy scenario with an estimate of the social cost of greenhouse
gases is used to quantify that particular externality,and analysis
including those costs is presented for the preferred portfolio and
selected variant portfolios.
Docket No. 90-2035-01 The public,state agencies and other interested parties will have PacifiCorp will participate fully in the described process.
p.33-39 the opportunity to make formal comment to the Commission on
the adequacy of the Plan. The Commission will review the Plan
for adherence to the principles stated herein and will judge the
merit and applicability of the public comment.If the Plan needs
further work the Commission will return it to the Company with
comments and suggestions for change. This process should lead
more quickly to the Commission's acknowledgement of an
acceptable Integrated Resource Plan.The Company will give an
oral presentation of its report to the Commission and all
interested public parties.Formal hearings on the
acknowledgement of the Integrated Resource Plan might be
appropriate but are not required. 7.Acknowledgement of an
acceptable Plan will not guarantee favorable ratemaking
treatment of future resource acquisitions.
Docket No.21-035-09, PacifiCorp must comply with Guidelines 4(b)and 4(i)by not The 2025 IRP included natural gas resource options,which had been
UPSC June 2,2022 constraining its model to preclude selection of new natural gas excluded in the 2021 IRP and restricted in the 2023 IRP.
Order p. 5-8 resources
Docket No.21-035-09, PacifiCorp will provide information to stakeholders three PacifiCorp consistently provided meeting materials to stakeholders via
UPSC June 2,2022 business days in advance of public meetings email and public website postings within the parameters of this
Order p.9-18 requirement. See Appendix C(Public Input).
Docket No. 90-2035-01 The Integrated Resource Plan will be used in rate cases to PacifiCorp is compliant with this standard.
p.33-37 evaluate the performance of the utility and to review avoided
cost calculations.
Docket No.23-035-10 For the 2025 IRP cycle,PacifiCorp shall: Not applicable to the 2025 IRP.
p. 15 1)incorporate all model inputs into the model by September 1,
2024; This requirement was suspended on September 24,2024 for the 2025
IRP cycle,which was scheduled and well under way by the time of the
original Order.The 2025 IRP has been developed on its previously
38

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
3
Reference Requirement or Recommendation 2025 IRP Approac
__
2)reveal modeling results up to and including the ranking of the updated schedule which had already been compressed and adapted to
portfolios at a PIM to be held on or before October 15,2024.If allow for a draft filing,which was distributed on December 31,2024.
new model inputs cannot be incorporated into the model without
jeopardizing compliance with this deadline,PacifiCorp must Under this schedule,data was locked down at the end of September,and
wait to incorporate the late-breaking data until the 2025 IRP draft results provided in the December draft filing,with discussion of
Update; feedback scheduled for two public input meetings held January 22-23,
3)hold a subsequent PIM to present updated modeling results 2025,and February 25-26,2025.
and the preferred portfolios to stakeholders,by no later than
November 15,2024;and,
4)file a preliminary IRP with the PSC by January 1,2025.
Docket No.23-035-10 PacifiCorp shall not make changes to the modeling assumptions This order requires that for Utah,subsequent corrections and updates are
IRP Timing Order used to produce the modeling results it intends to disclose on not available for further development of the IRP,and consequently the
January 1,2025,after disclosure of those modeling results.Any IRP filed in Utah will differ from the version files in other jurisdictions.
new or changing model inputs that cannot be incorporated into Inputs that have remained under development include loads,stochastics,
the modeling results disclosed January 1,2025,must wait to be corrections to supply-side resource data and the Natrium commercial
incorporated into PacifiCorp's 2025 IRP Update. online date.
The Utah 2025 IRP includes three Utah-specific chapters to address the
Order:
• Chapter 11 (Utah Executive Summary)
• Chapter 12(Utah Model Results)
• Chapter 13 (Utah Action Plan)
Docket No.23-035-10 Beginning with the 2027 IRP cycle and beyond,PacifiCorp shall: Not applicable to the 2025 IRP.
p. 15
1)prior to ranking resource portfolios,present indicative
resource portfolios to stakeholders at a PIM at least five months
before the planned filing date of any IRP.If new model inputs
cannot be incorporated into the model without jeopardizing
compliance with this deadline,PacifiCorp must wait to
incorporate the late-breaking data until the subsequent IRP
Update filing:
2)present updated modeling results,including final evaluations
and preferred portfolio selections,to stakeholders at a PIM
meeting to be held at least two months before the planned filing
date of any IRP.
39

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
pReference equirement or Recommendation 2025 IRP Approach
ket UE-210829,Order Transparency Condition 1.PacifiCorp will provide a copy of its Not due until the 2025 CEIP.However,PacifiCorp is streamlining
06 Appendix A:Full Multi- PLEXOS model database files in native file format upon request the process to provide these materials and has confirmed with
Party Settlement by any intervenor with a signed confidentiality agreement, Energy Exemplar that a version of the.xml formatted database can
Agreement,p. 9 subject to relevant and appropriate confidentiality concerns.The be made available on a highly confidential basis in future filings.
compressed version will include the PLEXOS database file(with
a.xml extension)or the functional equivalent,and all data input
files(with.csv extensions),organized using a structure that will
allow a party knowledgeable in PLEXOS to load,execute,and
run the Company's CEIP portfolio model via PLEXOS.
Additionally,PacifiCorp will include a"readme"file with
instructions for how interested parties that are knowledgeable in
PLEXOS can load,execute,and run the compressed CEIP
portfolio model using the PLEXOS long-term capacity
expansion software.PacifiCorp will also file a version of the
same PLEXOS input and output files in an easily accessible
format,such as Excel.Due Date:2025 CEIP.
Docket UE-210829,Order Transparency Condition 2.PacifiCorp will make a meaningful Not due until the 2025 CEIP,however,PacifiCorp's 2025 IRP is
06 Appendix A: Full Multi- effort to review each workpaper file for sensitive commercial committed to transparency and continues the commitments to
Party Settlement information and to the extent reasonable ensure that any non- provide an expanded set of public workpapers in which
Agreement,p. 10 confidential information within a workpaper designated as commercially sensitive data has either been aggregated or removed.
confidential is also provided in a non-confidential workpaper.
With this understanding,PacifiCorp will not file with confidential
designation any information that is not commercially sensitive,
including(but not limited to)information filed with the
Commission in other dockets without confidential designation,
and information reported to the Commission or any other
regulatory body that is reported without confidential designation.
Due Date:2025 CEIP.
40

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
6� = i 1 -Washingto
Reference Requirement or Recommendation 2025 IRP Approach
Docket UE-210829,Order Transparency Condition 3. PacifiCorp's workpaper index will Not due until the 2025 CEIP,however,the 2025 IRP meets these
06 Appendix A: Full Multi- include a parenthetical,naming convention,taxonomy,or other conditions.
Party Settlement description that is intuitive and makes it easy to tell what is in each
Agreement,p. 10 file and how one file connects with another.Due Date:2025
CEIP.
Transparency Condition 5.PacifiCorp will include a read-me tab
at the beginning of each summary report Excel workpaper that
explains what information or data is in each subsequent tab,and
PacifiCorp's workpaper index will crosswalk how that data flows
through to other tabs and other workpapers(i.e.,analytic files)that
may depend on data from the given file.Due Date:2025 CEIP.
Docket UE-210829,Order Transparency Condition 6.PacifiCorp will: (1)fund the purchase PacifiCorp has entered into an agreement with Washington
06 Appendix A:Full Multi- of four(4)full or partial licenses for Staff to use the PLEXOS Commission staff and Energy Exemplar to fulfill a modified
Party Settlement model,including reasonable development,training,and support version of this condition.
Agreement,p. 10 provided by Energy Exemplar to train Staff how contract
negotiations with Energy Exemplar;and(3)provide live PLEXOS
support to Staff regarding PacifiCorp's CEIP modeling,not to
exceed 4 hours each month,that includes but is not limited to,live
demonstration of portfolio runs,and review of file inputs for all
relevant models used in PacifiCorp's CEIP(if relying on screen
shots of PLEXOS files or email question-and-answer support is
not sufficient).This support provided by PacifiCorp shall not
include general PLEXOS development,training,or support. The
parties do not object to the Company seeking full cost-recovery of
these PLEXOS-related licensing costs,expenses,and support.Due
Date: Contract discussions to begin within 60 days of the date of
the Commission's final order in this case.
Docket UE-210829,Order Transparency Condition 7.As part of its CEIP workpapers, Not due until the 2025 CEIP.
06 Appendix A: Full Multi- PacifiCorp will provide a list of all the resources(including
Party Settlement generating units,conservation,demand response,and any other
Agreement,p. 10 resource types)that it allocates to serve Washington customers
throughout that CEIP,the fuel source for each resource,and a
yearly breakdown of the forecasted MWh allocated to Washington
from that resource.Due date:2024 Filing and 2025 CEIP.
Docket UE-210829,Order Incremental Cost Condition 2.The workpapers that PacifiCorp Not due until the 2025 CEIP.
06 Appendix A: Full Multi- supplies to support its incremental cost calculation will list all
41

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i 1I M TIM I I I
Reference Requirement or Recommendation 2025 IRP Approach
Party Settlement investments and expenses that the utility plans to make during the
Agreement,p. 11 period in order to comply with the requirements of RCW
19.405.040 and 19.405.050,and demonstrate that those
investments and expenses are directly attributable to actions
necessary to comply with,or make progress towards,the same
RCW provisions.Due Date:2025 CEIP.
Docket UE-210829,Order Incremental Cost Condition 3.PacifiCorp will participate in any PacifiCorp is not aware of additional discussions or workshops
06 Appendix A: Full Multi- further discussions and/or workshops regarding incremental cost applicable to this requirement.
Party Settlement calculations and incorporate any changes necessary to their
Agreement,p. 11 methodology.Due Date:As applicable.
Docket UE-210829,Order Interim Target Condition 3.PacifiCorp will optimize its resource Not due until the 2025 CEIP,however the 2025 IRP meets this
06 Appendix A:Full Multi- portfolio at lowest reasonable cost,when accounting for risk, requirement by running 21-year models.
Party Settlement using its long-term capacity expansion portfolio optimization
Agreement,p. 12 software(PLEXOS)to model its CEIP targets for the entire
compliance period through 2045,and not linearly interpolate its
2041-2045 targets from its modeling of the 2021-2040 time
period.Due Date:2025 CEIP.
Docket UE-210829,Order Interim Target Condition 4.In future CEIPs,PacifiCorp will Not due until the 2025 CEIP,however this condition is met by the
06 Appendix A: Full Multi- continue to include descriptions of quantitative(i.e.,cost based) IRP analysis and information provided in Appendix O regarding the
Party Settlement and qualitative(e.g.,equity considerations)analyses that support LEAP,including specific discussion of energy equity.
Agreement,p. 12 interim targets to comply with CETA's 2030 and 2045 clean
energy standards.Due Date: 2025 CEIP.
Docket UE-210829,Order Interim Target Condition 5.In its 2025 CEIP,PacifiCorp will Not due until the 2025 CEIP.
06 Appendix A:Full Multi- continue to advance the application of Non-Energy Impacts and
Party Settlement Customer Benefit Indicators to all resource and program selections
Agreement,p. 12 in determining its Washington resource strategy and will
incorporate any guidance given by the Commission on how to best
utilize CBIs in CEIP planning and evaluation.PacifiCorp agrees to
engage and consult with its applicable advisory groups(including
the IRP,demand-side management,and Equity advisory groups)
regarding an appropriate methodology for including NEIs and
CBIs in its resource selection.Due Date: 2025 CEIP.
Docket UE-210829,Order Interim Target Condition 6.PacifiCorp will update its CEIP with Not due until the 2025 CEIP,however the 2025 IRP provides
06 Appendix A: Full Multi- accurate and up-to-date cost information for all its specific actions, sensitivities regarding high and low potential for IRA impacts. See
42

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i 1I M TIM I I I
Reference Requirement or Recommendation 2025 IRP Approach
Party Settlement including incorporating applicable provisions of the Inflation Chapter 8 and 9.
Agreement,p. 12 Reduction Act(IRA).At a minimum,PacifiCorp should
incorporate,from the IRA,assumptions pertaining to bonus tax
credits for replacement generation in"energy communities,"the
availability of low-cost financing from the U.S.Department of
Energy under the Energy Infrastructure Reinvestment(EIR)
program,and make adjustments to the Company's load forecast to
account for the Greenhouse Gas Reduction Fund and the High-
Efficiency Electric Home Rebate Program,if warranted.Due
Date: 2025 CEIP.
Docket UE-210829,Order Miscellaneous Condition 4.PacifiCorp will evaluate methods to Not due until the 2025 CEIP.
06 Appendix A:Full Multi- improve the alignment of the Company's planning and
Party Settlement procurement processes and provide a narrative description of how
Agreement,p. 14 it plans to align the planning and procurement processes in the
2025 CEIP.Due Date:2025 CEIP.
Docket UE-210829,Order Miscellaneous Condition 5.PacifiCorp will incorporate its Not due until the 2025 CEIP,however the 2025 IRP meets this
06 Appendix A: Full Multi- ongoing climate analysis into the 2025 CEIP and future CEIPs. condition with the inclusion of climate change in its base
Party Settlement Due Date:2025 CEIP. assumptions.
Agreement,p. 14
Docket UE-210829,Order Miscellaneous Condition 6.PacifiCorp will prepare a sensitivity Not due until the 2025 CEIP,however the 2025 IRP meets this
06 Appendix A: Full Multi- PLEXOS model run that excludes non-commercialized resources condition with its `no nuclear' and`no future technology'variants,
Party Settlement from the candidate resource list and relies upon clean resources, as described in Chapter 8.
Agreement,p. 14 including offshore wind,demand response,enhanced geothermal,
iron-air batteries or similar long duration storage,and high-
capacity factor solar plus storage(among other resources),to meet
identified reliability gaps.Due Date: 2025 CEIP.
Docket UE-210830,Order During CPA development,demonstrate progress towards
01,Attachment A,condition identifying,researching,and properly valuing NEIs.Docket UE- Starting with the 2021 IRP cycle,PacifiCorp has been discussing
11a 210830,Order 01,Attachment A,condition 1 la with the DSM Advisory Group and EAG its research,findings,and
ongoing progress with NEI. Since that time,PacifiCorp has also
been incorporating NEIs into planning: specifically,the 2023 and
2025 CPAs have both included measure-specific NEI adjustments.
Please see the CPA Appendix E for further information.
WUTC v.Cascade Natural Commission issues preliminary guidance on equity at a high-level, PacifiCorp discusses the four tenets of energy justice in its
43

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
hmm = i 1 -Washingto
Reference Requirement or Recommendation 2025 IRP Approach
Gas Corporation,Docket clarifying definitions and expectations that should be applied to Appendix O: Clean Energy Action Plan and offers a qualitative
UG-210755 Order 09 utility planning and rate making.Integral to this work is the discussion of how these four tenets are applied and exemplified by
(August 23,2022) concept of energy justice and its core tenets to advance the goal of ongoing PacifiCorp actions.
achieving equity in Washington energy regulation.
Reference Requirement or Recommendation 2025 IRP Approach
Order,Docket No. Include a Reference Case based on the PacifiCorp has complied with this requirement by the inclusion of the"Business as Usual"
90000-144-XI-19 2017 IRP Updated Preferred Portfolio, sensitivity.Additional information on the specified reference case can be found in Chapter 8
(Record No. 15280) incorporating updated assumptions,such as and 9.
load and market prices and any known
changes to system resources and using
environmental investments or costs only
required by current law.For example,the
reference case will not include an estimate
or assumed price or cost for carbon
emissions absent an existing legal
requirement.
Order,Docket No. Conduct a more extensive analysis of the The impact of price-policy scenarios on the resource plan is summarized in Chapter 8
90000-144-XI-19 impact of alternative price-policy scenarios (Modeling and Portfolio Evaluation)and Chapter 9(Modeling and Portfolio Selection).
(Record No. 15280) on the resource plan.
Order,Docket No. Conduct a sensitivity analysis on top PacifiCorp has complied with this requirement.All candidate portfolios are evaluated under
90000-144-XI-19 performing portfolio cases and the other price-policies.Additional information on sensitivity analyses can be found within
(Record No. 15280) reference case. Chapter 8(Modeling and Portfolio Evaluation)and Chapter 9(Modeling and Portfolio
Selection).
Order,Docket No. Demonstrate rate impacts over the planning The 2025 IRP includes comparative analysis in Chapter 9 for all cases including the Business
90000-144-XI-19 period between preferred portfolio and the as Usual reference case and the preferred portfolio,using present value revenue requirement
(Record No. 15280) reference case. as indicative of rate pressure.
44

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
iWyoming
eference Requirement or Recommendation 2025 IRP Approach
Order,Docket No. Investigate alternative methodologies to Chapter 5 (Reliability and Resiliency)includes regional analyses of resource adequacy,a
90000-144-XI-19 integrate different reliability analyses discussion of power flow issues caused by baseload resource retirements and how PacifiCorp
(Record No. 15280) including regional analysis of resource Transmission is planning for those retirements,an assessment of weather-related outages,and
adequacy;analysis of power flow issues a discussion of wildfire risk and mitigation.
caused by retiring coal units;study of
potential weather-related outages on
intermittent generation;and an analysis of
wildfire risk.
Order,Docket No. Include additional analysis on operational PacifiCorp has included a description of procurement and operational experience since the
90000-144-XI-19 experience,if any,with battery acquisition previous IRP with battery acquisition and operations as part of Chapter 7(Resource
(Record No. 15280) and operations and include a review of Options).
capabilities learned from other utilities.
Order,Docket No. Include an analysis that demonstrates how PacifiCorp has included Carbon Capture and Sequestration analysis within the portfolio
90000-144-XI-19 the Company will maximize the use of modeling process. Chapter 8(Modeling and Portfolio Evaluation)and Chapter 9(Modeling
(Record No. 15280) dispatchable and reliable low-carbon and Portfolio Selection Results)5
electricity pursuant to H13200.
Order,Docket No. Incorporate an analysis of any agreed upon In 2024,PacifiCorp determined that a negotiated agreement was unlikely given the
90000-144-XI-19 change to the MSP and to the extent there differences in state energy policies and data limitations for parties to compare alternatives.
(Record No. 15280) are outstanding material disagreements PacifiCorp will file a new allocation methodology for approval by all six state commissions
regarding cost allocation at the time of and implementation in 2025.PacifiCorp addresses the multi-state process in Chapter 3.
filing,quantify those risks and potential
impact to Wyoming ratepayers.
Order,Docket No. Include a broader analysis of all generation PacifiCorp has continued to expand and update the generation types included in the supply-
90000-144-XI-19 types including nuclear and natural gas. side table as part of the 2025 IRP.Advanced nuclear and natural gas resources have both
(Record No. 15280) been updated and analyzed in all studies in the 2025 IRP(unless excluded to develop a
specific sensitivity or variant).New to the 2025 IRP is the combined gas plant with
electrolyzer option,and a renewable peaking resource assumed to be fueled by renewable
biodiesel.
Order,Docket No. Include a narrative discussing impacts and PacifiCorp has added this narrative analysis to the Planning Environment discussion in
90000-144-XI-19 regulatory framework for renewable Chapter 3 (Planning Environment).
(Record No. 15280) generation.
Order,Docket No. Include an acknowledgement that each of PacifiCorp acknowledges these requirements and has addressed each within the 2025 IRP.
90000-144-XI-19 these requirements are Addressed in the
(Record No. 15280) 2025 IRP to ensure compliance.
45

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
i 1
Reference Requirement or Recommendation 2025 IRP Approach
D.18-02-018 Addressing Disadvantaged Communities PacifiCorp serves fewer than 50,000 customers Imostlyal
northern California,with a significant number of customers on energy
D.22-02-004 Provide supplemental information about disadvantaged communities, assistance programs.PacifiCorp's California customers are
including"a demonstration of how disadvantaged communities were geographically-dispersed,with approximately four customers per
Public Utilities Code§§ considered."(D.18-02-018,p. 135.) square mile.10
399.13(a)(7),454.5,
454.52 "PacifiCorp is required to supplement its multi-state IRP with ... PacifiCorp is committed to affordability to protect disadvantaged
specific information on ... a separate demonstration that satisfies the
requirements for disadvantaged communities."(D.22-02-004,p.22.) communities.In PacifiCorp's most recent general rate case filed with
the California Public Utilities Commission,the company requested
"At a minimum,all LSEs shall provide the following information in recovery of costs associated with the addition of investments in
their IRPs: renewable generation resources. Those resources reduce overall
i.A description of which disadvantaged communities,if any,it serves emissions and provide zero-fuel cost energy and production tax credits
(LSEs will be expected to make the determination of what is that benefit our customers.PacifiCorp also proposed an increase to its
considered"disadvantaged"every two years); California Alternative Rates for Energy discount from 20 percent to
ii.What current and planned LSE activities/programs,if any,impact 25 percent,new time varying rate options,and paperless bill credit,
disadvantaged communities;and among other changes,to support customers during increased costs for
iii.A qualitative description of the demographics of the customers it wholesale energy and wildfire mitigation.
serves and how it is currently addressing or plans to comply with the
requirement to minimize air pollutants."(D.18-02-018,p. 68.) In 2024,PacifiCorp transitioned its Home Energy Savings residential
If we wish to provide additional information,we can address how energy efficiency program from a resource acquisition program to an
PacifiCorp is: equity program targeting Hard-to-Reach and Tribal customers.In
• strengthening"the diversity,sustainability,and resilience addition,PacifiCorp filed an advice filing requesting approval to offer
of the bulk transmission and distribution systems,and local Home Energy Reports as an equity program targeting only Hard-to-
communities."(D.18-02-018,p. 66;Pub.Util. Code§ Reach and Tribal customers.
454.52.)
• minimizing"localized air pollutants and other greenhouse PacifiCorp IRP identifies increased investment in non-emitting
gas emissions,with early priority on disadvantaged resources to service all of its customers.Further,PacifiCorp does not
communities."(D.18-02-018,p. 66;Pub.Util. Code§ own or operate any thermal generation in California that would
454.52.) negatively impact communities in the California service area.
• giving"preference to renewable energy projects that
10 SB 535 Disadvantaged Communities I OEHHA(ca. oovv�
46

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i California
Reference Requirement or Recommendation 2025 IRP Approach
provide environmental and economic benefits to
communities afflicted with poverty or high unemployment,
or that suffer from high emission levels of toxic air
contaminants,criteria pollutants,and greenhouse gases."
(D.18-02-018,p.67;Pub.Util.Code§ 399.13(a)(7).)
In soliciting bids for new gas-fired generating units,PacifiCorp should
"actively seek bids for resources that are not gas-fired generating units
located in communities that suffer from cumulative pollution burdens,
including,but no[sic] limited to,high emission levels of toxic air
contaminants,criteria air pollutants,and greenhouse gases."(D.18-02-
018,p. 67;Pub.Util. Code§454.5(b)(9)(D).)
D.19-04-040 GHG Emissions Accountine PacifiCorp met with CPUC staff in 2020 and agreed upon an alternative
methodology to address GHG benchmarks using the company's IRP.
D.22-02-004 "PacifiCorp should consult with Commission staff and describe an This methodology has been used and approved in subsequent IRP
alternative [to the CNS/CSP Calculator]methodology that addresses filings.
ALJ Ruling Finalizing its share of the 2030 GHG emissions reduction responsibility."(D.19-
Load Forecasts and 04-040,p.74.) PacifiCorp's IRP supplement will include the results of the emissions
Greenhouse Gas forecast in California,relative to the Company's GHG Benchmark.
Emissions Benchmarks "PacifiCorp is required to supplement its multi-state IRP with ...
for 2022 Integrated specific information on ... another(non-CSP calculator)method to
Resource Plan Filings fulfill requirements that would otherwise have required the CSP tool
and justification for the choice."(D.22-02-004,p.22.)
PacifiCorp's GHG benchmarks are available here:
https://www.gpuc.ca.gov/-/media/gpuc-website/divisions/energy-
division/documents/integrated-resource-plan-and-lon -tg erm-
procurement-plan-irp-ltpp/2022-irp-cycle-events-and-materials/2022-
final-ghc-emission-benchmarks-for-lses public.xlsx
47

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Table 13.3 —Oregon Public Utility Commission IRP Standards and Guidelines
01
1. Substantive Requirements
Reference Requirement 2025 IRP Approach
La.1 All resources must be evaluated on a consistent and PacifiCorp considered a wide range of resources including renewables,demand-side
comparable basis: management,energy storage,power purchases,thermal resources,and transmission.Chapter 4
All known resources for meeting the utility's load (Transmission Planning),Chapter 7(Resource Options),and Chapter 8(Modeling and Portfolio
should be considered,including supply-side Evaluation)document how PacifiCorp developed these resources and modeled them in its
options which focus on the generation,purchase and portfolio analysis.All these resources were established as resource options in the company's
transmission of power—or gas purchases, capacity expansion optimization model,PLEXOS,and selected by the model based on load
transportation,and storage—and demand-side requirements,relative economics,resource size,availability dates,and other factors.The
options which focus on conservation and demand supply-side resources were presented and discussed at five public input meetings at various
response. stages of development spanning nine months,and public materials were provided online for
examination and discussion.
La.2 All resources must be evaluated on a consistent and All portfolios developed with PLEXOS were subjected to stochastic representation.These
comparable basis: portfolios contained a variety of resource types with different fuel types(coal,gas,biomass,
Utilities should compare different resource fuel nuclear fuel,"no fuel"renewables),lead-times(ranging from front office transactions to nuclear
types,technologies,lead times,in-service dates, plants),in-service dates,operational lives,and locations. See Chapters 7-9,and Appendix I and
durations and locations in portfolio risk modeling. Appendix J.
La.3 All resources must be evaluated on a consistent and PacifiCorp fully complies with this requirement.The company developed generic supply-side
comparable basis: resource attributes based on a consistent characterization methodology.For Supply Side
Consistent assumptions and methods should be used Resources(SSR's),the National Renewable Energy Laboratory(NREL)Annual Technology
for evaluation of all resources. Baseline(ATB)was used as much as possible to maintain consistency.Most of the supply-side
resource options rely on the ATB and Energy Information Agency(EIA)reports. Some
SSR's contained in the SSR tables are not listed in the ATB,but were developed through other
reports,conversations with industry experts,developers and original equipment manufacturers
(OEM's).For demand-side resources,the company used the Applied Energy Group's supply
curve data developed for this IRP for representation of DSM resources.The study was based on
a consistently applied methodology for determining technical,market,and achievable DSM
potentials.All portfolio resources were evaluated using the same sets of price and load forecast
inputs.These inputs are documented in Chapter 6(Load and Resource Balance),Chapter 7
(Resource Options),and Chapter 8(Modeling and Portfolio Evaluation)as well as Appendix D
(Demand-Side Management).
48

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
1 • � i � . um,Lau,
1. Substantive Requirements
Reference Requirement 2025 IRP Approach
1.a.4 All resources must be evaluated on a consistent and PacifiCorp applied its nominal after-tax WACC of 6.77 percent to discount all cost streams.For
comparable basis: The after-tax marginal weighted- construction periods of supply side resources,allowance for funds used during construction
average cost of capital (WACC) should be used to (AFUDC),capital surcharge,and property taxes were applied per standard confidential
discount all future resource costs. Company accounting rules.Care was taken to ensure these costs were not double counted(by
any other assumptions)in the underlying assumptions.
Lb.l Risk and uncertainty must be considered:At a Each of the sources of risk identified in this guideline is treated as a stochastic variable in
minimum,utilities should address the following PacifiCorp's production cost simulation apart from CO2 emission compliance costs,which are
sources of risk and uncertainty: treated as a scenario risk and evaluated as part of a CO2 price assumption and a no CO2,a
1.Electric utilities:load requirements,hydroelectric high CO2,and a social cost of carbon price-policy scenario for specific studies. See Chapter 8
generation,plant forced outages,fuel prices, (Modeling and Portfolio Evaluation)and Chapter 9(Modeling and Portfolio Selection
electricity prices,and costs to comply with any Results).
regulation of greenhouse gas emissions.
1.b.2 Risk and uncertainty must be considered: Utilities Resource risk mitigation is discussed in Chapter 10(Action Plan).Regulatory and financial
should identify in their plans any additional sources of risks associated with resource and transmission investments are highlighted in several areas in
risk and uncertainty. the IRP document,including Chapter 3 (Planning Environment),Chapter 4(Transmission),
Chapter 8(Modeling and Portfolio Evaluation),and Chapter 9(Modeling and Portfolio
Selection Results).
1.c The primary goal must be the selection of a portfolio PacifiCorp evaluated cost/risk tradeoffs for each of the portfolios considered as a candidate to
of resources with the best combination of expected be the preferred portfolio.See Chapter 9(Modeling and Portfolio Selection Results),Chapter
costs and associated risks and uncertainties for the 10(Action Plan),and Appendix I(Capacity Expansion Results)a for the company's portfolio
utility and its customers("best cost/risk portfolio"). cost/risk analysis and determination of the preferred portfolio. See Appendix H(Stochastic
Methodology and Simulation)for a detailed discussion of the historical data used to construct
18 separate stochastic datasets and the performance of every candidate portfolio under a range
of possible conditions.
l.c.l The planning horizon for analyzing resource choices PacifiCorp used a 21-year study period(2025-2045)for portfolio modeling,and a real
should be at least 20 years and account for end levelized revenue requirement methodology for treatment of end effects.
effects.Utilities should consider all costs with a
reasonable likelihood of being included in rates over
the long term,which extends beyond the planning
horizon and the life of the resource.
49

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
1. Substantive Requirements
Reference Requirement 2025 IRP Approach
l.c.2 Utilities should use present value of revenue Chapter 8 (Modeling and Portfolio Evaluation)provides a description of the PVRR
requirement(PVRR)as the key cost metric.The plan methodology.
should include analysis of current and estimated
future costs for all long-lived resources such as
power plants,gas storage facilities,and pipelines,as
well as all short-lived resources such as gas supply
and short-term power purchases.
1.c.3.1 To address risk,the plan should include,at a PacifiCorp compares the average production costs across a random sample of stochastic runs
minimum: to the production costs in normalized runs as the measure of cost variability.For the severity
1.Two measures of PVRR risk: one that measures of bad outcomes,the company calculates the 951h percentile PVRR across the random sample
the variability of costs and one that measures the of stochastic runs and takes 5%of the difference between this PVRR and the PVRR from the
severity of bad outcomes. normalized run and adds it to the risk adjustment calculated for each variant portfolio.
1.c.3.2 To address risk,the plan should include,at a A discussion on hedging is provided in Chapter 10(Action Plan).
minimum:
2.Discussion of the proposed use and impact on
costs and risks of physical and financial hedging.
1.c.4 The utility should explain in its plan how its resource Chapter 9(Modeling and Portfolio Selection Results)summarizes the results of PacifiCorp's
choices appropriately balance cost and risk. cost/risk tradeoff analysis and describes what criteria the company used to determine the best
cost/risk portfolios and the preferred portfolio.
1.d The plan must be consistent with the long-run public PacifiCorp considered both current and potential state and federal energy/pollutant emission
interest as expressed in Oregon and federal energy policies in portfolio modeling.Chapter 7(Modeling and Portfolio Evaluation)describes the
policies. decision process used to derive portfolios,which includes consideration of state and federal
resource policies and regulations that are summarized in Chapter 3 (Planning Environment).
Chapter 9(Modeling and Portfolio Selection Results)provides the results.Chapter 10(Action
Plan)presents an acquisition path analysis that describes resource strategies based on
regulatory trigger events.
50

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
2. Procedural Requirements
Reference Requirement 2025 IRP Approach
2.a The public,which includes other utilities,should be PacifiCorp fully complies with this requirement.Appendix C(Public Input)provides an
allowed significant involvement in the preparation overview of the public input process,all public-input meetings held for the 2025 IRP,and
of the IRP.Involvement includes opportunities to summarizes public input received throughout the 2025 IRP cycle.PacifiCorp also made use of
contribute information and ideas,as well as to a Stakeholder Feedback Form for stakeholders to provide comments and offer suggestions.
receive information.Parties must have an Stakeholder Feedback Forms along with responses and the public-input meeting presentations
opportunity to make relevant inquiries of the utility are included in Appendix M,and also publicly available on PacifiCorp's webpage at:
formulating the plan.Disputes about whether www.pacificorp.com/energy/integrated-resource-plan.html.
information requests are relevant or unreasonably
burdensome,or whether a utility is being properly
responsive,may be submitted to the Oregon PUC
for resolution.
2.b While confidential information must be protected, 2025 IRP Volumes I and II provide non-confidential information used for portfolio
the utility should make public,in its plan,any non- evaluation,as well as other data requested by stakeholders.PacifiCorp also provided
confidential information that is relevant to its stakeholders with non-confidential information to support public meeting discussions via
resource evaluation and action plan. Confidential email and in response to Stakeholder Feedback Forms.Workpapers will be available with
information may be protected through use of a public data.Additionally,workpapers with confidential data will be provided to appropriate
protective order,through aggregation or shielding parties through use of a general protective order.
of data,or through any other mechanism approved
by the Oregon PUC.
2.c The utility must provide a draft IRP for public review PacifiCorp distributed draft IRP materials for external review throughout the process prior to
and comment prior to filing a final plan with the each of the public input meetings and solicited/and received feedback at various times when
Oregon PUC. developing the 2025 IRP.The materials shared with stakeholders at these meetings,outlined in
Appendix C and Appendix M,is aligned with the discussion of materials presented in Volumes
I and II of the 2025 IRP report.
PacifiCorp requested and responded to comments from stakeholders when establishing
modeling assumptions and throughout its portfolio-development process and sensitivity
definitions,and in the 2025 IRP footnoted stakeholder feedback forms to relevant topics
throughout the IRP document.
51

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
3. Plan Filing, Review, and Updates
Reference Requirement L. 2025 IRP Approach i4p
3.a A utility must file an IRP within two years of its previous IRP The 2025 IRP complies with this requirement.
acknowledgment order.If the utility does not intend to take any
significant resource action for at least two years after its next IRP is
due,the utility may request an extension of its filing date from the
Oregon PUC.
3.b The utility must present the results of its filed plan to the Oregon PUC This activity will be conducted following the filing of this IRP.
at a public meeting prior to the deadline for written public comment.
3.c Commission staff and parties should complete their comments and This activity will be conducted following the filing of this IRP.
recommendations within six months of IRP filing.
3.d The Commission will consider comments and recommendations on a This activity will be conducted following the filing of this IRP.
utility's plan at a public meeting before issuing an order on
acknowledgment.The Commission may provide the utility an
opportunity to revise the IRP before issuing an acknowledgment order.
3.e The Commission may provide direction to a utility regarding any Not applicable.
additional analyses or actions that the utility should undertake in its
next IRP.
3.f (a)Each energy utility must submit an annual update on its most Not applicable to this filing;this activity will be conducted following
recently acknowledged IRP.The update is due on or before the the filing of this IRP.
acknowledgment order anniversary date.Once a utility anticipates
a significant deviation from its acknowledged IRP,it must file an
update with the Oregon PUC,unless the utility is within six months
of filing its next IRP.The utility must summarize the update at an
Oregon PUC public meeting.The utility may request
acknowledgment of changes in proposed actions identified in an
update.
52

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
3. Plan Filing, Review, and Updates
Reference Requirement 2025 IRP Approach
3.g Unless the utility requests acknowledgment of changes in proposed Not applicable to this filing;this activity will be conducted following
actions,the annual update is an informational filing that: the filing of this IRP.
• Describes what actions the utility has taken to implement the plan;
• Provides an assessment of what has changed since the
acknowledgment order that affects the action plan to select best
portfolio of resources,including changes in such factors as load,
expiration of resource contracts,supply-side and demand-side
resource acquisitions,resource costs,and transmission availability;
and
• Justifies any deviations from the acknowledged action
plan.
4. Plan Components
Referencler Requirement 2025 IRP Approach
4.a An explanation of how the utility met each of the The intent of this table is to comply with this guideline.
substantive and procedural requirements.
4.b Analysis of high and low load growth scenarios in PacifiCorp developed low,high,and extreme peak temperature(one-in-twenty probability)
addition to stochastic load risk analysis with an load growth forecasts for scenario analysis using the PLEXOS model. The Company
explanation of major assumptions. developed factors incorporating the percentage difference between daily average actual
load and monthly average weather-normalized load for each state and included these
factors in stochastic analysis. See Chapters 6(Load and Resource Balance),Chapter 8
(Modeling and Portfolio Evaluation), Appendix A(Load Forecast),and Appendix H
Stochastics .
4.c For electric utilities,a determination of the levels of See Chapter 6(Load and Resource Balance)for details on annual capacity and energy
peaking capacity and energy capability expected for balances.Existing transmission rights are reflected in the IRP model topologies.Future
each year of the plan,given existing resources; transmission additions used in analyzing portfolios are summarized in Chapter 4
identification of capacity and energy needed to bridge (Transmission)and Chapter 8(Modeling and Portfolio Evaluation).
the gap between expected loads and resources;
modeling of all existing transmission rights,as well as
future transmission additions associated with the
resource portfolios tested.
4.d For gas utilities only. Not applicable.
53

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i R Q11idglines,
4. Plan Components
Reference Requirement 2025 IRP Approach
4.e Identification and estimated costs of all Chapter 7(Resource Options)identifies the resources included in this IRP and provides
supply-side and demand side resource options, their detailed cost and performance attributes.Additional information on energy efficiency
considering anticipated advances in technology. resource characteristics is available in Appendix D(Demand-Side Management
Resources)referencing additional information on PacifiCorp's IRP website.
4.f Analysis of measures the utility intends to take to All portfolios incorporate planning reserve margins modeled after the Western Resource
provide reliable service,including cost-risk tradeoffs. Adequacy Program(WRAP)specifications.The cost-risk tradeoffs of providing reliable
service are examined in stochastic analysis,where portfolios are evaluated under various
load and resource conditions and ranked based on their performance in these conditions.
Refer to Appendix H Stochastics for details of this stochastic analysis.
4.g Identification of key assumptions about the future(e.g., Chapter 8(Modeling and Portfolio Evaluation)describes the key assumptions and
fuel prices and environmental compliance costs)and alternative scenarios used in this IRP.Appendix I(Capacity Expansion Results)includes
alternative scenarios considered. summaries of assumptions used for each case definition analyzed in the 2025 IRP.
4.h Construction of a representative set of resource This IRP documents the development and results of portfolios designed to determine
portfolios to test various operating characteristics, resource selection under a variety of input assumptions in Chapters 8(Modeling and
resource types,fuels and sources,technologies,lead Portfolio Evaluation)and Chapter 9(Modeling and Portfolio Selection Results).
times,in-service dates,durations and general locations-
system-wide or delivered to a specific portion of the
system.
4.i Evaluation of the performance of the candidate portfolios Chapter 9(Modeling and Portfolio Selection Results)incorporates the stochastic portfolio
over the range of identified risks and uncertainties. modeling results as described in Chapter 8(Modeling and Portfolio Evaluation)and
describes portfolio attributes that explain relative differences in cost and risk performance.
4.j Results of testing and rank ordering of the portfolios by Chapter 9(Modeling and Portfolio Selection Results)provides tables and charts with
cost and risk metric,and interpretation of those results. performance measure results,including rank ordering.
4.k Analysis of the uncertainties associated with each See responses to l.b.l and 1.b.2 above.
portfolio evaluated.
4.1 Selection of a portfolio that represents the best See Lc above.
combination of cost and risk for the utility and its
customers.
4.m Identification and explanation of any inconsistencies of This IRP is designed to avoid inconsistencies with state and federal energy policies and
the selected portfolio with any state and federal energy therefore none are currently identified.
policies that may affect a utility's plan and any barriers
to implementation.
54

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i RMr@4TW1 Mi
4. Plan Components
Reference Requirement JL 2025 IRP Approach
4.n An action plan with resource activities the utility Chapter 10(Action Plan)presents the 2025 IRP action plan.
intends to undertake over the next two to four years to
acquire the identified resources,regardless of whether
the activity was acknowledged in a previous IRP,with
the key attributes of each resource specified as in
portfolio testing.
5. Transmission
Reference Requirement 2025 IRP Approach
JL
5 Portfolio analysis should include costs to the utility Resource and transmission costs and attributes are endogenously optimized as part of
for the fuel transportation and electric transmission PLEXOS functionality.Where new resources would require additional transmission facilities,
required for each resource being considered.In the associated costs are factored into the analysis.Fuel transportation costs are also factored
addition,utilities should consider fuel transportation into resource costs.Also,modeling of small-scale renewable resources for both the IRP and
and electric transmission facilities as resource CEP assumes there are no accompanying transmission requirements,providing an additional
options,taking into account their value for making opportunity to evaluate transmission avoidance beyond the native core functionality of the
additional purchases and sales,accessing less costly PLEXOS model. See Chapter 4(Transmission),Chapter 7(Resource Options),and Chapter 8
resources in remote locations,acquiring alternative (Modeling and Portfolio Evaluation).
fuel supplies,and improving reliability.
6. Conservation
Reference 1W Requirement 2025 IRP Approach
6.a Each utility should ensure that a conservation PacifiCorp's conservation potential study is available on the company's webpage,and the
potential study is conducted periodically for its most recent results from the conservation potential assessment have been incorporated into
entire service territory. the IRP modeling process.
6.b To the extent that a utility controls the level of PacifiCorp's energy efficiency supply curves incorporate Oregon resource potential.Oregon
funding for conservation programs in its service potential estimates were provided by the Energy Trust of Oregon. See the demand-side
territory,the utility should include in its action plan resource section in Chapter 7(Resource Options),the results in Chapter 9(Modeling and
all best cost/risk portfolio conservation resources Portfolio Selection Results),the targeted amounts in Chapter 10(Action Plan)and the
for meeting projected resource needs,specifying implementation steps outlined in Appendix D(DSM Resources.
annual savings targets.
55

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
6.c To the extent that an outside party administers See the response for 6.b above.
conservation programs in a utility's service territory
at a level of funding that is beyond the utility's
control,the utility should:
1. Determine the amount of conservation resources
in the best cost/risk portfolio without regard to
any limits on funding of conservation
programs;and
2. Identify the preferred portfolio and action plan
consistent with the outside parry's projection
of conservation acquisition.
C Oregon i . and Guidelines
7. Demand Response
Reference Requirement 2025 IRP Approach
7 Plans should evaluate demand response resources, PacifiCorp evaluated demand response resources(DSM)on a consistent basis with other
including voluntary rate programs,on par with resources.
other options for meeting energy,capacity,and
transmission needs(for electric utilities)or gas
supply and transportation needs(for natural gas
utilities).
Oregon i , iGuidelines
8. Environmental Costs
Reference Requirement 2025 IRP Approach
8.b Testing alternative portfolios against the compliance Chapter 9(Modeling and Portfolio Selection Results)provides the risk adjustments calculated
scenarios:The utility should estimate,under each of for each variant portfolio. Chapter 9 also reports PVRRs for each portfolio that incorporate
the compliance scenarios,the present value revenue end-effect considerations to forecast streams of revenues and costs that occur outside the 21-
requirement(PVRR)costs and risk measures,over year horizon.
at least 20 years,for a set of reasonable alternative
portfolios from which the preferred portfolio is Early retirement and gas conversion alternatives to coal unit environmental investments were
selected.The utility should incorporate end-effect considered in the development of all resource portfolios.A range of compliance scenarios was
considerations in the analyses to allow for also considered,with implications on the allowed lifetime of thermal resources in those
comparisons of portfolios containing resources with scenarios.
economic or physical lives that extend beyond the
planning period.The utility should also modify
56

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
III I1 1 1
8. Environmental Costs
Reference
7VRequirement 2025 IRP Approach
projected lifetimes as necessary to be consistent
with the compliance scenario under analysis.In
addition,the utility should include,if material,
sensitivity analyses on a range of reasonably
possible regulatory futures for nitrogen oxides,
sulfur oxides,and mercury to further inform the
referred portfolio selection.
8.c Trigger point analysis: The utility should identify See Chapter 8(Modeling and Portfolio Evaluation)for a description of initial portfolio
at least one CO2 compliance"turning point" development definitions. Comparative analysis of these case results is included in Chapter 9
scenario,which,if anticipated now,would lead to, (Modeling and Portfolio Selection Results).Also see Appendix P for additional description of
or"trigger"the selection of a portfolio of resources these varying CO2 futures.
that is substantially different from the preferred
portfolio.The utility should develop a substitute
portfolio appropriate for this trigger-point scenario
and compare the substitute portfolio's expected
cost and risk performance to that of the preferred
portfolio—under the base case and each of the
above CO2 compliance scenarios.The utility
should provide its assessment of whether a CO2
regulatory future that is equally or more stringent
that the identified trigger point will be mandated.
8.d Oregon compliance portfolio: If none of the above The 2025 IRP preferred portfolio presents a path that is compliant with all Oregon state
portfolios is consistent with Oregon energy requirements,including HB 2021 greenhouse gas emissions standards.For more in-depth
policies(including state goals for reducing discussion on Oregon compliance,see Appendix P:Oregon Clean Energy Plan Update.
greenhouse gas emissions)as those policies are
applied to the utility,the utility should construct
the best cost/risk portfolio that achieves that
consistency,present its cost and risk parameters,
and compare it to those in the preferred and
alternative portfolios.
57

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
9. Direct Access Loads
Reference Requirement 2025 IRP Approach
9 An electric utility's load-resource balance Oregon Docket UE 267 established a long-term opt-out option for eligible PacifiCorp
should exclude customer loads that are customers.Going forward PacifiCorp will cease planning for customers who elect direct-
effectively committed to service by an access service on a long-term basis(i.e.five-year opt out customers).
alternative electricity supplier.
• � IIII Jilli 11111i
10. Multi-state Utilities
Reference
7- Requirement 2025 IRP Approach
10 Multi-state utilities should plan their generation and The 2025 IRP conforms to the multi-state planning approach as stated in Chapter 2
transmission systems,or gas supply and delivery,on (Introduction)under the section"The Role of PacifiCorp's Integrated Resource Planning".
an integrated system basis that achieves a best The company notes the challenges in complying with multi-state integrated planning given
cost/risk portfolio for all their retail customers. differing state energy policies and resource preferences.
58

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
11. Reliability
Reference Requirement 2025 IRP Approach ME
11 Electric utilities should analyze reliability within See the response to 1.c.3.1 above. Chapter 9(Modeling and Portfolio Selection Results)
the risk modeling of the actual portfolios being walks through the role of reliability,cost,and risk measures in determining the preferred
considered.Loss of load probability,expected portfolio.All portfolios included planning reserve margins modeled after the WRAP
planning reserve margin,and expected and worst- specifications.The performance of variant portfolios under adverse conditions was
case unnerved energy should be determined by year evaluated in stochastic analysis.Refer to Appendix H for details of the stochastic analysis.
for top-performing portfolios.Natural gas utilities
should analyze,on an integrated basis,gas supply,
transportation,and storage,along with demand-side
resources,to reliably meet peak,swing,and base-
load system requirements.
Electric and natural gas utility plans should
demonstrate that the utility's chosen portfolio
achieves its stated reliability,cost and risk
objectives.
12. Distributed Generation
Reference Requirement did Mk 2025 IRP Approach
12 Electric utilities should evaluate distributed PacifiCorp contracted with DNV to provide estimates of expected distributed generation
generation technologies on par with other supply- penetration.The study was incorporated in the analysis as a deduction to load. Sensitivities
side resources and should consider,and quantify looked at both high and low penetration rates for distributed generation.The study is
where possible,the additional benefits of included in Appendix L(Distributed Generation Study).
distributed generation.
59

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
13. Resource Acquisition
Reference Requirement 2025 IRP Approach
3111
13.a An electric utility should,in its IRP: Chapter 10(Action Plan)outlines the procurement approaches for resources identified in the
1. Identify its proposed acquisition strategy for each preferred portfolio.
resource in its action plan.
2.Assess the advantages and disadvantages of A discussion of the advantages and disadvantages of owning a resource instead of
owning a resource instead of purchasing power purchasing it is included in Chapter 10(Action Plan).
from another party.
Identify any Benchmark Resources it plans to PacifiCorp has not at this time identified any specific benchmark resources it plans to
consider in competitive bidding. consider in the competitive bidding process summarized in the 2025 IRP action plan.
13.b For gas utilities only. Not Applicable.
egon StandardsandGuidelines
Flexible Capacity Resources
Reference Requirement 2025 IRP Approach
1 Forecast the Demand for Flexible Capacity: The PacifiCorp as met this requirement in Appendix F(Flexible Reserve Study).
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 PacifiCorp as met this requirement in Appendix F(Flexible Reserve Study).
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- ear planning period.
3 Evaluate Flexible Resources on a Consistent and PacifiCorp as met this requirement in Appendix F(Flexible Reserve Study).
Comparable Basis: In planning to fill any gap between
the demand and supply of flexible capacity,the
electric utilities shall evaluate all resource options,
including the use of EVs,on a consistent and
comparable basis.
60

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Table B.4—Utah Public Service Commission IRP Standards and Guidelines
B.4—Utah Standards and Guidelines
Procedural Issues
Reference Requirement 2025 IRP Approach
1 The Commission has the legal authority to promulgate Standards and Not addressed;this is a Public Service Commission of Utah responsibility.
Guidelines for integrated resource planning.
2 Information Exchange is the most reasonable method for developing Information exchange has been conducted throughout the 2023 IRP process.
and implementing integrated resource planning in Utah.
3 Prudence reviews of new resource acquisitions will occur during Not an IRP requirement as the Commission acknowledges that prudence
ratemaking proceedings. reviews will occur during ratemaking proceedings,outside of the IRP process.
4 PacifiCorp's integrated resource planning process will be open to the PacifiCorp's public process is described in Chapter 2(Introduction).Appendix
public at all stages.The Commission,its staff,the Division,the C(Public Input)provides an overview of the public input process,all public-
Committee,appropriate Utah state agencies,and other interested parties input meetings held for the 2025 IRP,and summarizes public input received
can participate.The Commission will pursue a more active-directive throughout the 2025 IRP cycle.PacifiCorp also made use of a Stakeholder
role if deemed necessary,after formal review of the planning process. Feedback Form for stakeholders to provide comments and offer suggestions.
Stakeholder Feedback Forms along with responses and the public-input
meeting presentations are included in Appendix M,and also publicly available
on PacifiCorp's webpage at:www.pacificorp.com/energy/integrated-resource-
lan.html.
5 Consideration of environmental externalities and attendant costs must PacifiCorp used a scenario analysis approach along with cost adders to model
be included in the integrated resource planning analysis. environmental externality costs. See Chapter 8(Modeling and Portfolio
Evaluation)for a description of the methodology employed,including how
COa cost uncertainty is factored into the determination of relative portfolio
performance through a base case planning assumption and other price-policy
scenarios.
6 The integrated resource plan must evaluate supply-side and demand-side Supply,transmission,and demand-side resources were evaluated on a
resources on a consistent and comparable basis. comparable basis using PLEXOS optimization models.Also see the response
to number 4.b.ii below.
7 Avoided cost should be determined in a manner consistent with the Consistent with Utah rules,PacifiCorp determination of avoided costs in
company's Integrated Resource Plan. Utah will be handled in a manner consistent with the IRP,with the caveat
that the costs may be updated if better information becomes available.
8 The planning standards and guidelines must meet the needs of the Utah This IRP was developed in consultation with parties from all state
service area,but since coordination with other jurisdictions is important, jurisdictions and meets all formal state IRP guidelines.
must not ignore the rules governing the planning process already in
lace in other jurisdictions.
61

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
StandardsBA—Utah i
Procedural Issues
Reference Requirement 2025 IRP Approach
9 The company's Strategic Business Plan must be directly related to its Chapter 10(Action Plan)describes the linkage between the 2023 IRP
Integrated Resource Plan. preferred portfolio and 2025 business plan resources. The business plan
portfolio was run consistent with requirements outlined in the Order issued
by the Utah Public Service Commission on September 16,2016,Docket No.
15-035-04.
BA—Utah Standards and Guidelines
Standards and Guidelines
Reference Requirement 2025 IRP Approach
1 Definition: Integrated resource planning is a utility planning process Chapter 8 (Modeling and Portfolio Evaluation)outlines the portfolio
which evaluates all known resources on a consistent and comparable performance evaluation and preferred portfolio selection process,while
basis,to meet current and future customer electric energy services Chapter 9(Modeling and Portfolio Selection Results)chronicles the
needs at the lowest total cost to the utility and its customers,and in a modeling and preferred portfolio selection process.This IRP also addresses
manner consistent with the long-run public interest.The process concerns expressed by Utah stakeholders and the Utah commission
should result in the selection of the optimal set of resources given the concerning comprehensiveness of resources considered,consistency in
expected combination of costs,risk and uncertainty. applying input assumptions for portfolio modeling,and explanation of
PacifiCorp's decision process for selecting top-performing portfolios and
the preferred portfolio.
2 The company will submit its Integrated Resource Plan biennially. The company submitted its last IRP on March 31,2023.PacifiCorp requested
and was granted a 60 day extension of time to file the final 2023 IRP on May
31,2023,in Docket No.23-035-10.The 2025 IRP filing date is March 31,
2025.
3 IRP will be developed in consultation with the Commission,its staff, PacifiCorp's public process is described in Chapter 2(Introduction).A
the Division of Public Utilities,the Committee of Consumer Services, record of public meetings and a summary of feedback and public comments
appropriate Utah state agencies and interested parties.PacifiCorp will is provided in Appendix C(Public Input).
provide ample opportunity for public input and information exchange
during the development of its Plan.
4.a PacifiCorp's integrated resource plans will include: a range of PacifiCorp implemented a load forecast range for both capacity expansion
estimates or forecasts of load growth,including both capacity(kW) optimization scenarios as well as for stochastic variability,covering both
and energy(kWh)requirements. capacity and energy.Details concerning the load forecasts used in the 2025
IRP are provided in Chapter 6 Load and Resource Balance and Appendix
62

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
!31
Standards and Guidelines
Reference Requirement 2025 IRP Approach Jill
A(Load Forecast).
4.a.i The forecasts will be made by jurisdiction and by general class and Load forecasts are differentiated by jurisdiction and differentiate energy and
will differentiate energy and capacity requirements.The company will capacity requirements. See Chapter 6(Load and Resource Balance)and
include in its forecasts all on-system loads and those off-system loads Appendix A(Load Forecast).Non-firm off-system sales are not
which they have a contractual obligation to fulfill.Non-firm off- incorporated into the load forecast.Off-system sales markets are included in
system sales are uncertain and should not be explicitly incorporated IRP modeling and are used for system balancing purposes.
into the load forecast that the utility then plans to meet.However,the
Plan must have some analysis of the off-system sales market to assess
the impacts such markets will have on risks associated with different
acquisition strategies.
4.a.ii Analyses of how various economic and demographic factors, Appendix A(Load Forecast)documents how demographic and price factors
including the prices of electricity and alternative energy sources,will are used in PacifiCorp's load forecasting methodology.
affect the consumption of electric energy services,and how changes in
the number,type and efficiency of end-uses will affect future loads.
4.b An evaluation of all present and future resources,including future Resources were evaluated on a consistent and comparable basis using the
market opportunities(both demand-side and supply-side),on a PLEXOS optimization models for both supply side and demand side
consistent and comparable basis. alternatives.Resource options are summarized in Chapter 7(Resource
Options).Also refer to portfolio outcomes in Chapter 9(Modeling and
Portfolio Selection Results).
4.b.i An assessment of all technically feasible and cost-effective PacifiCorp included supply curves for Demand Response
improvements in the efficient use of electricity,including load (dispatchable/schedulable load control)and Energy Efficiency in its
management and conservation. capacity expansion model.Details are provided in Chapter 7(Resource
Options).
4.b.ii An assessment of all technically feasible generating technologies PacifiCorp considered a wide range of resources including renewables,
including renewable resources,cogeneration,power purchases from cogeneration(combined heat and power),power purchases,thermal
other sources,and the construction of thermal resources. resources,energy storage,and Energy Gateway transmission configurations.
Newly evaluated resources in this IRP include long-term storage options
such as 24-hour Hydrogen storage, 100-hour battery and 20 MW biodiesel
peaking units.Chapters 7(Resource Options)and 8(Modeling and Portfolio
Evaluation)describe the assumptions and process under which PacifiCorp
developed and assessed these technologies and resources.
4.b.iii The resource assessments should include: life expectancy of the PacifiCorp captures these resource considerations in its IRP models.
resources,the recognition of whether the resource is replacing/adding Resources are defined as providing capacity,energy,or both.The DSM
63

PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
MEJ�i Standards and Guidelines
Standards and Guidelines
Reference Requirement 2025 IRP Approach
capacity or energy,dispatchability,lead-time requirements, supply curves used for portfolio modeling explicitly incorporate estimated
flexibility,efficiency of the resource and opportunities for customer rates of program and event participation.The distributed generation study,
participation. modeled as a reduction to load,also considered rates of participation.
Replacement capacity is considered in the case of thermal unit retirements
as evaluated in this IRP,and as an alternative to coal unit environmental
investments.
4.c An analysis of the role of competitive bidding for demand-side and A description of the role of competitive bidding and procurement is
supply-side resource acquisitions provided in Chapter 10(Action Plan).
4.d A 20-year planning horizon. This IRP uses a 20-year study horizon(2023-2042).In the 2025 IRP,this was
expanded to 21 years to capture a requirement particular to this IRP cycle.
4.e An action plan outlining the specific resource decisions intended to The IRP action plan is provided in Chapter 10(Action Plan).A status report
implement the integrated resource plan in a manner consistent with of the actions outlined in the previous action plan(2023 IRP Update)is
the company's strategic business plan.The action plan will span a provided in Chapter 10(Action Plan).
four-year horizon and will describe specific actions to be taken in the
first two years and outline actions anticipated in the last two years. In Chapter 10(Action Plan)Table 10.1 identifies actions anticipated in the
The action plan will include a status report of the specific actions next two-to-four years.
contained in the previous action plan.
4J A plan of different resource acquisition paths for different economic Chapter 10(Action Plan)includes an acquisition path analysis that presents
circumstances with a decision mechanism to select among and broad resource strategies based on regulatory trigger events,change in load
modify these paths as the future unfolds. growth,changes in federal regulation and incentives,and procurement
delays.
4.g An evaluation of the cost-effectiveness of the resource options from PacifiCorp provides resource-specific utility and total resource cost
the perspectives of the utility and the different classes of ratepayers. information in Chapter 7(Resource Options).
In addition,a description of how social concerns might affect cost The IRP document addresses the impact of social concerns on resource cost-
effectiveness estimates of resource options. effectiveness in the following ways:
•Portfolios were evaluated using a range of COz price-policy scenarios.
•A discussion of environmental policy status and impacts on utility
resource planning is provided in Chapter 3 (Planning Environment).
• State and proposed federal public policy preferences for clean energy are
considered for development of the preferred portfolio,which is documented
in Chapter 9,Appendix O and Appendix P.In addition,distinct state filings
also address clean energy.
•Appendix G Plant Water Consumption Stud reports historical water
64

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Mir Standards and Guidelines
Reference Requirement 2025 IRP Approach
consumption for PacifiCorp's thermal plants.
4.h An evaluation of the financial,competitive,reliability,and operational The handling of resource risks is discussed in Chapter 10(Action Plan),and
risks associated with various resource options and how the action plan covers managing environmental risk for existing plants,risk management
addresses these risks in the context of both the Business Plan and the and hedging and treatment of customer and investment risk.Transmission
20-year Integrated Resource Plan.The company will identify who expansion risks are discussed in Chapter 4(Transmission).
should bear such risk,the ratepayer,or the stockholder.
Resource capital cost uncertainty and technological risk is addressed in
Chapter 7(Resource Options).
For reliability risks,stochastic analysis incorporates the historical volatility
of forced outages for existing thermal plants and new conversions,as well
as historical annual volatility in new and existing wind and solar shapes and
existing hydro availability.These risks are factored into the comparative
evaluation of portfolios,and the selection of the preferred portfolio upon
which the action plan is based.
Identification of the classes of risk and how these risks are allocated to
ratepayers and investors is discussed in Chapter 10 Action Plan).
4J Considerations permitting flexibility in the planning process so that Flexibility in the planning and procurement processes is highlighted in
the company can take advantage of opportunities and can prevent the Chapter 7(Resource Options)and Chapter 10(Action Plan).
premature foreclosure of options.
4 J An analysis of tradeoffs;for example,between such conditions of Trade-off analysis including these elements is intrinsic to core model
service as reliability and dispatchability and the acquisition of lowest functionality used to determine and evaluate portfolios in the 2025 IRP.
cost resources. Every portfolio incorporates least-cost,least-risk objectives and provides
outcomes for documenting comparative assessments,as provided in Chapter
9.Key trade-offs include cost,reliability,emissions,market reliance,
integration and reserve requirements,transmission availability,and relevant
differences in technology type,location and timing.
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PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
MEJ�i Standards and Guidelines
Standards and Guidelines
Reference Requirement 2025 IRP Approach
4.k A range,rather than attempts at precise quantification,of estimated PacifiCorp incorporated a range of externality costs for COz and costs for
external costs which may be intangible,to show how explicit complying with current and proposed U.S.EPA regulatory requirements.
consideration of them might affect selection of resource options.The For COz externality costs,the company used scenarios with various
company will attempt to quantify the magnitude of the externalities, compliance requirements to capture a reasonable range of cost impacts.In
for example,in terms of the number of emissions released and dollar addition,sensitivities are included to provide estimates of potential impacts
estimates of the costs of such externalities. that are not or cannot be directly modeled. These modeling assumptions are
described in Chapter 8 (Modeling and Portfolio Evaluation).
4.1 A narrative describing how current rate design is consistent with the See Chapter 3 (Planning Environment).The role of Class 3 DSM(price
company's integrated resource planning goals and how changes in rate response programs)at PacifiCorp and how these resources are modeled in
design might facilitate integrated resource planning objectives. the IRP are described in Chapter 7(Resource Options).
5 PacifiCorp will submit its IRP for public comment,review and PacifiCorp distributed draft IRP materials for external review throughout
acknowledgment. the process prior to each of the public-input meetings and solicited/and
received feedback at various times when developing the 2025 IRP. The
materials shared with stakeholders at these meetings,outlined in Chapter 2
(Introduction),is consistent with materials presented in Volumes I and II of
the 2025 IRP report.Appendix C(Public Input Process)and Appendix M
(Stakeholder Feedback Forms)provide expanded details regarding
engagement for the 2025 IRP.Public-input meetings materials can be
located on PacifiCorp's website at:www.pacificorp.com/energy/integrated-
resource-plan/public-input-process.html.
PacifiCorp requested and responded to comments from stakeholders in
throughout its 2025 IRP process. The company also considered comments
received via Stakeholder Feedback Forms that can be located on
PacifiCorp's website at:www.pacificorp.com/energy/integrated-resource-
plan/comments.html A total of 71 Stakeholder Feedback Forms were
received and responded to during the 2025 IRP public-input process.
6 The public,state agencies and other interested parties will have the Not addressed;this is a post-filing activity.
opportunity to make formal comment to the Commission on the
adequacy of the Plan.The Commission will review the Plan for
adherence to the principles stated herein and will judge the merit and
applicability of the public comment.If the Plan needs further work the
66

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Standards and Guidelines
Reference Requirement 2025 IRP Approach
Commission will return it to the company with comments and
suggestions for change. This process should lead more quickly to the
Commission's acknowledgment of an acceptable Integrated Resource
Plan.The company will give an oral presentation of its report to the
Commission,and all interested public parties.
Formal hearings on the acknowledgment of the Integrated Resource
Plan might be appropriate but are not required.
7 Acknowledgment of an acceptable Plan will not guarantee favorable Not addressed;this is not a PacifiCorp activity.
ratemaking treatment of future resource acquisitions.
8 The Integrated Resource Plan will be used in rate cases to evaluate the Not addressed;this refers to a post-filing activity.
performance of the utility and to review avoided cost calculations.
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PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Washington IRP Requirements
The 2025 IRP aligns with Washington's four-year cadence for filing a full integrated resource plan, inclusive of IRP requirements stemming
from CETA rules. Table B.5 reports CETA requirements for RCW 19.280.030 and WAC 480-100-620 through WAC 480-100-630, per
Commission General Order R-601.
Table B.5—Washington CETA Standards, Rules and Guidelines
VIIFTIVIIJKU
Reference Requirement N 2025 IRP Approach
RCW 19.280.030(3) Incorporate the social cost of greenhouse gases(SCGHG)as PacifiCorp provides a narrative framework outlining carbon price
a cost adder,as required by RCW 19.280.030(3): policy scenario assumptions and nominal electric,natural gas price
(i)Evaluating and selecting conservation policies,programs, inputs and DSM modeling.Refer to Chapter 8(Modeling and Portfolio
and targets;(ii)Developing integrated resource plans and Evaluation).PacifiCorp incorporates the SCGHG into all resource
clean energy action plans;and(iii)Evaluating and selecting decisions for Washington customers.
intermediate term and long-term resource options.
Provide a narrative illustrating step-by-step how the SCGHG
cost adder is applied in modeling logic.
RCW 19.280.030(1)(m) Address how the IRP update meets with the requirement in PacifiCorp's load forecast accounts for zero-emission vehicles using
RCW 19.280.030(1)(m)regarding electric and zero-emission the methods to determine utility impacts described in the Company's
vehicles. Washington Transportation Electrification Plan.PacifiCorp develops
RCW 19.280.030(1)(m)An analysis of how the plan multiple electric vehicle adoption futures for consideration.PacifiCorp
accounts for: updated its zero-emission vehicle forecast in March 2024 account for
(I)Modeled load forecast scenarios that consider the impacts from the Inflation Reduction Act and recently adopted ZEV
anticipated levels of zero emissions vehicle use in a utility's standards.
service area,including anticipated levels of zero emissions
vehicle use in the utility's service area provided in RCW
47.01.520,if feasible;
(ii)Analysis,research,findings,recommendations,actions,
and any other relevant information found in the
electrification of transportation plans submitted under RCW
35.92.450,54.16.430,and 80.28.365;and
(iii)Assumed use case forecasts and the associated energy
impacts.Electric utilities may,but are not required to,use the
forecasts generated by the mapping and forecasting tool
created in RCW 47.01.520.This subsection(1)(m)(iii)
applies only to plans due to be filed after September 1,2023.
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PACIFICORP-2025 IRP APPENDIX B-REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
r E �i� i� 1�
Reference Requirement 2025 IRP Approach
WAC 480-100-625(1) Integrated resource plan updated every four years,with a The PacifiCorp IRP is published every two years with updates in the
and(4) progress report at least every two years. off cycles.This exceeds Washington State requirements. The mid-
cycle report is filed as the"Two-year Progress Report"in Washington.
WAC 480-100-620(1) Unless otherwise stated,all assessments,evaluations,and PacifiCorp's 2025 (and prior)IRPs span a 20-year long-term planning
forecasts comprising the plan should extend over the long- horizon.Additional analysis may extend or be extrapolated beyond the
range(e.g.,at least ten years;longer if appropriate to the life 20-year horizon under exceptional circumstances based on available
of the resources considered)planning horizon. data and model performance.
WAC 480-100-620(2) Plan includes range of forecasts of projected customer The range of load forecast cases includes high load,low load, 1-in-20
demand that reflect effects of economic forces on electricity load,high distributed generation,low distributed generation,and large
consumption. metered load growth scenarios.
WAC 480-100-620(2) Plan includes a range of optimistic and pessimistic PacifiCorp conducts a variety of load forecast scenarios. Also, to
assumptions of forecast load growth that address changes in account for changes in the number,type and efficiency of end-uses,the
the number,type,and efficiency of electrical end-uses,and Company updates its statistically adjusted end-use model used in the
electrification adjustments made to the forecast. load forecast.
See Appendix A(Load Forecast)for details regarding the alternative
load forecast scenarios. Specifically,the Company's base forecast
includes expected climate change impacts on loads,while the 20-year
normal load forecast scenario provides the load forecast without
explicitly accounting for climate change temperatures.Further,the
Company does produce both optimistic and pessimistic load forecast
scenarios.Please refer to Appendix A(Load Forecast)for details
regarding transportation and building electrification adjustments made
to the load forecast.
PacifiCorp has provided detail on load forecasts in Appendix A(Load
Forecast).Information can also be found in Chapter 6(Load and
Resource Balance).
WAC 480-100-620(3) Plan includes load management assessments that are cost- The IRP is informed by the company's current conservation potential
effective and commercially available,including current and assessment,which is available on PacifiCorp's website.Additional
new policies and programs to obtain: information on the load management assessments can be found in
Appendix D(Demand-Side Management Programs).
WAC 480-100-620(3) -all cost-effective conservation,efficiency,and load IRP modeling optimally selects all cost-effective energy efficiency and
management improvements; demand response in each portfolio as a part of core model
69

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
OW. - 7
Requirement 2025 IRP Approach
-all demand response(DR)at the lowest reasonable cost; functionality.Results are reported for portfolios in Chapter 9
(Modeling and Portfolio Selection Results)and Appendix O(Clean
Energy Action Plan).
WAC 480-100-620(3) -ten-year conservation potential used in the concurrent The IRP is informed by the current conservation potential assessment,
biennial conservation plan consistent with RCW which is available on PacifiCorp's website. Chapter 6(Load and
19.285.040(1); Resource Balance)provides additional detail.
WAC 480-100-620(3) -identification of opportunities to develop combined heat Combined heat and power are addressed as a component of the
and power as an energy and capacity resource;and Distributed Generation Study,which is included in Appendix L
(Distributed Generation Study).
WAC 480-100-620(3)(b) Distributed energy resource(DER)potential assessments The Company assesses various levels of DER through a variety of
(WAC 480-100-620(3)(b)) methods.PacifiCorp evaluates distributed generation by considering
varying levels of technology costs and electricity rate assumptions,
Sub-section(iii)(energy assistance potential assessment): which are considered within the Company's high and low distributed
The IRP must include distributed energy programs and generation load forecast sensitivities.
mechanisms identified pursuant to RCW 19.405.120,which
pertains to energy assistance and progress toward meeting Regarding the energy assistance potential assessment,PacifiCorp
energy assistance need. evaluates energy efficiency potential by income level so as to inform
how energy efficiency resources can meet energy assistance need.
Sub-section(iv)(other DER potential assessments)—The The 2023 IRP also assesses other DERs such as energy storage,which
IRP must assess other DERs that may be installed by the is considered within the Company's distributed generation study and
utility or the utility's customers including,but not limited to, the CPA as a demand response resource for acquisition is subsequently
energy storage,electric vehicles,and photovoltaics.Any incorporated into PacifiCorp's load forecast and IRP modeling.
such assessment must include the effect of DERs on the Further,utility scale battery storage is considered as a resource option
utility's load and operations.DER potential assessment(s) within the context of portfolio analysis.The Company incorporates
must go beyond the utility's legacy approach showing DERs electric vehicle demand within the load forecast along with the control
as simply a load forecast decrement of electric vehicle load as a demand response resource in the IRP
model.
WAC 480-100-620(3)(b) Plan includes assessments of distributed energy programs IRP modeling considers and selects energy efficiency and demand
and mechanisms pertaining to energy assistance and progress response potential,and distributed energy programs.Evaluation is
toward meeting energy assistance need,incl detailed in Chapter 8(Modeling and Portfolio),and Chapter 9
ding but not limited to the following: (Modeling and Portfolio Selection Results). See Appendix L for the
- Energy efficiency and CPA, Distributed Generation study and the IRP Studies webpage for the
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PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i.5—Washington CETA Standards, and Guidelines
Reference Requirement 2025 IRP Approach
- Demand response potential, CPA report,as well. Since at least the 2021 CPA,EE potential has
- Energy assistance potential been estimated at the income segmentation level,including for
Washington(see CPA Volume 2 Appendix F).
Since the 2021 IRP,PacifiCorp has contracted with Empower
Dataworks to conduct an energy assistance assessment in compliance
with WAC 480-100-620(3)guidelines.PacifiCorp shared the findings
with Washington stakeholder groups in June 2022,including the Low
Income Advisory Group,the DSM Advisory Group,and the EAG.
The findings are posted online."PacifiCorp has also discussed this
assessment in prior CEIP filings and submits annual reports to the
Washington State Department of Commerce.
WAC 480-100-620(3)(b) Plan assesses a forecast of distributed energy resources PacifiCorp has worked with DNV Consulting to prepare a Distributed
(DER)that may be installed by the utility's customers via a Generation Study,which assesses private and customer-sited
planning process pursuant to RCW 19.280.100(2). resources. Customer preference resources are also assessed as part of
the portfolio selection process.Additional detail can be found in
Chapter 8(Modeling and Portfolio Evaluation).
WAC 480-100-620(3)(b) Plan includes effect of DERs on the utility's load and The impacts of DERs on PacifiCorp's utility load and operations are
operations. assessed as part of Chapter 8(Modeling and Portfolio Evaluation).
Inputs are assessed as part of Appendix L(Distributed Generation
Study).
WAC 480-100-620(3)(b) If utility engages in a DER planning process,which is PacifiCorp summarizes relevant activities in Appendix O(Clean
strongly encouraged,IRP should include a summary of the Energy Action Plan).Also,summaries of our DER planning processes
process planning results. can be found in the conservation potential assessment and distributed
generation studies posted on our website.
WAC 480-100-620(4) Plan assesses wide range of conventional generating PacifiCorp considered a wide range of resources including renewables,
resources. demand-side management,energy storage,distributed energy
resources,power purchases,thermal resources,and transmission.
Chapter 7(Resource Options)provides relevant detail on conventional
generating resources.
" The 2022 Energy Burden Assessment is available online:
hgps://www.pacificpower.net/content/dgM/pcolp/documents/epZpacificolp/energy/ceip/DSM Advisory%20GrounMeeting June Energy Burden Assessment Slides.
pdf
71

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Reference Requirement AL AL 2025 IRP Approach
WAC 480-100-620(5) An assessment of integrating renewable resources Cost and performance data for all resource types is evaluated and
addressing overgeneration. entered as a model input for the optimal selection of resources.The
impacts of integration,saturation and curtailments are evaluated in
each study as part of model functionality.Additional information can
be found in Chapter 8(Modeling and Portfolio Evaluation)and
Chapter 9(Modeling and Portfolio Selection).
WAC 480-100-620(5). Plan assesses energy storage resources.Include an assessment Energy storage resources are considered as part of the supply-side
Also see WA-UTC of battery and pumped storage for integrating renewable resource table,found in Chapter 7(Resource Options).Energy
energy storage policy resources.The assessment may consider ancillary services at storage potential is assessed as part of Appendix N(Energy Storage
statement(UE-151069& the appropriate granularity required to model such storage Potential Evaluation).The 2025 IRP incorporates multiple storage
UE-161024 resources. options including lithium-ion,flow and iron-air batteries,and
consolidated) pumped hydro storage.Modeling was conducted at appropriate
granularity in the PLEXOS LT and ST models. See Chapters 7 and 8.
WAC 480-100-620(5) Plan assesses nonconventional generating,integration,and Compressed air storage and nuclear resources are represented in the
ancillary service technologies. Supply Resource Table,which is posted on PacifiCorp's IRP website
and included as Chapter 7(Resource Options).All resource types are
appropriately subject to integration and ancillary services
determination,including transmission upgrade costs,reserve holding
capability and additional reserve requirements that are particular to
technologies.These factors are inherent to every portfolio
optimization run.
WAC 480-100-620(6) Plan assesses the availability of regional generation and Regional generation is incorporated into market availability and
transmission capacity for purposes of delivery of price forecasts,which are described and analyzed in Chapter 3
electricity to customers. (Planning Environment),Chapter 5 (Reliability and Resiliency).
Transmission and resource options are described in Chapter 4
(transmission)and Chapter 7(Resource Options).
WAC 480-100-620(6) Plan assesses utility's regional transmission future needs, Regional transmission is represented through markets and region-
and the extent transfer capability limitations may affect based price forecasting,while PacifiCorp's transmission system is
the future siting of resources. represented by firm transmission rights and endogenous
transmission upgrade options. These factors are discussed in the
Chapter 7(Resource Options)and Chapter 8(Modeling and
Portfolio
Evaluation).
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i Washington CETA Standards, and Guidelines
r EReference Requirement 2025 IRP Approach
WAC 480-100-620(7) Plan compares benefits and risks of purchasing power As a component of core modeling functionality,all competing
or building new resources. resources are evaluated to determine each optimal portfolio.
Additional information can be found in Chapter 8(Modeling and
Portfolio Evaluation)and Chapter 9(Modeling and Portfolio
Selection Results).
WAC 480-100-620(7) Compare and evaluate all identified resources and The 2025 IRP compares all resource options in its optimized
potential changes to existing resources for achieving the evaluation and provides narratives of comparative analysis of
clean energy transformation standards in WAC 480-100- outcomes in Chapter 9,and details regarding resource attributes in
610 at the lowest reasonable cost,including a narrative Chapter 7.The comparison of resources on a cost-risk basis is core
of the decisions it has made.Plan compares all identified functionality of PacifiCorp's optimization modeling.Additional
resources according to resource costs,including: information can be found in Chapter 8(Modeling and Portfolio
Evaluation).
WAC 480-100-620(7) -transmission and distribution delivery costs; PacifiCorp's transmission system is represented by firm transmission
rights and endogenous transmission upgrade options. Transmission
dependencies implying additional resource costs are included in the
optimization,resulting in a reasonable comparison of resource costs.
Additional information can be found in Chapter 7(Resource
Options),Chapter 8(Modeling and Portfolio Evaluation),and
Chapter 9(Modeling and Portfolio Selection Results).
WAC 480-100-620(7) -risks,including environmental effects and the social All variant studies eligible for the preferred portfolio were evaluated
cost of GHG emissions; under a social cost of greenhouse gases price-policy scenario and
evaluated for environmental effects.A range of additional price
future impacts and environmental considerations are examined in
the 2025 IRP.Refer to Chapter 8(Modeling and Portfolio
Evaluation)and Appendix O(Washington Clean Energy Action
Plan).
WAC 480-100-620(7) -benefits accruing to the utility,customers,and Benefits are characterized by present value revenue requirement
program participants(when applicable);and differentials,emissions,reserve and load deficiencies,robustness
across stochastic variances and additional factors as may emerge
from modeling results.In addition to modeling outcomes presented
in Chapter 8(Modeling and Portfolio Evaluation),incremental costs,
community benefits and energy justice are discussed in Appendix O
(Clean Energy Action Plan).
WAC 480-100-620(7) -resource preference public policies adopted by WA The preferred portfolio selected in the 2025 IRP process meets all
73

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i.5—Washington CETA Standards, and Guidelines
Requirement 2025 IRP Approach
State or the federal government. anticipated policy requirements and considers alternative futures.A
summary of the policy and state environment is included as Chapter
3 (Planning Environment),and a description of compliance policy
strategy is included as Chapter 8(Modeling and Portfolio
Evaluation),and supplemented by Appendix O(Clean Energy
Action Plan).
WAC 480-100-620(7) Plan includes methods,commercially available technologies, IRP modeling endogenously considers "overgeneration"in dispatch
or facilities for integrating renewable resources,including and curtails resources appropriately. These curtailments are an
but not limited to battery storage and pumped storage,and inherent component of the cost and risk valuation of each portfolio,
addressing overgeneration events. and is a driver for the optimal size,type and
location of selected resources.
WAC 480-100-620(8) Plan assesses and determines resource adequacy metrics. For the 2025 IRP,resource adequacy is evaluated as a core model
function,where each portfolio is obligated to meet reliability
requirements including varying degrees of quality of operating
reserves.In addition,inter-nodal reliability is considered as long-
term and short-term modeling lead to different measures of
reliability. See Chapter 8
(Modeling and Portfolio Evaluation).
WAC 480-100-620(8) Identify an appropriate resource adequacy requirement PacifiCorp has addressed this requirement as described in Chapter 6
(i.e.,loss of load probability)and complete the (Load and Resource Balance)and Appendix K(Capacity
assessment. Contribution).
WAC 480-100-620(8) Plan measures corresponding resource adequacy metric PacifiCorp has addressed this requirement as pertains to requirements
consistent with prudent utility practice in eliminating coal- for the Clean Energy Transformation Act and the 2025 IRP as
fired generation by 12/31/2025(RCW 19.405.030), described in Chapter 6(Load and Resource Balance),Chapter 8
attaining GHG neutrality by l/l/2030(RCW 19.405.040), (Modeling and Portfolio Evaluation),and Chapter 9(Modeling and
and achieving 100 percent clean electricity WA retail sales Portfolio Selection Results),and Appendix O(Clean Energy Action
by l/l/2045 (RCW Plan).
19.405.050).
WAC 480-100-620(9) Plan reflects the cumulative impact analysis conducted Please see Appendix O for details regarding the Company's plan for
under RCW 19.405.140,and includes an assessment o£ reporting on metrics related to CBIs.
-energy and nonenergy benefits;
-reduction of burdens to vulnerable populations and
highly impacted communities;
74

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
R Requirement 2025 IRP Approac
-long-term and short-term public health and
environmental benefits,costs,and
-long-term and short-term public health and
environmental risks;and
-energy security and risk.
WAC 480-100-620(10) Utility should include a range of possible future scenarios A wide range of cases and sensitivities under various price-policy
and input sensitivities for testing the robustness of the futures have been included,as discussed in Chapter 8(Modeling and
utility's resource portfolio under various parameters, Portfolio Evaluation).
including the following required components:
WAC 480-100-620(10) CETA counterfactual scenario-describe the alternative
least reasonable cost and reasonably available portfolio that PacifiCorp has met this requirement—additional detail can be found
the utility would have implemented if not for the in Chapter 8(Modeling and Portfolio Evaluation).
requirement to comply with RCW 19.405.040 and RCW
19.405.050,as described in WAC 480-100-660(1).
WAC 480-100-620(10) Climate change scenario-incorporate the best science PacifiCorp has met this requirement by incorporating climate change
available to analyze impacts including,but not limited to, in its base assumptions,including future climate impacts on the load
changes in snowpack,streamflow,rainfall,heating and forecast,energy efficiency potential,and the hydro generation
cooling degree days,and load changes resulting from climate forecast. The base load forecast for the 2025 IRP is based on a Bureau
change. of Reclamation median projection of climate impacts through time on
heating and cooling degree days,resulting in increasing divergence
from the 20-year normal weather further in the IRP planning horizon.
The hydro forecast similarly relies on projected seasonal changes in
streamflows in response to climate impacts that evolve across the IRP
planning horizon.Refer to Chapter 8 (Modeling and Portfolio
Evaluation)and Appendix A(Load Forecast).
WAC 480-100-620(10) Maximum customer benefit sensitivity-model the PacifiCorp has met this requirement—additional detail on studies can
maximum amount of customer benefits described in RCW be found in Chapter 8(Modeling and Portfolio Evaluation)and
19.405.040(8)prior to balancing against other goals. Appendix O
WAC 480-100-620(11) Integrate the demand forecasts and resource evaluations PacifiCorp has met this requirement—additional detail can be found in
into a long-range IRP solution describing the mix of Chapter 6(Load and Resource Balance).The PLEXOS models were
resources that meet current and projected resource needs, used to evaluate resources on a comparable basis following the
abiding by a variety of constraints pursuant to statute and requirements in statute. See Chapter 8 and Appendix O.
per Commission rule
75

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i 11 CETA Standards, II Guidelines
F EReference Requirement 2025 IRP Approach
WAC 480-100-620(11) IRP solution or preferred portfolio must describe the resource PacifiCorp has met this requirement—additional detail can be found
mix that meets current and projected needs. in Chapter 9 and Appendix O.
WAC 480-100- Preferred portfolio must include narrative explanation of the See individual entries below.
620(11)(a) decisions made,including how the utility's long-range IRP
solution:
WAC 480-100- -achieves requirements for eliminating coal-fired PacifiCorp will remove coal-fired generation from Washington's
620(11)(a) generation by 12/31/2025 (RCW 19.405.030); allocation of electricity by 2025 and will continue to analyze this
pending further resolution of interpretive issues by the Commission.
Additional information can be found in Chapter 9(Modeling and
Portfolio Selection Results).
WAC 480-100- -attains GHG neutrality by l/1/2030(RCW PacifiCorp has met this requirement.Additional information can be
620(11)(a) 19.405.040);and found in Chapter 8 (Modeling and Portfolio Evaluation),and Chapter
9(Modeling and Portfolio Selection Results),and Appendix O
(Clean Energy Action Plan).
WAC 480-100- -achieves 100 percent clean electricity WA retail sales by This requirement is met as described in Chapter 8(Modeling and
620(11)(a) 1/l/2045 (RCW 19.405.050)at lowest reasonable cost, Portfolio Evaluation),and Chapter 9(Modeling and Portfolio Selection
Results),and Appendix O(Clean Energy Action Plan).
WAC 480-100- -achieves 100 percent clean electricity WA retail sales by This requirement is met as described in Chapter 8(Modeling and
620(11)(a) 1/l/2045 (RCW 19.405.050),considering risk. Portfolio Evaluation),and Chapter 9(Modeling and Portfolio
Selection Results),and Appendix O(Clean Energy Action Plan).
WAC 480-100- Consistent with RCW 19.285.040(1),preferred portfolio PacifiCorp has met this requirement.Additional information can be
620(11)(c) shows pursuit of all cost-effective,reliable,and feasible found in Chapter 8(Modeling and Portfolio Evaluation),and Chapter 9
conservation and efficiency resources,and DR. (Modeling and Portfolio Selection Results),and Appendix O(Clean
Energy Action Plan).
WAC 480-100- Preferred portfolio considers acquisition of existing PacifiCorp has met this requirement.Additional information can be
620(11)(d)and I renewable new resources and relies on renewable resources found in Chapter 8(Modeling and Portfolio Evaluation),and Chapter 9
and energy storage,insofar as doing so is at lowest (Modeling and Portfolio Selection Results),and Appendix O(Clean
reasonable cost. Energy Action Plan).
WAC 480-100- Preferred portfolio considers acquisition of existing PacifiCorp has met this requirement.Additional information can be
620(11)(d)and(e) renewable new resources and relies on renewable resources found in Chapter 8 (Modeling and Portfolio Evaluation),and Chapter 9
and energy storage,considering risks. (Modeling and Portfolio Selection Results),and Appendix O
76

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i.5—Washington CETA Standards, and Guidelines
Requirement 2025 IRP Approac
(Washington Clean Energy Action Plan).
WAC 480-100-620(11)(f) Preferred portfolio maintains and protects the safety, PacifiCorp has met this requirement.In addition to inherent modeling
reliable operation,and balancing of the utility's electric functionality,additional information can be found in Chapter 6(Load
system,including mitigating over-generation events and and Resource Balance).
achieving identified resource adequacy requirements.
WAC 480-100- Preferred portfolio ensures all customers are benefiting See individual entries below.
620(11)(g) from the transition to clean energy through the:
WAC 480-100- - equitable distribution of energy and nonenergy Please see Appendix O(Clean Energy Action Plan).
620(11)(g) benefits;reduction of burdens to vulnerable
populations and highly impacted communities;
demonstrate a wider incorporation of non-energy
impacts(NEIs)in addition to those applied during
conservation potential assessment(CPA)
development.
WAC 480-100- - long-term and short-term public health and Please see Appendix O(Clean Energy Action Plan).
620(11)(g) environmental benefits;reduction of costs and risks;
and
WAC 480-100- - energy security and resiliency. Please see Appendix O(Clean Energy Action Plan).
620(11)(g)
WAC 480-100- - Please see Appendix O(Clean Energy Action Plan). Please see Appendix O(Clean Energy Action Plan).
620(11)(h)
WAC 480-100-620(11)(i) - analyzes and considers combinations of DER costs, Detail is included in Chapter 8(Modeling and Portfolio Evaluation),
benefits,and operational characteristics(incl.ancillary Appendix L(Distributed Generation Study)and discussion in
services)to meet system needs, Appendix O(Washington Clean Energy Action Plan).
WAC 480-100-620(11)0) - incorporates the social cost of GHG emissions as Detail is included in Chapter 8(Modeling and Portfolio Evaluation)
a cost adder. and Appendix O(Washington Clean Energy Action Plan).
WAC 480-100-620(12) Utility must develop a ten-year clean energy action plan The Company's 2025 CEAP is provided as Appendix O(Washington
(LEAP)for implementing RCW 19.405.030 through Clean Energy Action Plain). See individual entries below.
19.405.050 at lowest reasonable cost,and at an acceptable
resource adequacy standard.
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PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i.5—Washington CETA Standards, and Guidelines
R Requirement In-2IRP A
The CEAP will:
WAC 480-100- - identify and be informed by utility's ten-year CPA per Please see Appendix O(Washington Clean Energy Action Plan).
620(12)(b) RCW 19.285.040(1);
WAC 480-100- - demonstrate that all customers are benefiting from Please see Appendix O(Washington Clean Energy Action Plan).
620(12)(c) the transition to clean energy;
WAC 480-100- - establish a resource adequacy requirement; PacifiCorp establishes resource adequacy at a system level,and the
620(12)(d) resource adequacy requirement is explained in Chapter 6(Load and
Resource Balance).
WAC 480-100- - identify the potential cost-effective DR and load This requirement is met in Chapter 9(Modeling and Portfolio
620(12)(e) management programs that may be acquired; Selection Results)and Appendix O(Washington Clean Energy Action
Plan).
WAC 480-100-620(12)(f) - identify renewable resources,non emitting electric This is described as part of PacifiCorp's resource planning process.
generation,and DERs that may be acquired and Chapter 7(Resource Options),Chapter 8(Modeling and Portfolio
evaluate how each identified resource may be expected Evaluation),and Chapter 9(Modeling and Portfolio Selection)provide
to contribute to meeting the utility's resource adequacy additional detail.Also see Appendix L and Appendix O with reference
requirement; to DERs.
WAC 480-100- - identify any need to develop new,or expand or upgrade This is described at the system level in Chapter 4(Transmission)and
620(12)(g) existing,bulk transmission and distribution facilities; within PacifiCorp's Chapter 10(Action Plan).
WAC 480-100- - identify the nature and possible extent to which the Please see Appendix O(Washington Clean Energy Action Plan).
620(12)(h) utility may need to rely on alternative compliance
options,if appropriate.
WAC 480-100-620(12)(i) Plan(both IRP and CEAP)considers cost of greenhouse gas PacifiCorp updated its social cost of greenhouse gas pricing consistent
emissions as a cost adder equal to the cost per metric ton of with DOCKET U-190730 ORDER 03,which updates this
carbon dioxide emissions,using the two and one-half specification.
percent discount rate,listed in Table 2,Technical Support
Document:Technical update of the social cost of carbon
(SCC)for regulatory impact analysis under Executive Order
12866,published by the interagency working group on
social cost of greenhouse gases of the United States
government,August 2016,as adjusted by the Commission
to reflect the effect of inflation.
78

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
Reference Requirement 2025 IRP Approach
WAC 480-100-620(13) Plan must include an analysis and summary of the estimated A new assessment of avoided cost is not a requirement of the Two-
avoided cost for each supply-and demand-side resource, Year Progress Report;however,future determinations of avoided cost
including(but not limited to): will follow the guidelines below.
-energy,
-capacity, The estimated avoided cost will be based on the values determined
-transmission, through the IRP modeling process.Values can be found in Chapter 8
-distribution,and (Modeling and Portfolio Evaluation)and Chapter 9(Modeling and
-GHG emissions. Portfolio Selection).
WAC 480-100-620(13) Listed energy and non-energy impacts should specify to The file labeled"2025 CPA-Appendix E-WA Non-Energy
which source party they accrue(e.g.,utility,customers, Impact Mapping",as part of the CPA supplemental materials
participants,vulnerable populations,highly impacted posted on the website,maps the accrual of NEIs to various groups
communities,general consistent with WAC 480-100-620(13).
public).
WAC 480-100-620(14) To maximize transparency,the utility should submit data PacifiCorp will make data available in the native file format consistent
input files supporting the plan in native file format(e.g., with practice in prior IRPs.
supporting spreadsheets in Excel,not PDF file format).
WAC 480-100-620(15) Information relating to purchases of electricity from See individual entries,below.
qualifying facilities. Each utility must provide information
and analysis that it will use to inform its annual filings
required under chapter 480-106 WAC. The detailed analysis
must include,but is not limited to,the following
components:
WAC 480-100-20(15)(a) - A description of the methodology used to calculate The estimated avoided cost will be based on the values determined
estimates of the avoided cost of energy,capacity, through the IRP modeling process.Values can be found in Chapter
transmission,distribution and emissions averaged 8(Modeling and Portfolio Evaluation)and Chapter 9(Modeling
across the utility; and and Portfolio Selection).
WAC 480-100-20(15)(b) - Resource assumptions and market forecasts used in the The estimated avoided cost will be based on the values determined
utility's schedule of estimated avoided cost required in through the IRP modeling process.Values can be found in Chapter
WAC 480-106-040 including,but not limited to,cost 8(Modeling and Portfolio Evaluation)and Chapter 9(Modeling
assumptions,production estimates,peak capacity and Portfolio Selection).
contribution estimates and annual capacity factor
estimates.
WAC 480-100-620(16) Plan must summarize substantive changes to modeling A comprehensive discussion of modeling methodology updates is
79

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
Requirement 2025 IRP Approach
methodologies or inputs that change the utility's resource included in Chapter 8(Modeling and Portfolio Evaluation),
need,as compared to the utility's previous IRP. however a brief list of highly impactful changes and updates is as
follows:
• Model must meet WRAP compliance.
• Existing thermal units can operate indefinitely with
maintenance.
• IRA Tax Credits are extended through the whole horizon.
• States are only able to impact the disposition of resources
in which they have an active share.
WAC 480-100-620(17) Utility must summarize: PacifiCorp has maintained compliance with this requirement by
- public comments received on the draft IRP, publishing all stakeholder comments received and associated responses
- utility's responses to public comments,and in a centralized location externally and additionally provides this
- whether final plan addresses and incorporates comments feedback with PacifiCorp responses in Appendix M,including a
raised. summary matrix of pertinent information.
WAC 480-100-625(4) Two-year progress report.At least every two years after the Not applicable.The 2025 IRP aligns with Washington's four-year IRP
utility files its IRP, beginning January 1,2023,the utility must filing cadence.The next two-year progress report is anticipated to be
file a two-year progress report. filed in 2027.
(a) In this report,the utility must update its:
(i) Load forecast;
(ii) Demand-side resource assessment,including a new
conservation potential assessment;
(iii) Resource costs;and
(iv)The portfolio analysis and preferred portfolio.
(b)The progress report must include other updates that are
necessary due to changing state or federal requirements,or
significant changes to economic or market forces.
(c)The progress report must also update for any elements
found in the utility's current clean energy implementation
plan,as described in WAC 480-100-640.
WAC 480-100-630(1) The utility must demonstrate and document how it considered PacifiCorp meets this requirement in the 2025 IRP in Appendix C and
input from advisory group members in the development of its Appendix M and also references stakeholder feedback in footnotes
IRP and two-year progress report. throughout the 2025 IRP document.
80

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
i Washington CETA Standards, and Guidelines
Reference Requirement 2025 IRP Approach
WAC 480-100-630(2) The utility must make available completed presentation PacifiCorp has met this requirement throughout the 2025 IRP public
materials for each advisory group meeting at least three input meeting series,and as documented in Appendix C and Appendix
business days prior to the meeting. The utility may update M.
materials as needed.
WAC 480-100-630(3) The utility must make all its data inputs and files used to PacifiCorp carefully manages its workpaper filing to adhere to this
develop its IRP available to the commission in native file requirement within the limits of technology.Context is provided by the
format,per RCW 19.280.030(10)(a)and(b),and in an easily accompanying listing of file names with a description of the file's
accessible format. content or purpose.This information is provided with the supporting
workpapers.
WAC 480-106-040 Plan provides information and analysis used to inform annual See individual entries below:
purchases of electricity from qualifying facilities,including a
description of the:
WAC 480-106-040 -avoided cost calculation methodology used; The estimated avoided cost will be based on the values determined
through the IRP modeling process.Values can be found in Chapter 8
(Modeling and Portfolio Evaluation)and Chapter 9(Modeling and
Portfolio Selection).
WAC 480-106-040 -avoided cost methodology of energy,capacity,transmission, The estimated avoided cost will be based on the values determined
distribution,and emissions averaged across the utility;and through the IRP modeling process.Values can be found in Chapter 8
(Modeling and Portfolio Evaluation)and Chapter 9(Modeling and
Portfolio Selection).
WAC 480-106-040 -resource assumptions and market forecasts used in the The estimated avoided cost will be based on the values determined
utility's schedule of estimated avoided cost,including(but through the IRP modeling process.Values can be found in Chapter 8
not limited to):cost assumptions,production estimates,peak (Modeling and Portfolio Evaluation)and Chapter 9(Modeling and
capacity contribution Portfolio Selection).However,resource assumptions,capacity factors
estimates,and annual capacity factor estimates. and price forecasts are included in workpapers.PacifiCorp would note
that its 2025 IRP uses forward market prices from September 2024,
which is the same vintage as PacifiCorp's October 30,2024 avoided
cost filing in docket number 240817.
81

PACIFICORP—2025 IRP APPENDIX B—REGULATORY COMPLIANCE
Table 13.6—Wyoming Public Service Commission Guidelines
Reference Requirement 2025 IRP Approach
The public comment process employed as PacifiCorp's public process is described in Chapter 2 (Introduction)and in Appendix C(Public Input).
A part of the formulation of the utility's IRP,
including a description,timing and weight
given to the public process;
The utility's strategic goals and resource Chapter 9(Modeling and Portfolio Selection Results)documents the preferred resource portfolio and
B planning goals and preferred resource rationale for selection. Chapter 10(Action Plan)constitutes the IRP action plan and the descriptions of
portfolio; resource strategies and risk management.
The utility's illustration of resource need See Chapter 6(Load and Resource Balance).
C over the near-term and long-term planning
horizons;
D A study detailing the types of resources Volume,I Chapter 7(Resource Options),presents the resource options used for resource portfolio
considered; modeling for this IRP.
Changes in expected resource acquisitions A comparison of resource changes relative to the 2023 IRP is presented in Chapter 10(Action Plan).A
E and load growth from that presented in the chart comparing the peak load forecasts for the 2025 IRP and 2023 IRP is included in Appendix A
utility's previous IRP; (Load Forecast Details).
The environmental impacts considered; Portfolio comparisons for CO2 and a broad range of environmental impacts are considered,including
F prospective early retirement and gas conversions of existing coal units as alternatives to environmental
investments. See Chapter 8(Modeling and Portfolio Evaluation)and Chapter 9(Modeling and
Portfolio Selection).
G Market purchases evaluation; Modeling of firm market purchases(front office transactions)and spot market balancing transactions
is included in the 2025 IRP.
H Reserve Margin analysis;and Reserve margin analysis is included in Chapter 8(Modeling and Portfolio Evaluation).
Demand-side management and See Chapter 7(Resource Options)and Appendix D(Demand-side Management)for a detailed
I conservation options; discussion on DSM and energy efficiency resource options.Additional information on energy
efficiency resource characteristics is available on the company's website.
82

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.pacificorp.com/energy/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
83

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
84

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/energy /y integrated-resource-plgpZpublic-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)
85

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, 2024
• 2025 IRP Progress Report
• Supply-side Resources
• Data Center Load Studies
• State and Federal Updates
January 22-23, 2025
• 2025 IRP Progress Report
• Integration and Allocation
• Additional Model Results
• Stochastics
• Long-term Duration Storage
• CPA
• Market Purchase Limits
• Local Load Study
February 27, 2025
• Modeling Refinements
• DSM
• Stochastics
86

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
In addition to the topics listed above, each public input meeting incorporated a concluding
discussion of stakeholder feedback forms received and next steps.
er 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
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.pacificorp.com/energy/integrated-resource-plan/comments.html.
PacifiCorp's IRP website: www.pacificorp.com/energy /y integrated-resource-plan.html.
Stakeholders and members of the public can also send comments, questions and requests to the
following email address:
IRPkPacifiCorp.com
87

PACIFICORP-2025 IRP APPENDIX C-PUBLIC INPUT PROCESS
88

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
APPENDIX D - DEMAND-SIDE MANAGEMENT
introduction
This appendix reviews the studies and reports used to support the demand-side management
(DSM) resource information used in the modeling and analysis of the 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.
1conservation 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,' 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.
89

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 State
Currently, PacifiCorp offers a robust portfolio of DSM programs and initiatives, most of which
are offered in multiple states, depending on size of the opportunity and the need. Programs are
reassessed on a regular basis. PacifiCorp has the most up-to-date programs on its website.2
Demand response and energy efficiency program services and offerings are available by state and
sector. Energy efficiency services listed for Oregon, except for low-income weatherization
services, are provided in collaboration with Energy Trust of Oregon.3
Table D.1 provides an overview of the breadth of demand response and energy efficiency program
services and offerings available by Sector and State.
PacifiCorp has numerous DSR offerings currently available. They include metered time-of-day
and time-of-use pricing plans (in all states, availability varies by customer class), and residential
seasonal rates(Idaho and Utah). System-wide, approximately 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
CaliforniaProgram Services&Offerings o i IdahoUtah i - - Wyoming
Residential Sector
Air Conditioner Direct Load
Control
Lighting Incentives
New Appliance Incentives
a 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.
s Funds for low-income weatherization services are forwarded to Oregon Housing and Community Services.
90

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
Program Services&Offerings California �o i . iUtah b - - Wyoming
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
ProgramServices&Offerings
b i � Oregon - -
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
Table D.2 provides an overview of DSM related Wattsmart Outreach and Communication
activities (Class 4 DSM activities)by state.
91

PACIFICORP—2025 IRP APPENDIX D—DEMAND-SIDE MANAGEMENT
Table D.2— Current Wattsmart Outreach and Communications Activities
Wattsmart Outreach&
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
State-Specific DSM Planning Processes
A summary of the DSM planning process in each state is provided below.
Utah, Wyoming, and Idaho
The company's biennial IRP and associated action plan provides the foundation for DSM
acquisition targets in each state. Where appropriate, the company maintains and uses external
stakeholder groups and vendors to advise on a range of issues including annual goals for
conservation programs,development of conservation potential assessments,development of multi-
year DSM plans, program marketing, incentive levels, budgets, adaptive management, and the
development of new and pilot programs.
Washington
The company is one of three investor-owned utilities required to comply with Washington's
Energy Independence Act(also referred to as 1-937)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-
92

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 for both demand response and
energy efficiency by state and year in the 2025 IRP preferred portfolio.5
Table D.3 shows cumulative additional demand response selections in units of MW capacity
during summer and winter seasons by state and year. This does not include already existing
demand response resources but is rather additional to them.
4 The Company's 2021 CEIP can be found online at
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/ceip/PAC-CEIP-12-30-
21_with_Appx.pdf
5These DSM resource selections follow the methodologies described in Chapter 7.
93

PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
Table D.3 —Cumulative Demand Response Resource Selections (2025 IRP Preferred
Portfolio) (MW)
Resource 2
DRSummer-CA 0 0 0 0 0 0 0 0 0 0 0
DR Winter-CA 0 0 0 0 0 0 0 0 0 0 0
DR Summer-ID 0 0 0 0 0 4 9 9 9 9 9
DR Winter-ID 0 0 0 0 0 0 0 0 0 0 0
DR Summer-OR 2 2 2 2 2 2 2 2 2 2 2
DR Winter-OR 0 0 0 48 64 71 71 76 77 80 83
DR Summer-UT 2 2 2 2 2 95 171 171 171 171 171
DRWinter-UT 0 0 0 0 0 0 0 0 0 0 0
DR Summer-WA 2 2 2 2 2 2 2 2 2 2 2
DRWinter-WA 0 0 0 15 18 19 19 19 19 19 19
DRSummer-WY 12 12 12 12 15 28 47 47 47 47 47
DR Winter-WY 1 01 01 0 01 01 OF 01 01 01 0 0
Resource 2036 2037 2038 2039 2040 2041 2042 2043 20" 2045
DRSummer-CA 2 2 2 2 3 5 5 5 5 5
DRWinter-CA 0 0 0 0 0 0 0 0 0 0
DRSummer-ID 9 15 15 15 15 15 26 27 28 29
DRWinter-ID 0 0 0 0 0 0 0 0 0 0
DR Summer-OR 2 2 2 2 2 2 2 2 2 2
DR Winter-OR 94 94 106 110 133 136 136 145 145 153
DR Summer-UT 171 277 277 277 277 331 419 437 462 487
DRWinter-UT 0 0 0 0 0 0 0 0 0 4
DR Summer-WA 2 2 2 2 2 2 2 2 2 15
DR Winter-WA 27 27 33 34 35 36 36 36 36 38
DR Summer-WY 1 471 48 481 48 48 48 55 55 55 55
DRWinter-WY 1 01 01 01 01 01 01 01 01 01 1
Table DA also shows cumulative selections,but for energy efficiency instead of demand response,
and in units of energy(MWh). These energy efficiency energy savings were converted from units
of nameplate capacity selected by the IRP using the load shapes of bundled measures,as described
in Chapter 7, and do not reflect first-year savings. For a corresponding view of cumulative energy
efficiency selections but in units of capacity(MW), see Figure 9.8 in Chapter 9.
Table D.5 similarly shows energy efficiency selections in units of energy, but in terms of
incremental,first year energy savings (MWh), not cumulative. These vary from the incremental
savings one would derive by subtracting year-over-year cumulative values in Table DA because
the savings in Table D.5 apply capacity selections at the specific measure-level, leveraging non-
bundled load shapes. Table D.5 is provided here to reflect how energy efficiency programs pursue
energy efficiency measures in practice and design their offerings, bridging the gap between the
proxy-based nature of the IRP and state-specific program implementation. Table DA and Table
D.5 both exclude energy efficiency savings from the Home Energy Report program.
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PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
Table DA-Cumulative Energy Efficiency Resource Selections (2025 IRP Preferred
Portfolio)'
Cumulative Energy Efficiency Energy(MWh)Selected by State and Year
State 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
CA 3,308 7,186 11,388 15,309 19,229 23,073 26,991 31,358 36,397 41,184 45,080
ID 17,544 42,512 65,097 89,893 116,455 143,426 171,556 201,714 232,221 262,131 291,754
OR 211,150 379,370 605,544 832,779 1,064,124 1,291,630 1,521,326 1,762,122 1,976,929 2,183,231 2,361,518
Ur 272,934 573,161 817,755 1,108,311 1,403,990 1,714,640 1,932,749 2,340,414 2,817,643 3,313,862 3,701,566
WA 46,965 80,143 117,022 161,600 203,520 248,039 288,737 346,363 405,470 462,659 518,944
WY 41,384 83,765 144,686 211,034 271,750 328,182 375,624 446,392 520,343 593,883 663,919
Total System 1 593,2861 1,166,1371 1,761,4931 2,418,9261 3,079,0681 3,748,9891 4,316,983 1 5,128,363 1 5,989,003 1 6,856,950 7,582,781
EnergyCumulative Energy Efficiency
State 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
CA 49,487 51,672 54,611 57,310 59,478 61,566 62,793 64,775 66,426 67,394
ID 320,075 348,696 371,724 393,809 412,398 429,787 446,895 465,603 483,738 496,213
OR 2,526,114 2,692,592 2,880,693 3,057,127 3,231,248 3,361,769 3,483,475 3,667,107 3,815,294 3,965,895
Ur 4,049,145 4,205,654 4,680,853 5,144,103 5,547,278 5,856,413 5,689,544 6,027,457 6,342,021 6,635,978
WA 573,179 617,869 664,707 702,340 732,534 759,948 760,498 789,514 810,692 830,752
WY 708,202 746,669 800,029 850,977 896,067 943,697 949,377 986,888 1,020,725 1,049,194
Total System 8.225.202 8,663,1511 9,452,617 1 10,205,665 1 10,879,002 1 11,413,179 1 11,3W,583 I 12,001,344 1 12,538,897 1 13,045,426
Table D.5-First-Year Energy Efficiency Resource Selections (2025 IRP Preferred Portfolio)
Energy Efficiency Energy(1st Year Savings MWh)Selected by State and Year
State 2025 2026 2027 2028 2033 2034
California 3,308 3,878 4,278 3,858 3,837 3,760 3,872 3,954 4,670 4,45q
,749
Idaho 17,544 24,968 22,631 24,590 26,413 27,024 28,091 28,280 28,823 28,61 ,366Oregon 211,150 168,220 227,146 230,505 233,662 233,917 231,092 225,755 216,770 195,20 ,456Utah 272,934 300,226 245,311 280,532 290,280 306,640 342,771 330,772 371,694 386,79 ,179Washington 46,965 33,177 36,986 44,044 41,252 43,767 45,340 50,434 53,981 55,37 ,949Wyoming 41,384 42,381 61,100 64,424 60,306 57,409 61,607 65,029 65,474 63,69 ,256
Total System 1 594,713 572,851 1 597,452 1 647,953 1 655,750 1 672,518 1 712,771 1 704,224 1 741,413 734,142 732,955
Energy Efficiency Energy(Ist Year Savings MWh)Selected byStateandYear
State 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
California 3,278 3,251 2,924 2,685 2,100 1,827 1,663 1,582 1,645 756
Idaho 27,509 26,368 21,080 20,231 18,922 17,621 17,586 15,513 14,796 11,289
Oregon 181,642 174,990 169,001 159,411 169,587 165,583 147,685 151,996 131,894 126,643
Utah 411,810 412,543 371,801 359,565 345,723 345,449 347,345 275,353 267,698 222,351
Washington 54,403 1 50,805 1 40,5231 37,159 1 32,029 1 28,548 1 27,671 1 25,382 1 21,944 18,247
Wyoming 58,616 1 55,056 1 47,532 1 45,951 1 40,842 1 39,675 1 39,9791 34,832 1 34,675 24,042
Total System 737,258 1 723,0141 652,861 1 625,003 1 609,202 1 598,703 1 581,930 1 504,657 1 472,652 403,327
*First-year energy cannotbe summed up to get the cumulative energy byyear because the hourlyshapes change from year to year.
**The period 2025-2026 represents planned energy efficiencyand does not change between all 2025IRP cases.
6 First-year energy may vary slightly from incremental values,i.e.,subtracting cumulative energy from the prior year,due to hourly shapes of
energy efficiency changing from year to year.
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PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
Table D.6-Energy Efficiency Selected Bundle Cost/KWh (2025 IRP Preferred Portfolio)'
Cost($/kWh)
qr CA OR WA WY
Cooll $ 0.05 $ 0.05 $ 0.05 $ 0.05 $ 0.10 $ 0.06
Coo12 $ 0.08 $ 0.08 $ 0.06 $ 0.06 $ 0.17 $ 0.08
C0013 $ 0.14 $ 0.25 $ 0.14 $ 0.10 $ 0.37 $ 0.14
Coo14 $ 0.24 $ 2.25 $ 0.17 $ 0.13 $ 2.30 $ 1.32
Coo15 $ 0.48 $ - $ 0.43 $ 0.17 $ - $ -
Coo16 $ 0.72 $ - $ 0.66 $ 0.22 $ - $ -
Coo17 $ 2.10 $ - $ - $ 0.36 $ - $ -
Coo18 $ - $ - $ - $ 0.97 $ - $ -
Coo19 $ - $ - $ - $ 1.76 $ - $ -
Heatl $ 0.11 $ 0.06 $ 0.06 $ 0.10 $ 0.09 $ 0.05
Heat2 $ 0.20 $ 0.08 $ 0.05 $ 0.20 $ 0.12 $ 0.09
Heat3 $ 0.36 $ 0.14 $ 0.06 $ 0.27 $ 0.21 $ 0.22
Heat4 $ 0.62 $ 0.18 $ 0.08 $ 0.43 $ 0.41 $ 0.43
Heats $ 0.99 $ 0.17 $ 0.09 $ - $ 0.54 $ -
Heat6 $ - $ 0.23 $ 0.21 $ - $ 1.17 $ -
Heat7 $ - $ 0.51 $ 0.35 $ - $ - $ -
Summerl $ - $ 0.03 $ 0.04 $ 0.05 $ 0.06 $ 0.04
Summer10 $ 0.30 $ 0.25 $ 0.14 $ 0.68 $ 0.22 $ -
Summerll $ 0.63 $ 0.21 $ 0.08 $ - $ 0.29 $ -
Summerl2 $ 1.05 $ 0.89 $ - $ - $ 0.34 $ -
Summerl3 $ - $ - $ - $ - $ 0.52 $ -
Summerl4 $ - $ - $ - $ - $ 1.37 $ -
Summer2 $ 0.08 $ 0.04 $ 0.04 $ 0.04 $ 0.07 $ 0.05
Summer3 $ 0.10 $ 0.06 $ 0.05 $ 0.06 $ 0.08 $ 0.06
Summer4 $ 0.12 $ 0.07 $ 0.06 $ 0.07 $ 0.09 $ 0.09
Summer5 $ 0.13 $ 0.06 $ 0.06 $ 0.08 $ 0.11 $ 0.13
Summer6 $_ 0.13 $ 0.11 $ 0.06 $ 0.10 $ 0.14 $ 0.20
Summer? $ 0.22 $ 0.10 $ 0.06 $ 0.13 $ 0.15 $ 0.67
Sunit=8 $ 0.17 $ 0.12 $ 0.06 $ 0.19 $ 0.17 $ -
Sutnmer9 $ 0.23 $ 0.13 $ 0.09 $ 0.17 $ 0.21 $ -
Winterl $ 0.15 $ 0.05 $ 0.06 $ 0.08 $ 0.28 $ 0.04
Winterl0 $ - $ - $ - $ - $ - $ 0.52
Winter2 $ - $ 0.27 $ - $ 0.28 $ - $ 0.05
Winter3 $ - $ - $ - $ - $ - $ 0.07
Winter4 $ - $ - $ - $ - $ - $ 0.10
Winters $ - $ - $ - $ - $ - $ 0.12
Winter6 $ - $ - $ - $ - $ - $ 0.12
Winter? $ - $ - $ - $ - $ - $ 0.18
Winter8 $ - $ - $ - $ - $ - $ 0.22
Winter9 $ - $ - $ - $ - $ - $ 0.34
ZeroFlat $ 0.01 $ 0.01 $ 0.01 $ 0.01 $ 0.00 $ 0.01
ZeroTemp $ 0.02 $ 0.02 $ 0.03 $ 0.03 $ 0.02 $ 0.02
'See Appendix M,stakeholder feedback form#57(Utah Clean Energy).For detail by State/Bundle/Year see the supporting workpaper,"Tbl
D.6-7,DSM Selection Bundle Costs by State-Year(SFF#57)-Preferred Portfolio(LT 155264 ST 157144).xlsx."
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PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
Table D.6-Energy Efficiency Selected Bundle Cost/KW (2025 IRP Preferred Portfolio)'
Cost($/kW)
OR
Cooll $ 34.44 $ 99.60 $ 39.10 $ 46.42 $ 58.81 $ 45.71
Coo12 $ 62.79 $ 151.49 $ 47.85 $ 64.59 $ 171.18 $ 81.58
Coo13 $ 110.32 $ 341.55 $ 59.43 $ 98.17 $ 384.37 $ 153.56
Coo14 $ 211.48 $ 3,207.09 $ 102.67 $ 112.22 $ 1,862.57 $ 1,118.48
Coo15 $ 305.54 $ - $ 350.07 $ 149.08 $ - $ -
Coo16 $ 470.02 $ - $ 729.84 $ 188.43 $ - $ -
Coo17 $ 1,445.21 $ - $ - $ 298.15 $ - $ -
Coo18 $ - $ - $ - $ 899.33 $ - $ -
Coo19 $ - $ - $ - $ 1,567.26 $ - $ -
Heatl $ 118.63 $ 79.46 $ 60.56 $ 110.77 $ 109.56 $ 68.60
Heat2 $ 214.28 $ 117.77 $ 50.73 $ 224.15 $ 151.09 $ 117.18
Heat3 $ 386.70 $ 191.18 $ 61.16 $ 269.11 $ 254.15 $ 298.04
Heat4 $ 690.00 $ 246.74 $ 41.02 $ 443.25 $ 503.58 $ 537.41
Heats $ 1,056.17 $ 231.95 $ 49.21 $ - $ 631.65 $ -
Heat6 $ - $ 296.21 $ 144.47 $ - $ 1,433.15 $ -
Heat7 $ - $ 702.88 $ 294.78 $ - $ - $ -
Summerl $ - $ 149.27 $ 255.86 $ 301.41 $ 262.11 $ 198.72
Suimnerl0 $ 2,040.47 $ 1,388.55 $ 339.80 $ 4,486.44 $ 1,376.70 $ -
Summerll $ 3,626.01 $ 1,487.96 $ 458.89 $ - $ 2,042.88 $ -
Summerl2 $ 5,178.58 $ 5,447.65 $ - $ - $ 2,535.65 $ -
Summerl3 $ - $ - $ - $ - $ 3,446.85 $ -
Summerl4 $ - $ - $ - $ - $ 9,501.19 $ -
Summer2 $ 504.17 $ 234.72 $ 255.15 $ 262.19 $ 323.76 $ 283.12
SummeO $ 601.57 $ 267.45 $ 244.48 $ 333.57 $ 467.09 $ 398.33
Summer4 $ 629.21 $ 316.92 $ 271.13 $ 468.89 $ 445.69 $ 559.25
Summer5 $ 655.98 $ 362.60 $ 282.17 $ 467.20 $ 726.66 $ 807.15
Summer6 $ 818.95 $ 479.70 $ 299.45 $ 510.05 $ 891.95 $ 1,134.83
Summer? $ 541.08 $ 650.65 $ 360.69 $ 882.82 $ 1,069.57 $ 4,615.21
Summer8 $ 1,111.37 $ 719.15 $ 290.70 $ 1,104.57 $ 1,143.29 $ -
Summer9 $ 1,470.95 $ 764.59 $ 459.74 $ 1,072.76 $ 1,364.76 $ -
Winterl $ 1,122.07 $ 361.68 $ 426.69 $ 644.23 $ 2,183.03 $ 347.96
Winterl0 $ - $ - $ - $ - $ - $ 3,982.36
Winter2 $ - $ 2,125.34 $ - $ 2,294.71 $ - $ 415.94
Winter3 $ - $ - $ - $ - $ - $ 524.62
Winter4 $ - $ - $ - $ - $ - $ 803.17
Winters $ - $ - $ - $ - $ - $ 972.07
Winter6 $ - $ - $ - $ - $ - $ 882.43
Winter? $ - $ - $ - $ - $ - $ 1,514.27
Winter8 $ - $ - $ - $ - $ - $ 1,660.83
Winter9 $ - $ - $ - $ - $ - $ 2,754.61
ZeroFlat $ 63.46 $ 38.41 $ 64.72 $ 83.06 $ 4.41 $ 53.18
ZeroTemp $ 22.11 $ 56.30 $ 29.95 $ 49.69 $ 27.01 $ 16.05
8 See Appendix M,stakeholder feedback form#57(Utah Clean Energy).For detail by State/Bundle/Year see the supporting workpaper,"Tbl
D.6-7,DSM Selection Bundle Costs by State-Year(SFF#57)-Preferred Portfolio(LT 155264 ST 157144).xlsx."
97

PACIFICORP-2025 IRP APPENDIX D-DEMAND-SIDE MANAGEMENT
98

PACIFICORP-2025 IRP 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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PACIFICORP-2025 IRP APPENDIX E-GRID ENHANCEMENT
• 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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PACIFICORP-2025 IRP APPENDIX E-GRID ENHANCEMENT
(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-
1 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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PACIFICORP-2025 IRP APPENDIX E-GRID ENHANCEMENT
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
Like 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-2025 IRP APPENDIX E-GRID ENHANCEMENT
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 grid enhancement 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.
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JhM Grid Enhancemenkd
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.
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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-VERs") 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):
https://www.pacificorp.com/content/dgmlpcorp/documents/en/pacificorp/energy/inte,grated-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,hlWs://www.nerc.com/pa/Stand/Reliabiliiy%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%20oP/`2OTerms/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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components or customer classes place different regulation reserve burdens on PacifiCorp's system
due to differences in the magnitude, frequency, and timing of their variations from forecasted
levels.
The FRS is based on PacifiCorp operational data recorded from January 2018 through December
2019 for load, wind, solar, and Non-VERs. PacifiCorp's primary analysis focuses on the actual
variability of load, wind, solar, and Non-VERs during 2018-2019. A supplemental analysis
discusses how the total variability of the PacifiCorp system changes with varying levels of wind
and solar capacity. The estimated regulation reserve amounts determined in this study represent
the incremental capacity needed to ensure compliance with BAL-001-2 for a particular operating
hour. The regulation reserve requirement covers variations in load, wind, solar, and Non-VERs,
while implicitly accounting for the diversity between the different classes. An explicit adjustment
is also made to account for diversity benefits realized because of PacifiCorp's participation in the
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.7 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.pacificop2.com/content/dgM/pcorp/documents/eg/pacificop2/enerMintegrated-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 F.1 - Portfolio Regulation Reserve Re uirements
941
Wind Solar Stand-alone Portfolio Regulation
Capacity Capacity Regulation Diversity Requirement
Requirement Credit with Diversity
[Case AMW (.MW) MW (MW) (%) (MW)
CY2017(2019 FRS) 2,750 1,021 994 47% 531
2018-2019(2021 FRS) 2,745 1,080 1,057 49% 540
Table F.2 - 2025 Flexible Reserve Costs as Compared to 2023 Costs, $/MWh
Wind 2025 Solar 2025 Wind 2023 Solar 2023
FRS FRS FRS FRS
(2024$) (2024$) (2024$) 2024$
Study Period 2025-2045 2025-2045 2025-2042 2025-2042
Flexible Reserve Cost $0.47 $0.66 $1.22 $1.53
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
8 NERC Standard BAL-002-WECC-3—Contingency Reserve:
https://www.nerc.coM/pa/Stand/Reliability%20 Standards/BAL-002-WECC-3.pdf
9 NERC Standard BAL-001-2—Real Power Balancing Control Performance:
https://www.nerc.coM/pa/Stand/Reliability%20Standards/BAL-001-2.pdf
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compliance with NERC standard BAL-003-2.10 Each type of operating reserve is further defined
below.
Contingency Reserve
Purpose: Contingency reserve may be deployed when unexpected outages of a generator or a
transmission line occur. Contingency reserve may not be deployed to manage other system
fluctuations such as changes in load or wind generation output.
Volume: NERC regional reliability standard BAL-002-WECC-3 specifies that each BAA must
hold as contingency reserve an amount of capacity equal to three percent of load and three percent
of generation in that BAA.
Duration: Except within 60 minutes of a qualifying contingency event, a BAA must maintain the
required level of contingency reserve at all times. Generally, this means that up to 60 minutes of
generation are required to provide contingency reserve, though successive outage events may
result in contingency reserves being deployed for longer periods. To restore contingency reserves,
other resources must be deployed to replace any generating resources that experienced outages,
typically either market purchases or generation from resources with slower ramp rates.
Ramp Rate: Only up capacity available within ten minutes can be counted as contingency reserve.
This can include "spinning" resources that are online and immediately responsive to system
frequency deviations to maintain compliance with frequency response obligations under BAL-
003-1.1, as well as from "non-spinning" resources that do not respond immediately, though they
must still be fully deployed in ten minutes.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
10 NERC Standard BAL-003-2—Frequency Response and Frequency Bias Setting:
https://www.nerc.comZpa/Stand/Reliability%20 StandardsBAL-003-2.pdf
" 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.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
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
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)/0.1 Herts (Hz). To comply with the standard, a BAA'S median measured frequency
response during a sampling of under-frequency events must be equal to or greater than its
frequency response obligation. PacifiCorp's 2024 frequency response obligation was 21.7
MW/0.1Hz for PACW, and 62.9 MW/0.1Hz 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.
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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
https://www.nerc.com/comm/OC/RS%2OLandin %g 2OPage%20DL/Frequency%2OResponse%2OStandard%2OReso
urcesBA FRO Allocations_for OY2024.pdf
13 NERC Standard BAL-002-3—Disturbance Control Standard—Contingency Reserve for Recovery from a
Balancing Contingency Event:hllps://www.nerc.coM/pa/Stand/Reliability StandardsBAL-002-3.pdf
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
contingency reserve or as regulation reserve. Contingency events are relatively rare while
opportunities to deploy additional regulation reserve in EIM occur frequently. As a result,
PacifiCorp typically schedules its lowest-cost flexible resources to serve its load and blocks off
capacity on its highest-cost flexible resources to meet its contingency obligations, subject to any
ramping limitations at each resource. This leaves resources with moderate costs available for
dispatch up by EIM, while lower-cost flexible resources remain available to be dispatched down
by EIM.
Regulation Reserve Data Input
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.I4
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 was
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(OATT). This includes EIM base schedule data(or forecasts)from all
resources included in the EIM network model at transaction points. EIM base schedules are
submitted by transmission customers with hourly granularity, and are settled using hourly data for
load, and fifteen-minute and five-minute data for resources. A primary function of the EIM is to
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.
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PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
measure load and resource imbalance (or deviations) as the difference between the hourly base
schedule and the actual metered values.
A summary of the data gathered for this analysis is listed below, and a more detailed description
of each type of source data is contained in the following subsections.
Source data:
- Load data
o Five-minute interval actual load
o Hourly base schedules
- VER data
o Five-minute interval actual generation
o Hourly base schedules
- Non-VER data
o Five-minute interval actual generation
o Hourly base schedules
Load Data
The load class represents the aggregate firm demand of end users of power from the electric
system. While the requirements of individual users vary,there are diurnal and seasonal patterns in
aggregated demand. The load class can generally be described to include three components: (1)
average load,which is the base load during a particular scheduling period; (2)the trend,or"ramp,"
during the hour and from hour-to-hour; and (3) the rapid fluctuations in load that depart from the
underlying trend. The need for a system response to the second and third components is the
function of regulation reserve in order to ensure reliability of the system.
The PACE BAA includes several large industrial loads with unique patterns of demand. Each of
these loads is either interruptible at short notice or includes behind the meter generation. Due to
their large size, abrupt changes in their demand are magnified for these customers in a manner
which is not representative of the aggregated demand of the large number of small customers
which make up most PacifiCorp's loads.
In addition, interruptible loads can be curtailed if their deviations are contributing to a resource
shortfall. Because of these unique characteristics, these loads are excluded from the FRS. This
treatment is consistent with that used in the CAISO load forecast methodology (used for PACE
and PACW operations),which also nets these interruptible customer loads out of the PACE BAA.
Actual average load data was collected separately for the PACE and PACW BAAS for each five-
minute interval. Load data has not been adjusted for transmission and distribution losses.
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
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
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,
"Increasing the relative amount of[VERs] on a system can increase operational uncertainty that
the system operator must manage through operating criteria, practices, and procedures, including
the commitment of adequate reserves."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 (GATT or legacy contract transmission customers); (2) PacifiCorp-owned resources;
and (3) other PacifiCorp-contracted resources, such as qualifying facilities, power purchases, and
exchanges. In total, the FRS study period includes an average of 2,745 megawatts of wind and
1,080 megawatts of solar.
Non-VER Data
The Non-VER class is a mix of thermal and hydroelectric resources and includes all resources
which are not VERs, and which do not provide either contingency or regulation reserve. Non-
VERs, in contrast to VERs, are often more stable and predictable. Non-VERs are thus easier to
plan for and maintain within a reliable operating state. For example, in Order No. 764, FERC
suggested that many of its rules were developed with Non-VERs in mind and that such generation
"could be scheduled with relative precision.""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-VERs.
In the FRS, resources that provide contingency or regulation reserve are considered a separate,
dispatchable resource class. The dispatchable resource class compensates for deviations resulting
from other users of the transmission system in all hours. While non-dispatchable resources may
offset deviations in loads and other resources in some hours, they are not in the control of the
system operator and contribute to the overall requirement in other hours. Because the dispatchable
resource class is a net provider rather than a user of regulation reserve service, its stand-alone
regulation reserve requirement is zero (or negative), and its share of the system regulation reserve
requirement is also zero. The allocation of regulation reserve requirements and diversity benefits
is discussed in more detail later in the study.
Regulation Reserve Data Analysis and Adjustment
Overview
This section provides details on adjustments made to the data to align the ACE calculation with
actual operations, and address data issues.
15 Order No. 764 at P 281;Order No. 764-B at P 210.
16 Order No. 764 at P 20(emphasis added).
17 Id. at P 92.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Base Schedule Ramping Adjustment
In actual operations, PacifiCorp's ACE calculation includes a linear ramp from the base schedule
in one hour to the base schedule in the next hour, starting ten-minutes before the hour and
continuing until ten-minutes past the hour.The hourly base schedules used in the study are adjusted
to reflect this transition from one hour to the next. This adjustment step is important because, to
the extent actual load or generation is transitioning to the levels expected in the next hour, the
adjusted base schedules will result in reduced deviations during these intervals, potentially
reducing the regulation reserve requirement. Figure F.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
v
2700
V
N
2600
2500
I
2400
—Base Schedule —Adjusted Base Schedule
2300
� 4�, 4, Ln Ln cn Ln Ln Ln rn rn rn rn rn m m m m m m m --, --, -_1 -_1
_P� ui ui O O I- N N N W W � � In In O O N N N N W W � _r� ui In O O N N
In O In O cn O Ln O cn O cn O to O to O In O to O to O In O to O to O to 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:
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PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
• Telemetry spike/poor connection to meter
• Missing meter data
• Missing base schedules
VERs:
• Curtailment events
Load in PacifiCorp's BAAS changes continuously. While a BAA could potentially maintain the
exact same load levels in two five-minute intervals in a row, it is extremely unlikely for the exact
same load level to persist over longer time frames.When PacifiCorp's energy management system
(EMS) load telemetry fails, updated load values may not be logged, and the last available load
measurement for the BAA will continue to be reported.
Rapid spikes in load telemetry either up or down are unlikely to be the result of conditions which
require deployment of regulation reserve, particularly when they are transient. Such events could
be a result of a transmission or distribution outage, which would allow for the deployment of
contingency reserve, and would not require deployment of regulation reserve. Such events are also
likely to be a result of a single bad load measurement. Load telemetry spike irregularities were
identified by examining the intervals with the largest changes from one interval to the next, either
up or down. Intervals with inexplicably large and rapid changes in load, particularly where the
load reverts within a short period,were assumed to have been covered through contingency reserve
deployment or to reflect inaccurate load measurements. Because they do not reflect periods that
require regulation reserve deployment, such intervals are excluded from the analysis. During the
study period, in PACW 15 minutes' worth of telemetry spikes were excluded while no telemetry
spikes were observed in PACE. There were also 10 minutes' worth of missing load meter data,
and 82 hours of missing load base schedules.
The available VER data includes wind curtailment events which affect metered output.When these
curtailments occur, the CAISO sends data, by generator, indicating the magnitude of the
curtailment. This data is layered on top of the actual meter data to develop a proxy for what the
metered output would have been if the generator were not curtailed. Regulation reserve
requirements are calculated based on the shortfall in actual output relative to base schedules. By
adding back curtailed volumes to the actual metered output,the shortfall relative to base schedules
is reduced, as is the regulation reserve requirement. This is reasonable since the curtailment is
directed by the CAISO or the transmission system operator to help maintain reliable operation, so
it should not exacerbate the calculated need for regulation reserves.
After review of the data for each of the above anomaly types, and out of 210,216 five-minute
intervals evaluated, approximately 1,000 five-minute intervals, or 0.5% of the data, was removed
due to data errors. While cleaning up or replacing anomalous hours could yield a more complete
data set, determining the appropriate conditions in those hours would be difficult and subjective.
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.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Regulation Reserve Requirement Methodology
Overview
This section presents the methodology used to determine the initial regulation reserve needed to
manage the load and resource balance within PacifiCorp's BAAs. The five-minute interval load
and resource deviation data described above informs a regulation reserve forecast methodology
that achieves the following goals:
- Complies with NERC standard BAL-001-2;
- Minimizes regulation reserve held; and
- Uses data available at time of EIM base schedule submission at T-40.18
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-VERB; 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.
18 See footnote 12 above for explanation of PacifiCorp's use of the T-40 base schedule time point in the FRS.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
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
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
19 NERC Standard BAL-001-2,hllps://www.nerc.coM/pa/Stand/Reliability%20Standards/BAL-001-2.pdf
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
circumstances,rather than acquiring resources for extremely unlikely events. The reliability target
balances the cost of additional capacity against the benefit of incrementally more reliable
operation. By planning to curtail firm load in the rare event of a regulation reserve shortage,
PacifiCorp can maintain the required 100 percent compliance with the BAL-001-2 standard and
the Balancing Authority ACE Limit.This balances the cost of holding additional regulation reserve
against the likelihood of regulation reserve shortage events.
The FRS assumes that a regulation reserve forecasting methodology that results in 0.50 loss of
load hours per year due to regulation reserve shortages is appropriate for planning and ratemaking
purposes. This is in addition to any loss of load resulting from transmission or distribution outages,
resource adequacy, or other causes. The FRS applies this reliability target as follows:
• If the regulation reserve available is greater than the regulation reserve need for an hour,
the LOLP is zero for that hour.
• If the regulation reserve held is less than the amount needed,the LOLP is derived from the
Balancing Authority ACE Limit probability distribution as illustrated below.
Balancing Authority ACE Limit: Allowed Deviations
Even if insufficient regulation reserve capability is available to compensate for a thirty-minute
sustained deviation,a violation of BAL-001-2 does not occur unless the deviation also exceeds the
Balancing Authority ACE Limit.
The Balancing Authority ACE Limit is specific to each BAA and is dynamic,varying as a function
of interconnection frequency. When WECC frequency is close to 60 Hz, the Balancing Authority
ACE Limit is large and large deviations in ACE are allowed. As WECC frequency drops further
and further below 60 Hz,ACE deviations are increasingly restricted for BAAs that are contributing
to the shortfall, i.e., those BAAS with higher loads than resources. A BAA commits a BAL-001-2
reliability violation if in any thirty-minute interval it does not have at least one minute when its
ACE is within its Balancing Authority ACE Limit.
While the specific Balancing Authority ACE Limit for a given interval cannot be known in
advance,the historical probability distribution of Balancing Authority ACE Limit values is known.
Figure F.2 below shows the probability of exceeding the allowed deviation during a five-minute
interval for a given level of ACE shortfall. For instance, an 82 MW ACE shortfall in PACW has a
one percent chance of exceeding the Balancing Authority ACE Limit. WECC-wide frequency can
change rapidly and without notice, and this causes large changes in the Balancing Authority ACE
Limit over short time frames. Maintaining ACE within the Balancing Authority ACE Limit under
those circumstances can require rapid deployment of large amounts of operating reserve. To limit
the size and speed of resource deployment necessitated by variation in the Balancing Authority
ACE Limit, PacifiCorp's operating practice caps permissible ACE at the lesser of the Balancing
Authority ACE Limit or four times 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/documentsiMC-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
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.2 -Probability of Exceeding Allowed Deviation
100%
90% -
0
0 80%
0 70%
3 60%
0
Q
tin 50%
c
1) 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(501h 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.
125

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 Forecast' + 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).
126

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% .. .
rn
3:_r.:1>g-> is .a- ..� ;..•: . .�•
.i"-f
QV
100/0 ZJf it„,
0% L.•.
0% 10% 20% 30% 40% 500/6 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
Figure FA -Wind Regulation Reserve Requirements by Forecast Capacity Factor- PACW
PACW Wind-Relationship between Forecast and Error
45%
40%
35%
c
100/0
5%
O%
O% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
127

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%
T
m 40%
rya �'te•=�};_
v -
rn Tr!� •ice:-y..•. _
ai ;;•hg-y ?•jam` �2t '~".�:•:i.
2501.
s
10%
5%
O%
0% 10% 20% 30% 40% 500/b 60% 70% 80% 90%
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°io
50%
45%
T
a
40%
ra
0 3SO/.
300/6
150/b
10%
5%
0%
0% 10% 20% 30% 40% 50% 60% 70% 80% 904
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
128

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 • All
22%
20%
x.
w - X.>�.i;Y r, r`• w+' ..t�'.• 'i;;i; ':. R�id.},'4' a:'.:S .�l
. •�._{.- •fig- ,�.. :t`,+
2% _
00/. Aj
20% 30% 40% 50% 60% 70% 800/0 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%
> 18%
16%
m 14% -
@ LU
2% 2: y
0%
20% 30% 40% 50% 60% 70% 80% 9
Forecast as a Percentage of Capacity
Reserves
M Reserve Requirement
129

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%
0
-
a
0 4.O% r,
rn c
c 3.5% E
2 2.5°/O i •�Y.J.•t. '."t}�:.•+±'r•a 4.-.�•i:.
1.5°/O
1.0%
0.5%
0.0°/O
30% 40% 50% 60% 70% 809E U
Forecast as a Percentage of Peak Load
Reserves
M Reserve Requirement
Figure F.10— Stand-alone Load Regulation Reserve Requirements- PACW
PACW Load-Relationship between Forecast and Error
7.0%
&5%
6.0%
5 0% •. ��
o i
4.5% �q -
0 4.0% i..
3.0 r°
rya 2.5%
1.5% 'i 't'• '
1.0% �: 7.• ..
o.s r°
0-0%I
30% 40% 50% 60% 70% 80% 90%
Forecast as a Percentage of Peak Load
Reserves
M Reserve Requirement
130

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) (M 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
kortfolio Diversity and EIM Diversity Benefits
The EIM is a voluntary energy imbalance market service through the CAISO where market
systems automatically balance supply and demand for electricity every fifteen and five minutes,
dispatching least-cost resources every five minutes.
PacifiCorp and CAISO began full EIM operation on November 1, 2014. 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-VERB, 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,
131

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.
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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) (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
133

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
IFast-Ramping Reserve Requirements
As previously discussed, Requirement 1 of BAL-001-2 specifies that PacifiCorp's CPSI 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 CPSI 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 CPSI 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 CPSI 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
134

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-
135

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
ncremental Requirement w/
Diversity(MW) Portfolio Diversity(%)
By Diversity Exponent 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 2007550 19 28 41 12% 9% 4%
300 200 100 32 50 79 23% 17% 7%
350 200 150 43 71 117 31% 23% 9%
400 200 200 53 90 153 37% 27% 12%
450 200 250 63 109 190 42% 31% 13%
500 200 j 300 72 128 226 46% 34% j 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
u 7,184 472% 19.2% 21.5% 23.0% 25.5% 26.5%
6,144 395% 22.9% 24.1% 25.6% 27.9% 28.5% 29.0%
U 5,104 319% 26.0% 27.3% 29.2% 30.7% 30.7% 30.5% 29.5%
4,064 242% 30.4% 31.6% 32.9% 33.8% 32.7% 32.8% 32.8%
3,024 166% 35.0% 36.2% 38.5% 37.1% 37.6% 36.2% 33.9% 31.9%
1,575 100% 48.0% 45.8% 43.1% 39.5% 35.8% 32.2% 29.4%
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
136

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% P W. 0 22.41% 22.9%
ewe 3,669 472% 23.4% 24.8% 25.4% 41W/° 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
137

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.
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 in each year of the IRP study
horizon (2025-2045). The change in resources applies to both 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 15% 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 in each year of the IRP study
horizon (2025-2045). The change in resources applies to both 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 7% 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 2023 IRP are also shown. Integration costs in the
2023 IRP were elevated in the near term as a result of compliance with the Ozone Transport Rule.
In the absence of those requirements, integration costs in the 2025 IRP are reduced in the near
term. Integration costs fall as energy storage resources are added to the portfolio, as they can
provide operating reserves at no additional cost 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.
138

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.11 —Incremental Wind and Solar Regulation Reserve Costs
$6.00 —
t •••••• Wind (231RP)
$5.00
Solar (231RP)
c/} $4.00 �
n Wind (251RP)
U $3.00
0 Solar (251RP)
$2.00
M
$1.00
..
$0.00
Ln �.D r, oo m o N M T Ln Lo r� oo m o N M q Ln
N N N N N M M M M M M M M M M �* �* �* 'T 'T
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
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.
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.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
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.
Table F.9 - Reserve Requirements (Average MW
East Requirement West Requirement
Spin Non-spin Regulation Spin Non-spin Regulation
Year
(10-minute) (10-minute) (30-minute) (10-minute) (10-minute) (30-minute)
2025 160 160 491 84 84 106
2026 158 158 548 85 85 106
2027 161 161 555 86 86 106
2028 163 163 569 88 88 292
2029 166 166 576 89 89 188
2030 169 169 576 90 90 359
2031 172 172 626 91 91 362
2032 173 173 624 91 91 370
2033 177 177 621 93 93 387
2034 180 180 620 94 94 397
2035 183 183 621 95 95 424
2036 186 186 618 96 96 451
2037 190 190 615 98 98 476
2038 194 194 609 100 100 493
2039 198 198 607 102 102 535
2040 201 201 602 104 104 569
2041 206 206 583 106 106 577
2042 210 210 592 108 108 579
2043 213 213 591 110 110 577
2044 216 216 580 112 112 591
2045 221 1 221 1 587 114 114 612
Flexible Resource Supply Forecast
Requirements by NERC and the WECC dictate the types of resources that can be used to serve the
reserve requirements.
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PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
• 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.
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.
zz 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 2026
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.
141

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
Table F.10 - Flexible Resource SupplyForecast(Average MW)
Year East Supply West Supply East Supply West Supply
10-Minute) (10-Minute) (30-Minute) (30-Minute
2025 1,816 942 2,507 1,016
2026 2,925 942 3,629 1,016
2027 2,924 942 3,628 1,016
2028 2,920 2,113 3,602 2,188
2029 2,971 2,362 3,661 2,437
2030 3,065 3,174 3,755 3,249
2031 3,136 3,265 3,826 3,340
2032 3,313 3,390 4,003 3,465
2033 3,327 3,433 4,017 3,508
2034 3,325 3,650 4,015 3,725
2035 3,327 3,676 4,017 3,751
2036 3,308 3,750 3,998 3,825
2037 3,425 3,761 4,116 3,835
2038 3,425 4,025 4,116 4,100
2039 3,432 4,132 4,122 4,207
2040 3,029 5,097 3,705 5,246
2041 3,077 5,274 3,753 5,423
2042 3,977 5,489 4,654 5,638
2043 3,947 5,902 4,567 6,051
2044 4,449 6,099 5,069 6,248
2045 5,165 6,464 5,785 6,613
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 are
required to achieve the reserve capability 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.
142

PACIFICORP—2025 IRP APPENDIX F—FLEXIBLE RESERVE STUDY
Figure F.12 - Comparison of Reserve Requirements and Resources, East Balancing
Authority Area (MW)
6,000
5,000
4,000 .... ............�.
3,000
r
2,000
1,000
�o `'o `_ `'o `'o `'o �o `'o �o `'o �o �o �o `'o `'o �o `'o
East Spin(I 0-minute) East Non-spin(I 0-minute) East Regulation(30-minute)
East Supply(10-Minute) ........East Supply(30-Minute)
Figure F.13 - Comparison of Reserve Requirements and Resources, West Balancing
Authority Area (MW)
7,000 - -
6,000
5,000
3 4,000 .....
3,000
2,000
1,000
0
`'o `'o `'o `'o �o `'o `'o To `'o 'PO �o `'o `'o To `'o TO, To `O) 'Po XJo
West Spin(10-minute) West Non-spin(I 0-minute) West Regulation(30-minute)
West Supply(10-Minute) .... ..•West Supply(30-Minute)
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
planning,market transactions,utilization of the transmission capability between the two balancing
authority areas, and operational activities that are performed on an economic basis.
143

PACIFICORP-2025 IRP APPENDIX F-FLEXIBLE RESERVE STUDY
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.
144

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.I
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 an approximately 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).
145

PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
146

PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
Study Data
Table G.1 -Plant Water Consumption with Acre-Feet* per Year
Acre-Feet Per Year \et%IWhs Per Dear 4-year Average
Zero Cooling 4-year Gals/ GPAU
Plant Name Discharge Media 2020 1 2021 2022 2023 Average 2020 2021 2022 2023 AMH JIR'
Chehalis As 66 71 47 45 57 2.407.519 2.248.23 7 2.1 2.465 2.239.346 S ID 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 3,581,919 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 6,578,673 6,456,506 229 3.8
Naughton Yes Water 7.622 7,236 6,929 7,570 1 7.339 2.659,033 2,596,446 2.456.201 2.766.289 913 15.2
Wyodak Yes Air 336 333 324 283 319 1.-32,784 1-717,528 1779843 1_282.117 64 1.1
ffOTAL 61,675 66,532 62,550 56,688 61,861 42,115,971 45,237,97 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.
147

PACIFICORP-2025 IRP APPENDIX G-PLANT WATER CONSUMPTION STUDY
Table GA-Plant Water Consumption by
Table G.2-Plant Water Consumption by State (acre-feet) Fuel Type acre-feet)
WtJTAH PUNTS q OAL FIRED PLANTS
Plant Name 2017 2013 2019 2020 2021 2022 2023 2017 2013 2019 1 2020 2021 2022 2023
Currant Creek 116 110 101 95 113 85 133 Dave Johnston 8,231 1 8,325 8,485 7,856 6,5 71 5,901 12,770
Gadsby 100 205 281 409 339 454 184 Hinter 15,383 14,751 15.808 15,103 16,326 13,426 8,788
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 Bridger 19,047 20,067 19,893 18,184 19,103 19,076 15,054
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
Lakeside 2,698 32648 3,894 4:075 4.421 4.591 4.435 Wvodak 332 319 292 336 333 324 283
TOTAL 27,9541 28 9,1100OVI F33,218 TOTAL 59,573 63,182 3
Percent of total«ester consumption= 44.40o Percent of total water consumption= 93.1%
X1'YOAHNG PLANTS NATL"RAL GAS F]RED PLANTS
Plant Name 2017 2013 019 2021 Plant Name 2017 2018 2019 2020 2021 023
Dave Johnston 8.231 8,325 8.485 7,856 62571 5,901 12,770 Cunant Creek 116 110 101 95 113 85 13
Chehalis 54 63 66 -1 47 45
Jim Bridger 19,047 20,067 19,893 18,184 19,103 19,076 15,054 Gadsbv 100 205 281 409 339 454 184
Naughton 6,927 9,916 10:195 7,622 7,236 6,929 7,570 Lakeside 2.698 3.64S 3.894 4.075 4121 4.591 4.43;
Wyodak 332 319 292 336 333 324 283 TOTAL 2,968 3,9% 4,339 4,645 4,944 5,177 4,7%
TOTAL 34,537 38,62 38,365 33,998 33,243 32,230 35,678 Percent of total water consumption= 6.90 o
Percent of total water consumption= 55.6°o
Table G.3 - Plant Water Consumption for Plants Located in
the Upper Colorado River Basin (acre-feet)
jr ErPlant Name 2020 2021 2022
Htutter 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
\aughton 6:927 9.916 10.195 7-622 7,236 6,929 7,570
Jim Bridget 19,047 20067 1989, 18,184 19,103 19076 15,054
TOTAL , 10 54,538 54,924 48 54,684 51,148
Percent of total water consumption= 79-60 o
148

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
APPENDIX H - STOCHASTICS
Introduction
For the 2025 IRP, PacifiCorp modified its stochastic analysis to include additional parameters, to
capture sustained deviations over the course of a year, and to better reflect the relationships
between the various stochastic parameters.
In past IRPs, PacifiCorp calculated stochastic parameters such as volatility and mean reversion to
represent most parameters. These parameters produce either normally distributed or log-normally
distributed inputs. The normally distributed results for different parameters are then tied together
via a correlation matrix. This type of stochastic analysis is well suited so long as the relevant
parameters that can be reasonably characterized by a normal distribution. Given the prevalence of
wind and solar generation in recent IRPs, PacifiCorp sought to account for risks associated with
these technologies. Both technologies are dependent on weather conditions,which is also a factor
the influences load,hydro, and market prices,but wind and solar output,particularly on an hourly
basis, is not readily characterized using a normal distribution. Upon closer inspection short-term
stochastic parameters also miss much of the real-world variation in other parameters, such as 1 in
20 load conditions or dry hydro years, which represent significant deviations from normal.
Stochastic parameters can also understate the relationship between different inputs, for example,
market prices may experience larger shocks in a dry hydro year or under 1 in 20 load conditions
than would be indicated by a normal distribution.
With these factors in mind, the 2025 IRP includes stochastic analysis based on the actual eighteen
historical years, from 2006-2023. When PLEXOS uses volatility, mean reversion, and correlation
parameters to create stochastic conditions,it produces daily"shock"values that adjust inputs away
from their expected values and aligned with other inputs consistent with the correlation inputs. For
the 2025 IRP, PacifiCorp is also using daily "shock" values, but they have been calculated from
specific historical conditions so that the correlation from history is captured. Rather than
independently drawing correlated shocks for a variety of parameters, each stochastic iteration in
the 2025 IRP reflects draws of a single historical calendar year for each year of the horizon, and
reflects the patterns specific to that historical year for a range of inputs:
• Load (including weather-sensitive energy efficiency): daily variation.
• Market prices (electricity and natural gas): daily variation.
• Hydro: monthly variation.
• Wind and solar: hourly values.
• Thermal outages (existing resources): hourly values.
Once the historical period is identified, the parameters for all inputs are mapped into the forecast
period using the same pattern used in PacifiCorp's chaotic normal load forecast, which maintains
the day of the week in history and in the forecast while generally keeping contiguous blocks of
days together. These patterns provide a representative range of conditions for stochastic analysis.
The stochastic analysis for the 2025 IRP continues to reflect short-run parameters, such that
PLEXOS was not allowed to re-optimize its capacity expansion plan based on stochastic results.
Certain types of resources may provide greater value in stochastic conditions relative to the
normalized conditions used in the capacity expansion process, this concept is analogous to the
stochastic risk reduction credit applied to energy efficiency, but it has not been adopted more
149

PACIFICORP—2025 IRP APPENDIX H—STOCHASTICS
broadly at this time. Long-run parameters, such as fundamental changes in markets and policy, are
addressed through analysis of price-policy scenarios, as discussed in Chapter 8 (Modeling and
Portfolio Evaluation).
Merview
Long-term planning demands specification of how important variables behave over time. For the
case of PacifiCorp's long-term planning, important variables include natural gas and electricity
prices, regional loads, and regional hydro generation. Modeling these variables involves not only
a description of their expected value over time as with a traditional forecast,but also a description
of the spread of possible future values. The following sections summarize the development of
stochastic process parameters to describe how these uncertain variables evolve over time .
Stochastic VarialTe=7
Load
For reporting purposes, PacifiCorp produces an estimate of weather-normalized actual load for
each of its states at the conclusion of each calendar year. This helps to identify the extent that
weather conditions were a driver of retail sales. For the 2025 IRP stochastic analysis, PacifiCorp
calculated the % difference between daily average actual load for each state, and the monthly
average weather-normalized load for that state. This calculation indicates how much above or
below expectations the actual load was on each day. This calculation also retains the possibility
that a given month will be above or below normal, as the average of the actual loads need not be
equal to the average of the weather-normalized loads in a given month. The daily load factor for
each state is applied to all of the load bubbles for that state within PLEXOS, which maintains
separate data streams for different jurisdictions, even in areas that are electrically contiguous like
Walla Walla (Oregon and Washington) or Northern Utah (Utah, Idaho, Wyoming). Using a load
factor, rather than actual hourly load, allows for the impact of load growth over time, as well as
changing in the patterns of load, for instance increased customer generation. Figure H.1 shows the
variation in forecasted load conditions modeled in the 2025 IRP stochastic analysis.Note that these
same load shocks are also applied to the energy efficiency savings from temperature-sensitive
bundles (heating and cooling). The savings from these measures is already aligned with
PacifiCorp's normalized load forecast (more savings on the highest load data), applying the same
shocks to energy efficiency ensures that the savings follows the high load conditions, whenever
and as often as they occur. This should increase the value of temperature-sensitive energy
efficiency with both higher energy value and reliability benefits.
'A stochastic or random process is the counterpart to a deterministic process. Instead of dealing with only one
possible reality of how the variables might evolve over time,there is some indeterminacy in the future evolution
described by probability distributions or random draws.
150

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
Figure H.1 —Chaotic Normal and Historical Load Patterns
11,000
10,500 - - - - - - - - - - - - - - - - - •- - - - - - - - - - - - - - - - - - - - -
� 10,000 - - - - - - - - -
- - - - - - - - - - - - - - - - - - -
0
J 9,500
E
0) 9,000 ........ ... .. ............. ...... ..............I.......
8,500 —F,
an
fD 8,000
> 11tti , I
Q 7,500
.50 .50 ,y�0 ,50 ,y�0 ,50 ,�O .50 .50 ,y�0 ,50 ,y�0 ,50 ,�O ,50 .50
\'05
Chaotic Normal •.••.......•• Normal (Average)
- - - - Chaotic Norm. Peak+lStDev - - - - Chaotic Norm. Peak+2StDev
—Load_2013 (High) Load_2015 (Low)
Market Prices
For the 2025 IRP stochastic analysis,PacifiCorp calculated the%difference between daily market
actual prices and monthly average actual market prices. Unlike load, PacifiCorp does not have a
readily available "normalized"market price, so it is likely that some of the market price response
relative to expected conditions is not captured. For example, a wet hydro year would result in a
lower monthly average market price on all days, which would not be apparent in the daily price
factors. That is just one of many regional factors (i.e., external to PacifiCorp) that impact market
prices and could be more thoroughly assessed in future analysis. As a part of the analysis for 2025
IRP, PacifiCorp identified that recent market prices have exhibited significantly higher volatility
since 2018,relative to prior years, as shown in Figure H.2. Electricity supply and demand must be
matched from moment to moment and volatile market prices may reflect growing concerns that
available supply may be insufficient, potentially because of load growth, retirement of
dispatchable resources, increasing penetration of renewable resources, and/or more extreme
weather conditions. PacifiCorp does not expect these drivers to revert to previous conditions (i.e.,
lower load,dispatchable resources additions outpacing increases in load, fewer renewables, or less
volatile weather), so the variability of historical market prices was increased to align with more
recent conditions. This technique retains the relative pattern of pricing across each month while
increasing the spread between days with above average prices and days with below average prices.
151

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
Figure H.2—Historical Market Price Variation
1200%
—COB
1000%
F
—Palo Verde
0
0 800%
u
°>° —Mid-Columbia
a
T
600%
0
m
U
C
f9 400%
d
U
L
a
Y 200%
LL16
0%
000 00� o00 0°0' otio otiti otiti oti3 otio otih otio otio otio otio oyo o�ti o�ti ory�
',\ 4
1\ti \ti\ti 1\hti 1\h0 \'L 1\yti 4\ 4\ titi\� \ti\ti 4\1\(L 4\�ti 4\
� y\titi ti\y0 4\
-200%
Hydro Conditions
Hydro is a relatively small portion of PacifiCorp's portfolio, representing about seven percent of
the energy supply in 2025. Because several of its river systems have flexibility to smooth out some
variation, notably the Lewis River and Mid-Columbia, PacifiCorp's hydro analysis is based on
monthly variation relative to the average of all historical years. The percentage change in hydro
output is applied to the climate change-adjusted hydro forecast, so climate impacts continue to be
incorporated. Figure H.3 shows that the highest and lowest hydro months are clustered. 2017 has
five of the highest months,while 2021 has four of the lowest months. Previous analysis that relied
on random weekly draws would have been unlikely to capture this behavior.
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PACIFICORP—2025 IRP APPENDIX H—STOCHASTICS
Figure H.3—Historical Hydro Variation
Month 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Average
1 487 449 495 523 557 586 411 351 528 448 343 613 384 482 499 393 436 481
2 382 352 336 321 419 595 463 503 464 559 566 471 214 515 335 246 229 421
3 402 526 363 375 341 506 520 305 570 293 593 644 353 261 296 268 420 228 404
4 336 380 331 375 328 481 341 349 383 234 356 522 426 390 320 232 261 333 354
5 393 284 373 503 331 504 392 362 415 F2 22 304 549 337 346 364 258 368 422 373
6 346 263 467 365 442 438 382 308 251 226 253 430 264 299 279 225 363 291 327
7 217 230 342 208 249 374 283 236 229 201 204 292 220 210 205 169 226 203 239
8 194 199 229 133 161 1 255 1 244 190 189 136 171 175 173 181 152 125 155 134 178
9 173 172 200 138 174 260 177 165 147 120 155f 262 147 194 78 103 156 191 167
10 243 253 231 183 279 301 243 287 294 F1471 373 178 260 164 166 189 188 245
11 623 408 447 396 510 542 597 378 551 442 594 71� 316 F274 358 535 304 380 463
12 631 315 390 636 436 644 334 651 601 559 630 413 322 457 420 310 561 499
Average 406 352 341 325 358 423 416 315 377 298 385 454 325 278 305 277 283 300 348
0/16 c h g 16% 1% -2% -7% 3% 21% 19% -10% 8% j!6 11' 30" -20�� -131'- -20%
Lowest monthly Highest monthly
Wind and Solar Output
Wind and solar are already a large part of PacifiCorp's portfolio,representing more than a third of
energy supply in 2025 and projected to be more than half of the energy supply by 2030. With the
growing reliance on these technologies, their variability is a key component of both cost and
reliability. PacifiCorp's transmission system provides access to a wide range of geographic
locations. This provides access to locations with the highest annual capacity factors, as well as
opportunities for diverse deployment of wind and solar generation to reduce the impact of
transmission congestion and localized weather conditions.
For the 2025 IRP, PacifiCorp contracted with Hendrickson Renewables2 to develop historical
hourly wind and solar generation profiles for both its existing portfolio and for proxy resource
locations. Some existing resources located in close proximity were evaluated in aggregate for this
analysis. The methodology used by Hendrickson Renewables is described below.
For each solar resource,hourly irradiance, and weather data specific to the location were extracted
from the Vaisala satellite irradiance dataset and PVsyst model was configured and run for each
project site to simulate energy output. For existing facilities, the monthly results were tuned to
match historical actual generation from 2020 through 2023. For contracted facilities that do not
yet have actual generation data, the results were tuned to match the expected output per the
contract. The resulting time series do not include degradation effects,which are applied within the
IRP modeling. For proxy locations, annual energy production was reduced by 3% to account for
additional availability losses that are not part of the PVsyst model and tuned so that the long-term
aggregated energy output matched that targeted annual energy production, again prior to
degradation. Small-scale solar resources have the same generation profile as utility-scale in a given
location as the technology is equivalent and siting has limited impact on irradiance.
For each existing wind resource, hourly one-hundred-meter wind speeds and air density specific
to the location were extracted from the ERA5 reanalysis data set. Wind speeds were also modified
Z https://hendricksonrenewables.com/
153

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
to account for air density effects using International Electrotechnical Commission(IEC)standards.
The end result is a project-specific power curve and adjusted wind speed data that aligns with the
historical actual generation by month from 2020 through 2023. For each onshore proxy wind
resource, the Global Wind Atlas was used to estimate hub-height-specific annual average wind
speeds. For the Offshore Brookings project, multiple references were reviewed, and Hendrickson
determined a 10.5 m/s annual average wind speed at the specified 137m hub height. Proxy wind
projects are also based on the ERA5 dataset and have gross energy production that is reduced by
total losses of 20%. Small-scale wind resources may use different technology (such as lower hub
heights and smaller turbines) and may be sited in less favorable locations (existing transmission
and distribution infrastructure may not be near prime wind sites), so the 2025 IRP includes small-
scale-specific wind generation profiles for the west side of its system,where there is greater interest
in small-scale resources. Small-scale wind resources on the east side of the system have the same
generation profile as utility-scale wind resources in a given location.
Figure HA shows the annual variation in proxy wind and solar generation for the variety of
potential locations considered in the 2025 IRP. The annual variation in wind is higher solar, with
individual locations varying by more than ten percent of the annual output (e.g., a three percent
capacity factor decrease on a thirty percent annual capacity factor). The average across the wind
fleet can also vary by nearly that amount, as the lowest year (2013) is approximately 9.8% less
than the annual average. Solar resources change by a smaller amount as the lowest year (2017) is
only 1.8% below the annual average. This annual variation is important, particularly for
compliance with clean energy requirements in Oregon and Washington which include annual
reporting. But more important to the IRP optimization of costs and reliability is the hourly and
daily variation underlying these wind and solar results, the alignment of output with load, market
prices, and other wind and solar resources.
154

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
Figure HA-Historical Variation of Proxy Wind and Solar Resources
WD COR 35% 30% 33% 32% 37% 32% 35% 27% 33% 27% 37% 35% 32% 29% 33% 35% 31% 34% 33%
WDCLV 30% 28% 29% 30% 28% 33% 25% 31% 28% 33% 31% 31% 31% 32% 32% 30% 26% 30%
WD BOR/GOE 31% 32% 30% 27% 30% 35% 35% 28% 33% 28% 31% 33% 31% 28% 32% 31% 28% 25% 30%
WD HTG 25% 28% 28% 28% 29% 27% 26% 29% 26% 26% 30% 26% 29% 28% 29% 24% 27%
WD NTN/NUT/WSF 29% 31% 33% 30% 31% 329" 321A 28% 35% 28% 32% 30% 31% 30% 34% 33% 30% 23% 31%
WDSOR(Offshore) 55% 45% 49% 47% 55% 50% 49% 44% 50% 46% 50% 48% 46% 47% 48% 43% 52% 49%
WDSOR/SUM 38% 33% 36% 33% 41% 34% 37% 29% 37% 30% 39% 35% 32% 34% 33% 37% 32% 3YA 35%
WD UTS 27% 29% 29% 30% 29% 29% 30%F 25% 29% 28% 31% 32% 30% 30% 32% 31% 31% 28% 29%
WDWWA 36% 34% 36% 32% 34% 38% 37% 30% 35% 28% 34% 31% 34% 26% 39% 36% 29% 28% 33%
WD WMV 41% 38% 40% 38% 39% 38% 41% 33% 40% 34% 39% 41% 37% 33% 40% 41% 35% 38% 38%
WD BDG/WYC 37% 36% 41% 35% 38% 43% 39% 39% 43% 35% 39% 39% 39% 39% 42% 40% 40% 32% 39%
WD DJW/WYE 43% 41% 44% 41% 40% 46% 43% 42% 42% 38% 43% 40% 38% 41% 44% 40% 44% 42% 42%
WD WYN 42% 40% 39% 37% 36% 42% 41% 38% 39% 36% 41% 38% 35% 35% 39% 41% 41% 33% 39%
WDYAK 31% 31% 32% 32% 31% 33% 32% 29% 34% 28% 30% 27% 31% 28% 35% 34% 28% 28% 31%
Average Utility Scale WD 35.5%33.9%35.6%33.7%35.6%36.4%36.5%31.7%36.4%3L2%36.0%34.8%34.0%32.6%36.6%36.7%33.7%32.0% 34.6%
. � I I I I I
PVCLV 32% 32% 33% 32% 32% 32% 32% 31% 32% 32% 32% 32% 32% 32% 32% 32% 32% 32%
PV BOR/GOE 27% 28% 28% 28% 27% 28% 27% 28% 28% 28% 28% 27% 28% 28% 28% 28% 28% 28% 28%
PV HTG 29% 29% 30% 30% 29% 29% 29% 28% 29% 29% 29% 29% 30% 29% 30% 29% 30% 29% 29%
PV NTN/NUT/WSF 29% 30% 29% 29% 29% 29% 29% 28% 29% 29% 29% 28% 29% 29% 30% 29% 29% 29% 29%
PVCOR 31% 31% 31% 31% 30% 31% 31% 31% 31% 31% 31% 30% 31% 31% 32% 32% 31% 31% 31%
PVSOR/SUM 29% 30% 29% 30% 29% 29% 29% 29% 29% 29% 29% 28% 29% 29% 30% 29% 30% 29% 29%
PV UTS 30% 32% 31% 31% 31% 31% 31% 31% 32% 31% 31% 32% 31% 31% 31% 31% 31% 31%
PV WWA 26% 26% 26% 26% 26% 25% 25% 26% 26% 27% 27% 25% 26% 26% 26% 27% 25% 26% 26%
PV WMV 25% 24%1�% 24% 25% 25% 24% 24% 25% 25% 24% 26% 25% 24%
PV BDG/WYC 28% 29% 29% 29% 29% 28% 29% 28% 29% 29% 29% 28% 30% 29% 30% 29% 29% 28% 29%
PV DJW/WYE 27% 28% 27% 27% 28% 27% 28% 27% 27% 27% 28% 27% 27% 27% 29% 27% 28% 27% 27%
PV WYN 28% 27% 28% 27% 28% 27% 28% 27% 26% 27% 28% 27% 27% 27% 28% 27% 27% 27% 27%
PV YAK 27% 27% 27% 27% 26% 27% 26% 27% 27% 27% 28% 26% 27% 26% 28% 28% 27% 27% 27%
Average Utility Scale PV 28.1%28.6%28.2%28.5%28.3%28.1%28.6%28.0%28.2%28.4%28.6%27.9%28.7%28.3%29.5%28.6%28.7%28.0% 28.4%
Thermal Outages
PacifiCorp used NERC-GADS data reported for its existing thermal fleet to identify the start and
end times for forced outages, maintenance outages, and derates at each unit. The actual outage
events from history are replicated in the forecast period.
Correlated Inputs
While the variation in individual inputs is a valuable enhancement, the patterns and range of
conditions when considering multiple inputs is where this historical data technique really surpasses
PacifiCorp's previous stochastic techniques. Figure H.5 shows the pattern of market prices and
load during July 2023, while Figure H.6 shows October 2020.
Actual loads for July 2023 were somewhat above the median weather-normalized level. The
pattern across the month shows that market prices tend to be higher when loads are high, and vice
155

PACIFICORP-2025 IRP APPENDIX H-STOCHASTICS
versa. This relationship between market prices and PacifiCorp's load is common. Prices also
reflect other factors, including renewable resource output,and loads of other utilities in the region.
Figure H.5--Historical Market Prices vs Load, July 2023
259% 20%
150
C> 200k o
u
S
150% 10.b Vakres
5% '
100% OR Load
r
Orb c System Load
50% UT Load
>
a` 096 10��b c Mid-Columbia
N J
Y Palo Verde
-50% -15%
N1 N1 Cn N1 c7 N1 N1 Cn N1 c7 0 VI 0
CV N N N N N N N N N N N N N N
C � ti N N N N Cq
r` N iz � z � � rZ rZ rZ iz - z
Actual loads for October 2020 were close to the median weather-normalized level. Loads are
particularly low on weekends(e.g.,Oct. 3,2020,is a Saturday).Price variation also occurs outside
of PacifiCorp's peak load days, as a result of regional conditions. In actual operations, correlation
is not perfect, so it is not intended to be so for forecasting.
Figure H.6—Historical Market Prices vs Load, October 2020
250% 20%
O 15% c
0 200%
150% 10%
Yaiues
c 100% 5% a OR Load
F 0% c System Load
cc 50% T
-5% UTLoad
a 0% l -10% M Mid-Columbia
N -0
ti
50% -15% Palo Verde
L-AC -03 -4 -4 -4 -4 N N N N N Cn
O O O O O Q O o 0 0 0 0 0 a ► a
156

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.Maps of PacifiCorp's
service area overlaid with 2025 IRP preferred portfolio incremental resource additions by location are also presented. See the below
tables for a list of cases presented here.
Table I.1 —Price-Policx Case Definitions
Price-Policy Existing Coal(') Existing Gas(b) Other Existing Resources Proxy 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,offshore wind,storage,natural gas,transmission,DSM,purchases,and sales,etc.
Table I.2—Portfolio Variants
Ampillir 1 i Refer
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 convert to gas by January 1, 2032 -
Offshore Wind Counterfactual to the Preferred Portfolio selection: -
Offshore wind must be selected
No Forward No nuclear, hydrogen storage, 100-hour storage or -
Technology biodiesel peaking
Geothermal Counterfactual to the Preferred Portfolio selection: -
Geothermal must be selected
Hunter Retire Require all Hunter units to retire no later than l/1/2030 -
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
157

158

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
20251
Preferred Portfolio
Figure I.1: 2025 IRP Preferred Portfolio Incremental Resource Additions 2025-2030
Yakima and Walla Walla WA
2028-122 MW Solar
2028-21MWWind F CentralORandSLmr­rla1e
2028-865 MW 4-hour Battery 2028-100 MW Solar
(-1OO MW at Chehahsl 2028-254 MW 4-hour Battery
2028-393 MW Walla Walla Tx_ 2028-400 MW Summerlake Tx.Inter.
Inter. �+ 2028-152 MW Cent ra 10 R Tx-I nte r.
2028-628 MW Ya ki ma Tx.I nte r. - 2029-138 MW Sol a r
2029-42 MW Solar - - _�-- 2029-100 MW4-hour Battery
2029-114 MW 4-hour Battery 2030-596 MW Solar
203D-1.260 MW Solar \ y 20",472MWWind
2030-78O MW Wind 2030-128 MW 4-hour Battery
2030-168MW4-hour Battery -/ 2030-67 MW 100-hou r Batte ry 2029-27
2030-238 MW 100-how Battery 2030-670 MW Summerlake to MW 4-hour
2030.400 MW Yakima Tx.Inter, Cerdrral ORTT�+x.Inter. Battery
tr
Portland North Coast ❑ l
2030-56MW 100 hour ��
Battery thern OR and Y:illa mene'VsUeti
2028-26 MW 4-hour Battery 4 8`"lii■ '8��'
2028-199 MW Willamette ValleyTx. f T
Inter. Bndaer and DJ,'Y,tic da,: ❑ Solar
2029-594MWWind � 2029-1Naughtc0 0MW 2029-1O0MWWind �
2029.393MW Willamette Valley Tx. , .J �-10 - 2030-100MWWind ❑ Wind
Inter. ✓ 203D-100MW
J. 203D-154 Solar Wind
2030-149MW10O-hourBattery - El Batter
ElPumped Hydro
• s
Southern UT
zozs-zSOMwutah South to ❑ Non-Emitting Peaker
r _ t1,. +•,{��' Wasatch Front Tx-Inter.
2028-20OMW Utah Southto
i
Wasatch Font Tx.Inter. Nuclear
L`A Market
0Transmission
159

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Figure I.2: 2025 IRP Preferred Portfolio Incremental Resource Additions 2031-2035
Central OR and Summerlake
2031-22 MW 100-hour
Battery
2032-73 MW 4-hour Battery
�t , 2033-276MWSolar
2033-39MW4-hourBattery
2033-518 MW Central OR
< Tx.lnter.
2034-220 MW Solar BridrerandNaughton
2034-210 MW 4-hour
� 2031-89 MW Solar(Bridger)
PortlandP.-rh1- s Battery 2031-100 MW Wind(Bridger)
2031-18 MW 100- 2035-134MWWind 2031-100 MW Solar
hour Battery 2035-20MW4-hourBattery (Naughton)
2032-500 MW Nuclear
( (Natriurn")
Southern OR and Willamette VaBev
2031-181MWSolar Solar
2031-48 MW 100-hour Battery ( - D1iM;owk
2031.231 MW Southern OR Tx.I nter. 2031-2"MW Wind
2032-248MWSolar _ ® Wind
2032-46 MW 4-hour Battery
2032-300 MW Souther OR Tx.Inter. ❑
2033-152 MW Solar Battery
2034-25 MW Solar 2031-406 M W Solar
2034-27MWWind Pumped Hydro
2035.37 MW Solar
2035-213 MW Wind
Non-Emitting Peaker
So�lhern UT
2031-74 MW Sola r
Nuclear
Market
Transmission
160

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
Figure I.3: 2025 IRP Preferred Portfolio Incremental Resource Additions 2036-2040
Yalama and Walla Walla WA
2038-122 MW Solar
2038-21 MW Wird
2038-129 MW 4-hour Battery
2039-42 MW Solar Central OR and Summerlake
2039-67MW4-hour Battery _r,1j�, "J"-�1/� 2036-39 Mw Wind
2039-670MW Walla Wallato r 2036-47MW4-hour Battery
Central ORTx.Inter. `��t' - ,ram 2037-173MWWind
2040-1,260MWSolar 'F 2038-100MWSolar - -
2040-780MWWind f 2038-37MWWind
n 2038-42 Mw 4-hour Battery
,! 2038-20 MW 100-hour Battery
'� - 2039-654 MW Solar
2040-596 MW Sola r
Portland North Coast - 2040-778 MW Wind
2038-16 MW 100-hour 2040-230 MW 100-hour Battery
Battery ` t_
2040-192 MW 100-hour Am 1
Battery
Bridger and Naughtcr Solar
D17Wvodal:
r I' 2039-SOOMWWind 203g_100M4VNlind
Southern OR and Willamette VaBev - --=-�—'
2036-132 MW Solar (�,:r' (Bndger) 2040.100 MN!Nlind
%' 2oao-looMWWind Wind
2038-309MWSolar ;" ff/I},�J,'�
;' El
Bnd er
2038-43 MW 100-hour Battery 1 .���,, !• / ,( g )
2039-SsdMWWind i �. . .'�� ` ,/ ❑ Batter
2039-18 MW 100-h54 our Battery Ar - y Y
2040-1MWSolar _ � •��-'f Ij•�,'r 'f► ,�:''6�
2040-107MW4-hour Battery 'y`;� - - .�= '-�• Pumped Hydro
2040-512 MW 100-hour Battery Z �r , ��9�� El
Non-Emitting Peaker
Nuclear
i Market
UJ
'- ElTransmission
161

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Figure L4: 20 IRP Preferred Portfolio Incremental Resource Additions 2041-2045
Central OR and S_mr-erlAe
2041.13 MW Solar
2041-50 MW Wind
Yakima and Walla Walla WA 2041-25 MW 4-hour Battery
2041-19MWBiodieselPeaking 2041-25MW100-hour Battery
2042-9 MW Solar
2041-12MW4-hour Battery 2043 276MWSolar
2043.4MWBiodieselPeaking 2043-20MWWind
2045-18 MW Biodiesel Peaking Brid¢er and
M
2045-12 MW 4-hour Battery 2043-179 W 100-hour Battery Nauphton
2044-310 MW Solar 2041-188 MW Solar
2044-47 MW 100-hour Battery 2041-100MWWind
2045.17MWSolar 2042-179MW4-
Portland North Coast 2045-133MWWind hour Battery North err WY
2041-21 MW 100-hour 2045-131 MW 100-hour Battery 2044-31 MW 4-hour
2044-19 MW 4-hour Battery
Battery - Battery
2042-43 MW 100-hour Battery 2045-395 MW 4-
2043-60 MW 100-hour Battery how Battery
2044-40 MW 100-hour Battery ':.'Y East
2045-61 MW 100-hour Battery - 2045-12MW4-hour
Gcsh�n IC ❑ Battery
2 MW -
j y 4-hour-hour Battery 4�
Southem OR and Willamette Va lLey r ❑ Solar O�c)r
2041-291MWSolar 1 D1�Wvodak
2041-30MW4-hour Battery Wasa' -Frcn, 2041-244MWWind
2041-56 MW 100-hour Battery 2042-104 MW 100-hour 2042.221 MW 4-hour ❑ Wind
2042-248 MW Solar Battery -%. Battery
2042-123 MW 100-hour Battery 2044-99 MW 4-hour Battery
2043-152MWSolar 2045-272 MW 4-hour � �
2043-158MW100-how Battery Battery Hunter UT ❑ Battery
2044-229 M W Solar 2041-406 M W Solar
20"-27MWWind
❑ Pumped Hydro
2044-105 MW 100-hour Battery ,
2045-105 MW Solar
2045-213MWWind '_ - -�thernUT ❑ Non-Emitting Peaker
2045-161 MW 100-hour Battery 2041-74MWSolar
7' 2042-267 MW 4-hour Battery
++ 2044-126MW4-hourBattery Nuclear
-_ ✓ 2045-14MW4-hour Battery `
Market
Transmission
162

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
2025 IRP Portfolio Summaries
Preferred Portfolio
Sunmary Portfolio Capacity by Resource Type and Year,Installed MW
Im;talled Capacity,M
Resource :0:5 :0:6 1 :0:7 1 :0:8 1 :0:9 1 :030 1 2031 1 2032 1 :033 2094 1 :035 1 2036 2037 2038 2039 2040 2041 2042 2043 2044 204E Total
Expansion Options
Gas-CCC I
Gas.P-1cin_e - - - - - - - - - - - - - -
Nuclear _CO NCO
- - - - - - - - - - - - - -
ReneRable P-Akins 19 - 4 18 41
DS2s4-Enern Effie suet SS 239 261 329 291 299 295 299 315 347 314 293 301 303 315 238 205 182 5.436
DSTf-Demand Response S 21 120 99 1 3 3 21 112 18 5 24 61 106 29 26 52 789
Rena- ble-Wind '94 1,452 344 29 347 40 175 37 376 50 20 96 3,782
Renewable-Small Scale Wind
Rene- ble-Utility Solar 180 1,690 949 240 403 225 13 1 554 1C4 12 197 75 4,765
Renewable-Small Scale Solar - - - 320 18 26 21 30 132 309 - 110 - - f14336 1,147
Renewable-Geothermal - - - - - - - - - -Renetvable-Batten.<3 hog - - - 1.146 242 296 - 119 39 210 20 47 175 67 113 6- -.3 4,451
Renee able-Batten.8-23 hogReae cable-Batten.24—hog 511 91 4 3 4 4 11 83 37 939 107 319 4C2 3.073
Other Renewable - - - - - - - - -
StoraEe-Other - - - - - - - - - -
Existing Unit Changes
Ccal--I nt RetifKnents-Minority Orn N(3
(33) (123) (148) 356
Coal Plant Retirements - (220) - - - - - - - - - - - - -
Coal Plant Ceases as Coal (205) (700)
Coal-CCS 526
Coal-Gas Conversions 205 Gas Plant Retirements - - - - - - - - - - - - - - - - -
Retire-Hydro
Retire-Non-Thermal (3) (32) (3i
Retire-Rind - - - - - - - - - -
Retire-Solar
- - - - - - - - - - - - - - - -
Expire-Wind PPA 64 (99) (26C 1 (6%)
Expire-Solar PPA - (2) (5 (100) - (230) (407)
Empire-QF (47) (3) (50)
Expire-Other (20) 500
Total 110 1 464 1 209 1 1.417 1 1 153 1 4.229 1 1,505 1 1.177 1 772 1 7S3 1 716 1 559 1 546 1 904 1 956 1 1.857 1 3311 1,453 1 (31) 994 1,530
163

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Oregon Full Jurisdictional Portfolio
Summary Portfolio Capacity b�Resource T�pe and Year,InstaUed IM
F Installed Capacity,MW
Resource 2025 2026 1 2027 1 2028 1 2029 2030 2031 2032 1 2033 2034 2035 2036 2037 2038 2039 2040 1 2041 1 2042 1 2043 1 2044 204-9 Total
Expansion Options
Gas-CUT - - - - - -
Gas-Peaking - - - - - - - - - -
Nuclear 50.0 500
Renewable Peaking -- - 19 - 4 -
;S 41
- - - - - - - - - - - - -
DSA1-Energy Efficiency SS 201 209 220 237 306 280 283 28C 300 309 333 303 283 291 266 286 252 230 189 5,239
DSM-Demand Response -S 2 53 17 9 53 5 1 3 3 11 239 15 50 23 4 100 9 50 25 710
Renewable-Wind 21 1 260 1,066 1 100 1 51 29 347 1 40 175 1 37 376 50 20 96 2.668
Renewable-Small Scale Wind - - - -
- - - - - - - - - - - - - - - - - -
Renewable-Utility Solar 122 99 1,871 19 220 315 225 13 554 104 12 197 75 3,826
Fe ewaable-Small Scale Solar - - - - 320 2 18 26 21 30 132 - 309 110 143 36 1.147
Renewable-Geothermal
Ren—able-Battery,<8 hoar - - - 876 255 228 31 ::B 39 210 20 83 - 1C4 100 314 58 2 2,439
Rene ble-Battery.8-23 hour - - - - - - 17 224 241
Renewable-Battery.24—hour 134 59 4 752 129 341 59 1.477
Other Renee able - - - - - - - -
Storae=--Other - - - -
- - - - - - - - - - - - - - - - -
sx:sting Unit Changes
Coal Pimt Retir� is-Minority Own (82; (33) (123) (148) (336,
Coal Plant Retirements - (220) - - - - - - - (220)
Coal Pleat Ceases as Coal (357) (205) (1,387) (1,949)
Coal-CCS 526 (526) 0
Coal-Gas Conversions 46 687 (418) 315
Gas Plant Retirements (79) (79)
Retire-Hydro
Retire-Non-Thermal (3) (35)
Retire-Wind
Retire-Solar
Expire-Wind PPA - (64) - (99) (200) - - - - - - - - (333) - (696)
Expire-Solar PPA (2) (9) (65) (230) (407)
Expire-QF (47) (3) (50)
Expire-Other 520 (20) 500
Total 110 1 153 1 201 1 1,026 1 523 1 3,444 1 302 1 1,193 1 664 1 765 ?13 1 575 1 667 1 795 1 1,005 I 2.1)S4 1 :49 1 (140) 581 1367 lSi
164

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
Washington Full Jurisdictional Portfolio
L.��j,Portfolio Capacity by Resource Type and Year,IROaHed Nf%l*
Installed Capacity-,Iff
Resource 202E 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 1 2035 2036 2037 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 1 2045 Total
Expansion Options
Gas-CCCT - - - - -
Gas-Peaking
Nuclear - - - - 500 - - - - - 500
Renewable Peaking
- - - - - - - - - - - - - - - - - - - - - -
DShI-Energy Efficiency 4 291 2 316 323 356 324 93 186 5.430 A 2
DSM-Dernaad Response :S 197 5 17 - - 43 17 24 8 5 331 31 27 107 834
Renewable-Rind - - 1,607 260 1 - 1,868
- - - - - - - - - - - - - - -
Renewable-Small Scale Rind - - - - - -
Renewable-Utility Solar 201 138 463 1,437 770 52- = S 772 249 100 1 5,076
Renewable-Small Scale Solar - - - - - -
Renewable-Geothermal
- - - - - - - - - - - - - - - - - - - -
Renewable-Batterv.<8 hour - 38 856 232 1,376 - - - - - - 129 67 66 129 149 6" 170 1,357 5.215
Renewable-Battery-;8-23 hour - - - - - - - -
- - - - - - - - - - - - - -
Renewable-Battery,24+hour - - - - -
- - - - - - - - - - - - - - - - -
Other Renewable - - - - - - - - - - - -
Storaee-Other
- - - - - - - - - - - - - - - - - -
Existing Unit Changes
Coal Plant Retirentents-\Iinoritv0-,-.n (82) (33) (12=) (148)
Coal Plant Retirements (906) (906)
Coal Plant Ceases as Coal (357) (205) (2,679) (3,241)
Coal-CCS 526 (526) 0
Coal-Gas Conversions 311 205 1,979 (330) (448) 1,717
Gas Plant Retirements - - - - - - - - - -
Retire-Hydro
Retire-Non-Thermal - - - (32) - - - - (35)
Retire-Rind
Retire-Solar
Expire-Rind PPA (64) (99) (200) (333) (696)
Expire-Solar PPA (2) (9) (100" (65) (230) (407)
Expire-QF (47) (3) (50)
Expire-Other 520 1 (20) 500
total 110 1 41S 1 264 1 SU 1 2,074 1 1,669 j 1,447 1 1.5E8 1 818 705 LOSS 615 356 1 439 1 395 1 M7 1 141 M I M 1198 656
165

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
Utah, Idaho, Wyoming, California (UIWC) Full Jurisdictional Portfolio
Summary Portfolio Capacity by Resource Type and Year,Installed MAY
Installed Capacity,AM
Resource 2026 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 204c Total
Ezpansinn Options
Gas-CCCi
Gas-Peaking - - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking - - - - - - - - -
DSIsI-EnergyEffidencv 59 -64 182 196 270 236 247 251 261 286 312 294 278 257 252 283 216 200 165 47691
DSM-Demand Response 7 112 99 - 5 39 115 3 4 70 106 43 30 32 687
Renewable-Wind 306 1 684 344 1,334
Renewable-Small Scale Wind - - -
- - - - - - - - - - - - - - - - - - -
Renewable-Utitity Solar - - - 153 12 79 668 31 123 133 3 2 65 1.269
Renewable-Small Seale Solar - - - - - -
Rznzwable-Geothermal - - - - - - - - - - - -
Renewable-Batterv.<Shour 193 71 224 171 4 474 249 14C - S36 =.CS' 733 5.519
Renewable-Battery.8-23 hour - - - - - - - - - - - -
Renewable-Battery.24-hour - 104
Other Renewable - - - - - - - - - - - - - -
Storaee-Other - - - - - - - - - - - - - - - -
Eriating Unit Changes
Coal Plant Retirement-Minority ORn - - - ,123) (148) - - - - - - - - -
Coal Plant Retirements - - - (220) - - - - - - - - - - (220)
Coal Plant Ceases as Coal (205) (700) (1,262)
Coal-CCS 526 (526) 0
Coal-Gas Conversions 144 (156) 239
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) (65) (230) (407)
Expire-QF (47) (5) (52)
Expire-Other 520 - (20) 500
Total 110 M 164 --63 1 394 874 1 1,172 1 736 27S 371 4S4 499 331 729 527 403 1 393 1 1.206 426 1.157 910
166

PACIFICORP—2025 IRP APPENDIX I—CAPACITy EXPANSION RESULTS
MN No CCS
Summary portfolio Capacity b�Rewurce TyW and Ye",InstaUed MW
Installed Capacity,Bfw
Resource 2025 1 2026 1 2027 1 2028 1 2029 2030 2031 1 2032 1 2033 1 2034 1 2035 1 2036 2W7 2038 2039 1 2040 1 2041 1 2042 1 2043 1 2044 2045 Total
Expansion Options
Gas-CCCT
Gaa-Pealciar
Nuclear 500 500
Renewable Pealan4 19 4 18 41
Mf-Energy Efficseacy 92 89 207 218 229 253 326 287 284 282 294 300 333 312 292 289 304 315 260 232 219 1 5.417
DS1%l-Demaad Response 13 63 19 34 187 5 1 3 3 21 93 18 5 25 6 176 30 26 50 785
Reae�able-Wind 21 594 1,252 276 1 29 347 40 175 37 376 50 20 96 3,314
Renemble-Small Scale Wiad
ReaeRable-Utility Solar 222 180 1,690 614 240 403 225 13 1 554 104 12 197 75 4,530
Renemble-Small Scale Solar 320 2 18 26 21 30 132 309 110 143 36 1,147
Renewable-Geothermal
- - - - - - - - - - - - - - - - - - - - - -
Fen—able-Batten.<8 hour 2 1,146 215 299 119 39 210 20 47 175 188 113 67 115 5 758 1 3,518
Rene-able-Battery-;8-23 hog 1 1
- - - - - - - - - - - - - - - - - - - -
Ren—able-Battery.24—hour 511 91 3 4 3 4 4 11 83 37 939 107 261 402 197 358 3,015
Other Renewable
Storaee-Other
Eristing Unit Changea
Coal Plant Retirements-Minority Oa (82) (33) (123) (148) (386)
Coal Plant Retirements (220) (220)
Coal Pleat Ceases as Coal (357) (205) (562)
Coal-CCS
Coal-Gas Conversion 357 205
Gaa Pleat 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-QF (47) (3) (50)
Expire-Other 520
Total 110 464 1 210 1 1,415 1 1,114 1 4,112 1 1,287 1,173 7-7 1 770 1 711 1 -441 913 1 90: 1 1.076 1.S46 1 277 967 271 1ri20 832
167

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
MR No CCS
Summary Portfolio Capacity by Resource Type mud Year,lustaned XfW
Installed Capacity-,lfW
Resource 2025 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2031 1 2035 1 2036 1 2W7 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 204E Total
Expansion Options
Gv-CCCI
Gu-Peaking
Nuclear 500 500
- - - - - - - - - - - - - - - - - - - -
Rene—ble Peaking 19 4 18 41
DSD1-Energy Efficie . 92 89 207 218 230 251 302 288 282 271 292 302 343 314 293 301 304 315 270 246 219 5,431
DS',I-Demand Response 18 2 63 19 16 5 1 3 3 19 2 18 5 27 8 467 11 44 51 792
Renewable-Wind 21 594 2,857 1 1 29 347 40 173 37 376 50 20 96 4,643
Rene—ble-Saull Scale Wind
_ _ _ _ _ _ _ _ _ _ _
Reo—ble-Utility Solar 222 180 1,690 681 891 503 325 68 2 554 104 12 197 75 5,503
Rene—ble-Snull Scale Solar 320 2 18 26 21 30 132 309 110 143 36 L147
Rene—ble-Geothero W
Rene—ble-Battery,<8 hour 2 12146 215 1,002 119 39 210 20 47 175 67 131 67 163 1 907 4315
Renewable-Battery,8.23 hour 1 1
R—able-Battery,24+hour 522 9- 3 1 4 3 4 4 1= 83 37 939 107 315 402 197 362 3,084
Other Renewable
Storage-Other
Existing Unit Change.
Coal Plant Retirements-Minority Oac s (82) (33) (123) (148) (386)
Coal Pleat Retiremesstn (220) (419) (268) (906)
- - - -- - - - - - - - - - - - - -
Coal Pleat Ceases as Coal (357) (205) (2,679) (3,241)
- - - - - - - - - - - - - - - - - -
Coal-CCS
- - - - - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions 357 205 2,679 3,241
Gas Pleat Retirements
_ _ _ _ _ _
Retire-Hydro
Retire-Non-Thermal (3) (32) (35)
Retire-Rind
Retire-Solar
Expire-Wind PPA (64) (99) (200) (333) (696)
Expire-Solar PPA (2) (9) :C' (65`. (230) (407)
Expire-QP (47) (3) (2) (52)
Expire-Other 320
Total 110 1 464 1 210 1 1,415 1 1,115 1 6,411 1 4491 1 1,557 1 8E4 1 859 1 761 1 544 1 434 1 904 1 956 1 1,878 1 279 1 1,097 1 665 1 757 1 1,742
168

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
No Nuclear
Summary Portfolio Capacity b�*Resource Ty
Installed Capacity,MW
source 2021; 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 2032 1 2033 1 2034 1 2035 1 2036 1 2037 1 2038 1 2039 2040 1 2041 1 2042 2043 1 20" 2045 Total
.c
n Option- AL
Gvcc=Gas-Peaking
Nudear
R—ble Pea1-iag
I)Slvl-Energy Efficiency 92 89 210 220 237 256 331 314 310 299 299 314 324 267 283 251 286 299 282 261 220 3,444
DSM-D—d Response 18 2 63 20 136 13 8 26 79 32 4 70 14 151 24 46 31 12 102 48 899
ResseR-able-Wind 500 1,728 300 301 302 322 380 292 4,127
Renea-able-S-11 Scale Wind
_ _ _ _ _ _ _ _ _ _ _ _ _ I _ _ _ _ _ _ _ _ _
Reoea-able-Utility Solar 656 1,444 962 299 326 395 456 391 1 22 108 5,060
Rene-able-S—U Scale Solar 320 2 18 26 21 26 53 307 49 153 10 126 36 1,147
Rene-able-Geothermal
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
ReneRable-Battery,<8 hoar :6 1.399 109 462 274 39 209 34 72 313 130 6 937 159 605 30 602 5,376
ReneR-able-Battery-8-23 hour
Renea-able-Battery:24-hour 191 2 3 3 3 3 3 114 3 3 186 78 233 168 118 4 1,115
Other Reaeu-able
_ _ _ _ _ _ _ _ _ _ _ _ _
Storage-Other
Lasting Unit Changes
Coal Plant Reti—ents-Minority ORa (82) (33) (123) (148) (386)
Coal Pleat Retir—ta (220) (220)
- - - - - - - - - - - - - - - - - - - -
Coal Plant Ceases as Coal _(357) (205) (700) (1,262)
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Coal-CCS 526 526
- - - - - - - - - - - - - - - - - - - -
Coal-Gas Conversions 337 205 562
Gas Plant Ret remeots
_ _ _ _ _
Retire-Hydro
Retire-Noa-The—al (3) (32) (35)
Retire-Wind
Retire-Solar
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
Expire-Ur-d PPA (64) (99) (200) (333) (696)
- - - - - - - - - - - - - - - - -
Expire-Solar PPA (2) (9) (100) (65) (230) (407)
Expire-QF (47) (3) (50)
Expire-Other 520 (20) 500
Total 1 110 1 464 1 226 1 2,093 1 743 1 4,116 1 1,401 1 1,217 1 1,032 1 1,329 1 1,230 1 1,129 1 724 1 689 1 4431 1,4471 3241 963 1,030 1406 998
169

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
No Coal 2032
Summary Portfolio Capacity by Remurce Type and Year,lustaUed MW
lustalled Capacity-,AM
Resource 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 2032 1 2033 1 2034 1 2035 1 2036 2037 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 1 204S Total
Expanaion Options
Gas-CCCT
Gas-Peak-
Nuclear 500 500
Renewable Peaking 19 4 18 41
M1-Energy-Efficiencs- 92 89 210 221 231 251 319 304 308 298 309 323 347 314 293 299 304 313 270 246 220 5,565
MI-Demand Response 13 2 63 19 16 5 1 3 3 19 328 18 5 25 5 146 33 27 51 797
Renewable-Rind 21 594 2,914 1 29 347 40 175 37 376 50 20 96 4,700
Remew-able-Small Scale Wend
Renewable-Utility Solar 222 130 1,690 494 635 545 792 114 100 554 104 12 197 75 5,715
Ren -able-Small Scale Solar 320 2 13 26 21 30 132 309 110 143 36 1,147
Renewable-Geothermal
Renewable-Battery-,<8 hour - 215 565 119 39 210 20 47 175 67 113 67 152 t5416 18 3.373
Renewable-Battery-.8-23 hourRenewable-Battery•,24+hour 510 91 3 4 3 4 4 33 83 37 939 107 390 358 3.164
Other Renewable
Storaee-Other
Existing Unit Changes
Coal Plant Retirements-Minority Owen (82) (33) (123) (148) (386)
Coal Plant Retirements (220) (686) (906)
Coal Plant Ceases as Coal (357) (205) (2,679) (3,241)
Coal-CCS
Coal-Gan Conversion 357 205 2,679 (156) 3,085
Gat Phm[Retirements
Retire-Hydro
Retire-Non-Thermal (3) (32) (35)
Retire-Wind
Retire-Solar
Expire-Wind PPA (64) (99) (200) (696)
Expire-Solar PPA (9) (230) (407)
Expire-QF' - (47) (3) AExpire-Other 520 500
Total 1 110 1 464 1 210 1 1,417 1 1,116 1 6,019 1 6971 899 1 923 1 1,53 1 827 1 6671 784 1 904 1 956 1 1,8%1 276 1 1,003 1 530 1 993 850
170

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
Offshore Wind
Summary Portfolio Capacity by Resource Type and Year,Installed MW
Installed Capacity,Aff
Resource 2026 2026 1 2027 1 2028 1 2029 2030 2031 2032 2033 2034 2035 7 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Ezpansinn Options
Gas-CUT - - - - - - -
- - - - - - - - - - -
Gas-Peaking -
- - - - - - -
- - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking - - - - -
- - - - - - - - - - - - - - - - -
DSIs1-Energy Efficiency 89 209 219 240 260 331 292 306 294 299 322 345 314 310 301 303 314 222 218 182 5,462
DSM-Demand Response 2 63 20 206 21 8 1 C 4 4 110 29 5 11 8 166 30 31 50 796
Renewable-Wind 100 100 762 1 630 400 1 1,000 98 100 100 353 95 162 3,901
Renewable-Small Scale Wind -
- - - - - - - - - - - - - - - - - - - - -
Renewable-UtilitySolar 103 237 205 1.382 885 249 104 '-CC 100 100 101 392 444 100 116 26 4.646
Renewable-Small Seale Solar 416 - - - 24 29 114 142 36 250 26 1.037
Renewable-Geothermal - - - -
- - - - - - - - - - - - - - - - - -
Renewable-Battery,<8hour 7 2,291 527 528 149 131 46 54 113 1.454 211 675 768 82 834 81123
Renewable-Battery.8-23 hour - 1 - - - - - 1
- - - - - - - - - - - - - -
Renewable-Battery,24—hour 1,577 2C 23 1 22 2 26 2428 1 12' 1 34 142 96 30 34 2258
Other Renewable - - - - - - - - - - - - - -
Storare-Other - - - - - - - - - - - - - - - - - - - -
Eriating Unit Changes
Coal Plant Retirement-Minority On - - - (123) (148) - - - - - - - - -
Coal Plant Retirements - - - (220)
Coal Plant Ceases as Coal (205) (700) (1,262)
Coal-CCS 526 (526) 0
Coal-Gas Conversions - 205 (156) 406
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) (65) (230) (407)
Expire-QF (47) (3` (2) (52)
Expire-Other 520 - 20) 500
Total 110 464 1 420 1 2,6ff 1 1,631 4.578 1 1.443 1 1222 1.433 6c2 974 606 484 1.00E 929 2.460 1 395 1 1.297 423 1 494 1.292
171

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
LN (Low Natural Gas / No M Proxy)
Summary Portfolio Capacity k-Resource Type and Year,InstaRed MW
77 Installed Capacity,Aff
Resource 202E 1 2026 2027 1 2028 1 2029 2030 2031 1 2032 1 2033 1 2034 203+ 2036 2037 2038 2039 2040 2041 2042 2043 2044 204E Total
Expansion Option-
Gas-CUT 496 496
Gm-Peakin_e - - - - - - - - - - - - - -
Nuclear 500 500
- - - - - - - - - - - - - - - -
Rmemable Peaking
- - - - - - - - - - - - - - - - - - - - - -
DSM-Enerw Efficimcw 92 89 207 223 236 257 325 288 300 239 311 319 343 309 322 305 302 291 272 244 217 5.540
DSM-Demand Response 18 63 19 75 149 7 4 4 14 110 14 5 24 124 8 80 51 773
Renea-able-Wind 594 1,265 594 1 2 24 369 1 176 11 33 365 90 3 150 3,671
ReneRable-Small Scale Wind
- - - - - - - - - - - - - - - - - - - - - -
RmeR-able-Utility Solar 20C 138 1,761 517 239 398 23C 7 1 570 93 61 44 110 4,369
Ren-- able-Small Scale Solar - 320 2 18 26 21 31 153 306 97 35 101 36 1 1.146
Rene«able-Geothermal
ReneaabL-Bat ten-.<8hour 12=2 220 609 99 39 2C9 23 32 239 67 1.126 1,060 272 12rl�437 6.746
ReneRable-Battery.8-23 hour - - - - - -Rmescable-Battery.24+how - - 271 95 4 4 3 4 4 17 3S 40 132 26 2li 137 li9 1.165
Other Renescable - - - -Storaee-Other -
Ldstins Unit Chansm
Coal Plant Reetirmtmts-Minorinv 0-:-.r. - S (33) l:_ (148) - - - - - - - - - - - -
Coal Plant Retirements (220) (220)
Coal Plant Ceases as Coal (357) (205) (700) (1,262)
Coal-CCS 526 (526) 0
Coal-Gas Conversions 357 205 - 562
- - - - - - - - - - - - -
Gm Plant Retiremmts - - - - - - - - - - - -
Retire-Hydro
Retire-Non-Then (3) 2 (35)
Retire-Wind - - - - - - - - - - - - - - - -
Retire-Solar
- - - - - - - - - - - - - -
Expire-Wind PPA - (64) - - - (200) - - - - - - - - (333) (696)
Expire-Solar PPA - (9) (65) (230) (407)
Expire-QF (47) (3) (2) (52)
Expire-Other (20). LEM
Total 1 110 1 464 1 207 1 1,483 1 1,084 1 4,137 1 1,473 1 1,157 1 769 1 777 749 E4'1 912 1 1.004 1 2,045 1 1,362 1 (20)1 680 407 2,491
172

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
MR (Medium Natural Gas / Current Federal CO2 Regulations)
Summary Portfolio Capacity tn-Resource Type and Year,lustalled1M
Installed Capacity.Aff
Resource 1 2025 1 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 1 2034 203 2036 1 2037 1 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 1 2045 Total
Ezpansiou Options
Gas-CCCI - -
Gas-Peakin5 - - - - - - - - - - - - - -
Nuclear 500 500
Renewable Peaking - 19 4 - 18 41
=I-Energy Efficiency 89 209 221 231 256 329 313 326 315 318 326 369 335 313 308 304 315 254 224 209 5:656
DSDI-Demand Response S2 63 19 16 3 5 1 5 3 19 323 18 5 24 114 34 34 25 205 936
Renewable-Wind - - 21 694 1,931 200 382 100 129 447 40 175 37 376 50 2C 96 4:698
Renewable-Small Scale Wind
- - - I - - - - - I - - - - - - - - - - - -
Rmewable-Utility Solar - - - 222 180 1,690 863 934 420 467 213 133 1 554 1C4 12 197 75 6,065
Renewable-Small Scale Solar - - - 320 L 13 26 21 30 132 - 309 - 110 143 36 1,147
Renewable-Geothermal -
- - - - - - - - - - - - - - - I - - - - - -
Reaewable-Batten.<8 hour - - - 1.156 215 438 219 39 210 20 47 27 175 67 113 `S2 33 5 305 324 3.875
Renewable-Batten.8-23 hour - - -
- - - - - - - - - - - - - - - - - -
Renewable-Batten.24—hour - - - 510 91 - 41 3 4 4 17 33 37 939 107 510 1 401 197 435 3.323
Other Renewable - - - - - - - - - - -
Storaze-Other - - - - - - - - - -
Existing Unit Chances
Coal?lantRetiresnmts-MinoritvOan (123) (143) - - - - 13S6s
Coal Plant Retirements (220) (686) (906)
Coal Plant Ceases as Coal (357) (205) (2,679) (3,241)
Coal-CCS 526 (526) 0
Coal-Gas Conversiom 357 205 1:979 (156) 2.335
Gas Plant Retirements
- - - - - - - - - - - - - -
Retire-Hydro - - - - - - - -
Retire-Non-Thermal - - - (3) - - - - (35)
Retire-Rind
Retire-Solar - - - - - - - - - - - -
Expire-Wind PPA (64) (99) (20C (333) (696)
Expire-Solar PPA (2) (9; (65) (230) (407)
Expire-QF - - - - - - - - - - - - - (47) (3) (2) (52)
Expire-Other 520 (20) 500
Total 110 464 209 1 1.428 1 1216 1 4.740 1 1.79 1 1.588 916 1,147 1,035 701 970 925 1 976 1.364 900 892 (11)1 M 1,396
173

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
HH (High Natural Gas / High M Proxy)
Sunmam portfolio Capacity toy Resource Type and Year,Installed MW
Inatalled Capacity,MW
Resource 202 2026 1 2027 1 2028 1 2029 1 2030 1 2031 1 2032 1 2033 2034 2035 2036 2037 2038 1 2039 1 2040 1 2041 1 2042 1 2043 1 2044 2045 Total
Expansion Option?
Gas-CCC i - - - - - - - - - -
Gm-Peskin_= - - - - - - - - -
Ntsclem - - - - - 500 - 500
- - - - - - - - - - - - - -
Renewable Peaking 19 4 18 41
- - - - - - - - - - - - - - - - - -
DSM-Energy Effiaenc 92 S9 211 237 257 309 295 300 289 309 315 347 326 305 302 305 316 259 252 230 5568
DSNI-Demand Response is 6 2.1 13 5 1 3 3 19 18 8 24 5 463 15 157 30 869
Renewable-Wind +94 2,712 42 29 349 40 175 37 376 50 20 96 4,741
Renewable-Smalt Scale Rind - -
- - - - - - - - - - - - - I - - - - - - -
Renewable-titAitySotar 222 181 1,813 1,750 240 457 225 267 1 554 104 12 197 75 6,098
Renewable-Small Scale Solar - 320 2 18 26 21 30 132 309 110 143 36 1,147
Renewable-Geothermal - - -
- - -
ry- - - - - - - - - - - - - - - - -
Renewable-Battery,c 8 hog - 1.146 302 1,383 119 39 210 20 47 175 67 113 67 5 37695
Renewable-Batten.8-23 hog - - 1
Renewable-Battery,24+how - - 511 91 3 4 3 4 1 4 11 83 37 939 107 641 402 197 598 3.635
Other Renewable - - -
Storaee-Other - - - - - - - - - - -
Existing Unit Changes
Coal Pimt Ret n> r-Minority Own (82) (33) (123) (148) (386)
Coal Plant Retirements (220) (268) (488)
Coal Plant Ceases as Coal (357) (205) (1:299) (1,861)
Coal-CCS 526 (526) 0
Coal-Gas Conversions 357 205 599 (269) 892
Gm Plant Retirements - - - - - - - - - - - -
Retire-Hydro
Retire-Non-Thermal (3) (35)
Retire-Wind - - - - - - - - - - - -
Retire-Solar
Expire-WindPPA (64) (99) (200) (333) (696)
Expire-Solar PPA (2) (9) (65) (230) (407)
Expire-QF (47) (3) (2) (52)
Expire-Other 520 (20) 500
Total 1 1101 464 1 214 1 1,420 1 1,413 1 6,.488 1 1,675 1 1,222 1 558 1 777 1 982 1 557 1 434 1 916 1 971 L858 177 1 1,420 132 1 713 1 1,061
174

PACIFICORP—2025 IRP APPENDIX I—CAPACITY EXPANSION RESULTS
SC (Social Cost of Greenhouse Gases)
Summary Portfolio Capacity b�Resource Ty
Instaued Capaci".\rW
Resource 2025 1 2026 1 2027 1 2028 1 2029 2030 2031 1 2032 2033 2034 1 2035 1 2036 2037 2038 2039 1 2040 1 1041 1 2042 1 2043 1 2044 204E Total
Expansion Options
Gas-CCC— - - -
Gas-Peak n_e
- - - - - - - - - - - - - - - - - - - -
Nudl 500 500
- - - - - - - - - - - - - - -
Rene�able Peaking
- - - - - - - - - - - - - - - - - - - - - -
=Im Energy Efficimcv 92 89 211 226 241 263 329 293 314 305 318 325 357 325 320 308 305 315 270 260 219 5.685
DSM-Demand Response 18 2 2 64 28 191 14 1 1 18 11 108 18 10 24 6 :_C 12 50 46 779
RmeRable-«'tad - 20 =.614 1,353 352 1 65 293 237 1 114 26 29 423 47 - 11 196 4,781
Ranmable-Small Scale Rind - - - - -
Rene�able-Utility Solar 22 331 K3229
2,005 1.259 335 400 206 225 90 1 471 115 288 92 6.034
e Ren ble-Small Scale Solar - - - 320 19 26 23 24 20 9 312 42 170 - 56 26 1.049
e Ren able-Geothermal - -Rme able-Batterv.<8 hour - - 2.147 484 175 7 194 2 23 296 121 1.095 138 245 192 237 331 1 6.206
Ranetyable-Batters.8-23 ho - - - - -
Renemable-Batterv_,24—hour - 1,4 19 19 13 20 21 69 22 34 1411 141 442 219 169 94 2.945
Other Fene ble - - - - - - -
Storaee-Other - - - - - - - - -
Existing Unit Changes
Coal Plant Retirements-MinoritvORn (52i (33) (123) (148) - - - - - - -
Coal Plant Retirements (488) (269) (757)
Coal Pleat Ceasm as Coal (357) (205) (17030) (1,592)
Coal-CCS 526 526
Coal-Gas Conversions 357 205 330 (99) 793
Gas Plant Retirements (167) (167)
Retire-Hydro - - - - - - - - - - -
Retire-Non-Therein (3) (32) (35)
Retire-Wind - - - - - - - - - - -
Retire-Solar -
Expire-WtndPPA (64) (99) (200) (333) (696
Expire-Solar PPA (2) (9) (100) (65) (230) (407)
Expire-QF (47) (3) (2) (52)
Expire-Other 520 (20) 500
total 1 110 1 464 1 235 1 2,146 1 2233 1 5,605 I 1,854 1 1,347 1 7671 909 1 900 1 727 1 498 1 957 1 98.+ 1 2.148 1 409 1 1,152 1 278 1633 1.132
175

PACIFICORP-2025 IRP APPENDIX I-CAPACITY EXPANSION RESULTS
176

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
APPENDIX K - CAPACITY CONTRIBUTION
Introduction
The capacity contribution of a resource is represented as a percentage of that resource's nameplate
or maximum capacity and is a measure of the ability of a resource to reliably meet demand. This
capacity contribution affects PacifiCorp's resource planning activities, which are intended to
ensure there is sufficient capacity on its system to meet its load obligations inclusive of a planning
reserve margin. Because of the increasing penetration of variable energy resources (such as wind
and solar) and energy-limited resources (such as storage and demand response), planning for
coincident peak loads is no longer sufficient to determine the necessary amount and timing of new
resources. To ensure resource adequacy is maintained over time, all resource portfolios evaluated
in the integrated resource plan(IRP)have sufficient capacity to meet PacifiCorp's load obligations
and a planning reserve margin in all hours of each year. Because all resources provide both energy
and capacity benefits, identifying the resource that can provide additional capacity at the lowest
incremental cost to customers is not straightforward. A resource's energy value is dependent on
its generation profile and location, as well as the composition of resources and transmission in the
overall portfolio. Similarly,a resource's capacity value(or contribution to ensuring reliable system
operation)is also dependent on both its characteristics and the composition of the overall portfolio.
To further complicate the analysis, PacifiCorp's portfolio composition changes dramatically over
time, as a result of retirements and expiring contracts.
In the 2019 IRP, PacifiCorp developed initial capacity contribution estimates for wind and solar
capacity that accounted for expected declining contributions as the level of penetration increased.
A key assumption in this analysis was that only a single variable was modified, for example,when
evaluating solar penetration level, the capacity from wind and energy storage resources in the
portfolio were held constant. As the preparation of the 2019 IRP continued, PacifiCorp identified
that these initial estimates did not adequately account for the interactions between solar,wind, and
energy storage and thus did not ensure that each portfolio was adequately reliable. Therefore, as
part of the 2019 IRP PacifiCorp assessed each portfolio to verify that it would support reliable
operation in each hour of the year. PacifiCorp has continued to perform this portfolio-wide
reliability assessment.
In the past,PacifiCorp's stochastic analysis has reflected standard deviations,mean reversion, and
correlation to represent the expected variation in loads, thermal outages, and hydro conditions
(along with market prices, which only impact economics, and not loss of load risk). As discussed
in Appendix H (Stochastics), for the 2025 IRP PacifiCorp is adding variations in wind and solar
generation, and will account for inter-annual variations, rather than relying upon mean reverting
variables.
PacifiCorp calculates two kinds of capacity contribution values for different purposes. First,
Appendix K (Capacity Contribution) in prior IRPs has reported marginal capacity contribution
values which reflect the expected reduction in loss of load events as a result of a small increase in
a given resource, with no other changes in a PacifiCorp's portfolio. Second, values based on the
Western Resource Adequacy Program (WRAP) methodology are used to measure resource
adequacy and are reported in the load and resource balance. The WRAP methodology produces
"portfolio" capacity contribution values, or the average contribution from all resources of a given
177

PACIFICORP—2025 IRP APPENDIX K—CAPACITY CONTRIBUTION
type based on the combined portfolios of WRAP participants,though with some variation to reflect
the performance of individual projects. However, the WRAP methodology does not give priority
to existing projects relative to new projects, as all projects of a given type receive equivalent
treatment.
CF Methodology
Marginal capacity contribution values are calculated using the capacity factor approximation
method (CF Method) as outlined in a 2012 report produced by the National Renewable Energy
Laboratory (NREL Report).' The CF Method calculates a capacity contribution based on a
resource's expected availability during periods when the risk of loss of load events is highest,
based on the loss of load probability(LOLP) in each hour. This CF Method analysis is performed
using a portfolio that is comparable to the preferred portfolio. For the reasons discussed above,
this analysis provides a reasonable estimate of capacity contribution value so long as the changes
relative to the preferred portfolio are small, since in effect,the CF Method calculates the marginal
capacity contribution of a one megawatt resource addition. Changes to the locations and quantities
of wind, solar, and energy storage are key drivers of the marginal capacity contribution results.
The NREL Report summarizes several methods for estimating the capacity value of renewable
resources that are broadly categorized into two classes: 1) reliability-based methods that are
computationally intensive; and 2) approximation methods that use simplified calculations to
approximate reliability-based results. The NREL Report references a study from Milligan and
Parsons that evaluated capacity factor approximation methods, which use capacity factor data
among varying sets of hours,relative to a more computationally intensive reliability-based metric.
As discussed in the NREL Report,the CF Method was found to be the most dependable technique
in deriving capacity contribution values that approximate those developed using a reliability-based
metric.
As described in the NREL Report, the CF Method "considers the capacity factor of a generator
over a subset of periods during which the system faces a high risk of an outage event."When using
the CF Method, hourly LOLP is calculated and then weighting factors are obtained by dividing
each hour's LOLP by the total LOLP over the period. These weighting factors are then applied to
the contemporaneous hourly capacity factors to produce a capacity contribution value.
The weighting factors based on LOLP are defined as:
_ LOLPL
w` J LOLP•
where wi is the weight in hour i,LOLPi is the LOLP in hour i, and T is the number of hours in the
study period, which is 8,760 hours for the current study. These weights are then used to calculate
the weighted average capacity factor as an approximation of the capacity contribution as:
' Madaeni, S.H.; Sioshansi,R.;and Denholm,P."Comparison of Capacity Value Methods for Photovoltaics in the
Western United States."NREL/TP-6A20-54704,Denver,CO:National Renewable Energy Laboratory,July 2012
(NREL Report)at:www.nrel.gov/docs/fy12osti/54704.pdf
178

PACIFICORP—2025 IRP APPENDIX K—CAPACITY CONTRIBUTION
T
CV = wi Ci,
i=1
where Ci is the capacity factor of the resource in hour i, and CV is the weighted capacity value of
the resource.
For fixed profile resources, including wind, solar, and energy efficiency,the average LOLP values
across all iterations are sufficient, as the output of these resources is the same in each iteration. To
determine the capacity contribution of fixed profile resources using the CF Method, PacifiCorp
implemented the following three steps:
1. A multi-iteration hourly Monte Carlo simulation of PacifiCorp's system was produced
using the Plexos Short-Term (ST) model. Each iteration reflects load, hydro, wind, solar
and existing thermal resource conditions from a specified historical year from 2006-2023.
The LOLP for each hour in the year is calculated by counting the number of iterations in
which system load and/or reserve obligations could not be met with available resources
and dividing by the total number of iterations.' For example, if in hour 19 on December
22nd there are three iterations with shortfalls out of a total of 50 iterations, then the LOLP
for that hour would be 6 percent.3
2. Weighting factors were determined based upon the LOLP in each hour divided by the sum
of LOLP among all hours within the same summer or winter season. In the example noted
above, the sum of LOLP among all winter hours is 58 percent.' The weighting factor for
hour 19 on December 22nd would be 1.0417 percent.5 This means that 1.0417 percent of
all winter loss of load events occurred in hour 19 on December 22nd and that a resource
delivering in only that single hour would have a winter capacity contribution of 1.0417
percent.
3. The hourly weighting factors are then applied to the capacity factors of fixed profile
resources in the corresponding hours to determine the weighted capacity contribution value
in those hours. Extending the example noted, if a resource has a capacity factor of 41.0
percent in hour 19 on December 22nd, its weighted winter capacity contribution for that
hour would be 0.4271 percent.6
For resources which are energy limited, such as energy storage or demand response programs,the
LOLP values in each iteration must be examined independently,to ensure that the available storage
or control hours are sufficient. Continuing the example of December 22nd described above,
2 While PacifiCorp participates in the Northwest Power Pool(NWPP)reserve sharing agreement,this only provides
energy from other participants within the first hour of a contingency event, e.g., a forced outage of a generator or
transmission line. Shortfalls in the 2023 IRP are much more likely to result from changes in load,renewable resource
output,or energy storage limitations,which do not qualify as contingency events.In light of this,PacifiCorp's analysis
includes the first hour of every shortfall event.
3 0.6 percent=3/500.
a For each hour, the hourly LOLP is calculated as the number of iterations with ENS divided by the total of 500
iterations.There are 288 winter ENS iteration-hours out of total of 5,832 winter hours.As a result,the sum of LOLP
for the winter is 288 / 500 = 58 percent. There are 579 summer ENS iteration-hours out of total of 2,928 summer
hours.As a result,the sum of LOLP for the summer is 579/500= 116 percent.
5 1.0417 percent=0.6 percent/58 percent,or simply 1.0417 percent=3/288.
6 0.4271 percent= 1.0417 percent x 41.0 percent.
179

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
consider if hour 18 and hour 19 both have three hours with energy or reserve shortfalls out of 500
iterations.If all six shortfall hours are in different iterations,a 1-hour energy storage resource could
cover all six hours. However, if the six shortfall hours are in the same three iterations in hour 18
and hour 19 (i.e. 2-hour duration events),then a 1-hour storage resource could only cover three of
the six shortfall hours. Additional considerations are also necessary for hybrid resources which
share an interconnection and cannot generate their maximum potential output simultaneously.
The details of the wind and solar resource modeling in the study period are an important aspect of
the results. For the 2025 IRP, PacifiCorp is using generation profiles for existing wind and solar
and proxy options based on the time period 2006-2023.For each iteration,load,hydro,and existing
thermal resource conditions are developed from the same time period. Using historical conditions
for as many variables as possible maintains the correlation between the variables as well as the
distribution of the results.As one would expect,days with higher load or lower renewable resource
generation are more likely to result in shortfall events. By drawing conditions over an entire year,
sustained conditions like droughts and under-supply of renewables can be identified, and longer-
duration storage may be necessary to avoid loss of load events under those conditions. Given the
increasing complexity of the iteration data, basing CF Method capacity contribution calculations
on an average or 12-month by 24-hour forecast of renewable generation will tend to overstate
capacity contribution, particularly if there is a significant quantity of similarly located resources
of the same type already in the portfolio,or if an appreciable quantity of resource additions is being
contemplated. Even if an hourly renewable generation forecast is used, capacity contributions can
be overstated if the weather underlying the forecast is not consistent with that used for similarly
located resources used to develop the CF Method results. Because similarly located resources of
the same type would experience similar weather in actual operations, a mismatch in the underlying
weather conditions used in renewable generation forecasting will create diversity in the generation
supply than would not occur in actual operations.
CF Method Results
The CF Method results presented in Figure K.1 provide a reasonable capacity contribution value
so long as the changes relative to the preferred portfolio are small, since in effect, the CF Method
calculates the marginal capacity contribution of a one-megawatt resource addition.Please note that
marginal capacity contribution values reported herein are applicable to small incremental or
decremental changes relative to the composition of the IRP preferred portfolio and do not represent
the average capacity contribution for each of the megawatts of a given resource type included in
the preferred portfolio. Nor do these values match what is used in the load and resource balance
and discussed later on in the WRAP Methodology and WRAP Results sections of this Appendix.
In general, wind, solar, and energy storage have declining marginal capacity contribution values
as the quantity of a given resource type increases. This results in average capacity contribution
values that exceed the marginal capacity contribution values reported here.
Values presented in Figure K.1 are based on the stochastic results used to develop the risk
adjustment for the preferred portfolio, specifically the loss of load events identified as part of that
analysis. Values have been aggregated for groups of years due to the limited frequency of events
in this data set, which spans 18 conditions (weather years for 2006-2023). The events vary across
the horizon, and the preferred portfolio did not experience any loss of events during 2032-2036.
The capacity contribution of solar is relatively low at the start of the horizon but increases in the
summer as the portfolio becomes more dependent on energy storage.Because of its reduced output
180

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
during the winter season,the CF Method contribution of solar in the winter ends up close to zero,
though solar is still likely providing reliability benefits for the portfolio as a whole. The capacity
contribution of wind varies somewhat over time,particularly on the west,where large amounts of
wind as wind resources are a relatively small portion of the resource mix on the west today. The
contribution of offshore wind is relatively high,in keeping with its high capacity factor and diverse
generation profile relative to onshore wind locations. The capacity contribution of energy storage
is limited based on the duration of the event, and the duration of the storage resource. Most loss of
load events start in the late afternoon or evening, and the longest loss of load event in this data set
was ten hours. Detail on loss of load events is presented in Figure K.2.
Figure K.1 -CF Method Capacity Contribution Values for Wind, Solar, and Storage
Solar Wind Storage Seasonal
Period Season East West East West Offshore 2 Hour 4 Hour 8 Hour Weight
Summer 4.7% 6.0% 22.5% 40.0% 65.3% 48.1% 72.2% 100.0% 88%
2025-2027 Winter 3.6% 4.4% 38.1% 19.5% 38.9% 100.0% 100.0% 100.0% 12%
Annual 4.6% 5.8% 24.5% 37.5% 62.0% 51.7% 74.1% 100.0%
Summer 18.1% 15.2% 31.0% 14.0% 47.7% 81.8% 100.0% 100.0% 35%
2028-2031 Winter 0.5% 0.0% 27.1% 6.8% 54.6% 35.5% 61.3% 94.6% 65%
Annual 6.7% 5.4% 28.4% 9.4% 52.2% 40.4% 65.4% 95.2%
Summer 13.9% 15.8% 35.4% 18.5% 66.8% 72.2% 83.3% 100.0% 51%
2037-2041 Winter 0.6% 0.0% 2.1% 1.8% 1.8% �;8.3% 83.3% 100.0% 49%
Annual 7.4% 8.1% 19.2% 10.4% 35.2% 66.7gb 83.34o 100.0%
Summer 16.7% 25.7% 28.0% 44.4% 78.1% -9.2% 95.8% 100.0% 94%
2042-2045 Winter 1.7% 0.0% 13.2% 90.4% 60.4% 40.0% 80.0% 100.0% 6%
Annual 1 15.7% 24.1% 1 27.1% 47.2% 77.044o 72.44io 93.1% 100.04%
Figure K.2-Loss of Load Event Detail
10
9 ♦ Each triangle
0 represents one
= 8 loss of load event
o 7
�a
6 ♦ A&
A 5
as
w' 4 ♦ ♦ v
3 ♦ v ♦ A&
0
J
c 2 ♦ ♦ ♦ Y Y v ♦ LY
W
c 1 & A"" AAM& Y► ♦ 1V
J
Summer Winter Summer `''inter Summer Winter Summer Winter
2025- 2025- 2023- 2028- 2037- 2037- 2042- 2042-
2027 2027 2031 2031 2041 2041 2045 20455
181

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
WRAP M
The capacity benefits of wind, solar, and storage decline as their share of a portfolio increases,
though this effect can be offset some degree as wind, solar, and storage in combination may
provide more capacity than they each would provide on their own. But even the combined effect
will exhibit diminishing benefits as penetration levels increase. Because WRAP has a wide
footprint, the diversity among geographically dispersed wind and solar resources can result in a
higher capacity contribution and dilute the impact of resource additions of a given type.
M&AP
Participants in WRAP must register their resources and will then be assigned a Qualifying
Capacity Contribution (QCC) that can be counted toward meeting their load requirements. The
QCC values are calculated by or on behalf of the WRAP, with methodologies that vary by type,
as described in WRAP Business Practice Manual 105 (Qualifying Resources).' The current
resource types include:
• Thermal or long-duration storage
• Variable energy resources (wind and solar)
• Energy storage
• Hybrid facilities
• Demand response
• Hydro resources (storage and run of river)
In general, WRAP QCC values reflect Effective Load Carrying Capability (ELCC). For thermal
and long-duration storage, QCC values are based on a resource's historical forced outage rate
during capacity critical hours (the top five percent of hours based on load net of wind, solar, and
run of river hydro). These resources are assumed to have random outages, and because they can
operate throughout any outage event, their contributions are not impacted if their share of the
portfolio goes up or down. As a result, QCC values for thermal and long-duration storage do not
require portfolio ELCC analysis. Storage hydro resources have somewhat more involved
calculations, accounting for operational limitations and non-power constraints, but generally
follow the same treatment as thermal and long-duration storage, based on their potential for
maximizing output during capacity critical hours. For wind, solar, run of river hydro, and short-
duration energy storage (under eight hours at present), ELCC analysis must account for the share
of these resources in the portfolio, as it is impacted by the magnitude of each type as well as
interactions among the different types.
WRAP Business Practice Manual 105 Qualifying Resources.Version 1.0.Accessed 11/8/2024:
ho2s://www.westeMpowelpool.oriz/private-
media/documentsNI.0 BPM 105 Forward Showing_Qualifying Resources 12-07-2023.pdf
182

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
The WRAP ELCC analysis has several stages and starts by identifying the QCC values for each
resource type and location, with results for each forward showing month in the summer (June-
September) and winter seasons (November-March). Each individual resource receives a share of
the monthly total QCC for their type and location,based on the ratio of their output during capacity
critical hours to the total output for all resources of their type and location.
The WRAP ELCC analysis is repeated each year, one year in advance of the forward showing
deadline, as detailed in WRAP Business Practice Manual 101 (Advance Assessment).$ For
example, studies would be completed in October 2023 for the summer 2025 season, as the forward
showing deadline for the summer of 2025 would be October of 2024.9 Similarly, the studies for
the winter season would be completed in March 2024 for the winter season starting in November
2025.I o
The recent WRAP ELCC analysis has also included projections of the impacts of increasing wind,
solar, and energy storage resource additions on QCC values. Because these values are based on
the resource mix of the WRAP regions, and not PacifiCorp's specific portfolio, the 2025 IRP
includes a projection of the decline in QCC values over time that is based on the forecast of
regional resource changes underlying the September 2024 official forward price curve.As a result,
the forecast is independent of PacifiCorp's portfolio selection.Figure K.3 through Figure K.5 show
the 2025 WRAP QCC values for solar, wind, and storage, and the Company's projection through
the end of the IRP study horizon.
'WRAP Business Practice Manual 101 Advance Assessment.Version 1.0.Accessed 11/8/2024:
hllps://www.westelnpowerpool.oriz/private-media/documentsNl.O BPM_101 Advance Assessment_12-07-
2023.pdf
9 WRAP Summer 2025 Data.Accessed 11/8/2024:htWs://www.westernpowerpool.org/private-
media/documents/2024-01-31_Webinar_Summer_2025_and_2028_Data.pdf
'o WRAP Winter 2025-2026 Data.Accessed 11/8/2024:htws://www.westeMpowerpool.oriz/yrivate-
media/documents/2024-06-13_Webinar Winter 2025-2026_and 2028-2029_Data.pdf
183

PACIFICORP-2025 IRP APPENDIX K-CAPACITY CONTRIBUTION
Figure K.3—WRAP Contributions Through Time—Solar
100%
---SolarVER1WA,0R,No.ID,MTSummer ---SolarVER1WA,0R,No.ID,MTWinter
90%
—Solar VER2UT,NV,COSummer —Solar VER2UT,NV,COWinter
80%
-&-SolarVER3So.ID,WYSummer -.&-SolarVER3So.ID,WYWinter
70% 2025 2045
Solar WRAP Forecast
60°i°
Peak Load MidC 5% 35%
50°i° - % Peak Load SWEDE 33% 68%
0
40%
30%
209'0
---------
10% ----------------------------
0%
(n (D r, 00 O O -1 N (1) (D t\ 00 O O N M V U-)
N (V fV fV N Cl) Cl) Cl) Cl) M Cl) M M M M V V V V V q*
O O O O O O O O O O O O O O O O O O O O O
N (V N (V N N N N N (V (V (V N N (V N N N N N N
184

PACIFICORP—2025 IRP APPENDIX K—CAPACITY CONTRIBUTION
Figure K.4—WRAP Contributions Through Time—Wind
100%
90% ... Wind VERIWA+Columbia GorgeSummer ••••-Wind VERSWA+Columbia GorgeWintei
—Wind VER2UT,NV,So.IDSummer —Wind VER21JT,NV,So.IDWinter
80% Wind VER3No.ID,MTSummer � Wind VER3No.ID,MTWinter
—h—Wind VER4WY,COSummer Wind VER4VN.COWinter
70%
0
2025 2045
60% Wind WRAP Forecast
°'o Peak Load MidC 20% 360'o
50%
o `�•� % Peak Load SWEDE 15% 640'o
U
2 40%
T
30%
1096 FY�� YY� • y��tlY1oNY�� YY� .Y�� •M� •�.••� Y��•.Y Mom.�1MY��Y•f r.-.r� •r
0%
v) (D r- 00 Q) O .-+ N M C LO (D n 00 M O N M
N N N N N M CM M M M M M M co M 'R V V V V V
O O O C. 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
185

PACIFICORP—2025 IRP APPENDIX K—CAPACITY CONTRIBUTION
Figure K.5—WRAP Contributions Through Time—Storage
100%
90% '_________ 5hr+: 100%
80% =
70%
0
o so°ro 4hr: 40%
5hr: 50%
rD
4-1 50% 10hr+: 100%
0
40% 2025 2045
oac Storage WRAP Forecast
30% % Peak Load MidC 1% 22% Contributions shown based
20°/c % Peak Load SWEDE 15% 37% on four-hour duration
--- ESR MidCWA,OR,No. ID,MTSummer —ESR SWEDEUT, NV,CO,So.ID,WYSummer
10`%
--- ESR MidCWA,OR,No. ID,MTWinter —ESR SWEDEUT, NV,CO, So.ID,WYWinter
0%
186

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.
187

PACIFICORP-2025 IRP APPENDIX L-DISTRIBUTED GENERATION STUDY
188

DNV
DISTRIBUTED GENERATION FORECAST
Behind-The-Meter Resource
Assessment
PacifiCorp
Date: November 25, 2024
il � li

DNV
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
DNV — www.dnv.com Page i

DNV
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.
❑ Commercial In Confidence Not to be disclosed outside the Customer's organization.
❑ DNV only Not to be disclosed to non-DNV staff
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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DNV
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
1,000 °
0.115% . ° PV+Battery
Micro 7.60%
Turbine
3: 800 0.11%
600 / Reciprocating
Engine
0.00%
�j 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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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 000010<
4,000
3,500 i
i
Q i i
3,000 00
dop
2,500 0
> 2,000
i
1,500
U 1,000
500
0
ONcb OO 0 0 O�O O 0� O 0 O 0 0�H 0�00 0 0 00 0A 00 0o OO 0 000O�OHO
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
6
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
2,500 I
2,000
E 1,500 _-
U 1,000 y
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
sR.—o
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AREA
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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
U) ■Permitting&Interconnection
't $20,000 N ■Design&Engineering
O
N ■$15,000 Installation Labor
Balance of System
$10,000 ■Battery Inverter
■Battery Pack
$5,000 PV Inverter
$0 ■PV 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
tV ■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.
DNV - www.dnv.com Page 13

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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
Q 2500
Y 2000
64
It
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
(V
$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
N $2,000
0
$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
$2,000
N $1,500
0
N $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 $38 https://www.nrel.qov/docs/fv22osti/82519.pdf
Annual fixed NREL.2023."2023 Annual Technology
O&M cost Baseline."Golden,CO: National Renewable
change %, 2024-2043 -3.5% -1.9% -1.9% Energy Laboratory. https://atb.nrel.gov/
Capacity
Factor System Advisor Model Version 2023.12.17.
(dependent 15.2%- National Renewable Energy Laboratory.
on state) % 7.7-10.8% 15.1%-18.5% 18.4% Golden,CO. https://sam.nrel.gov
3.1 .3 Small-scale hydropower
Hydroelectric power is an established, mature technology, but small-scale systems are a newer permutation of the
technology and are still quite costly compared to other distributed generation technologies. Small hydro systems generate
electricity by transforming potential energy from a water source into kinetic energy that rotates the shaft of an AC generator.
Assumptions on system capacity sizes in each state and sector are detailed in Appendix A, section 5.1.Table 3-5 provides
the cost and performance assumptions used in the small hydro forecast and the source for each.
Table 3-5. Small hydro assumptions
Micro- Mini-
Cost& hydro hydro
performance 0i i0
metric Im or less) MW)
International Renewable Energy Agency(IRENA).2012.
Installed cost 2024$/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 $3,125 California."2019.California Energy Commission.
Annual installed NREL.2023. "2023 Annual Technology Baseline."
cost change p p Golden, CO: National Renewable Energy Laboratory.
2024-2043 -0.5/o https://atb.nrel.gov/
"A Comprehensive Assessment of Small Combined
Variable O&M Heat and Power Technical and Market Potential in
2024$/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.goy/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://energv.utah.gov/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/idstat/title63/t63ch3O/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
0.07/° pV+
Hydro Wind PV+ 0.00%
y ° 0.02 Battery Battery
Micro
0.000/° °/° 3.16% Micro 12 93%
Turbine
Turbine 0.00%
0.00%
Reciprocating Reciprocating
Engine
Engine 0.00%
0.00%
PV Only PV Only
96.81% 87.00%
PG capacity installed: 15.8 MW-AC PG capacity installed: 23.6 MW-AC
OR UT
Small Small
Hydro Wind PV+ Hydro Wind PV+
0.000/° 0.04% Battery 0.003% '�02% Battery
Micro 9.48%
Micro 3.10/° Turbine
urbine
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 Turbine
Hydro 0 08% Battery Micro 0.000% 0.49% Battery
Turbine
0.000/0 1.62/0 11.55%
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:10.2172/1130425.
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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DNV
Figure 3-10. Bass diffusion curve illustration
70%
Cumulative Adoption 3%o Annual Adoption
60% « 3%
w w
50% -.,o 2%
40% c
O .2 2%
S 30% a
0
A 20% M 1%
m A
��- 10% 1%
E 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°ro
100%
c 80%
c
60%
a
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%
0 80% 0 80%
0 70% 0 70%
rn 60% rn 60%
c c
3 50% 3 50%
c 40% 40%
m m
y 30% 30%
d 20% D 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 Corn Mid Ind Mid Res Low Res Mid Res High
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DNV
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 0000--<
4,000
3,500 .10 i .00
i
Q 3,000 OV
so,dop
2,500 O
00
> 2,000
i
1,500
v 1,000
500
0
(b OO O O O�O O O O O� O O OO O� 00�00 00 03 OH O� 0 000 ON A lb
0
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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DNV
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 r
w
M
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
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
Q
4,000
3,000
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
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DNV
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 --- _--
-----
E 2,000
� r
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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DNV
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
Wind Small Hydro Reciprocating Engine 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
20
15
U
10 r
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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DNV
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
c�
E 2,000
D
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.
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DNV
Figure 4-9. Cumulative new distributed generation capacity installations by scenario(MW-AC), California,2018-2043
80
70 doo
i
i
i
60
U 50
Q
40
a�
'— 30
E 20
U
10
0
lb �� r14 �N r1`L �� rt� �h ry(b rLA rLlb �0 3� 3N r�j`L 33 3� �h �� 31
ON �O �O �O ,y0 �O �O �O �O �O �O � �O 'O �O
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 d
75 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
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DNV
Figure 4-11. Cumulative new capacity installations by technology(MW-AC), California low case, 2024-2043
80
70
Q 60
50
> 40
30 mop -
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
Figure 4-12. Cumulative new capacity installed by technology(MW-AC), California high case, 2024-2043
80 —
70
Q 60
50
40
i
30
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
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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
15 15 /
> >
� 10 5 10
E E
U U
5 5
0 0
�0 D� �� `L� `L�° `L� 3� `5j7' 3� �� -0, �� �1 b�
�o
Industrial Irrigation
0.06 18
16
0.05
14
0.04 12
10
> 0.03
Zia 8
3 5
3 0.02 6
U U
4
0.01
2
0.00 "00000000000000000
rL� `L`0 rL� �0 `��, t�, + `�� �� R� �� OP O`L0 O�0 OHO �g`L OgD OryO o�0 OHO O�'L o�A
`lo do `Lo do do 'o do 'P 'o 'o do `t `t `t
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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
U
Q
150
i
i
i 100
75
E �
v 50
0
�O �'� �1. �"� rL� �h rt� �,1 �� �°� „�4 n�'� g`L g'3 n��' gh n��o g'l n�00 n�O �O K`I ry �3
2022 Study —Historical —Low —Base —High
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DNV
Figure 4-15. Cumulative new capacity installations by technology(MW-AC), Idaho base case, 2024-2043
300
U 250
Q
200
> 150 �� � ago
w
alp
ca O
100 .0p i
=3
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
30C
250
Q
200
a) 150
amp
-
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 Hydm
Reciprocating Engine �Micro Turbine 2022
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DNV
Figure 4-17. Cumulative new capacity installations by technology(MW-AC), Idaho high case, 2024-2043
300
250
U
Q
200 - -
> 150 MOPdw
r
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
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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 Q
100 50
> 80 > 40
60 30
v 40 U 20
20 10
0 0
O`L� O`lb O`L� O�1 O��O�tk 03lb O�� O�� O�V Ot`� O`L11 00b O`L� O�� O�� O�� Orb O� ON� O�� OWN
ti ti ti T ti ' ti ' ti ti ti ti ti ti T ' ti ti ti ti ti ti
Industrial Irrigation
70 70
60 60
Q 50 ¢ 50
2 40 2 40
16 30 m 30
E E
Lj 20 20
10 10
0 0
rLR rLlb `LO 3� `�j1' „�b �0 �0 �O �� Dtx �R `L0 ti( �O r�j`V �� �ro nil �O NIV t lx
T(O r(O T'Z ,yO tiO yO r1O tiO r1O r1O r1O rtO T TO T')
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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
800
600
E 400
U
200
0
ON� ONE 0`1� 0`V O`1�O`l� Z IV O`t� O`16 0`1A o`l� O`l� 03� O�� O�1 O`�5 O, 03� O15 Or! 003 O�� O�� O�� O��O��
`L `f `L `� `L `L `L `L `L ti `L `L `L `L `L - `L `L `L `L `L `L `L `L `L `L
2022 Study -Historical -Low -Base -High
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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
> 800 �--
600
E
U 400
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
1,000
800
ca75 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
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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
w
600
E
U 400
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
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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 ;
w 150
E 400
U U 100
200 50
0 0
tip` tit tit �� �� It` -t� 2� tp �� bx ti� ti6 �� 3� 3� 3� �� 3b
rp rV T rV '-p 'P rp 'P rP '-p 'P �O �O �O �O �O TO TO TO
Industrial Irrigation
14 40
12 35
Q 10 Q 30
25
2 8 M
> > 20
m g M
E E 15
U 4 U 10
2 5
0 0
tip` `Llb ti0 R "I,3 3 �N "alb "alb A� art t�N `�� `Lb rL0 3� "�7 "�� "fib �t NO p`L NN
TO TO TO rL0 rL0 �O �O �O 'O "0 0T TO rL0 rL0 rO �O rL0 'o 0 rp 0
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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
1,500 aw mop
> i
oge
1,000
U
500
0
O�� OHO OHO "'P "d,OHO J O�� OHO O�� O�� OHO 030 O�� 00) 00� 00� 00� OHO O�� 00� 000
2022 Study —Historical Low Base —High
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DNV
Figure 4-25. Cumulative new capacity installations by technology(MW-AC), Utah base case, 2024-2043
3,000
U 2,500
r
2,000 r
> 1,500 -�
ca � �
� 1,000 .00 r r r
=3 � rdop
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
Figure 4-26. Cumulative new capacity installations by technology(MW-AC), Utah low case, 2024-2043
3,000
U 2,500
Q
2,000
> 1,500
ca
1,000 mop
r i
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 Hydm
Reciprocating Engine �Micro 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
U 2,500
Q
2,000
> 1,500
ca �
� 1,000 � mop
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
800 800
> 600 > 600
E 400 F 400
U Lj
200 200
/000
0 0
oti° o`�o oti�o`�o o`l�o`�1 o`§1 o`§1 o°o o°5 o°° o`�° o`��o`��030 03�o`t° o'�o o`�o o°°o0 oN"
ti ti ti ti ti li ti ti ti ti 1 ti ti ti ti ti ti ti ti ti ti ti
Industrial Irrigation
16 70
14 60
Q 12 Q 50
10
2 40
> 8 >
m 76 30
E 6 E
c i 4 ci 20
2 10
0 0
rR fro �1b n�0 n�`L rbtK "pro n�0 �o p't �R �tx �'o 10 �o nj� n�� 3Q) z bo b1. NR
,y0 To TO �O
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
Q 250
200
150
5
E
v 100
50
0
,�O �O ,�O ,�O ,�O yO ,�O �O ,�O ,�O �O ,�O �O ,�O ,�O �O ,�O
2022 Study -Historical Low Base -High
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DNV
Figure 4-30. Cumulative new capacity installations by technology(MW-AC),Washington base case, 2024-2043
400 - - -
350 - - -
Q 300 - - -
250 - -
> 200cc
— -
w
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 r� 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 -
150 -
U 100
50 WON
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
w
150 _ -
E
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 Q 80
150
> > 60
100
3 E 40
U U
50 20
0 0
`LD do ti� ,�O D 3`L ,�D 30 00 �O p`L �� ,L ti� 30 �`L �N 30 �� VO t- R�
TQ �O �O �O �O �O �O �O ,LO �O ,LO �O �O ,yO �O �O �O ,yO �O ,LO rp ,V
Industrial Irrigation
5 20
4 18
4 16
3 Q 14
12
3
> > 10
.1� 2
8
U 2 U 6
1 4
1 2
0 0
� � � 03� O�� O`l�
tiO`t' O`l O`l
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
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
is
60
E 40
U �
20
dop
�( �°6 ti� �^ �`1, tie ti� �0 tiQ tiA (b �°� 30 ^�N �`1, 3' 3b, 3b ^�0 3'1 3� 3°'
do �o ,tio �o ,tio ,tio To do T To To T ,tio T T V T �o fl do P rpP ,P ro Io
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
80
a)
60Cc
—
E 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
Figure 4-36. Cumulative new capacity installations by technology(MW-AC),Wyoming low case, 2024-2043
140 —
120
U
Q 100
80
60
E 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 55

DNV
Figure 4-37. Cumulative new capacity installations by technology(MW-AC),Wyoming high case, 2024-2043
140
120
U
Q 100
80
a)
M
E 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
,LO yO ,LO �O ,ti0 LO 'ti 'y ti0' ,LO , 'V r10 r1O �O '1 'O 'L r1O ' ,LO '
Industrial Irrigation
0.50 0.30
0.45
0.40 0.25
U 0.35 U
Q Q 0.20
0.30
> 0.25 > 0.15
.5
7s 0.20
cm0.15 U 0.10
0.10 0.05
0.05
0.00 0.00
�p fro �g �p �� �p „�� �g �� �0 �p �b ��o ry�b „�O „�`L 3� ^5�O .
rp 'O �O 'O 'O 4 'O TO TO TO TO ,LO 'O 'O �O 'O f f
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DNV
5 APPENDIX
5.1 Technology assumptions and segment-level inputs
Appendix A.xlsx
5.2 Detailed results
Appendix B.xlsx
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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
M
:3 30
E
D
U 20
10 Residential
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.
DNV — www.dnv.com Page 60

DNV
Figure 5-2. Cumulative new battery storage capacity installed by scenario(MW), 2023-2042
600 7-
500
U
Q 400
> 300
CID
E 200
U
100
0
2018 2022 2026 2030 2034 2038 2042
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/energy/Incentives/Pages/Solar-Storage-Rebate-Program.aspx
DNV — www.dnv.com Page 61

DNV
Figure 5-3. Cumulative new battery storage capacity installed by state (MW), 2024-2043, base case
60
500
3: 400
a�
300
m
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
2
a)
300
m
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
DNV — www.dnv.com Page 62

DNV
Figure 5-5. Cumulative new battery storage capacity installed by state(MW),2024-2043, high case
600
500
3: 400
m
ca
300
E
U 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
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
1.5
m
1.0
U
0.5
0.0
2018 2022 2026 2030 2034 2038 2042
Range Base Historical
DNV — www.dnv.com Page 63

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
1M 0.15.0 a —
>
R m
0.8
E E 0.10
U 0.6 U
0.4
0.05
0.2
O`11b 21 `L9 3� n�3 3� 3l 39 p,,
� O y0 20 ZO 20 �O
CA Non-Residential PV+ Battery CA Non-Residential Battery Retrofit
1.0 0.30 —
0.9
0.8 0.25 —
0.7
0.20 —
A 0.6 — m
M 3
v0.5 E 0.15 —
0.4 v
0.3 0.10
0.2
0.1 0.05
�3 'b
�O .10 �O �O �O 20 �O �O �O �O ,LO,L3 29gb�(PI �O�g ti9�1 ti93b 29ap ti9p 2 9
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
Z3 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
8 0.9 —
7 0.8
6 0.7
> 5 °1
0.6
M — 0.5
4
E E 0.4
v 3
v 0.3
2
0.2
1
0.1
�O`L3 y0`1� y0`1� yOti9 y03� y033�03��03� �03g 20�� ,Lp`L3,Lp`L6,Lp`L1 �p`L°,�p3�,Lp33,Lp35 2�3� ,Lpbq
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 °0.030 —
E 1.0 3
ci 0.8 0.025
U
0.6 0.020
0.015
0.4
0.010
0.2
0.005
,Lp`L ti0`L ti0`L ti0`L `LOB •1,0� ti0� �03 ti02� ti0�
DNV— www.dnv.com Page 66

DNV
Oregon
Figure 5-10. Cumulative new battery storage capacity installed by scenario(MW), Oregon,2018-2043
450
400
350
U
Q 300
a�
250
200
D 150
U
100
50
0
2018 2022 2026 2030 2034 2038 2042
Range —Base Historical
DNV— www.dnv.com Page 67

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
2 12 3.0
10 > 2.5
R
3 8 2.0
E
ci 6 ci 1.5
4 1.0
2 000000,
0.5
LO�Lll`L41�`L(91 `L49`V `LO��`5S5 `555 15 5 20�1 pP p'L1 01L pp,1
`L `L `L `L `L `L 2 `L `L `L
OR Non-Residential PV+Battery OR Non-Residential Battery Retrofit
3.5 3.0
3.0 2.5
2.5
>_ >_ 2.0
W Y
2.0
3 3 1.5
v 1.5 V
1.0 1.0
0.5 0.5
lb Ib 2�3A 2�39
DNV — www.dnv.com Page 68

DNV
Figure 5-12. Cumulative new battery storage capacity installed by scenario(MW), Utah,2018-2043
450
400
350
U
Q 300
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 —
m 80
> > 50
m �
60 40
E F
t� 40 v 30
2
20 0
10
�031 �039�OP ,L(9L1,L41b,Lp91 ,L41,LQ;�' ,Lp`53 2p`i5,Lp15, 2p10,LppN�
UT Non-Residential PV+ Battery UT Non-Residential Battery Retrofit
7 - 8
6 7
m 5
6
> >
4
R 5 —
£ 4
t1 3 V
3
2
2
1
1
2p`l- Z61 ,O`Z' ,LD'L �p3 �03 �p3 3 �p`3 20D
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
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 2 0.8
1.2 >
1.0 5 0.6 —
�?0.8 B
0.6 V 0.4
0.4 —
0
0.2
.2
�O`1lb�41��O`11 L4g`L03�`L03�`505 2031 15 35 20 0" 41b p`L1 411 Q` ' Q;b" 635 o51 1�39
2 ti ti � � ti � ti ti ti
WA Non-Residential PV+ Battery WA Non-Residential Battery Retrofit
1.2 0.25
�
1.0 30.20
0.8 >
3 R 0.15 —
0.6 E
L) 3
0.4 V 0.10
0.2 0.05
0 0p\
ZO`i `LO`L ti0`l 20L 2�3 `10� 20� `10� �03 `1
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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
M
- 8
B
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
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DNV
About DNV
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the environment,we enable our customers to advance the safety and sustainability of their business. We provide
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PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
APPENDIX M - STAKEHOLDER FEEDBACK FORMS
Introduction
As of December 2024, stakeholder have submitted 71 stakeholder feedback forms, summarized
below. Stakeholder feedback forms,including PacifiCorp responses,are publicly posted to the IRP
website. The stakeholder feedback forms have allowed the company to review and summarize
issues by topic as well as identify and respond to specific recommendations. Information collected
was 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 C.1 — Stakeholder Feedback Form Summary
SEE# 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) Bridget 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 Optimurvzatan 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 PIMs. Appendix M
Climate 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 of geothermal 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 for tables.
tables Chapter 6
2023 IRP Update assumptions locked before SB-224 passed;legislative
2025.013 Emma Verhamme(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 PIMs. 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 EPA's GHG Rule,including
2025.016 PRBRC(4/30/24) greenhouse gas emissions riles IRP liance scenarios,descriptions,charts,and details as part of the 2025 Chapter 3
Distributed generation study, Chapter 6;
2025.017 OPUC(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
271

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
Table C.1 —Stakeholder Feedback Form Summary continued
SFF# Request Topic PacifiCorp Reply Reference
Wildf re-related costs are part of the SCGHG scenario.Regional and
Wildfire risk,regional and Chapter 5;
2025.018 OCA(7/19/24) interregional transmission interregional transmission plans are developed through the NorthemGrid Chapter 8
re ' nal planning process.
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- Chapter 8
cap-and-invest program, and-invest program
modeling scenarios
2025.021 FPA(7/9/24) Configuration details for Table of PLEXOS Production Settings provided. Chapter 8
PLEXOS modeling exercises
2025.022 SLC(7/29/24) PLEXOS model variant The IRP is based on proxy resource costs and related assumptions that are Chapter 8
generic and intended to be broadly applicable.
2025.023 NPE(8/9/24) Non-emitting peakers- Responses provided to each request. Chapter 7
Hydrogen fuel availability
2025.024 NPE(8/9/24) Candidate resource costs Resource cost adjustments explained. Cha ter 7
2025.025 NPE 8/9/24 Carbon capture storage Descitpion of FEED study role;CCS ass lions and status. Chapter 7
Distributed generation study,
2025.026 VSO(8/9/24) Please see responses to individual questions in the form Chapter 6
sensitivities
2025.027 VSO(8/9/24) Tax Credits Modeling accounts for tax credits and bookend sensitivities will cover Chapter 8
unknown magnitudes outside of PacifiCorp control
PLEXOS modeling and
2025.028 UCARE(8/30/24) differential coal quality cost Modeling accounts for coal costs on a BTU-adjusted basis. Chapter 8
impacts
2025.029 UCE 8/9/24 Modeling coal costs and risks in Description of coal reporting, ass tons,and risks. Chapter 8
( ) 2025 IRP planningprocess p 'spy P
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 Chapter 8
proportion of energy generated by the PacifiCorp system over time.
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 Chapter 8
proportion of energy generated by the PacifiCorp system over time.
PacifiCorp is committed to achieving emissions reduction targets as required
2025.032 Sara Kerney(8/14/24) Carbon Dioxide Emissions by state and federal regulatory obligations and welcomes the development of Chapter 8
alternative fuel sources that can provide a similar level of system flexibility as
traditional thermal resources at reduced emissions rates.
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 moding,reporting and access to
2025.036 SC(8/27/24) Infrastructure Reinvestment, materials Chapter 8
Federal legislation,resource
availability
2025.037 UCARE 8/30/24 Utah state legislative actions Will be addressed in the September 25-26 public input meeting. Chapter 3
Infornration and market variant Further information about the origin of the Wyoming market treatment and
2025.039 WRA(9/9/24) Chapter 8
request WRAP.
2025.040 RNW 9/11/24 IRP transmission planning Please see responses to individual questions in the form Chapter 8
2025.041 Nathan Strain(9/20/24) Nuclear&geothermal Sensitivity studies planned for nuclear and geothermal costs. Chapter 7
development in Utah
2025.042 FPA(9/23/24) Request for LT plan settings Not available;to be provided with the work a ers in the IRP filrt 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 amemdments being used in CPA. Chapter 7
assessment modeling
Not included in
Requests energy efficiency& the 2025 IRP;
2025.046 UCE(11/7/24) demand response data from Please see responses to individual question in the form refers to 2023
past filings IRP and 2023
IRP Update
272

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
Table C.1 —Stakeholder Feedback Form Summary continued
Sensitivity targeting 85% Chapters 8;
2025.048 UCE(12/17/24) reduction in PaciiCorp emissions Study will be run if time and resources allow. Chapter 9
by 2032 using 2005 baseline
2025.049 UAEU(1/8/25) Clarifying composition of Additional information added for the final IRP. Chapter 7;
resource and portfolio tables. Chapter 9
2025.050 UCE(1/14/25) Emissions sources and drivers Emissions include purchases;rate given,explanation in Appendix A. Chapter 9;
Appendix A
Chapter 1;
2025.52 WEA(1/15/25) Load forecasting,resource Some load considerations are not in the scope of the IRP.Market purchases Chapter 5;
adequacy are restricted during critical peaks more than in past IRPs. Chapter 7;
Appendix A
Preferred portfolio selection of Topics addressed in the Jnauary 22-23,2025 PIM.Coal pricing in final Chapter 7;
2025.053 SC(1/16/25) MN vs MR,coal pricing,HB workpapers.Final filing will include coal assumptions,CCS,and a new CEP Chapter 9;
2021 compliance,CCS costs appendix as a bride to the CEP filing. Appendix Q
Draft table clarifications, Clarifications given will also be included in the final IRP filing.Some special
2025.54 WYC(1/15/25) transmission-only customers, contracts are considered in the bad forecast.PLEXOS.xml data is Chapter 6;
load forecast components, confidential Appendix A
PLEXOS model data
Study request which excludes Chapter 8;
2025.55 DPU(1/24/25) Request is under consideration
100-hour iron-air batteries Chapter 9
Concerns regarding lack of Geothermal parameters defined.Request for a counterfactual study is under
2025.56 UCE(1/25/25) geothermal selections,request consideration. Chapter 7
for sensitivity
Concerns regarding DSM All resources are selected on a technology-agnostic competitive basis in the Chapter 7;
2025.57 UCE(1/25/25) variability and selection over the
tann optimization process. Chapter 8
in horizon
Questions regarding interactions
2025.62 RNW(2/10/25) of WRAP,transmission and Please see responses to individual questions in the form Chapter 8
resource selections
PTC interactions with study PTCs will be modeled to taper off after five year to mitigate the observed Chapter 7;
2025.63 UCE(2/10/25) Chapter 8;
horizon in plain modeling clustering of resources in 2036.
Chapter 9
Transmission topology, Transmission options are available for selection by the model.Please see Chapter 7;
2025.64 IEA(2/10/25) upgrades and modeling responses to individual questions in the form Chapter 8;
Chapter 9
2025.69 SC(2/20/25) Request for sensitivity, Please see responses to individual questions in the form. N/A
PLEXOS request for input file
2025.71 Jeremy Rishe(3/03/25) Encouragement to develop PacifiCorp is exploring divese options for customers. Chapter 7
solar,storage and transmission
equested Additional Studies
Stakeholder feedback forms provided more than 50 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 eight requests 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.
273

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
The eight specifically requested cases are summarized below.
1. 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 is assumed to include SCR
technology.
6. Wyoming Market Removal Variant(SFF#39, Western Resource Advocates): Assumes there
is no access to the presumed Wyoming market. This study request is not addressed given that
in the 2025 IRP it is already assumed that there is no market availability during peak hours,
and all integrated portfolios must include sufficient generating and storage resources to be
compliant with WRAP-based planning reserve margins. Thus, integrated portfolios are
already required to meet reliability goals without the use of markets.
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 is not addressed for the same reasons
given in the above discussion of the Wyoming Market Removal Variant request, above.
8. Early Renewable Availability(SFF#69, Sierra Club): Conduct a sensitivity that includes a
commercial operation date of 2026 for an initial tranche of solar,wind, and battery storage
resources that equate to the AS2022 RFP. This study request is outside of the proxy-based
scope of the 2025 IRP.
274

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
blished Stakeholder Feedback ko
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:
hgps://www.pacificorp.com/energy /y integrated-resource-plan/comments.html
275

PACIFICORP-2025 IRP APPENDIX M-STAKEHOLDER FEEDBACK FORMS
276

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
* Required fields

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 2 0 2 4-0 5-0 6
*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 2 0 2 4-0 5-0 6
*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.
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Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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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 2024-05-03
*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.
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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]
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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.
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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):
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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 1 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]
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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.
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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

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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)
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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.
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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
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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.
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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 1RP, 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: 0 5-0 2-2 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.
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.
* Required fields

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.
* Required fields

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
* Required fields

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):
* Required fields

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
* Required fields

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.
* Required fields

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?
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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.\u00 1 D 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.
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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 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 primemo—s-
Qe laf Data source_US Energy Information AdmnisUation
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
Chapter 4:Grid Performance
14% Resource Mix%
11.7% Nuclear,10%
Hydro,12% 'Other,9%
12%
Coal,22%
SO%
Ga5.48%
rr
O 8%
6.4%
3 �
6%
4%
2%
2% all
0%
2014 2018 2023 2014 2018 2023 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
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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.
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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. PaciflCorp 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.
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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 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 8/27/2024
*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
Thank you for participating.
* Required fields

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 Milestone Public Input Request
I-.r.. aFy 25 7074 Present en CGepe of W9FI
March 14 7117n
Arai Q 202
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$175/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 Impact of 25C Tax Credit and HEEHRA
Rebate on Cost of Heat Pumps(80%to 150%AMI)
HEEHRAEst.25C Tax Est.
Net cost
Credit Value Rebate
Centrally Ducted ASHP
Centrally Ducted ASHP—Base $14,1 W b s $14,800
Centrally Ducted ASHP—Moll Stage $17,175 b s $17,175
Centrally Ducted ASHP—ENERGY STAR S17,1l00 $2AW 5 o00 $7,1 W
Centrally Ducted ASHP—Cold Climate $19,425 52AW $a," $9,425
Centrally Ducted ASHP—Dual Fuel $11,277 k $11,277
Centrally Ducted ASHP+Furnace—Dual Fuel $16,250 b $16,250
Ductless Mini-Split Heat Pump(assumed 3 tons)
DucbessMiri-Split Heat Pump—Base $13,443 b $13,443
DuctlessMiri-Split Heat Pump—ENERGY STAR MAN $2A00° $7,443 $5,443
DucdessMiri-Split Heat Pump—Cold0mote $15,246 $2,000° $7,623d $5,623
Sources:26 C.F.R§25C,An Acr to provide for recarx*odan pursuant to tide ll of S_Con_Res.14,Public Law 117-169(2022)_
1817-2090.httoc:/lww•v_coneress.eovl117/olaws/oubl169/P LAW-117oubi169.r>df
•While this table shows the HEEHRA rebate estimate for residents making 80%to 1SO%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.
11 Equipment is not assumed to meet the efficiency 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.
* Required fields

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/1/2030 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/l/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
* Required fields

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 KRIS?
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.
* Required fields

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.
* Required fields

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.
* Required fields

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
* Required fields

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
* Required fields

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
* Required fields

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
* Required fields

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
* Required fields

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
* Required fields

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
* Required fields

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

PacifiCorp - Stakeholder Feedback Form
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 12/17/2024
*Name: Logan Mitchell Title: Climate Scientist and Energy Analyst
*E-mail: LogangUtahCleanEnergy.org Phone:
*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.
• Request for a 2025 IRP technology agnostic model sensitivity that reduces portfolio emissions by 85%by 2032.
❑ 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.
Impacts from the changing climate are now having material impacts on PacifiCorp and ratepayers, from wildfire impacts
that present one of the most significant financial threats to utilities,to heat waves driving up peak demand and power
prices,to drought affecting hydroelectric generation, extreme weather events affecting infrastructure, and more. There's
broad consensus in the need to limit warming to below 2°C, at which point many societal risks and costs from climate
change impacts are projected to substantially increase.
To keep warming below 2°C,US economy wide emissions need to decrease by 50-52%by 2030 using a 2005 baseline, as
discussed in Utah Clean Energy's direct testimony in Rocky Mountain Power's 2024 rate case [1]. A recent research
study used six coupled energy-economy models to investigate sectoral emission reductions needed to reach that economy
wide emission reduction target[2]. This report found that the most cost-effective near-term emission reductions come
from the electricity sector. Therefore,to achieve US economy wide emission reductions of 50-52%by 2030,the
electricity sector would need to reduce greenhouse gas emissions by 80%by 2030. This analysis provides critical
guidance to the entire electricity sector in the US about the amount of emission reductions needed to mitigate the costs
and risks posed by climate change.
However,given the timeframe of resource planning and procurement, and the 2025 IRP Action Plan window that will
extend through 2028,we are concerned that there is not enough time for the IRP model to achieve that 80%reduction by
2030 endogenously.
We therefore have the following request: A technology agnostic IRP model sensitivity run that determines the least-cost
approach to achieving an 85%reduction in PacifiCorp's greenhouse gas emissions by 2032 using a 2005 baseline. These
targets are largely in line with the emission reduction pathway in the 2023 IRP preferred portfolio(see figure below).
In other words,PacifiCorp's 2005 baseline CO2 emissions were 54.60 million metric tons, so we are requesting a
sensitivity such that PacifiCorp's 2032 emissions are at or below 8.19 million metric tons (85%reduction).
* Required fields

PacifiCorp's 2023 IRP vs 2023 IRP Update
20%
2023 IRP
2023 IRP Update
O 30% Actual
C
Gl
fC 40%
.Q
to
O
N 50%
C
O
+J 60% -
u
O
O
L 70% -
C
O
`-" 80% 800/6 x 2030
85% x 2032
0 90%
100%
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
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.
[I] Phase I Direct Testimony of Dr. Logan Mitchell of Rocky Mountain Power,Docket No. 24-035-04(filed Oct 17,
2024)https://pscdocs.utah.gov/electric/24docs/2403504/335983PhsIDirTstmnLoganMitchelUCEIO-17-2024.pdf
[2] Bistline, John,Nikit Abhyankar, Geoffrey Blanford,Leon Clarke, Rachel Fakhry,Haewon McJeon,John Reilly, et al.
"Actions for Reducing US Emissions at Least 50%by 2030." Science 376,no. 6596(May 27, 2022): 922-24.
htips:Hdoi.org/10.1 126/science.abn0661.
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
Please submit your completed Stakeholder Feedback Form via email to IRPkPacificorp.com
Thank you for participating.
PacifiCorp's Response:
Thank you very much for your feedback and recommendation. PacifiCorp is currently evaluating the variety of sensitivity
requests received and, should sufficient modeling time be available,will incorporate this sensitivity in the March 31 final
filing.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 5-01-0 8
*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 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.
Draft IRP Document
® 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.
1. Long Duration Battery Storage / Iron Air Battery a. Please address the
feasibility of the Iron Air Battery storage technology. b. In table 7.3 the 100 hour
Iron Air battery has a resource availability of 2030, and a commercial operation year of
2032. Commercial operation year is defined in the IRP as \u001CYear when the Resource is
available for generation and dispatch. It is based on the Resource Availability Year plus
the Total Implementation Time.\u001D Please discuss how these two years are used in the
modeling for Iron Air batteries and if Iron Air batteries are considered having capacity
value prior to the commercial operation year. c. In tables 9.5, 9.6, 9.7 and 9.10
please provide the detail of the resources on the \u001CRenewable Battery (Long Duration)
row, i.e. what is Iron Air Battery, CAES, Pumped Hydro, other. 2. Previously
Contracted Resources, not yet built or operational a. Please provide a detailed
list of previously contracted resources noted in the Executive Summary on pgs. 4-5:
\u001CThe 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 MW of solar additions, and 1,072 MW of battery storage capacity. These
resources will come online in the 2025 to 2026 timeframe.\u001D Please include year (2025
or 2026) , the resource type and, if battery storage, the type of battery. b. Please
indicate if any of the previously contracted resources are included in the Expansion
Options section of table 9.10 c. Please indicate or confirm the previously contracted
resources are included in the Planned Resources section of tables 9.11 and 9.12 d.
Consider adding a separate section to tables 9.11 and 9.12 for previously
contracted resources 3. Please explain in detail the change in modeling hydrogen
resources as noted in the Chapter 7 highlights: \u001CIn 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.\u001D
* Required fields

4. In figure 9.13 please provide the detail of what is in the \u001COther\u001D
category 5. Please provide versions of figures 9.13 and 9.14 net of Demand Response
and Energy Efficiency resources. 6. Master list of Expansion Resources and
Previously Contracted Resources \u0013 Please provide a master list of Expansion and
Previously Contracted resources with the following information a. Online year, or
year assumed able to meet capacity requirements b. Average Summer and Winter Capacity
Contribution, i.e. tables 9.13 and 9.14 c. For Expansion Resources, the
corresponding row in tables 7.2 and 7.3 for each resource
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(2/11/2025)
1. As indicated on page 143 of the 2025 IRP Draft Volume 1, input assumptions for the 100-hour iron-air battery
were developed in cooperation with Form Energy based on their commercial long-duration storage product.For more
information,please visit: https://formenergy.com/technoloayibattery-technology/.
In Table 7.3 the 100-hour iron-air battery mistakenly has a resource availability year of 2030 and a commercial operation
year of 2032. The availability year and commercial operation year of the 100-hour iron-air battery should be 2028 and
2030 respectively. The commercial operation year for the 100-hour iron-air battery was already being modeled as 2030 in
PLEXOS. The first year the 100-hour iron-air battery may provide capacity value in PacifiCorp's 2025 IRP modeling is
2030. While this product is currently available, it may take a few years for production capacity to support the quantities
contemplated in PacifiCorp's 2025 IRP.
The long-duration storage category for selections in the preferred portfolio and any portfolio variants includes both 8-hour
lithium ion batteries and 100-hour iron-air batteries. For detail of the resources included on the"Renewable Battery(Long
Duration)"row in Table 9.10,please refer to the public LT model report for the 2025 IRP draft preferred portfolio
included on the public data disc: (P)_LT_251.LP.iLT.21.Integrated.EP.2409MN.Base IntTrans_106955 v78.1.xlsb.
Specifically,please refer to tab"Portfolio Data"and filter column T for"Renewable- Battery(Long Duration)". LT
model reports for Tables 9.5, 9.6 and 9.7 will be available along with the final filing of the 2025 IRP. Please note,
PacifiCorp is considering updates to how storage resources are categorized in Tables and Figures included throughout the
2025 IRP document to help stakeholders identify the specific storage resource types being represented.
2. The previously contracted resource totals referenced on pages 4 and 5 of PacifiCorp's 2025 IRP Draft Volume I
are nameplate installed capacity MWs while Tables 9.11 and 9.12 in PacifiCorp's 2025 IRP Draft Volume I present
Western Resource Adequacy Program(WRAP)qualifying capacity contribution values in MWs. For nameplate capacity
detail on all of the previously contracted energy storage resources,please refer to Table 6.6 and Table 6.11 in PacifiCorp's
2025 IRP Draft Volume 1. The qualifying capacity contribution detail will be provided with the confidential workpapers
in PacifiCorp's final IRP filing. With regard to the online date for energy storage in those tables,the Panguitch battery
achieved commercial operation in 2020,the Oregon Institute of Technology(OIT)battery is expected to reach
commercial operation in 2025, and all of the other previously contracted energy storage is expected to reach commercial
operation in 2026.Additional detail on nameplate capacity of previously contracted wind and solar resources may be
found on tab"Portfolio Data"in file(P)_LT_25I.LP.iLT.2l.Integrated.EP.2409MN.Base IntTrans_106955 v78.1.xlsb on
the public data disc accompanying PacifiCorp's 2025 Integrated Resource Plan Draft.
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The only resources included in the totals presented on pages 4 and 5 also included in the"Expansion Options"section of
Table 9.10 are the 2026 value for battery storage which includes Dominguez BESS,Enterprise BESS, Escalante BESS,
Granite Mountain BESS and Iron Springs BESS battery storage facilities totaling 520 MWs of nameplate installed
capacity. Dominguez BESS is a stand-alone energy storage resource while the remaining four battery storage resources
will be added at existing solar resources and use surplus interconnection.All five of these four-hour battery storage
resources were committed since the filing of the 2023 IRP Update and are scheduled to come online ahead of the peak
summer season in 2026.
The previously contracted resources referenced on pages 4 and 5 are not included in the"Planned Resources"section of
Tables 9.11 and 9.12. These resources are included in the"Existing Resource" section of Tables 9.11 and 9.12, including
the five battery storage facilities referenced above.PacifiCorp has discovered errors related to PLEXOS modeling setups
of WRAP qualifying capacity contribution values which caused errors in Tables 9.11 and 9.12, along with Tables 6.14,
6.15, 9.13 and 9.14 and Figures 6.2 and 6.4-6.7. These modeling setups will be corrected along with all aforementioned
Tables and Figures in the final filing of PacifiCorp's 2025 IRP.
3. The decision to model hydrogen as an alternative fuel, including electrolyzer cost and performance,has been
discussed in several meetings throughout the course of the 2025 IRP public input meeting series (e.g.August 14-15, 2024
public input meeting). PacifiCorp considered both tank and cavern storage options for hydrogen which in combination
with electrolysis could allow for increased clean energy production. The tank option is being modeled in PLEXOS in the
2025 IRP. PacifiCorp decided to model the hydrogen storage peaker resource for the 2025 IRP after soliciting stakeholder
feedback and comparing the viability of tank or cavern storage options for hydrogen fuel to hydrogen resource options
requiring a hydrogen pipeline.
4. Figure 9.13 includes existing,planned and proxy resources for each category. "Contract"includes long term
contract purchases, sales and interruptible contracts. "Other"includes hydro,hydro storage, geothermal and nuclear
resources.
5. PacifiCorp has not prepared versions of Figures 9.13 and 9.14 net of demand response and energy efficiency
resources. The workpapers supporting Figures 9.13 and 9.14 may be found on the public data disc for PacifiCorp's draft
2025 IRP: (P)_Fig 9.13-ST Cost Summary(106957)v78.3 -Preferred Portfolio with Energy Pivot Chart.xlsb and
(P)_LT_251.LP.iLT.21.Integrated.EP.2409MN.Base IntTrans_106955 v78.1.xlsb.
6. The company has not produced the requested list of resources and information. Details related to Tables 9.13 and
9.14 may be found on the public data disc for PacifiCorp's draft 2025 IRP: (P)_Fig 6.2-6.7, Tables 6.14-6.15, 9.11-14,
2025 IRP-L&R.xlsx. As stated in response 2 above,Tables 9.13 and 9.14 contain erroneous values due to a modeling
error of WRAP qualifying capacity contribution values. These tables will be corrected in the final 2025 IRP filing.
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PacifiCorp - Stakeholder Feedback Form
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 Jan 14,2025
*Name: Logan Mitchell Title:
*E-mail: [e-mail] Phone:
*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.
• CO2 Emissions from the 2025 IRP Draft
❑ 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.
The CO2 emissions in the 2025 IRP Draft in the years 2025-2030 are lower than they were in the 2023 IRP and the 2023
IRP Update, according to Figure 9.10 in the 2025 IRP Draft. However, in those years PacifiCorp is planning to procure a
very limited amount of new emission free generation resources like solar and wind, far less than what was included in the
2023 IRP and 2023 IRP Update. We have a few questions to help us gain an understanding of what explains this change.
1) Do the emissions in the 2025 IRP Draft include emissions from market purchases?
2) If so,how are market purchase emissions calculated, and what data inputs were used?
3) If not,we request that these emissions are estimated and accounted for in the final 2025 IRP.
4) More generally,what is causing the lower emissions in the 2025 IRP Draft as compared to the 2023 IRP and 2023
IRP Update in the 2025-2030 timeframe?In the Chapter 9 highlights, four factors are listed: retirements,
additional natural gas conversions,reduced capacity factors at existing coal and natural gas facilities, and
installation of carbon capture and sequestration(CCS). However,retirements and gas conversions have been
planned for a while and the CCS installation wouldn't happen until 2030. So,what is the primary driver of
emission reduction in 2025-2030,especially in the year 2025, and how is that calculated, and what inputs were
used?
Lastly,Figure 9.12 shows Oregon allocated emission reductions relative to HB2021 target. We request companion figures
that show how emissions in the rest of PacifiCorp's states and each state individually change as a result of this allocation
to Oregon.
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 submit your completed Stakeholder Feedback Form via email to IRP(c�r�,Pacificorp.com
Thank you for participating.
PacifiCorp Response(2/11/25)
1) Yes.
2) As described on page 226 of the Draft,market purchases are assigned emissions at a rate of 0.428 metric tons
CO2e per MWh. The market purchases selected in the 2025 IRP Draft preferred portfolio are used as inputs from
2025 to 2045.
3) N/A
4) The 2025 IRP has lower load than the prior versions, as discussed in Appendix A in Volume II of the 2025 IRP
Draft. Additionally,market prices for electricity and natural gas in the 2025 IRP incorporate increased volatility,
leading to more periods where it is cost-effective to run gas plants instead of coal plants, and more periods when
low-cost market purchases displace emitting resources,with limits on wholesale sales also playing a role. Please
refer to Chapter 9 for details on the calculation of system emissions.
PacifiCorp is actively looking for helpful ways to present emissions data in the final 2025 IRP and will consider this
request to present state-level emissions data.
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PacifiCorp - Stakeholder Feedback Form
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 5-01-15
*Name: Rob Creager Title: Executive Director
*E-mail: [e-mail] Phone: [phone]
*Organization: Wyoming Energy Authority
Address: 1912 Capitol Ave #305
City: Cheyenne State: WY Zip: 82001
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.
Demand Forecasting and Generation
® 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.
Demand Forecasting and Generation: According to the Draft IRP, PacifiCorp projects that
Wyoming is to only experience 0.03% annual load growth from the years 2025-2034 (Vol. 2
pg. 3) . As the state agency that promotes and supports the development of commercial
energy projects, the Wyoming Energy Authority is aware of the demand for hundreds of
megawatts of generation capacity in our State. In addition, as is widely known, WECC and
the United States are expected to experience annual electric load growth rates closer to
3% or higher. Specifically in Wyoming, we know that Rocky Mountain Power has had requests
for large energy users--like data centers--and have pressing needs to serve other organic
growth in communities, like in the case of Laramie. Further explanation of the load
growth forecasting in Wyoming is required to accurately reflect our development interest
and in order for PacifiCorp to meet these vital economic development needs. Under the
demand forecasting system-wide (Vol. 1 pg. 31) , there is mention of non-CAISO WECC region
projected to experience annual growth of 1.8% through 2030. There is further discussion
of this on pg 98. However, demand forecasts for all six states in PacifiCorp service
territory (Vol. 2 pg 3) fall under the demand forecast by WECC in its latest WARA (Dec
2024) . The exception is Utah which is making up for projected anemic growth particularly
in Wyoming and Idaho. In addition, as stated in WECC's latest WARA, forecasts beyond 2025
outperform forecasts from previous years 2022 and 2023. The WEA would recommend further
clarification on the demand forecasts here, in particular to better understand the
assumptions PacifiCorp is using in demand forecasting (e.g. high-growth scenarios because
many studies seem to be raising the forecast for load growth) . While possibly intuitive,
further explanation on page 98 as to why the non-PacifiCorp regions in WECC (California
and Desert Southwest) are expected to see higher demand growth. In Vol 1 on page 8, it
is stated, "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." WEA feels that this should be further clarified either here or in
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Chapter 7 to better understand what this means and how this affects the assumptions into
the models affecting demand forecasts. (On its surface, it appears PacifiCorp is
projecting lower demand from new large customers which, again, is incongruent with the
regional and national facts on the ground) . Chapter 5 discusses resource adequacy and
beginning in Volume 1 on page 102 in the Adequacy Assessment section, there is a line
about higher data center loads could lead to reliability shortfalls. This, coupled with
increasing capacity constraints on the system, from an economic development perspective,
is alarming as it could mean that it could be harder to site large-load economic
development projects in Wyoming moving forward. Further explanation is necessary. Tied to
the above bullet point, Chapter 6, there is mention regarding "the uncertainty in the
company's load and resource balance is increasing. . .the resources and load relationships
ultimately drive the frequency and characteristics of the relatively extreme conditions
that are most likely to trigger reliability shortfalls." It is also mentioned that
PacifiCorps's system is capacity deficient relative to WRAP compliance by Summer of 2026
without resorting to short-term capacity procurements like market purchases. While the
WEA appreciates PacifiCorp's plans to extend the life of many of its generation units in
Wyoming, WEA is also concerned that if the company will be resorting further trading on
the open market which can lead to more volatile costs that will be passed on to our
residents. WEA recognizes that PacifiCorp, like all utilities, trades in a market.
However, as resources become more intermittent and scarce, trading on an open market will
become more competitive and thus drive up costs. In addition, the retirements/exit of
Colstrip, Craig, and Hayden units take away critical baseload at a time when generation
resources are critical as evident in the 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.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
PacifiCorp Response:
The Company appreciates the feedback regarding the need for further clarifications on the demand forecasts and the
drivers of the change to PacifiCorp's load forecast. The Company will enhance its response in the final IRP deliverable.
1) The base load forecast used in the 2025 Integrated Resource Plan(IRP)Draft includes minimal incremental
industrial load growth given the Company's understanding that future projects will be served with specially
designated resources that will not affect the Company's need to procure new resources to serve systemwide load
growth. The final 2025 IRP will include sensitivities that represent a range of possible load forecasts, including
high growth in data center loads.
2) As presented in the January 22-23,2025 public input meeting,the 2025 IRP includes greater volatility in market
prices and, after 2028, does not allow market purchases during peak hours. This means that the resource
selections included in portfolios must be sufficient to serve peak loads on their own without relying on the market.
Additionally,the inclusion of constraints modeling compliance with the Western Resource Adequacy Program
(WRAP) starting in 2028 requires portfolios to include significant resource acquisition in the early years of the
horizon. The Company's capacity position in 2026 is outside the scope of the 2025 IRP,which does not allow
new resources to be selected until 2027. The Company's expected exits from Colstrip, Craig, and Hayden units
are also included in the modeling for the 2025 IRP, and the Company is aware that the baseload generation
provided by these units will need to be replaced.
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PacifiCorp - Stakeholder Feedback Form
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 1/16/2025
*Name: Rose Monahan, Staff Attorney Title:
Matt Gerhart, Senior Attorney
* Rose.monahanksierraclub.org
E-mail: Phone: [phone]
Matt.gerhart(asierraclub.org
*Organization: Sierra Club
Address: 2101 Webster Street, Suite 1300
City: Oakland State: CA Zip: 94612
Public Meeting Date comments address: 1/22-23/2025 ❑ 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.
• Feedback on Draft 2025 IRP
❑ 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.
Requests for additional explanation/information at the Jan. 22-23 Public Input Meeting
• Explain why PacifiCorp did not select the Integrated Base MR portfolio as its preferred portfolio
o The Integrated Base MR portfolio has, as a practical matter, the same costs as the preferred
portfolio, but significantly lower CO2 emissions. Given its much lower CO2 emissions, the
Integrated Base MR portfolio better protects against the risk of future federal CO2 regulations
than PacifiCorp's preferred portfolio. In addition, because the Integrated Base MR portfolio
would have lower emissions of other pollutants (e.g., S02, NOx, etc.) than PacifiCorp's
preferred portfolio, the Integrated Base MR portfolio better protects against the risk of future
federal regulations imposing stricter limits on conventional pollutants such as S02 and
NOx. Thus, when both cost and risk are considered, the Integrated Base MR portfolio appears
to be the least-cost, least-risk portfolio.
o The draft IRP does not offer an adequate explanation of how PacifiCorp selected the MN
portfolio as the preferred portfolio.
• Clarify how the IRP accounted for the risk of future carbon regulations
o At the January public input meetings and in the final 2025 IRP, PacifiCorp must provide further
clarity on each of the price-policy scenarios, including the specific CO2 prices and/or other
constraints assumed under each of the scenarios. For instance, the draft 2025 IRP does not
explain what assumptions or constraints were used in the "MR" price-policy scenario, except to
say that only the MR scenario would be compliant with the EPA's 111(d) regulation and that it
includes "current EPA regulations." The draft does not include a list of"current EPA regulations"
or state what constraints were included in the MR scenario in order to comply with the 111(d)
regulation. Moreover, since the 111(d) regulation is not a carbon tax, it is unclear whether MR
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also included an assumed carbon price or whether zero carbon price was used under this
scenario. Additionally, although PacifiCorp representatives stated in public input meetings (e.g.,
a public input meeting held for the Washington Clean Energy Implementation Plan on October
29, 2024) that "MN" is not "no CO2," it is unclear whether any carbon price was included in the
MN scenario, particularly because "MN" is described as "medium gas/zero CO2." Draft IRP at
175. Figure 8.4 appears to indicate that no CO2 was assumed under MR or MN, but again it is
not clear. This information should be included in narrative form, not buried in spreadsheets, and
an explanation of each portfolio at the January meetings would greatly help stakeholders in their
review of the draft IRP.
o Regarding the final 2025 IRP, for several IRP cycles, PacifiCorp has used an assumed CO2
price not to represent an anticipated carbon tax but to represent the risk of future environmental
regulations impacting fossil fuel generation. PacifiCorp should continue that practice in the 2025
IRP. As a 20-year document, failing to account for the risk of future environmental regulations
places significant risk on customers that the chosen resource strategy will not comply with future
regulations and require rapid and expensive transitions to cleaner technologies that could have
been achieved over a longer time frame. Lack of CO2 pricing further ignores the external costs
of continuing to burn fossil fuels, which Utah's IRP Guidelines explicitly require PacifiCorp to
take into account.
• Provide additional explanations of Tables 9.5 to 9.7
o Tables 9.5, 9.6, and 9.7 purport to provide the Washington, Oregon, and remaining states'
jurisdictional portfolios. The tables differ with respect to new resources by showing the amount
of new resources allocated to each jurisdiction. However, the tables appear to contain the
identical actions for existing resources.
o We are unclear as to how the OR and WA jurisdictional portfolios can lawfully include actions
contained in these tables. For example, both Tables 9.5 and 9.6, for WA and OR respectively,
contain 526 MW of coal CCS in 2030 to reflect CCS on Jim Bridger Units 3-4. However, WA
and OR laws prohibit utilities from charging their customers for the costs of coal after 2025 and
2030, respectively. Therefore, we do not understand why 526 MW of coal CCS appears in the
portfolios for WA and OR in 2030 and the years thereafter, when state law prohibits that
outcome.
o More generally, we are concerned that PacifiCorp's modeling may be accounting for state-
specific requirements when considering new resource procurements, but not fully accounting for
state-specific requirements when considering changes to existing units. Explanation on all of
these points should be provided at the January meetings.
• Provide additional explanation of Tables 7.09-7.11
o Tables 7.09, 7.10, and 7.11 include a final "Adjusted Total Resource Cost with PTC/ITC Credits"
column. Please explain at the January meetings what this column represents, as the column to
the immediate left appears to reflect the total resource cost minus ITC/PTC tax credits but then
is further adjusted downwards in the final column without explanation.
• Explain how the Community Renewable Energy Act, HB 411 was factored into the 2025 IRP
o The draft IRP says little about how the Company accounted for HB 411 in its modeling and
what, exactly, it intends to do to procure clean energy to serve the communities that elect to
participate in the program.
o At the January meetings, PacifiCorp should provide a summary of how HB 411 was
incorporated into the draft IRP and the final 2025 IRP should contain a narrative explaining the
same, including all constraints, inputs, and manual adjustments made to account for HB
411. The final IRP should also explain which communities are assumed to participate; the
aggregate energy and demand of participating communities; how much incremental clean
energy PacifiCorp needs to procure by 2030 to serve the participating communities.
o The action plan is also woefully short on details regarding what steps PacifiCorp will take to
procure the clean energy resources needed to serve participating communities. The action plan
in the final IRP should provide additional details.
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• Explain Natrium Modeling Assumptions
o Sierra Club continues to be concerned that overly optimistic pricing has been used for the
Natrium facility, particularly in light of the lack of any binding contractual agreements between
PacifiCorp and TerraPower. Please provide additional information regarding what price
assumptions were used for the Natrium facility in PLEXOS and how those price assumptions
compare to price assumptions used for proxy nuclear resources.
o Please confirm whether Natrium was endogenously selected by PLEXOS or if PacifiCorp
manually added Natrium to the final portfolios.
Requests for more information and/or modeling to be completed in the final 2025 IRP
• Clarify in the Final 2025 IRP What Coal Pricing Assumptions Were Used
o The draft 2025 IRP (page 192) indicates that, in response to stakeholder feedback, the high gas
and market price-policy scenario includes an elevated coal fuel supply cost. However, the draft
does not include a chart, similar to Figure 8.5, depicting the differences between the "base" coal
forecast and the "elevated" coal forecast. Moreover, Sierra Club assumes that coal pricing is
dependent upon the coal plant, as coal supply from the Powder River Basin, for instance, is
generally much less expensive than other coal supplies. PacifiCorp should explain, in narrative
form, what coal pricing was assumed for each plant. To the extent that this information is
considered confident, the final IRP should clearly indicate where this information can be found in
PacifiCorp's workpapers and could still provide a general narrative explanation of the
differences between the base and elevated forecasts (e.g., "the elevated forecast is
approximately 25% higher than the base forecast for the Jim Bridger plant").
• Model Compliance with HB 2021 and Include an Action Plan for Complying with the 2030
Emission-Reduction Requirement in HB 2021
o The brief discussion of HB 2021 on pages 231-32 of the draft IRP leaves many questions
unanswered. The draft IRP is unclear as to (1) what methodology was used to reflect HB 2021
requirements in the PLEXOS modeling, including whether any manual adjustments were made;
and (2) if the modeling was constrained to meet the emission-reduction requirements of HB
2021, what changes were made to existing resources and which new resources are procured to
comply with HB 2021
o The final 2025 IRP should provide additional detail on how compliance with HB 2021 was
modeled, i.e., the specific constraints, assumptions, etc. that were input into PLEXOS, and
whether any manual adjustments were made. The final 2025 IRP should also describe how, if
at all, compliance with HB 2021 results in changes to existing resources, and new resource
procurements.
o In addition, the final 2025 IRP should provide additional explanation of this statement, which
appears on page 232: "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."
• This statement, along with Figure 9.12, indicates that the preferred portfolio would not
reduce Oregon emissions 80% by 2030, but instead would reduce emissions by only
77.8% by 2030 (excluding specified sales). The draft IRP states that PacifiCorp intends
to sell the output of certain Oregon-allocated resources in 2030 and 2031 to come into
compliance, on the theory that the emissions from such sales would then not be
allocated to Oregon. We are concerned with this approach to HB 2021 compliance,
because it would not actually reduce emissions, but merely shift emissions off of
PacifiCorp's books. At a minimum, PacifiCorp should explain in the final 2025 IRP:
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• the years in which it intends to sell the output of OR-allocated resources in order
to comply with HB 2021, particularly to comply with the 80% by 2030 mandate;
• the incremental amount of emissions PacifiCorp would need to reduce in 2030
through 2034 to reduce Oregon emissions by 80% in each year; and
• Which emitting resources allocated to Oregon PacifiCorp intends to sell the
output of, and what PacifiCorp's plans are for identifying purchasers of that
output.
o We are also deeply concerned that the preferred portfolio would not achieve compliance with
the requirement to reduce Oregon emissions 80% by 2030 or 90% by 2035. Figure 9.12 shows
that the preferred portfolio would not reduce Oregon emissions by 90% by 2035, and instead
would reduce emissions by only 81.1% (excluding specified sales). In fact, the preferred
portfolio would not achieve a 90% reduction in emissions until 2040 (excluding specified sales)—
five years after the statutory deadline to reduce emissions 90% by 2035. It is unacceptable for
PacifiCorp to present portfolios that do not comply with state law. The draft IRP must be revised
such that all portfolios in the final IRP, including the preferred portfolio, reflect timely compliance
with the clean energy targets in HB 2021. Non-compliance with HB 2021 also raises questions
as to what constraints were inputted to the Oregon jurisdictional model that apparently were not
stringent upon to meet Oregon jurisdictional requirements, which reinforces our request above
to clearly explain what modeling constraints were used.
o While HB 2021 allows PacifiCorp to file a Clean Energy Plan in Oregon within 180 days of filing
this IRP, that does not justify developing this IRP without constraining all portfolios to comply
with HB 2021. This IRP contains an action plan for the next two to four years, and describes
actions PacifiCorp will take through 2030. It is deeply concerning that the action plan does not
specify the actions PacifiCorp will take to reduce its Oregon emissions 80% by 2030. If
PacifiCorp waits until the 2027 IRP to develop an action plan for meeting the 2030 emission-
reduction requirement in HB 2021, PacifiCorp may not have enough time to procure any new
resources that might be needed to meet the 2030 compliance requirement.
o Finally, we are concerned that the draft IRP's discussion of emissions omits consideration of HB
2021 or other state policies, as this omission presents an incomplete and inaccurate picture of
PacifiCorp's emissions trajectory. Draft IRP at 227 ("The emissions trajectory does not
incorporate clean energy targets set forth in Oregon House Bill 2021 or any other state-specific
emissions trajectories."). The final IRP should correct this omission and present system-wide
emissions inclusive of the impacts of all state-specific policies.
• Conduct more granular modelinq of coal unit retirements by forcinq the retirement of specific
units in certain portfolios
o The only portfolio that forces the model to cease burning coal at coal units is the "No Coal"
scenario, in which all existing coal units must stop burning coal by 2030.
o Because this scenario requires all existing coal units to cease burning coal, it is impossible to
glean information on the economics of ceasing to burn coal at any particular unit. Therefore,
this scenario does not provide useful information on the economics of individual coal units.
o The final IRP should present modeling of additional portfolios in which individual coal units, and
combinations of coal units, are forced to cease burning coal by 2030. Specifically, the final IRP
should include the results from modeling the following portfolios:
• A portfolio that forces Hunter to cease burning coal by 2030; and
■ A portfolio that forces Jim Bridger to cease burning coal by 2030;
• A portfolio that forces Huntington to cease burning coal by 2030.
o If all three portfolios cannot be run, Sierra Club has listed the requested portfolios in order of
priority.
• Modeling of CCS on Jim Bridger Units 3-4
o We have several concerns with the modeling of CCS at Jim Bridger Units 3-4, including the
modeling conducted for the "No CCS" scenario.
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o To begin, the modeling assumption that CCS can come online by the year 2030 is completely
unrealistic. As far as we are aware, PacifiCorp has not commenced any permitting, design, or
construction work for CCS at Jim Bridger. Thus, the entire CCS project, from permitting and
design work through construction and testing, would need to take 5 years or less to come online
by 2030. We are not aware of any CCS project on a coal unit that has been installed in this
short time frame. Moreover, other utilities have estimated it would take at least double this
amount of time—at least 10 years—to design, permit, and construct CCS on a coal unit.
■ To remedy this shortcoming, PacifiCorp should re-run all portfolios and make CCS
available for selection in PLEXOS no earlier than 2035.
o Given PacifiCorp's wildly unrealistic assumption as to when CCS can come online, we are
concerned that PacifiCorp has used similarly unrealistic assumptions about other aspects of
CCS. We are concerned about the accuracy of the assumptions PacifiCorp used for CCS for
capital and O&M costs; the CCS capture rate (i.e., what percent of CO2 produced by the coal
boilers is captured by the CCS equipment); and the cost to transport and/or store the captured
CO2.
• PacifiCorp has not yet disclosed these CCS assumptions, and thus at this stage it is
impossible for us to meaningfully review the assumptions PacifiCorp used in modeling
CCS.
• Given the likelihood that PacifiCorp used overly optimistic assumptions about CCS, we
are concerned that the modeling in the draft IRP underestimates the cost to install and
operate CCS at Jim Bridger Units 3 & 4.
o In the final 2025 IRP, PacifiCorp must disclose modeling assumptions, particularly price
assumptions, used for CCS and ensure that these pricing assumptions provide a realistic
forecast of CCS costs.
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.
As described above, Sierra Club requests additional information on the following topics. This information
should, at a minimum, be provided in the final 2025 IRP but we also request, to extent possible, that the
Company address these information gaps at the January 22-23, 2025 public input meetings.
At the January 22nd-23rd public input meeting:
• Provide greater explanation for why PacifiCorp selected MN as the preferred portfolio, particularly over
MR, which has similar costs, lower emissions, and performs better under different pricing assumptions;
• Clarify how the IRP accounted for the risk of future environmental regulations, and provide a narrative
summary for each of the base portfolios evaluated (e.g., MN, MR, etc.), including what specific
constraints were included in each of these portfolios and what, if any, carbon price was assumed;
• Provide additional explanation for what is depicted in Tables 9.5, 9.6, and 9.7, which purport to provide
the Washington, Oregon, and remaining states'jurisdictional portfolios, but appear to show identical
actions for existing resources and appear to allocate Washington and Oregon coal shares beyond 2025
and 2030.
• Provide additional explanation of Tables 7.09-7.11, particularly what is represented by the final
"Adjusted Total Resource Cost with PTC/ITC Credits" column and what final price point was used in
PLEXOS for the supply side resources
• Explain how, if at all, the Community Renewable Energy Act, HB 411 was incorporated into the 2025
IRP modeling
• Explain whether the Natrium nuclear facility was "forced into" the final portfolio or endogenously
selected and explain what price assumptions were used for the Natrium facility and how those price
assumptions compared to price assumptions for proxy nuclear facilities.
In the final 2025 IRP:
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1. Disclose what coal pricing was assumed for each coal plant, particularly under the high gas/high coal
scenario;
2. Model compliance with HB 2021 emission reduction requirements and include in the action plan
specific actions that will be taken in the next 2-5 years to make progress towards HB 2021's emission
reduction requirements
3. Conduct more granular modeling of coal unit retirements by forcing the retirement of specific plants in
separate portfolios, specifically by separately modeling the retirement of Jim Bridger (units 3-4) by
2030; the retirement of Hunter by 2030; and the retirement of Huntington by 2030.
4. Provide cost assumptions (fixed O&M, variable O&M, CapEx, etc.) used for CCS and ensure that such
assumptions provide a realistic picture of likely CCS costs. Adjust the modeling so that CCS is only
available beginning in year 2035 or later.
Please submit your completed Stakeholder Feedback Form via email to IRPkPacificorp.com
Thank you for participating.
PacifiCorp Response:
For the Public Input Meetingequests:
PacifiCorp responded to questions and comments regarding these topics at the January 22-23, 2025 public input meeting
and is committed to providing time for open discussion as appropriate at future meetings. PacifiCorp continues to
welcome dialogue to provide clarity and have further conversations related to these modeling and outcomes questions.
Regarding the final document:
1. Plant coal pricing is expected to be provided for dissemination via workpapers(either confidential or highly
confidential depending upon contract/negotiation status).
2. PacifiCorp is including a CEP Update appendix in the 2025 IRP. Compliance with HB 2021 emissions
requirements will be modeled. The IRP action plan will include actions that help Oregon reach compliance.
Additional detail related specifically to Oregon is likely to be contained in the CEP.
3. These study requests are noted. PacifiCorp will look to complete any of these for which there is sufficient
modeling time,prioritizing the various coal units as requested above in comments.
4. This information will be provided in workpapers. Given the role of CCS in meeting federal EPA I I I(d)
compliance, a 2032 date is the latest date that has been provided for CCS implementation. Jim Bridger units 3 and
4 are modeled in 2030 given the selection of these units in the 2023 IRP update and potential for them to come
online earlier as such.
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PacifiCorp - Stakeholder Feedback Form
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 1/15/25
*Name: WY Commission Title:
*E-mail: [e-mail] Phone:
*Organization: WY Commission
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.
Draft 2025 IRP questions
® 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.
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.
1.1 Regarding the peak wind generation amounts reflected in Tables 6.14 and 6.15,page 130 of the Draft 2025 IRP as
pictured below:
Please see attached original request for information.
1.1.1 Please explain why the two seasons appear to have such a drastic difference.
1.1.2 Based on the Company's overall wind capacity and expected capacity factor,the summer peak wind generation
shown in Table 6.14 appears to be considerably less than one would intuitively expect to see. Please explain.
1.2 Does the Company include transmission-only customers in the load forecast?
1.2.1 Does the Company consider transmission-only customers to be special contracts?
1.2.2 Does the Company include special contracts in its load forecast?
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1.3 On page 2 of the Draft 2025 IRP,under the"Changes to our Portfolio"subsection,the Company uses phrases
like: "continue to evaluate", "continue the process", and"continue to work".Are the bulleted items listed with these
phrases still in the Company's preferred portfolio?Please clarify.
1.3.1 Why does the Draft 2025 IRP list the Dave Johnston Unit 3 retirement in 2027 in the"Changes to our Portfolio"
section?The 2023 IRP and 2023 IRP Update also shows this unit retiring in 2027 so it does not appear to be a change.
Please explain.
1.4 Please provide the PLEXOS ".xml"file along with a copy of the solution file. Please also provide all data input
files,custom constraints, scenarios, etc. necessary to perform PacifiCorp PLEXOS model run(s)and receive the same
solution.
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
PacifiCorp Response:
1.1 Regarding the peak wind generation amounts reflected in Tables 6.14 and 6.15,page 130 of the Draft 2025 IRP as
pictured below: Please see attached original request for information.
Reply: To clarify,the rows labeled"Wind"in Tables 6.14 and 6.15 display the peak capacity contribution of wind
for summer and winter,not peak wind generation.
1.1.1 Please explain why the two seasons appear to have such a drastic difference.
Reply: The company has discovered an error in the PLEXOS calculation for the summer peak system capacity,
resulting in a significant discrepancy between summer and winter peak capacities. The corrected Summer Peak
Resource Capacity will be included in the 2025 IRP February 26-27 public input meeting.
1.1.2 Based on the Company's overall wind capacity and expected capacity factor,the summer peak wind generation
shown in Table 6.14 appears to be considerably less than one would intuitively expect to see. Please explain.
Reply: See Response to 1.1.1.
1.2 Does the Company include transmission-only customers in the load forecast?
Reply: The IRP load forecast does not include transmission-only customers. The Company's customers enrolled
in Oregon's direct access program are transmission-only customers and excluded from the Company's generation
planning load for the IRP.
1.2.1 Does the Company consider transmission-only customers to be special contracts?
Reply:None of the Company's customers who have individual commission-approved special contracts are
transmission-only customers.
1.2.2 Does the Company include special contracts in its load forecast?
Reply: Yes, load for customers with individual commission-approved special contracts are included in the load
forecast.
1.3 On page 2 of the Draft 2025 IRP,under the"Changes to our Portfolio"subsection,the Company uses phrases like:
"continue to evaluate", "continue the process", and"continue to work". Are the bulleted items listed with these phrases
still in the Company's preferred portfolio?Please clarify.
Reply: The Company is considering changing the section header from "Changes to Our Portfolio" to "Key
Thermal Outcomes."All items listed as bullet points are part of the company's preferred portfolio.We
continuously evaluate and move forward in response to events and updated analysis.
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1.3.1 Why does the Draft 2025 IRP list the Dave Johnston Unit 3 retirement in 2027 in the"Changes to our Portfolio'
section?The 2023 IRP and 2023 IRP Update also shows this unit retiring in 2027 so it does not appear to be a change.
Please explain.
Reply: See response to 1.3, above.
1.4 Please provide the PLEXOS".xml"file along with a copy of the solution file. Please also provide all data input files,
custom constraints, scenarios, etc.necessary to perform PacifiCorp PLEXOS model run(s) and receive the same solution.
Reply: The circumstance for providing the".xml"file is the subject of agreements currently being worked out
between Wyoming staff and commission,PacifiCorp and Energy Exemplar.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
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PacifiCorp - Stakeholder Feedback Form
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 5-01-2 4
*Name: David Williams Title:
*E-mail: [e-mail] Phone:
*Organization: Utah Division of Public Utilities
Address:
City: State: Zip:
Public Meeting Date comments address: 01-2 3-2 0 2 5 ®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.
Draft IRP; Iron-Air Batteries
® 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 the 2023 IRP, the Company evaluated a "No Forward Tech" portfolio (P06, see Figure
9.11 "Increase/ (Decrease) in Proxy Resources when all Forward Technology is Eliminated
from the P-MM Portfolio") . The description of P06 stated: "The P06-No Forward Tech
portfolio is a variant of the P-MM portfolio that eliminates all future resource options
which are not currently available within the existing PacifiCorp portfolio." This
scenario disallowed nuclear and non-emitting peakers. The technology of non-emitting
peakers was not established at the time of the 2023 IRP, and so this technology was not
currently available, and counted as "forward tech". P06 was run with non-gas options
available (i.e. natural gas was not allowed to be selected) (Table 8.12) . At the Jan.
22-23 public input meetings for the 2025 IRP, the Division and other parties asked about
the 100-hour iron-air batteries selected in the 2025 IRP. The Company performed an
analysis on a "No Nuclear" scenario (e.g. Table 8.5; Figure 9.17 of 2025 Draft IRP) . The
Company said that iron-air batteries were allowed to be selected in the no nuclear
scenario. The Division asked if there should be a "no new technologies" case that did not
allow either nuclear or iron-air batteries. The Company responded (this is a paraphrase,
not a direct quote) : "The iron-air battery technology is viable at the commercial level,
even though it's not being used yet at the utility scale. Therefore, the iron air
technology is different than the non-emitting peakers in the 2023 IRP." The Division
appreciates that the iron-air batteries could be different (developmentally speaking)
than the non-emitting peakers in the 2023 IRP. However, the iron-air batteries are not
currently available at the utility level. There could be unforeseen challenges that
prevent a utility-scale project. See, e.g. , "Will Iron-Air Batteries Revolutionize
Renewable Energy Storage?", August 19, 2024, at
https://www.environmentenergyleader.com/stories/will-iron-air-batteries-revolutionize-
renewable-energy-storage, 48339 "Despite their benefits, iron-air batteries face several
challenges: Slower Response Time: Iron-air batteries may struggle in applications
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requiring rapid energy discharge and recharge cycles due to their slower response time.
Developmental Stage: Iron-air technology is still in its early stages, and unforeseen
technical and scalability challenges could emerge as the technology matures." Thus it is
not yet settled how effective this technology will be at the utility scale. The Division
requests that a "no new forward technology" scenario be evaluated in the 2025 IRP, with
both nuclear and iron-air batteries disallowed. Natural gas should be allowed in this
scenario.
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(2/17/25)
Thank you for your feedback. PacifiCorp will consider this request to conduct a study that does not allow the selection of
100-hour iron air batteries.
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PacifiCorp - Stakeholder Feedback Form
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 2025-01-25
*Name: Sean Maher Title:
*E-mail: [e-mail] Phone:
*Organization: Utah Environmental Caucus
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.
Geothermal
® 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 am surprised and concerned to see how little geothermal energy is included in
PacifiCorp\u0019s future energy mix according to the Draft 2025 IRP. The International
Energy Agency estimates that geothermal could meet up to 15% of global electricity demand
growth to 2050, and the Western Governor\u0019s Association projects 12,558 MW of new
energy in the western US from conventional geothermal alone. This figure excludes
enhanced geothermal technologies, which are already planned to produce an additional 2 GW
in Utah by 2028 (see CleanTechnica article) . Despite this, geothermal is barely visible
in the installed MW projections in Figure 1.2, page 5 of the Draft 2025 IRP Volume 1, and
it does not appear to increase over time. Geothermal is also absent from Figures 9.13 and
9.14 (Preferred Portfolio's Projected Energy Mix and Capacity Mix, Vol.l p.233) . Why
isn\u0019t geothermal being included in these projections, despite being listed among
supply-side resource options identified "through external studies, internally generated
studies, permitting, regulatory requirements, and stakeholder input" (Vol./ pp. 139 and
142) ? Recall that PacifiCorp's slide presentation at the July 17-18, 2024 public input
meeting included geothermal among Supply Side Resources in the IRP [slide 67] , noting
that it could "operate as traditional baseload." The presentation mistakenly claimed
that the "soonest commercial operation date possible" is 2030. The U.S. Energy
Information Administration reports that seven states are already producing 17 billion kWh
of electricity from geothermal, including four states in PacifiCorp\u0019s service area.
Even if 2030 were the soonest that PacifiCorp could generate new geothermal power, why is
geothermal not included in a 2025 IRP that runs through 2045? Though the draft 2025 IRP
describes geothermal as a non-0O2-emitting resource with continuous operation (Vol.1
p.188) , nowhere in Volumes 1 or 2 is there any indication that geothermal was actually
considered for inclusion as a sensitivity or variant factor in any of the potential
integrated portfolios. In its July 15, 2024 response to Ms. Hilding's stakeholder
inquiry of June 10, 2024 [Vol.2 pp. 222/340, 223/340] , PacifiCorp said it was
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"considering the broad range of geothermal cost scenarios." How was geothermal
subsequently modeled for 2025 IRP inclusion? While geothermal is included as a
renewable energy source with the 2024 Utah Renewable Communities Request for Proposals
[Vol. 1. p.74] , how will geothermal be competitive if not included in the 2025 IRP? Is
it correct to assume that PacifiCorp also has no plans to interconnect new Utah
geothermal resources to the transmission system? How will the multiple new geothermal
plants and planned expansions of existing plants (see energy.utah.gov link) be integrated
with PacifiCorp\u0019s energy mix?
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.
July 2024 PacifiCorp PIM Slide Deck:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-
resource-plan/2025-irp/PacifiCorp 2025 IRP PIM July 17-18 2024.pdf PacifiCorp's "Supply
Side Resources in the IRP" presentation, starting with slide 58, addresses Geothermal on
slide 67. EIA on seven states producing geothermal electricity:
https://www.eia.gov/energyexplained/geothermal/use-of-geothermal-energy.php Western
Governor\u0019s Association projection of conventional geothermal:
https://www.eesi.org/files/geothermal 030206 gawell.pdf International Energy Agency on
geothermal growth potential: https://www.iea.org/reports/the-future-of-geothermal-
energy/executive-summary Enhanced geothermal plant planned for Utah:
https://cleantechnica.com/2024/10/21/fervo-energys-update-shows-enhanced-geothermal-is-
hot-literally/ Existing and future geothermal in Utah: https://energy.utah.gov/wp-
content/uploads/Geothermal-In-Utah.pdf
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
The Final 2025 IRP should specifically address all the concerns and questions raised in
this comment about the status of Geothermal in the Draft 2025 IRP. The Final 2025 IRP
should include additional portfolio variants and sensitivity cases, with work papers,
that include Geothermal as a baseload and peak thermal resource.
PacifiCorp Response:
Geothermal resources are available to be selected by the PLEXOS model in all jurisdictional runs in the LT Capacity
expansion planning phase of the model. Geothermal cost characteristics in PLEXOS match the supply side resource table
and leverage the National Renewable Energy Laboratory(NREL)escalation curves that reflect anticipated build cost
changes over time. In response to the concern related to the earliest availability date, geothermal is available beginning in
2027 in PLEXOS.
The PLEXOS model was able to select Geothermal resources in either Central Oregon or Utah South,given that these are
the two locations within the overall PacifiCorp system where Geothermal production is expected to be technically
feasible. Resources in these locations(including geothermal)require interconnection upgrades resulting in higher overall
costs than are shown in the supply side resource table. The geothermal resources for the 2025 IRP are assumed to be 707
MW in size, and the base build cost modeled in PLEXOS matches the Wasatch Front and Portland North Coast costs on
the supply side table.Note that PLEXOS is able to select any number of these resources, including a fractional amount of
a unit. Additionally,geothermal resources are assumed to receive production tax credits of 100 or 110 percent depending
on the location. The inclusion or exclusion of geothermal resources from any portfolio is related solely to the modeled
economics of the resource in competition with all other available resources.
Should there be sufficient time to complete and integrate runs,the IRP team will consider a variant that forces the model
to select a minimum of 1 unit of geothermal in each location where the resource is available (much like the offshore wind
variant).
While the IRP provides an indication of possible future resource additions,the generic or"proxy"cost and availability
estimates represented in the IRP do not and cannot comprehensively represent the available opportunities.As a result the
IRP does not represent a commitment to specific future resources,but instead is a road map that identifies how future
resources can be assessed and procured. With regard to the competitiveness of geothermal resources, PacifiCorp considers
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the costs,benefits, and operational characteristics of each resource offered in request for proposal processes and procures
the most cost-effective resources,notwithstanding what was included in the most recent IRP preferred portfolio. Several
requests for interconnection of geothermal resources have been submitted to PacifiCorp Transmission and are currently in
the study process. Once more certainty on the timing any necessary transmission upgrades is known,these resources could
be offered to PacifiCorp for consideration in a request for proposal process.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 1/31/25
*Name: Kevin Emerson Title: Director of Building Efficiency and
Decarbonization
*E-mail: Kevin(a)utahcleanenerML= Phone: [phone]
*Organization: Utah Clean Energy
Address: 215 S.400 E.
City: Salt Lake City State: Utah Zip: 84111
Public Meeting Date comments address: ® Check here if not related to specific meeting
List additional organization attendees at cited meeting: Justin Brant,jbrant(&swenerg_y org and Ramon Alatorre,
[e-mail]
*IRP Topic(s) and/or Agenda Items: List the specific topics that are being addressed in your comments.
• 2025 Conservation Potential Assessment and 2025 IRP draft
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.
Thank you for responding to our last stakeholder comments submitted on November 7,2024,about the assumptions for
the residential energy code baseline in Utah and requesting a year-by-year and state breakout of the DSM selections in the
2023 IRP Update.
With regard to the residential energy code baseline incorporated in the 2025 CPA,we recommend that in the final
Conservation Potential Assessment,Table 3-6 (page 42 in the draft CPA) should explicitly reflect that Utah's residential
IECC is recognized as equivalent to the 2009 IECC as per U.S. Dept. of Energy(see this link:
hops://www.energycodes.gov/state-portal). This additional level of specificity will aid in the development of relevant and
impactful energy efficiency programs for the new homes sector in Utah.
With regard to the DSM selections in the draft 2025 IRP,we have several comments. First,we are encouraged to see
positive growth in the DSM selections within the Action Plan period of the draft 2025 IRP. For example,the DSM
selection identifies 492,816 MWh of cost-effective energy efficiency for Utah in 2028 (see chart below). We continue to
urge the utility to model and implement all cost-effective energy efficiency investments. For the company to be able to
successfully implement electricity-saving programs to reach the 2028 target, it is imperative for the company's DSM team
to begin scaling up current DSM programs immediately. Scaling up immediately will provide energy efficiency program
implementors and contractors the time they need to staff up and meet these targets in a timely fashion.
Similarly,we are concerned about the potential impact the significant fluctuations in the DSM resources selected in later
years of the draft 2025 IRP could have on the Action Plan period and beyond. The growth,dips, and subsequent increases
in the DSM selections for Utah send a mixed signal that creates uncertainty for DSM implementation contractors,
complicating the achievement of the DSM targets selected.We strongly recommend that the company's DSM team work
closely with utility energy efficiency contractors to implement the cost-effective DSM selections in a way that gradually
and consistently increases/maintain savings targets over the planning horizon.
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We have additional requests regarding the DSM selections in the draft 2025 IRP:
1. Please explain how other resource selections in the model are impacting the DSM selection each year in Utah.Are
fluctuations in the cost-effectiveness of other resources driving the increases and decreases in the amount of DSM
resources selected in Utah?And if so,how?
2. Please provide data showing the amount and cost of the energy efficiency bundles selected in the draft 2025 IRP for
each year,by state,in dollars per kWh and dollars per kW. This will help us better understand and evaluate the way that
energy resources, including DSM resources, are evaluated/selected based on cost.
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.
Class 2 DSM Selections for Utah in the draft 2025 IRP
600,000
500,000
m
400,000
'0C 300,000
ro
.t 200,000
w 100,000
0
M Lm l0 n oo M O fV M �T In l0 h oo M O —4 N M
N N N N N N M M M M M M M M M M V V V a V
O O O 0 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
—0-2025 IRP Draft(Utah)
Source:PacifiCorp Draft 2025 IRP extrapolated from Table DA—Cumulative Energy Efficiency Resource Selections(2025 IRP Preferred Portfolio
Recommendations:Provide any additional recommendations if not included above-specificity is greatly appreciated.
See recommendations embedded in the Respondent Comment section above.
Please submit your completed Stakeholder Feedback Form via email to IRP(c-r�,Pacificorp.com
Thank you for participating.
PacifiCorp Response(2/21/2025):
1. All resources available for selection in the PLEXOS long term/capacity expansion model are
selected in a competitive manner which is agnostic to technology type.
Additionally,demand response resources are cumulatively selectable(i.e. the model could
delay the selection of multiple years of demand response and later select the total available
amount over that period in a single year). This means that in some years,the model may
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identify cost effective resources which would preclude the need to select demand response,
and then a few years later select all the demand response that it had chosen not to select
earlier.
Conversely, energy efficiency selections are take-or-leave; something not selected in a
particular year cannot be cumulatively added to a future year.
The optimization of DSM is therefore always in competition with other resource options,
which are optimized for size and timing.
2. The granular detail requested has not been calculated for the Draft 2025 IRP,but will be
provided in the final 2025 IRP to be filed March 31, 2025.
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PacifiCorp - Stakeholder Feedback Form
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 5-0 2-0 6
*Name: Jon Martindill Title:
*E-mail: [e-mail] Phone: (707) 548 - 0367
*Organization: Renewable Northwest
Address:
City: State: CA 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.
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.
RNW seeks additional information from and provides recommendations to PacifiCorp
regarding its resource options inputs and assumptions in the 2025 Draft IRP. Our feedback
consists of four sections: Coal, CCS, Capital Costs, and Biodiesel Coal: Were
PacifiCorp's majority-owned coal units available for early retirement? Please explain why
all minority-owned coal units retire before 2030, while all but one majority-owned coal
unit remains in service through the planning horizon or gas converts. CCS: Page 140
states that \u001Calthough the common abbreviation for carbon capture and storage (CCS)
is used, data for these resources does not include sequestration.\u001D Page 143 states
that \u001CData for \u0018Carbon Capture Retrofits at existing coal plants\u0019 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.\u001D In Stakeholder
Feedback Form #25 (Vol. 2 pp. 256-257) , Pacificorp says their selection of CSS
\u001Crelied 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\u001D which \u001Cwill evaluate an option for transport and storage of
the CO2.\u00lD Public estimates for the cost of storing or transporting CO2 suggest a
range of under $5 to over $20 per metric ton. Capital Cost: Page 140 states that
\u001CThe National Renewable Energy Laboratory (NREL) Annual Technology Baseline (ATB)
was used as much as possible to maintain consistency.\u001D However, the values in the
supply-side resource data summary (see Data Support) do not match the values in the 2024
ATB, and the IRP does not describe how the values from NREL were adjusted. For example,
CCS retrofits and large-scale solar capital costs are more than 20% cheaper than NREL,
while capital costs for wind are consistently significantly higher than NREL estimates
\u0013 more than 60% higher in the case of offshore wind. Biodiesel: The 2025 Draft IRP
introduces biodiesel as the assumed non-emitting fuel source for new peaking plants and
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as an alternative fuel source to transition gas and dual-fuel resources. However, there
is no discussion about the cost and availability of biodiesel as a fuel. According to the
EIA (See Data Support) , there are no biodiesel production plants in Idaho, Wyoming, or
Utah, where many of the plants that PAC assumes can transition to biodiesel are located.
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.
1. Example for CCS storage & transportation costs: https://www.globalccsinstitute.com/wp-
content/uploads/2022/03/CCE-CCS-Technology-Readiness-and-Costs-22-1.pdf; 2. SSR Database
available at:
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; 3. EIA Biodiesel Plant Production
Capacity: https://www.eia.gov/biofuels/biodiesel/capacity/
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
CCS 1: We recommend that PacifiCorp use a placeholder value for the cost of transporting
or storing carbon captured in CCS retrofits. A cost of $10 per metric tonne of CO2 would
result in an additional $13/MWh in variable operating costs for CCS at Jim Bridger, which
could have a significant impact on its selection in the IRP. CCS 2: We recommend that
PacifiCorp specify their assumptions about carbon storage or utilization as it relates to
tax credit qualification - for example, geologic sequestration qualifies for a much
higher tax credit than using carbon for enhanced oil recovery. CCS 3: We also recommend
that the FEED study mentioned in PacifiCorp\u0019s response to Stakeholder Feedback Form
#25 be included in their action plan, to be completed prior to any commitments to the
construction of CSS at Jim Bridger. Capital Cost: We request that PacifiCorp describe in
detail how NREL ATB values were adapted and adjusted to arrive at the values visible in
the public SSR database. In particular, we recommend that PacifiCorp include inputs
beyond NREL ATB used for small-scale wind, large-scale wind, offshore wind, large-scale
solar, coal & gas CCS retrofits, and nuclear. Biodiesel 1: We request that PacifiCorp
specify the cost and availability assumptions that PacifiCorp uses for biodiesel in the
2025 IRP. Biodiesel 2: We recommend that PacifiCorp assess what biodiesel transportation
infrastructure would be required make the transition it models in the IRP, and perform a
sensitivity analysis on the resulting fuel price impact.
PacifiCorp Response(3/17/25)
CCS 1—PacifiCorp does model transportation and sequestration as a cost related to the CCS units. This is modeled as a
fixed cost as the infrastructure would need to be built and maintained regardless of the volume of CO2 captured.
CCS 2—PacifiCorp has stated in the past, and will clarify in the IRP document,that the tax credit assumes the highest
level of tax credit for CCS use,which as stated in this form is the geologic sequestration credit.
CCS 3—Thank you for this feedback.
Capital Costs—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, conversations with industry experts,
developers and original equipment manufacturers(OEM's). CCS cost estimates are not based on the ATB,but on
estimates specific to PacifiCorp plants.Wind and solar costs may vary from high-level ATB cost estimates based on year
of construction, interconnection costs, locational modifiers,proprietary overhead and owners' costs, and node-specific
meteorological assumptions. Additional information will be provided in Chapter 7 of the final 2025 IRP to be filed March
31,2025.
Biodiesel 1— PacifiCorp's biodiesel costs are derived from the U.S. Department of Energy's April 2024 edition of the
Clean Cities and Communities Alternative Fuel Price Report,available online at:
hiips:Hafdc.energy izov/files/i/publication/altemative_fuel price report april_2024.pdf?2d6513fb43
Specifically,PacifiCorp is using the average of the West Cost pricing for biodiesel in Table 11 ($5.86/gal),and the
California pricing for renewable diesel stated on page 20 (also shown in Figure 16), ($5.36/gal). This equates to
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approximately$43/MMBTU and is assumed to escalate at inflation. At this price, demand is projected to be limited.
PacifiCorp estimates that approximately three tanker trucks would be necessary to completely fill the tank storage for the
20 MW peaking resource.At this scale,PacifiCorp expects the same transportation infrastructure used for retail fueling
stations would be used, and notes that retail rather than wholesale pricing has been applied, so it includes delivery costs.
Biodiesel 2—The cost to transport Biodiesel to a site is included in the cost of the fuel.Additionally,unit specific retrofit
and build costs include projected storage costs for this fuel type.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 5-0 2-0 6
*Name: Katie Chamberlain Title:
*E-mail: [e-mail] Phone:
*Organization: Renewable Northwest
Address:
City: State: Zip:
Public Meeting Date comments address: 01-2 2-2 0 2 5 ®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.
Procurement, transmission, price-policy scenarios, market reliance, emissions reductions
® 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 on the draft 2025 IRP regarding procurement,
transmission, price-policy scenarios, market reliance, and emissions reductions.
Procurement: At various points in the draft IRP, PacifiCorp provides information on
resources that are coming online in the near term. Can PacifiCorp provide a comprehensive
list of resources it has contracted for that were submitted as bids into either the 2020
all-source RFP or the 2022 all-source RFP? Please include the name of the project,
resource type, MW size, contracted year, expected COD, and the RFP or other source from
which they came. Transmission: PacifiCorp states that B2H is no longer included in the
preferred portfolio: \u001C[N]ote, 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\u001D (p.5) . Can PacifiCorp provide more details around its reevaluation of
B2H? Why was it not selected in the preferred portfolio as it has been in the last
several IRP cycles? Given that PacifCorp jointly owns the line with Idaho Power, what
does this mean for the project and for Idaho Power moving forward? Is PacifiCorp still
contributing financially to the development of B2H? Doe\u0019s PacifiCorp\u0019s
position have implications on future requests for cost recovery and sharing costs with
Idaho Power? Price-policy scenarios: On page 175 of the draft IRP, PacifiCorp explains
that the IRP contains five distinct price-policy scenarios: medium gas / existing federal
regulations (MR) , medium gas / zero CO2 (MN) , high gas / high CO2 (HH) , low gas / zero
CO2 (LN) , and medium gas / SCGHG (SC) . In tables 9.30-9.33, PacifiCorp presents the cost
and risk results of the initial and variant cases under four of the five price-policy
scenarios, excluding the MR case. Why did the company not include a similar table with
initial and variant cases under the MR case? In table 9.33, why did the company not
include the integrated base MR case for comparison against the other cases? In tables
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9.30-9.32, the integrated base MR case performs well across these price policy scenarios
- consistently ranking 1st or 2nd in both the PVRR assessment and CO2 emissions
assessment. Please confirm our understanding of what this means: the MR case performs
best in terms of being low cost and low risk across the majority of future price policy
scenarios. Meanwhile, the preferred portfolio (MN case) does not perform as well across
different price-policy scenarios and ranks next to last on emissions risk in the expected
case. PacifiCorp states that \u001Cthe 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\u001D
(p.249) . Please confirm that by selecting the MN case as the preferred portfolio,
PacifiCorp is not planning to comply with existing federal regulations. Market
reliance: In the January 22-23 public input meeting on the draft IRP, PacifiCorp
explained that the model treats market purchases for capacity and energy differently.
Market purchases are excluded during high-risk hours for the top five risk days per month
for both the summer and winter seasons. However, the model allows the company to make
market purchases for energy needs up to their economic limit. Has PacifiCorp attempted to
quantify energy availability for the 2025 IRP? Can the company run a scenario/sensitivity
for the final 2025 IRP where markets are tighter than expected from an energy
perspective? Emissions reductions: Figure 9.12 shows Oregon allocated emissions
reductions relative to HB 2021 targets. Please explain the difference between the
\u00182025 IRP w/o spec. sales\u0019 line and the \u00182025 IRP w/ spec. sales\u0019
line.
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 (3/17/25):
Procurement—Thank you for this suggestion. To the extent practicable based on any confidentiality agreements,
PacifiCorp will seek to incorporate this information into the IRP narrative.
Transmission—B2H as a transmission project is not eligible for endogenous selection in the 2025 IRP. PacifiCorp's use
case for this transmission investment has evolved.At present,the transmission line is needed to facilitate load service for
certain large new loads. As has been previously communicated,PacifiCorp is evaluating transmission and resource needs
for these large new loads outside of the traditional planning process, and with removal of these loads from the load
forecast in the IRP,the associated transmission is also being removed. In previous IRP cycles,B2H would facilitate
existing load growth via a redirect of existing transmission rights on Bonneville Power Administration's(BPA)system.
PacifiCorp has not been successful in getting this redirect of transmission rights granted by BPA. Special contracts with
large new load customers will drive cost recovery. This has not changed PacifiCorp's partnership with Idaho Power.
Price-Policies—Thank you for your feedback. The initial view of the MR case was that it ultimately applied only to the
UIWC jurisdiction,given that the impact is primarily on units in which Oregon and Washington can no longer participate
after 2030. With testing,the IRP team realized that Oregon and Washington jurisdictional initial selections would in fact
be impacted by restrictions. The MR portfolio that will be presented in the final IRP will be different than the draft
version, and the analysis above has not yet been completed on updated portfolios. Regarding table 9.33,the ST run of the
MR portfolio under an SCGHG future pricing condition was not completed when the draft portfolio was published. A
similar table was not contemplated for the MR price policy scenario because if a portfolio was NOT MR compliant, it
could not be compared, and there was only 1 additional MR compliant portfolio.PacifiCorp plans to require one to two
additional variants to be compliant under MR for the final filing. Given the timing of compliance, if current federal rules
were to be upheld,PacifiCorp would further evaluate the various conversion and closure options as indicated by the final
MR case.
Market Reliance—A low or no purchase sensitivity has not yet been contemplated. If time allows,PacifiCorp is willing
to evaluate the preferred portfolio in an environment where purchases are limited further.
Emissions—The graph referenced is going to be updated for the final filing. The view presented demonstrates that
Oregon allocated resources provide sufficient energy to meet its load on an annual basis,but that some emitting resources
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allocated to Oregon were dispatched because it was economic to do so. The"with specified sales"line on this graph
demonstrates that Oregon could dispatch gas resources when it is economic to do so, sell these resources to another
jurisdiction, and still have enough allocated energy to meet Oregon load. PacifiCorp believes that this may be counter to
current DEQ methodology for emissions reporting and as a result will be dispatching the final preferred portfolio to be
compliant with Oregon emissions limits,which will limit natural gas-fired generation and economic benefits.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 2/7/2025
*Name: Benedikt Springer Title:
*E-mail: [e-mail] Phone:
*Organization: Oregon Public Utility Commission
Address:
City: State: Zip:
Public Meeting Date comments address: 1/22-23/2025 ❑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.
Feedback on Draft 2025 IRP
x 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.
• Staff appreciates that the IRP shows compliance with HB 2021,but it's unclear what planning changes resulted in
the associated emission reductions. Please explain what actions or drivers are resulting in the change in GHG emissions
between the 2023 IRP update and the 2025 IPR draft. Please ensure this is fully explained in the final IRP.
• Please explain whether Oregon HB 2021 emission targets are a binding constraint for the modeling of system
resource additions and dispatch.What happens to existing resources in jurisdictional portfolios?
• What does"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"mean exactly?
• To which degree does Oregon carbon emission compliance rely on situs vs. system resources,what assumptions
were made about resource sharing(including in terms of dispatch)?
• What are the costs and development assumptions associated with the off-take agreement for the Natrium
Demonstration Project, and how are they reflected in the modeling?
• What is the full suite of characteristics assumed for the four non-0O2-emitting thermal resources (nuclear, small
renewable fuel peaking, geothermal, and non-emitting hydrogen peaking) and in what ways are these emerging
technology resources considered differently than resources for which attributes are well, or at least better known?
• What is meant by action item lh?This is not mentioned anywhere else in the document. Please explain what
"changes in accounting and/or dispatch of existing natural gas resources"specifically entails,the extent to which HB 2021
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emission reductions are dependent upon these changes, and the specific Natural Gas Emissions Compliance obligations
the Company is considering.
• How does the Company model compliance with the EPA GHG emission rules?Why did the Company select the
MN portfolio as the preferred portfolio,especially when potentially cheaper options with lower emissions are available
(MR)?
• Given the rapidly changing federal policy environment, does the Company anticipate making any changes to the
IRP and its associated modeling to reflect environmental policy under a Trump administration?
• Tables 9.2, 9.3, and 9.4 omit existing resource options. How are jurisdictional shares of existing resources
modeled and to those similarly comply with jurisdictional rules?
• Explain in more detail the steps used and the underlying logic of creating jurisdictional portfolios and integrating
them into a system-wide portfolio. Explain what the Company's method implies about state-specific ownership of
resources, and how the capacity/energy of those resources can be dispatched by the model. Furthermore, explain common
alternative methodologies for allocating resources to jurisdictions and describe why PAC's choice is the preferred method
and what tradeoffs it presents.
• Explain how sensitive IRP modeling results,including resource selections, are to changes in the MSP.
• Add a more detailed section on compliance with Oregon emissions rules. Explain how emission compliance is
achieved and under which conditions emissions might deviate.
PacifiCorp response:
• New Resource actions should be further explicated. Explain how much new resources the Company is planning to
acquire on what schedule.
• Assumptions vs. outcomes need to be better differentiated. For instance,the draft document makes it sound like
the Natrium reactor was chosen by the model as the least-cost/least-risk option. However, during the public input meeting
Staff learned that the acquisition of the Natrium reactor was added to the model as an a priori assumption.
PacifiCorp Response: Natrium was endogenously selected by the model as part of the least-cost, least-risk portfolio. At
the January public input meeting,PacifiCorp explained that no costs associated with Natrium were included in the
modeling process given that the Company has not yet reached an agreement with Terra Power.
• Explain the Company's natural gas dispatch strategy in Oregon.
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 Responses (3/17/2025):
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• Staff appreciates that the IRP shows compliance with HB 2021,but it's unclear what planning changes resulted in
the associated emission reductions. Please explain what actions or drivers are resulting in the change in GHG
emissions between the 2023 IRP update and the 2025 IPR draft. Please ensure this is fully explained in the final
IRP.
PacifiCorp Response: In the 2025 IRP Draft,three modeling changes contributed to the emissions
reductions:
1. A model driver dispatch price was applied to each ton of Oregon-allocated emissions produced
between 2030 and 2040 to incentivize the model to reduce emitting generation and to build additional
clean resources.
2.No gas plants or market purchases were allocated to Oregon after the end of 2039.
3. Some emitting Oregon-allocated generation produced in excess of Oregon load was treated as a
specified sale and was not counted towards the HB2021 emissions reduction targets. Further details were
presented at the February public input meeting.
• Please explain whether Oregon HB 2021 emission targets are a binding constraint for the modeling of system
resource additions and dispatch. What happens to existing resources in jurisdictional portfolios?
PacifiCorp Response: In the 2025 IRP Draft,HB 2021 emission targets were not modeled as a binding
constraint in PLEXOS. Instead,the Oregon jurisdictional portfolio includes a driver to incentivize clean
energy production(on a$/MWh basis) and a second driver to disincentivize emissions from Oregon-
allocated emitting resources(in proportion with their emissions factor in metric tonnes per MWh).
• What does"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"mean exactly?
PacifiCorp Response: Imagine that we lined up every MWh of Oregon-allocated generation in a given
year against every MWh of Oregon load in that year. Each MWh of Oregon-allocated generation that is
not matched to a MWh of Oregon load is not necessary to meet Oregon compliance on an annual basis.
The PLEXOS Short-Term(ST) dispatch model does not see that this MWh of generation is in excess of
Oregon load. In the 2025 IRP Draft,the Company removed some emitting generation allocated to Oregon
in excess of Oregon's annual load after viewing the results of economic dispatch in the ST model. In
response to stakeholders,the Company will demonstrate compliance in the final 2025 IRP solely within
the ST model using a model driver dispatch price.
• To which degree does Oregon carbon emission compliance rely on situs vs. system resources,what assumptions
were made about resource sharing(including in terms of dispatch)?
PacifiCorp Response: Existing,non-Qualifying Facility(QF)resources were allocated according to
System Generation(SG)factors except for coal,which was not allocated to Washington or Oregon after
the dates those states have elected to exit coal.After 2040,no gas was allocated to Oregon given the
required 100%reduction in emissions set by H132021.From 2030-2039, existing gas plants were
allocated to Oregon based on SG factors. To enable Oregon compliance with HB2021 during 2030-2039,
Oregon's share of each natural gas resource was modeled separately from the share allocated to other
states, i.e. as two resources that can dispatch independently. Emissions cost drivers and emissions
accounting for HB2021 compliance are based only on the Oregon-allocated resource.
• What are the costs and development assumptions associated with the off-take agreement for the Natrium
Demonstration Project, and how are they reflected in the modeling?
PacifiCorp Response:No costs associated with Natrium are modeled in the 2025 IRP,given federal
funding and customer protection assumptions. At this time no agreement has been reached between
TerraPower and the Company. There is no current off-take agreement. To the extent PacifiCorp commits
to off-taking the output of Natrium, customer protections will be maintained.Natrium is modeled as
selectable for each jurisdiction and is dispatched on a system-wide basis.Note that in the 2025 IRP Draft,
it was assumed that Natrium was available January 1 st,2030. In the final 2025 IRP, it is assumed that
Natrium is available January 1 st,2032.
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• What is the full suite of characteristics assumed for the four non-CO2-emitting thermal resources (nuclear, small
renewable fuel peaking, geothermal, and non-emitting hydrogen peaking) and in what ways are these emerging
technology resources considered differently than resources for which attributes are well,or at least better known?
PacifiCorp Response: Details regarding the modeling of nuclear,renewable peaking, geothermal, and
hydrogen peaking are included in the supply side tables in Chapter 7 of the 2025 IRP Draft. These
resources are not considered differently than other resources.
• What is meant by action item lh?This is not mentioned anywhere else in the document. Please explain what
"changes in accounting and/or dispatch of existing natural gas resources"specifically entails,the extent to which
HB 2021 emission reductions are dependent upon these changes, and the specific Natural Gas Emissions
Compliance obligations the Company is considering.
PacifiCorp Response: In the 2025 IRP, Oregon's share of existing gas plants and some gas conversions
are modeled as distinct units that dispatch separately from the rest-of-system share of these units. Given
the need to reduce emissions to comply with HB2021,the units representing Oregon's share of gas plants
have significantly lower generation than the rest-of-system units.
The emission reductions modeled in the 2025 IRP are not dependent on changes in accounting or dispatch
of existing natural gas resources. The following strategies could address action item lh:
- New resources—additional clean generation can reduce the frequency of gas-fired generation
dispatch.
- Allocation—Oregon could potentially exit a portion of its gas-fired generation ahead of 2040.
- Market Dispatch—to manage its emissions requirements, Oregon's natural gas-fired generation
may not be offered to the market or may have restricted availability. This may be difficult to
coordinate if Oregon is allocated only a portion of a resource.
- Market Design—HB2021 compliance is based on the emissions of generation used to serve
Oregon consumers. Specified sales of emitting resources to other entities that assume
responsibility for the associated emissions could provide economic benefits and support regional
reliability. Similarly, specified purchases of low or zero-emitting resources could reduce
emissions relative to unspecified market purchases. Exactly how this would work in the market
and in compliance reporting has not yet been determined.
• How does the Company model compliance with the EPA GHG emission rules?Why did the Company select the
MN portfolio as the preferred portfolio, especially when potentially cheaper options with lower emissions are
available (MR)?
PacifiCorp Response: In the integrated MR portfolio, compliance with the Environmental Protection
Agency's (EPA)rule 111(d) is modeled by forcing all coal plants to either:
- Cease coal-fired operation and convert to lower-emitting fuel by January 1,2030;
- Retire by January 1st,2032; or
- Install carbon capture and sequestration(CCS)technology or cease coal-fired operation
In addition,the maximum allowed capacity factor for any new natural gas fired resource that is
endogenously selected by the model is 40%. The Company selected the MN portfolio as the draft
preferred portfolio because it was the least cost portfolio under the MN price-policy scenario but
recognizes that the draft did not include complete price-policy results or stochastic results that
could have influenced the portfolio outcomes.
• Given the rapidly changing federal policy environment, does the Company anticipate making any changes to the
IRP and its associated modeling to reflect environmental policy under a Trump administration?
PacifiCorp Response: The Company does not currently plan to make any changes to its modeling to
reflect possible new federal policies.As in the 2025 Draft,the Company will produce a sensitivity with
lowered production tax credits and investment tax credits.
• Tables 9.2, 9.3, and 9.4 omit existing resource options. How are jurisdictional shares of existing resources
modeled and to those similarly comply with jurisdictional rules?
* Required fields

PacifiCorp Response: Except for coal, and gas,which are removed from those states whose policy
requires it and reallocated among the remaining states, existing resources are modeled as system
resources,with allocation aligned the 2020 Protocol(and via the Washington Inter-Jurisdictional
Allocation Methodology or"WIJAM", for Washington).
• Explain in more detail the steps used and the underlying logic of creating jurisdictional portfolios and integrating
them into a system-wide portfolio. Explain what the Company's method implies about state-specific ownership of
resources,and how the capacity/energy of those resources can be dispatched by the model. Furthermore, explain
common alternative methodologies for allocating resources to jurisdictions and describe why PAC's choice is the
preferred method and what tradeoffs it presents.
PacifiCorp Response:
The essential logic of the jurisdictional portfolio selection and integration in the 2025 Draft is as follows:
- Jurisdictional Studies: All three jurisdictional studies are prepared using the same essential
inputs,though with adjustments where necessary. A separate jurisdictional study is prepared for
each variant and price-policy scenario (although Washington's jurisdictional study always uses
the social cost of greenhouse gases). For the 2025 Draft,this initial step assumed 100%allocation
of all proxy resource selections—this identifies the most cost-effective resources and results in
fewer overall selections than a partial allocation(under Oregon's—30%allocation,more than 3x
as many resources would be needed,whereas under Washington's—8%allocation,more than 12x
as many resources would be needed).
- Integrated Portfolio: In general,the integration logic takes the maximum of the cumulative
builds in each of the jurisdictional portfolios, for each individual resource that is selected in any
of the portfolios.
o Resources allocated to one jurisdiction ignore the selections by other jurisdictions. For
example, energy efficiency is always based on the results specific to its own jurisdiction.
Similarly, coal resource selections are based on the Utah/Idaho/Wyoming/California
jurisdictional portfolio.
o Because of the tie to the underlying asset,brownfield or surplus interconnection resource
selections at coal plants are also tied to the Utah/Idaho/Wyoming/California jurisdictional
portfolio.
- Resource allocations: The"max of resources"logic described above is not inherently dependent
on allocations. Sharing a resource among the jurisdictions in which it was selected and shown to
be cost-effective reduces the amount available to be allocated to each of those jurisdictions. In the
2025 Draft IRP, allocations were based on the jurisdiction that first identified an incremental
resource addition—if one jurisdiction adds resources in 2028 while a second adds resources in
2030,the first jurisdiction would get all of the 2028 resources while second would only get
incremental additions in 2030 to the extent they exceed the 2028 level.When resources are
selected in all of the jurisdictions at the same time, allocation was based on their system load
factors (SG share).
- Additional resource selections: if the integrated portfolio is not compliant for a particular
jurisdiction due to allocations,the jurisdictional portfolio can be rerun in one of two ways: add
the compliance shortfall to the target(so the model selects more), or reduce the assumed
allocation of proxy resources(so the model gets less credit for each, and selects more).
The intent of the jurisdictional methodology is to ensure that proxy selections are cost-effective using
jurisdiction-specific compliance obligations and planning assumptions. These planning assumptions are
mutually exclusive, for example Washington requires that the social cost of greenhouse gas be used in
resource dispatch,while recently Oregon has directed that potential future carbon policies be excluded
from resource dispatch. On the other hand,the 2025 Draft results indicate that Oregon and Washington
have many overlapping resource selections. This is particularly true if selections are limited to resources
on the West side of PacifiCorp's system which have greater likelihood of being deliverable to Oregon and
Washington customer loads. With that in mind PacifiCorp is exploring allocation of west-side resource
selections based on west-side load shares(Control Area Generation—West, i.e. CAGW from the 2020
Protocol). Because the IRP deals with proxy resources,rather than specific alternatives, it is more
important to consider overall quantities than the assumed allocation and this CAGW treatment. The IRP
* Required fields

is not equipped to distinguish whether Oregon and Washington take a CAGW share of each and every
west-side resource option or situs shares of specific resources totaling the same level,but these remain
important and necessary considerations as part of actual procurement.
Please refer to the company's materials and discussion in its public input meeting series. Also,please
refer to the discussion of modeling strategy presented in Chapters 8 and 9 of the Draft 2025 IRP and the
final 2025 IRP to be filed March 31,2025.
• Explain how sensitive IRP modeling results, including resource selections, are to changes in the MSP.
PacifiCorp Response: Any change to agreed-upon allocations can impact IRP model drivers,post-model
compliance assessments, and iterative resource selections to ensure compliance in competitive portfolios.
A larger share of existing clean resources would reduce the need for new resources to serve Oregon
customers, and vice versa.
• Add a more detailed section on compliance with Oregon emissions rules. Explain how emission compliance is
achieved and under which conditions emissions might deviate.
PacifiCorp Response: An appendix in the final 2025 IRP will include details regarding Oregon
emissions compliance.
• New Resource actions should be further explicated. Explain how much new resources the Company is planning to
acquire on what schedule.
PacifiCorp Response: The Company appreciates Staff s desire for more specific details regarding future
resource acquisitions and will consider ways to incorporate them into the final 2025 IRP. The final IRP
action plan will include additional details regarding the pursuit of resources as indicated in the preferred
portfolio.
• Assumptions vs. outcomes need to be better differentiated. For instance,the draft document makes it sound like
the Natrium reactor was chosen by the model as the least-cost/least-risk option. However, during the public input
meeting Staff learned that the acquisition of the Natrium reactor was added to the model as an a priori
assumption.
PacifiCorp Response:Natrium was endogenously selected by the model as part of the least-cost, least-
risk portfolio,inclusive of customer protections and federal funding for this unique project. PacifiCorp
has not yet reached a contractual agreement with Terra Power(per the Draft 2025 IRP Chapter 10,pages
259 and 265). The final 2025 IRP will include a nuclear counterfactual study and alternative path
analysis.
• Explain the Company's natural gas dispatch strategy in Oregon.
PacifiCorp Response: In the Draft 2025 IRP, Oregon's jurisdictional portfolio results indicate that
existing natural gas plants remain a cost-effective source of capacity for the Western Resource Adequacy
Program(WRAP)in 2030. How Oregon should transition away from natural gas by 2040 remains to be
determined. The degree to which gas units remain valuable for Oregon is influenced by their impact on
emissions compliance.Natural gas plants generally dispatch when their variable costs are lower than
market,lowering the cost of serving load during expensive market conditions. Combined cycle plants also
have lower emission rates than unspecified market purchases and can serve more load for a given quantity
of emissions.
For the 2025 IRP,PacifiCorp has broken each natural gas plant into Oregon and non-Oregon shares and
has allowed the shares to dispatch independently. The Oregon share counts toward Oregon's WRAP and
emissions compliance requirements,while the non-Oregon share can dispatch without impacting
Oregon's emissions compliance requirements. In actual operations,PacifiCorp has dispatch agreements
for jointly owned units including Jim Bridger(shared with Idaho Power). These agreements work best
when the units are flexible(e.g., low startup costs or low minimum operating level as a percentage of
nameplate)and the joint owners are generally aligned regarding when a unit should be online or offline.
Sharing of combined cycles is more complex, due to startup costs,relatively high minimum operating
levels, and run-time and startup impacts on maintenance requirements. Sharing can still be possible in
* Required fields

special circumstances, as with PacifiCorp's 50%share of the Hermiston natural gas plant,which consists
of two comparable units, and PacifiCorp and its co-owner each independently control one unit at a given
time. It is likely HB2021 compliance will drive Oregon to reduce natural gas plant dispatch relative to
other jurisdictions, so independent control of emitting resources is likely to be necessary. That could
include consolidation in particular units, or some form of joint dispatch arrangement. This would require
coordinated electricity market decisions in order to manage the emissions impact associated with
unspecified market purchases.
Natural gas capacity may need to be dispatched in WRAP for regional reliability needs, it could also be
dispatched in the Enhanced Day-Ahead Market(EDAM) for regional requirements (if/when it is made
available to the market). Depending on the structure of the market and the resource allocation
methodology,the generation and emissions associated with market dispatches might not be considered
part of the resources used to serve Oregon's load. While such processes have not yet been developed,
reduced control over resource dispatch(and the resulting emissions)will reduce the economic benefits of
natural gas plants for Oregon customers as HB2021 compliance requirements tighten over time.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 2/20/2025
*Name: Rose Monahan, Staff Attorney Title:
Matt Gerhart, Senior Attorney
* [e-mail]
E-mail: Phone: [phone]
[e-mail]
*Organization: Sierra Club
Address: 2101 Webster Street, Suite 1300
City: Oakland State: CA Zip: 94612
Public Meeting Date comments address: 1/22-23/2025 ❑ 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.
• Feedback on Draft 2025 IRP
❑ 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.
IRP Topic: Early Deployment Resources
Sierra Club is concerned that there is a mismatch between PacifiCorp's previous cancellation of its 2022 All-Source RFP
and assumptions regarding the earliest date for commercial operation of certain resource types. Some of the projects being
considered for the 2022 RFP were under development for several years and likely still exist in some form. These could
potentially be completed in a more expedited manner. While bid pricing may need to be updated,these projects would not
need to wait for a subsequent procurement cycle to be completed.As such, it does not make sense to push out the earliest
practicable date for all new greenfield solar,wind, and storage projects if some projects could be brought online sooner.
Sierra Club recommends that PacifiCorp conduct a sensitivity that includes a commercial operation date of 2026 for an
initial tranche of solar,wind,and battery storage resources that equate to the 2022 AS RFP. This sensitivity should also
employ the modified PTC inputs discussed in response to Utah Clean Energy's 2/10/2025 feedback form.
IRP Topic: PLEXOS Input Files
Sierra Club requests that upon filing the 2025 IRP that the Company also provide (upon request and subject to applicable
non-disclosure agreements)the specific PLEXOS input files in XML format used to conduct its modeling. This would
allow stakeholders to validate PacifiCorp's model results and conduct their own sensitivity analyses. It would also be
consistent with the approach taken by many states as part of their IRP process to provide model data and licenses to
intervenors including Arizona,New Mexico,Michigan,North Carolina, and Georgia. In fact,the Oregon PUC adopted a
similar requirement for PacifiCorp as part of Order 20-392 in the 2021 TAM proceeding(Docket No.UE 375):
"PacifiCorp will provide AURORA licenses to Commission Staff and intervenors for each future TAM. PacifiCorp will
provide all inputs, data,model settings,constraints, and any other modeling changes. The costs of the licenses,training,
and data sets will be included for cost recovery in any TAM until the next general rate case."
* 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.
Recommendations: Provide any additional recommendations if not included above-specificity is greatly appreciated.
(1) Conduct a sensitivity that includes a commercial operation date of 2026 for an initial tranche of solar,wind, and
battery storage resources that equate to the 2022 AS RFP;
(2) Provide,upon request and subject to the applicable non-disclosure agreements,the specific PLEXOS input files in
XML format used to conduct the 2025 IRP modeling to requesting parties.
PacifiCorp Response(3/17/2025):
1. PacifiCorp is continually evaluating current opportunities to acquire resources. Given the results the IRP team has
seen thus far,resources become less expensive over time due to the NREL ATB cost escalation curve. Resources
acquired in 2026 would be modeled as higher cost than those acquired later. Additionally,WRAP compliance is
not binding until 2028, and Oregon and Washington compliance is not binding until 2030. The optimal solution in
this case is to procure resources as late as possible to avoid early years of higher build costs, levelized over the
21-year horizon. Providing the model with a 2026 COD is unlikely to result in additional resource procurement in
2026.
2. Pursuant to confidentiality agreements and any other required negotiations,PacifiCorp can provide this input data.
Please submit your completed Stakeholder Feedback Form via email to IRP&Pacificorp.com
Thank you for participating.
* Required fields

PacifiCorp - Stakeholder Feedback Form
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 5-0 3-0 3
*Name: Jeremy Rishe Title:
*E-mail: [e-mail] Phone: [phone]
*Organization: Stock holder of Berkshire Hathawa
Address: 986 Sterling Place
City: Brooklyn State: Zip: 11213
Public Meeting Date comments address: 0 3-0 3-2 0 2 5 ❑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.
Solar
® 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.
As a shareholder I wish it to be known that I am a proponent of using the natural power
of the sun to energize our cities and homes. It's clean, it's always in the sky and
therefore efficient. Pacific Corp would be wise to develope long term storage batteries
for such a future, and update he grid to help deliver such energy with maximum effieincy.
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 your feedback. PacifiCorp is exploring transmission investments as well as long duration storage to address
these concerns, and the draft preferred portfolio contains significant long duration storage selections.
Please submit your completed Stakeholder Feedback Form via email to [e-mail]
Thank you for participating.
* Required fields

PACIFICORP-2025 IRP APPENDIX N-ENERGY STORAGE POTENTIAL EVALUATION
APPENDIX N - ENERGY STORAGE POTENTIAL
EVALUATION
Introduct
Energy storage resources can provide a wide range of grid services and can be flexibly sized and
sited. Many of these grid services have been increasing in value with increasing penetration of
variable energy resources such as wind and solar,while energy storage costs have been falling. As
a result, storage resources are an increasing component of PacifiCorp's least-cost, least-risk
preferred portfolio.While the IRP portfolio analysis captures the system benefits of energy storage,
it does not fully account for localized benefits and siting opportunities. This appendix provides
details on how energy storage resources can be configured to maximize the benefits they provide.
Because energy storage resources are highly flexible,with the ability to respond to dispatch signals
and function as both a load and a resource, they can potentially provide any of the grid services
discussed herein. Other types of resources,including distributed generation,energy efficiency,and
interruptible loads can also provide one or more of these grid services, and can complement or
provide lower-cost alternatives to energy storage. Given that broad applicability, Part 1 of this
appendix first discusses a variety of grid services as generically and broadly as possible. Part 2
discusses the key operating parameters of energy storage and how those operating parameters
relate to the grid services in Part 1. Finally, Part 3 discusses how to optimize the configuration and
dispatch of energy storage and other distributed resources to maximize the benefits to the local
grid and the system. Part 3 also provides examples of specific applications and examples of
applications that may be cost-effective in the future.
Grid Services
PacifiCorp must ensure that sufficient energy is generated to meet retail customer demand at all
times. It also must maintain resources that can respond to changing system conditions at short
notice,these operating reserves are held in accordance with reliability standards established by the
National Electric Reliability Corporation (NERC) and Western Electricity Coordinating Council
(WECC). Both energy and operating reserves are dispatch-based, and dependent on the specific
conditions at a specific place and time. These values are generally independent from hour to hour,
as removing a resource in a subset of hours may not impact the value in the remaining hours.
Because load can be higher than expected and some resources may be unavailable at any given
time, sufficient generation resources are needed to ensure that energy and operating reserve
requirements can be met with a high degree of confidence. This is referred to as generation
capacity. The transfer of energy from the locations where it is generated to the locations where it
is delivered to customers requires poles,wires, and transformers, and the capability of these assets
is referred to as transmission and distribution (T&D) capacity. Generation and T&D capacity are
both generally asset-based and provide value by allowing changes in the resources and T&D
elements. In general, assets cannot be avoided based on changes to a subset of the hours in which
they are needed, and only limited changes are possible once constructed or contracted. It should
also be noted that the impact of asset or capacity changes on dispatch must also be included in any
valuation.
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PACIFICORP-2025 IRP APPENDIX N-ENERGY STORAGE POTENTIAL EVALUATION
These obligations are broken down into the following grid services, which are discussed in this
section:
• Energy, including losses;
• Operating reserves, including:
o Spinning reserve;
o Non-spinning reserve;
o Regulation and load following reserves; and
o Frequency response;
• Transmission and distribution capacity; and
• Generation capacity.
Energy Value
Background
Because PacifiCorp's load and resources must be always balanced, when an increment of
generation is added to PacifiCorp's system,an increment of generation must also be removed. This
could take the form of a generator that is backed down, an avoided market purchase, or an
additional market sale. The cost of the increment that is removed (or the revenue from the sale),
represents the energy value,and this value varies by location and by time.Location can also impact
line losses relative to the generation which would otherwise have been dispatched, with losses
manifesting as a larger effective volume.Regarding time,there are two relevant time scales:hourly
values, and sub-hourly values.
The energy value in a location is dependent on PacifiCorp's load and resource balance,the dispatch
cost of its resources, and the transmission capability connecting those resources to load.
Differences in energy value occur when the economic resources in area exceed the transmission
export capability to an area that must then use higher cost resources to serve load. Once
transmission is fully utilized, the higher cost resources must be deployed to serve the importing
area and lower cost resources will be available in the exporting area. As a result, the value in each
location will reflect the marginal resources used to serve load in each area. If transfers are not fully
utilized in either direction, the marginal resource in both areas would be the same, and the energy
value would be the same.
Both load and resource availability change significantly across the day and across the year.
Differences in value over time are driven by the cost of the marginal resource needed to serve load,
which changes when load or resource availability change. When load goes up, or the supply of
lower-cost resources goes down, the marginal resource needed to serve load will be more
expensive.
The value by location is also dependent on the losses relative to the generation which would
otherwise have been dispatched.Losses occur during the transfer of energy across the T&D system
to a customer's location. As distance and voltage transformation increase, more generation must
be injected to meet a customer's demand. For example, a distributed resource that is close to
customer load or located on the same voltage level can avoid both energy at its location as well as
the losses which otherwise would have occurred in delivering energy to that location. As a result,
the marginal generation resource's output may be reduced by an amount greater than the metered
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PACIFICORP—2025 IRP APPENDIX N—ENERGY STORAGE POTENTIAL EVALUATION
output of a distributed resource. This increase in volume due to losses is also relevant to generation
and T&D capacity value.
Modeling
There are two basic sources of energy values: market price forecasts and production cost models.
There are also two relevant time scales: hourly values, and sub-hourly values.
PacifiCorp produces a non-confidential official forward price curve (OFPC) for the major market
points in which it typically transacts on a quarterly basis. The OFPC represents the price at which
power would be transacted today, for delivery in a future period. The OFPC contains prices for
each month for heavy load hour (HLH) and light load hour (LLH) periods and goes forward
approximately 20 years.I However,not all hours in the HLH or LLH periods have equal value. To
differentiate between hours, PacifiCorp uses scalars calculated based on historical hourly results.
For PacifiCorp's operations and production cost modeling, scalars are based on the California
Independent System Operator's day-ahead hourly market prices. Because these values are used in
operations, the details on the methodology and the resulting prices are treated confidentially. To
allow for transparency, PacifiCorp has also developed non-confidential scalars using historical
Western Energy Imbalance Market prices. With either scalar, the result is a forecast of hourly
market prices that averages to the values in the OFPC over the course of a month. Using hourly
market price to calculate energy value implies that market transactions are either the avoided
resource, or a reasonable representation of the avoided resource's marginal cost in any given
interval.
Production cost models contain a representation of an electric power system, including its load,
resources, and transmission rights, as well as markets where power can be bought or sold. They
also account for operating reserve obligations and the resources held to cover those obligations.
All models are simplified representations, and there are several key simplifying assumptions. The
granularity of a model is its smallest calculated timestep. While calculating twice as many
timesteps should take roughly twice as long from a mechanical standpoint, evaluating decisions
that span multiple time steps (such as when to charge or discharge a battery, or when to start or
shutdown a thermal resource) requires the evaluation of multiple timesteps at once, resulting in a
larger more complicated problem that can take longer to solve. In addition, maintaining inputs to
represent smaller timesteps is more complicated, and a model is only as good as its inputs. To
simplify the representation of location, transmission areas can be defined by the key transmission
constraints which separate them,with transmission within each area assumed to be unconstrained.
Another simplifying assumption is to model all load and resources at a level equivalent to generator
input. For instance, load is "grossed up" from the metered volume to a level that includes the
estimated losses necessary to serve it. This allows for a one for one relationship between all
volumes, which vastly simplifies the model.
PacifiCorp's production cost modeling for the IRP uses the Plexos model and reflects system
dispatch at an hourly granularity. While the IRP modeling uses the hourly market prices from the
OFPC as inputs, a distributed resource's energy value will depend on its location and other
characteristics and can be either higher or lower than the market price in a given hour. Generally,
a resource's value is based on the difference between two production cost model studies: one with
the resource included, and one with the resource excluded. This explicitly identifies the marginal
'HLH is 6:00 a.m.to 10:00 p.m.Pacific Prevailing Time Monday through Saturday,excluding NERC holidays.LLH
is all other hours.
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PACIFICORP-2025 IRP APPFNDIx N-ENERGY STORAGE POTENTIAL EVALUATION
resources dispatched in the absence of the resource being evaluated. The Plexos model offers an
alternative in that it reports the value of energy produced by each resource, by multiplying that
resource's output by the marginal price in that resource's location for each hour. A comparable
calculation is performed for operating reserves. This provides an estimate of the marginal benefits
from any resource in the portfolio, without the need for with and without studies. However, for
large resources or significant portfolio changes, with and without studies may still be necessary,
as the reported results reflect the marginal cost of the last increment of generation, rather than the
average across all the resource's output.
More detailed models of the electrical power system also exist, for instance PacifiCorp uses
physical models for grid operations and planning that account for power flows and the loading of
individual system elements. Similarly,the California Independent System Operator(CAISO)uses
a "Full Network Model" with detailed representations of all resources and loads, as well as the
transmission system. CAISO's model includes a representation of PacifiCorp's system for the
purpose of dispatching resources in the Western Energy Imbalance Market (EIM), and models a
five-minute granularity for that purpose. The added detail these physical models produce comes
from a significant increase in the complexity of inputs and computational requirements.
Figure N.I contains a sample of energy margin values for various combinations of energy storage
specifications, and reflects marginal values reported by the Plexos model, including both energy
and operating reserves.
Figure N.1 -Energy Margin by Energy Storage Attributes
$250
a
$200
c) $150
a $100Cc
I •• /
L
o $0
Z N N N M M M M M M M M M M � � IZI 14IZI
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 CV N N N N N
•• • ••• Li-ion 4hr (85% Eff.) Li-ion 8hr (85% Eff.)
Iron-Air 100hr (44% Eff.) Theoretical 100hr (85% Eff.)
These energy values will vary by location,volume, and operating reserve requirements, as well as
with changes in the portfolio.Longer duration provides greater value,though it diminishes as more
duration is added.As shown above,changes in efficiency also have an impact on dispatch revenue,
442

PACIFICORP—2025 IRP APPENDIX N—ENERGY STORAGE POTENTIAL EVALUATION
notably because revenues are net of greater charging costs. Storage of all types benefits when
marginal costs are negative, and the prevalence of PTC-eligible resources results in relatively high
values in 2031-2041. In addition to declining value from PTCs, significant storage resource
additions in 2042 result in higher marginal costs to charge the larger storage fleet and lower
marginal benefits from discharging. These effects could be outweighed by a variety of factors
including changes in renewable resources or load.
The Plexos model identifies resources to carry operating reserves for each hour but does not
include the intra-hour changes that would cause those resources to be deployed.Because resources
that are dispatchable within the hour can be dispatched up when marginal energy costs are high,
and down when marginal energy costs are low, this can result in incremental value relative to an
hourly market price or hourly production cost model result. In practice, sub-hourly dispatch
benefits are largely derived from PacifiCorp's participation in EIM, and the specific rules
associated with that market. For instance, resources must be participating in EIM to receive
settlement payments based on their five-minute dispatches. Resources that are not participating
receive settlement payments based on their hourly imbalance. Furthermore, because non-
participating resources are not visible to the market, their sub-hourly dispatch would not impact
the market solution. Because distributed resources can be aggregated for purposes of EIM
participation, size should not be an impediment; however, the structure of the EIM may dictate
some aspects of their use and would need to be aligned with the other services a distributed
resource provides. While intra-hour dispatch is a key aspect of reliable system operation, and
potentially an additional source of revenue for flexible resources, it is difficult to represent the
interactions between hourly dispatch in Plexos and sub-hourly dispatch in EIM— since they have
finite storage capability, a battery that is discharged in response to high prices in EIM is likely to
forego dispatch at relatively high prices in a later interval. In addition, imbalance in the EIM is
finite in both duration and magnitude and the battery resources added in PacifiCorp's preferred
portfolio could easily move the market thereby drastically reducing the frequency of price
excursions and the associated intra-hour revenue.
In addition to potential EIM revenue for intra-hour dispatch, dispatchable resources may receive
additional revenue for their availability during day-ahead and hour-ahead market operations, for
example as part of the Extended Day-Ahead Market (EDAM) being developed by the California
Independent System Operator. Because the Plexos model has a single system dispatch solution for
each hour,without day-ahead or hour-ahead resource commitments and uncertainty,the additional
value associated with this type of uncertainty is not part of the reported results.
For these reasons,PacifiCorp has not quantified the costs or benefits of intra-hour dispatch for the
2025 IRP but expects to continue evaluating them as its portfolio and the market itself continue to
evolve.
Operating Reserve Value
Background
Operating reserve is defined by NERC as "the capability above firm system demand required to
provide for regulation, load forecasting error, equipment forced and scheduled outages and local
area protection."2 Operating reserves are capability that is not currently providing energy, but
2 Glossary of Terms Used in NERC Reliability Standards:
hilps://www.nerc.com/pa/Stand/Gloss4ry%20oP/`2OTertns/Glossaa of Terms.pdf,updated February 26,2025.
443

PACIFICORP-2025 IRP APPENDIX N-ENERGY STORAGE POTENTIAL EVALUATION
which can be called upon at short notice in response to changes in load or resources. Operating
reserves and energy are additive— a resource can provide both at the same time, but not with the
same increment of its generating capability. Operating reserves can also be provided by
interruptible loads, which have an effect comparable to incremental resources. Additional details
on operating reserve requirements are provided in Volume II, Appendix F (Flexible Reserve
Study).
As with energy value, operating reserve value is based on the marginal resource that would
otherwise supply operating reserves, and varies by both location, time, and the speed of the
response.Because operating reserve requirements are primarily applied at the Balancing Authority
Area (BAA) level, the associated value is typically uniform within each of PacifiCorp's BAAs.
An exception to this is that operating reserves must be deliverable to balance load or resources, so
unused capability in a constrained bubble without additional export capability does not count
toward the meeting the requirements. Operating reserve value is somewhat indirect in comparison
to energy value, as it relates to the use of the freed-up capacity on units that would otherwise be
holding reserves. If that resource's incremental energy is less expensive that what is currently
dispatched,it can be dispatched up,and more expensive energy can be dispatched down. The value
of the operating reserves in that instance is the margin between the freed-up energy and the
resource that is dispatched down.Note that the dispatch price of the resource being evaluated does
not impact the value, since holding operating reserves does not require dispatch. When the freed-
up resource is more expensive than what is currently dispatched, it will not generate more when
the operating reserve requirement is removed, and the value of operating reserves would be zero.
Operating reserves are generally held on the resources with the highest dispatch price. Finally,
operating reserve value is limited by the speed of the response: how fast a unit can ramp up in a
specified period, and how soon it begins to respond after receiving a dispatch signal. Reliability
standards require a range of operating reserve types, with response times ranging from seconds to
thirty minutes.
Modeling
As discussed above, the value of incremental operating reserves is equal to the positive margin
between the dispatch cost of the lowest cost resource that was being held for reserve, and the
dispatch cost of the highest cost resource that was dispatched for energy. Similar to the value of
energy, the price of different operating reserve types could be forecasted by hour, based on
forecasts of reserve capability, demand, and resource dispatch costs. Given the range and
variability in these components, this would be an involved calculation. In addition, because
operating reserves are a small fraction of load, they are more sensitive to volume than energy. For
instance, spinning reserve obligations are approximately three percent of load in each hour. As a
result, resource additions may rapidly cover that portion of PacifiCorp's requirement met by
resources that could otherwise provide economic generation and which produce a margin when
released from reserve holding. This is particularly true for batteries and interruptible load resources
that can respond rapidly and thus count all or most of their output toward reserve obligations.
While a market price for operating reserve products does not align well with PacifiCorp's system,
the specifics of the calculation described above are embedded within PacifiCorp's production cost
models. Those models allocate reserves first to energy limited resources in those periods where
they could generate but are not scheduled to do so. Examples of energy limited resources include
interruptible loads,hydro, and energy storage. If called on for reserves,these resources would lose
the ability to generate in a different period, so the net effect on energy value for that resource is
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relatively small. As a result, the unused capacity on these resources can't be used for generation,
but that also means it can count as reserves without forgoing any generation and incurring a cost
to do so. After operating reserves have been fully allocated to the available energy-limited
resources,reserves are allocated to the highest cost generators with reserve capability in the supply
stack, up to each unit's reserve capability, until the entire requirement is met. This is generally
done prior to generation dispatch and balancing because the requirements are input to the model
or based on a formula and aren't typically restricted based on transmission availability. After the
reserve allocations are complete, the remaining dispatch capability of each unit is used to develop
an optimized balance of load and resources.
As part of the calculation of wind and solar integration costs reported in Volume II, Appendix F
(Flexible Reserve Study), PacifiCorp assessed the cost of holding incremental operating reserves.
That study identified a cost of approximately $8/kw-yr (2024$), based on a 2025-2045 study
period. This value would be applicable to any resource that provided operating reserves uniformly
throughout the year. Like reporting on energy values, the Plexos model also reports operating
reserve revenues specific to each modeled resource, accounting for availability, location, and use
for energy dispatch (during which a resource could not also provide reserves with any portion of
its capacity that was generating energy). As with the annual wind and solar costs shown in
Appendix F, operating reserve value is projected to be highest in the near term and decline across
the study horizon as the amount of battery resources on the system increases.
Transmission and Distribution Capacity
The IRP includes endogenous transmission upgrades as part of portfolio selection. This allows the
cost of transmission upgrades to be considered as part of the modeled cost of resources in each
area. However,because energy efficiency and load control are customer-sited,they are not subject
to these constraints,placing them at an advantage relative to both thermal and renewable resource
options. For some sizes and locations, distributed resources can also potentially avoid significant
transmission upgrades and may help to defer distribution system investments. While the cost of
specific T&D projects varies, a generic system wide estimate of transmission upgrade costs is
included as a credit to energy efficiency in the 2025 IRP and amounts to $5.83/kw-year (2024$).
In practice, these costs would vary by project and some transmission upgrades would not be
suitable for deferral by distributed resources. Because of the large scale of many transmission
upgrades, and the binary nature of the expenditures, it may be difficult to procure adequate
distributed resources to cover the need in a timely fashion and in accordance with reliability
requirements, though it is always appropriate to consider the available options when considering
expenditures on an upgrade. Distribution capacity upgrades are more likely to be suitable for
deferral by a distributed resource, as the scale of the need is closer to that of these types of
resources.
To that end, PacifiCorp maintains an "Alternative Evaluation Tool" which is used to screen the
list of projects identified during T&D planning to assess where distributed resources, including
energy storage, could be both technically feasible and cost competitive as compared to traditional
T&D solutions. If a study shows that distributed resource alternatives are feasible and potentially
cost-competitive that project is flagged for detailed analysis.
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Generation Capacity
Background
To provide reliable service to customers, a utility must have sufficient resources in every hour to:
• Serve customer load, including losses and any unanticipated load increase.
• Hold operating reserves to meet NERC and WECC reliability standards, including
contingency, regulation, and frequency response.
• Replace resources that are unavailable due to:
o Forced and planned outages
o Dry hydro conditions
o Wind and solar conditions
o Market conditions
PacifiCorp refers to "Generation Capacity" as the total quantity of resources necessary to reliably
serve customers, after accounting for the items above. For the 2025 IRP, PacifiCorp is using
planning reserve margins from the Western Resource Adequacy Program that vary by month and
can range from 10-20% of the peak load in a given month. The planning reserve margin does not
translate directly into either resources or need.
All resources contribute to a reliable portfolio, but they do so in ways that are not straightforward
to measure and are dependent on the composition of the portfolio. Removing a resource from a
portfolio will make that portfolio less reliable unless it is replaced with something else, ideally in
a quantity that provides an equal capacity contribution and results in equivalent reliability. For
more details on capacity contribution, please refer to Volume II, Appendix K (Capacity
Contribution).
As a result, the most direct measurement of the generation capacity value of a resource is to build
a portfolio that includes it and compare that portfolio to one without it. But even that analysis
would identify more than just generation capacity value, as it would also include energy and
operating reserve impacts related to both the resource being added and resources that were delayed
or removed. This is an essential description of the steps used to develop portfolios in the IRP, and
while powerful,the IRP models and tools do not lend themselves to ease of use,rapid turnaround,
or the evaluation of small differences in portfolios.
As an alternative, a simplified approach to generation capacity value can be used when the
resources being evaluated are small or like the proxy resource additions identified in the IRP
preferred portfolio. The premise of the approach is that the IRP preferred portfolio resources
represent the least-cost, least-risk path to reliably meet system load. The appropriate level of
generation capacity value is inherently embedded in the IRP preferred portfolio resource costs
because those resources achieve the stated goals of reliable operation and compliance with regional
resource adequacy requirements.
Mart 2: Energy Storage Operating Parameters
This section discusses some of the key operating parameters associated with energy storage
resources. Beyond just defining the basic concepts, it is important to recognize the specific ways
in which these parameters are measured and ensure that any comparison of different technologies
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or proposals reports equivalent values. For example, many battery systems operate using direct
current(DC)rather than the alternating current(AC) of most of the electrical grid. When charging
or discharging from the grid, inverters must convert DC power to AC power,which creates losses
that reduce the effective output when measured at the grid, rather than at the battery. To manage
this distinction,PacifiCorp uses the AC measurement at the connection to the electrical grid for all
parameters, as this aligns with the effective "generation input" of an energy storage resource. As
previously discussed, an additional adjustment for line losses on the electrical grid may also be
necessary, but that is dependent on the location and conditions on the electrical grid, rather than
the energy storage resource.
• Discharge capacity: The maximum output of the energy storage system to the grid, on an
AC-basis, measured in megawatts (MW). This is generally equivalent to nameplate
capacity.
• Storage capacity: The maximum output of the energy storage system to the grid, on an
AC-basis, when starting from fully charged, measured in megawatt-hours (MWh).
• Hours of storage: The length of time that an energy storage system can operate at its
maximum discharge capacity, when starting from fully charged, measured in hours.
Generally, the hours of storage will be equal to storage capacity divided by discharge
capacity.
• Charge capacity: The maximum input from the grid to the energy storage system, on an
AC-basis, measured in megawatts (MW).
• Round-trip efficiency: The output of the energy storage system to the grid, divided by the
input from the grid necessary to achieve that level of output, stated as a percentage. A
storage resource with eighty percent efficiency will output eight MWh when charged with
ten MWh. If charge and discharge capacity are the same, losses result in a longer charging
time. For instance, an energy storage system with four hours of storage, eighty percent
efficiency, and identical charge and discharge capacity would require five hours to fully
charge (4 hours of discharge divided by 80 percent discharge MWh per charge MWh).
• State of charge: This is a measure of how full a storage system is, calculated based on the
maximum MWh of output at the current charge level,divided by the storage capacity when
fully charged, and is stated as a percentage. One hundred percent state of charge indicates
the storage system is full and can't store any additional energy, while zero percent state of
charge indicates the storage system is empty and can't discharge any energy.As previously
indicated,PacifiCorp's state of charge metric is based on output to the grid.As a result,the
entire round-trip efficiency loss is applied during charging before reporting the state of
charge. For example, a storage system with a ten MWh storage capacity and eighty percent
efficiency would only have an eighty percent state of charge after ten MWh of charging
had been completed, starting from empty.
• Station service: Round-trip efficiency is a measure of the losses from charging and
discharging. Some energy storage systems also draw power for temperature control and
other needs. This is typically drawn from the grid, rather than the energy storage resource.
Some energy storage technologies experience degradation of their operating parameters over time
and based on use. The following parameters are used to quantify the effects of degradation.
• Storage capacity degradation: The primary impact of degradation is on storage capacity.
Much of the degradation occurs as part of charge-discharge cycles and can be measured as
the degradation per thousand cycles.After one thousand cycles,a four-hour storage system
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might only be capable of storing 3.5 hours of output. Some storage resources also
experience degradation that isn't tied to cycles, for instance based on differing state of
charge levels or time.
• Cycle life: This is the total number of full charge and discharge cycles that energy storage
equipment is rated for. Three thousand cycles are common for lithium-ion resources, but
operating under harsh conditions can also cause the effective cycle count to decline faster.
Once storage capacity has degraded by thirty percent degradation per cycle may accelerate.
• Depth of discharge: Operating at a very high or very low state of charge, particularly for
an extended period, can cause more rapid degradation. This metric can be used to identify
how particular operations impact the effective remaining cycle life.
• Variable degradation cost: Lithium-ion energy storage equipment is composed of many
battery modules, each of which experience degradation. These modules can be gradually
replaced over time to maintain a more consistent storage capacity, or they can be replaced
all at once when cycle limits are reached, at the expense of a reduced storage capacity in
the interim. In either case, the replacement cost of storage equipment can be expressed per
MWh of discharge and accounted for as part of resource dispatch.
Part 3: Distributed Resource Configuration and Applications
This section described the potential benefits of different distributed resource siting and
configuration options. Due to economies of scale, distributed resource solutions generally higher
cost relative to utility-scale assets. Many of PacifiCorp's distribution substations have capacity
more than fifteen megawatts, such that a battery of that size could be feasible at the distribution
level, with the potential for incremental benefits relative to the transmission-connected battery
resources modeled as part of the preferred portfolio. The most cost-effective locations for
distributed resource deployment are likely to reflect a balance of local requirements and economies
of scale.
Secondary Voltage
A distributed resource which is located downstream from the high voltage transmission grid will
have a larger energy impact than its metered output would indicate, due to line losses. This is true
for both charging and discharging. To the extent discharging is aligned with periods with higher
load, and charging is aligned with periods with lower load, the benefits will be proportionately
higher. For example, the marginal primary voltage losses for Oregon have been estimated at 9.5
percent on average across the year. Savings based on primary losses would be appropriate to apply
to a resource connected at the secondary voltage level so long as it is not generating exports to the
higher voltage system, as losses would still occur within that level, but would be reduced due to
lower deliveries across the higher voltage system. For lithium-ion batteries, there is also an
incremental benefit related to variable degradation costs. While the effect of losses makes the
battery appear larger from a system benefits perspective, it discharges the same amount, so the
variable cost component doesn't scale with losses, creating an additional benefit that is captured
in this energy margin.
In addition to incremental energy value, resources connected at primary or secondary voltage will
also have a proportionately higher generation capacity value and will have a higher capacity
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contribution based on their ability to avoid primary losses. Such adjustments to account for avoided
losses are also applied to energy efficiency and demand response measures.
T&D Capacity Deferral
As indicated in the grid services section, distributed resources can allow for the deferral of
upgrades by reducing the peak loading of the transmission and distribution system elements
serving their area. For deferral to be achieved, a distributed resource must reliably reduce load
under peak conditions. However, the timing of peak conditions for a given area is likely to vary
from the peak conditions for the system. As a result, the energy or generation capacity value of
energy-limited resources used for a T&D capacity deferral application are likely to be reduced.
For instance, when energy-limited resources are reserved for local area requirements they would
not be available for system reliability events or a period of high energy prices.
Long Duration Energy Storage
PacifiCorp's 2025 IRP preferred portfolio includes the addition of one-hundred-hour iron air
storage in several locations around the system. The supply-side resource table also includes
hydrogen resources with storage options of 24 hours or more. Optimization of energy storage
resources with this much storage duration is somewhat more complicated than a four-hour or eight-
hour battery,which PLEXOS is reasonably capable of optimizing within the one-week(168 hour)
horizon of the ST model. To assist PLEXOS in managing the functionality of long duration
storage,PacifiCorp sets state of charge targets to ensure storage with duration of 24 hours or more
is gradually filled up during periods with relatively high supply and low demand, and allowed to
deplete stored volumes across peak seasons when demand is high. Figure N.2 illustrates the two
seasonal charging and discharging cycles modeled in each year, along with an example of
PLEXOS-optimized results.The energy targets are not hard limits,and PLEXOS can also use extra
charging to support additional discharging within the same week. However, the relatively low
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PACIFICORP—2025 IRP APPENDIX N—ENERGY STORAGE POTENTIAL EVALUATION
round-trip efficiency of one-hundred-hour iron air storage, at 44%, results in fewer opportunities
for economic arbitrage than lithium-ion storage, which has an 85%round-trip efficiency.
Figure N.2—Long Duration Storage Charging and Discharging, Targets and Optimization
100%
Storage Target(%)
90% t
••••• Storage Status N
80%
70%
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CU 40% c°p
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1 c�
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Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
While the seasonal cycles shown help to increase the benefits of one-hundred-hour iron air
storage,there is the potential for further optimization. Rather than targeting uniform charging or
discharging across a season, charging can be increased during periods when renewable supply is
high and discharging can be increased shifted to allow more output on the highest load days. In
the real world, future weather conditions are highly uncertain beyond the next week, so it is not
possible to know that high loads in the first week of July won't be followed by even higher loads
in the last week of July. Therefore, it is important to maintain a minimum state of charge during
periods of possible peak-producing weather to ensure reliability. As discussed in Volume II
Appendix K(Capacity Contribution), the longest loss of load event seen in analysis of the 2025
IRP preferred portfolio was ten hours, so reliability requirements are likely to outweigh
economic arbitrage as the state of charge drops to that level. As an example,with a state of
charge down to five hours of discharge, iron air storage might not be dispatched, despite market
prices exceeding $100/MWh, ensuring output is available if demand increases or market prices
go up in future periods. With a round-trip efficiency of 44%, iron air storage would need to be
charged at costs of$441MWh or less in order to economically discharge at $100/MWh. As the
state of charge approaches zero, it would be economic to charge at up to $440/MWh to avoid the
possibility of market pricing at $1,000/MWh. Administrative pricing provisions kick in at that
point, limiting market outcomes, but adequate state of charge would still be needed for provision
of operating reserves as well as to meet market requirements including balancing and flexibility
tests. With all that taken into consideration,reliable system operation may result in charging at
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high prices and willingness to purchase at even higher market prices rather than discharge. This
is true for any storage resource but is exacerbated for storage with a low round-trip efficiency.
These reliability considerations could also be a factor for storage with a slow charging speed,
such as hydrogen electrolysis sized below the hourly consumption of the associated hydrogen-
fueled generator. As storage makes up a greater portion of a utility's resource mix, and that of a
region as a whole, coordination to plan around and operate within these limitations will be
increasingly important.
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Contents
INTRODUCTION...................................................................................................................................................439
PART1: GRID SERVICES....................................................................................................................................439
ENERGYVALUE.....................................................................................................................................................440
Background......................................................................................................................................................440
Modeling..........................................................................................................................................................441
OPERATING RESERVE VALUE................................................................................................................................443
Background......................................................................................................................................................443
Modeling..........................................................................................................................................................444
TRANSMISSION AND DISTRIBUTION CAPACITY......................................................................................................445
GENERATIONCAPACITY........................................................................................................................................446
Background......................................................................................................................................................446
PART 2: ENERGY STORAGE OPERATING PARAMETERS........................................................................446
PART 3:DISTRIBUTED RESOURCE CONFIGURATION AND APPLICATIONS....................................448
SECONDARYVOLTAGE..........................................................................................................................................448
T&D CAPACITY DEFERRAL...................................................................................................................................449
LONG DURATION ENERGY STORAGE.....................................................................................................................449
No table of figures entries found.
FIGURE N.1 -ENERGY MARGIN BY ENERGY STORAGE ATTRIBUTES..........................................................................442
FIGURE N.2—LONG DURATION STORAGE CHARGING AND DISCHARGING,TARGETS AND OPTIMIZATION................450
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PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
APPENDIX O - WASHINGTON CLEAN ENERGY
ACTION PLAN
Introduction
PacifiCorp's 2025 Integrated Resource Plan presents a fully compliant approach to meeting
Washington obligations through long-term resource planning, near-term actions and ongoing
evaluation and execution. In this appendix, the company presents the Clean Energy Action Plan
and other components that bridge the evolution from the 2025 IRP to the filing of the 2025 Clean
Energy Implementation Plan on October 1, 2025.
Key Findings
1. Washington will require 3,448 megawatts (MW) of new situs-allocated renewable, non-
emitting, and storage resources to meet its capacity, energy, and clean energy needs over
the 21-year planning horizon, in addition to cost-effective demand-side management
resources.
2. In the near-term, Washington customers will require 254 MW of new situs-allocated
renewable resources before the end of 2029, and nearly 1 GW of battery storage.
3. Washington's clean energy interim targets will reach over 100% by 2030 and progress
towards 2045 zero-greenhouse gas emissions goals steadily over the next 21 years.
4. The CETA-compliant preferred portfolio includes 700 MW of additional wind relative to
the Alternative Lowest Reasonable Cost Portfolio.
5. PacifiCorp continues to grow in its approach to ensuring equitable benefits and outcomes
across its customers throughout the clean energy transition.
Background
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 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(LEAP)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
' 2019 WA Laws Ch.288.
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PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
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;
(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).
2 WAC 480-100-620.
3 WAC 480-100-640.
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Unergy Justice
Washington's CETA guidelines and regulatory direction mandate the consideration of equitable
distribution of energy and nonenergy benefits and burdens across populations.4 The Washington
Utilities and Transportation Commission leverages four core tenets of energy justice:
distributional, procedural, recognition and restorative.' On September 29, 2023, the commission
initiated Docket A-230217 (Equity Docket) to address the application of equity and justice in
commission and regulated companies' processes and decisions.6 On December 2, 2024, the
commission communicated that it had determined it needed to adjust the schedule of the work in
this proceeding until the first quarter of 2025 to re-evaluate and clarify the scope of work required.
Activities within this docket at present are paused until further notice. PacifiCorp continues to
monitor communications and activities within this docket to better understand how the four tenets
overlap and reinforce each other to achieve energy justice.
Figure 0.1 —Tenets of Energy Justice
0
i
Energy
Justice
i
The following discussion of energy justice describes how these tenets are relevant to PacifiCorp's
path forward, clarifying the scope and meaning of energy justice as applied to the achievement of
CETA standards. As acknowledged in regulatory agreements, CETA standards include not only
readily quantifiable requirements, but also requirements that are qualitative in nature.7 The four
tenets generally fall into this second, qualitative, arena, and are devised to ensure that,
"...all customers are benefiting from the transition to clean energy: Through the equitable
distribution of energy and nonenergy benefits and the reduction of burdens to vulnerable
4 RCW 19.405.060(1)(c)(iii);WAC 480-100-610(4)(5).
5 See, Commission-led Policy Statement to Address the Application of Equity and Justice in Commission and Regulated
Companies'Process and Decisions, Docket No. A-230217, Notice of Continuance (Dec. 2, 2024) (pending equity
policy statement docket); Docket, Washington Utilities and Transportation Commission v. Cascade Natural Gas
Corporation,Docket No.UG-210755,Final Order 09 at 18.
6 Docket A-230217 Washington UTC Equity Docket
7 Docket UE-210829, Order 06, Appendix A: Full Multi-Party Settlement Agreement, p. 12. "In future CEIPs,
PacifiCorp will continue to include descriptions of quantitative (i.e., cost based) and qualitative (e.g., equity
considerations)analyses that support interim targets to comply with CETA's 2030 and 2045 clean energy standards."
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populations and highly impacted communities; long-term and short-term public health and
environmental benefits and reduction of costs and risks; and energy security and
resiliency"8
In essence, CETA standards one (1) through three (3), below, are to be achieved within the
protections of the standards four(4) and five (5):9
(1) On or before December 31, 2025, each utility must eliminate coal-fired resources from
its allocation of electricity to Washington retail electric customers;
(2)By January 1,2030, each utility must ensure all retail sales of electricity to Washington
electric customers are greenhouse gas neutral;
(3) By January 1, 2045, each utility must ensure that nonemitting electric generation and
electricity from renewable resources supply 100 percent of all retail sales of electricity to
Washington electric customers;
(4) In making progress toward and meeting subsections (2) and (3) of this section, each
utility must:
(a) Pursue all cost-effective, reliable, and feasible conservation and efficiency
resources and demand response;
(b)Maintain and protect the safety,reliable operation, and balancing of the electric
system; and
(c) Ensure that all customers are benefiting from the transition to clean energy
through:
(i) The equitable distribution of energy and nonenergy benefits and
reduction of burdens to vulnerable populations and highly impacted
communities;
(ii)Long-term and short-term public health and environmental benefits and
reduction of costs and risks; and
(iii) Energy security and resiliency.
(5) Each utility must demonstrate that it has made progress toward and has met the
standards in this section at the lowest reasonable cost.
In the discussion which follows, PacifiCorp examines the fulfillment of the four tenets of energy
justice as a component of achieving CETA's targets of transitioning the state of Washington to a
clean energy future.
Distributional Justice
"...which refers to the distribution of benefits and burdens across populations. This
objective aims to ensure that marginalized and vulnerable populations do not receive an
inordinate share of the burdens or are denied access to benefits."Io
PacifiCorp's modeling of resource selections in the IRP is agnostic to location,timing,technology,
and sizing. This allows for the preferred portfolio to send a market signal in a future request for
proposals for projects that fit an optimal view of future portfolio composition. While the IRP does
not account for precise project details, which are as unknown at the time of publishing an IRP,
8 RCW 19.405.060(1)(c)(iii).
9 WAC 480-100-610.
10 DOCKET UG-210755,Washington Utilities and Transportation Commission v. Cascade Natural Gas Corporation,
Final Order 09,p. 18.
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there are important considerations that can inform the analysis of candidate portfolios for the
preferred portfolio, and also inform the downstream processes used to make bid acquisition
decisions.
From the inception of CETA, and beginning with PacifiCorp's 2021 IRP and 2021 CEIP,I 1
distributional justice has been incorporated into PacifiCorp's IRP modeling assumptions and
customer benefit indicator(CBI) framework. In the 2025 IRP, the inclusion of competitive small-
scale supply-side resources provides for energy and capacity resources that are tied to local
community needs, mitigating possible downsides of transmission projects while potentially
increasing community resiliency.
Distributional justice is also incorporated into the use and assessment of the social cost of
greenhouse gases. This view of system planning increases economic cost but also increases
nonenergy benefits for Washingtonians by capturing the non-monetary burdens imposed by
greenhouse gas emissions.
PacifiCorp's Maximum Customer Benefit case is designed to address distributional justice by
avoiding those portfolio elements that can disproportionately burden vulnerable communities. 12
This case is operationalized by 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 those
customers. In this study, Washington's load forecast reflects the high private generation forecast.
Also, the study assumes the social cost of greenhouse gas price-policy scenario and includes all
available Washington energy efficiency and demand response. The Maximum Customer Benefit
case is introduced in Chapter 8. Additional detail and portfolio results are provided later in this
appendix.
Distributional justice is also represented in the consideration of CBIs. While it is important to note
that the concept of distributional justice is represented in all of PacifiCorp's CBIs, only four of ten
elements of the CBI framework explicitly represent non-energy benefits to highly impacted and
vulnerable communities,as well as other potentially underrepresented people. These specific CBIs
are to:
• Increase culturally and linguistically responsive outreach by engaging in efforts to
improve language accessibility and developing communications strategies that target
highly impacted and vulnerable communities.
• Increase community-focused efforts and investments by enhancing incentive programs to
improve accessibility for highly impacted and vulnerable communities.
• Increase participation in energy efficiency and billing assistance programs like low-
income weatherization and the Washington Low-Income Bill Assistance (LIBA)
programs.
• Improve indoor air quality through promotion of weatherization programs that target
highly impacted and vulnerable communities.
11 2021 IRP filed on September 1, 2021, https://www.pacificorp.com/energy/integrated-resource-plan.html; 2021
CEIP filed on December 31,2021,https://www.pacificorp.com/energy/Washington-clean-energy-transformation-act-
equity.html
12 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."
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PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Beyond the reduction of energy costs, nonenergy benefits help vulnerable communities by
improving their overall quality of life, including aspects such as improved health, comfort, safety,
and housing quality,which are particularly important for populations facing economic hardship or
environmental challenges that might exacerbate their vulnerabilities.I3
To prioritize diverse suppliers, PacifiCorp is expanding its non-price scoring methodology that
will be applied to resource bid evaluation in forthcoming RFPs. These were first identified in the
2021 IRP/CEAP for use in subsequent RFP processes. The company will consider non-price
metrics again in procurement activities following the 2025 IRP. As part of this effort, PacifiCorp
is looking at further refinement of its non-price scoring to include explicit consideration of 1) the
four energy justice tenets and 2) its CBIs (where appropriate). These may include, for example,
consideration of local job creation,continuing education and apprenticeship opportunities,and Use
of Disadvantaged Business Enterprises and/or tribal,women, or minority owned subcontractors in
its evaluation of bidder proposals.
Procedural Justice
"...which focuses on inclusive decision-making processes and seeks to ensure that
proceedings are fair, equitable, and inclusive for participants, recognizing that
marginalized and vulnerable populations have been excluded from decision-making
processes historically."I4
Unlike distributional justice, which looks primarily at the fairness of the final result, procedural
justice emphasizes the fairness of the steps taken to reach that result. The focus is therefore on the
equitability of the decision-making process itself,regardless of the final outcome,to ensure voices
are heard and opportunities are fairly distributed, even if participants do not ultimately obtain the
full result they wanted.
The 2025 IRP and related downstream processes seek to give people a voice, treat them with
respect, and demonstrate trustworthiness. The primary avenue for procedural energy justice in the
CEAP can be found in our expanded public participation opportunities, described later in this
appendix.
Some of the same CBI framework considerations that help to ensure the fair distribution of
outcomes are also tied to procedural justice through efforts to broaden participation. This includes,
for example, development of communication strategies that target highly impacted and vulnerable
communities. It may also include engaging interested parties by increasing the number of
informational events regarding energy-related programs, like public meetings.
In addition to the steps taken regarding CETA participation specifically, the 2025 IRP also
significantly advances its participation and incorporation of public input. More than in any
previous IRP, PacifiCorp has greatly expanded efforts to provide responsiveness and open
discussion in its public input meeting series. Key topics were introduced earlier and often, and in
advance of key decision-making. The link between public input and the handling of critical topics
13 Refer to Portfolio Impacts and Customer Benefit Indicators later in this appendix.
14 DOCKET UG-210755,Washington Utilities and Transportation Commission v. Cascade Natural Gas Corporation,
Final Order 09,p. 18.
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
has been made more transparent by directly linking requests and comments to responses in the
2025 IRP document."
Also in the 2025 IRP, participants increasingly drove the amount of time spent on various topics,
including open discussion of the entirety of the Draft 2025 IRP in the public meetings held on
January 22-23, 2025, and February 26-27, 2025. At each of these meetings, significant and open-
ended time was devoted to discussion lead by stakeholders, with no preset agenda. This resulted
in robust explorations of the ideas and concerns of stakeholders. PacifiCorp has and will continue
to also hold CEIP-specific engagement sessions to allow interested parties opportunities to engage
with specific elements of the final CEIP to be filed later this year. Part of increasing accessibility
to this material includes releasing a draft CEIP 45 days prior to filing, to allow for robust and
thoughtful feedback.
In this cycle, PacifiCorp publicly posted key documents in development, such as the draft
Conservation Potential Assessment and the supply-side resource table. Stakeholder feedback
forms have also been posted publicly and incorporated in the IRP and are summarized in the 2025
IRP Appendix M. Additionally, PacifiCorp has again refined and expanded its treatment of public
workpapers for greater access.
Recognition Justice
"...which requires an understanding of historic and ongoing inequalities and prescribes
efforts that seek to reconcile these inequalities."I6
Recognition justice entails"acknowledging historical injustices and ensuring that the transition [to
clean energy] does not further marginalize already vulnerable groups."I7
In incorporating recognition justice, the company through collaboration with advisory groups and
external parties seeks to understand and acknowledge differences, respect identity, ensure
participation and recognize systemic injustices, which can then be addressed via procedural,
restorative and distributional justice.
In addition to the effort of the Washington advisory groups, the IRP and the CEAP further the
success of recognition justice through the identification of Named Communities, multiple public
input processes, and through assessments such as the Non-Energy Impact Mapping in its
Conservation Potential Assessment."
15 Refer to Appendix C(Public Input Process)and Appendix M(Stakeholder Feedback Forms).
16 DOCKET UG-210755,Washington Utilities and Transportation Commission v. Cascade Natural Gas Corporation,
Final Order 09,p. 18.
17 U.S. Department of Energy, DOE P 120.1, ENERGY AND ENVIRONMENTAL JUSTICE POLICY, p.4,
11/26/2024.
" Refer to the "2025 CPA - Appendix E - WA Non-Energy Impact Mapping" as part of the CPA supplemental
materials posted on the website,which maps the accrual of NEIs to various groups of measures available to customers
consistent with WAC 480-100-620(13):https://www.pacificorp.com/energy/integrated-resource-plan/support.html
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PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Restorative Justice
"Which is using regulatory government organizations or other interventions to disrupt and
address distributional, recognitional, orprocedural injustices, and to correct them through
laws, rules,policies, orders, and practices. "19
Unlike the prevention-focused tenets of procedural,distributional and recognition justice, a central
feature of restorative justice is rectifying the injustices of the past. Restorative justice seeks to
address the negative impacts of energy production and consumption through proactive measures
that prioritize community involvement and restoration of balance.
For example, on a simple cost-basis it can be less expensive to locate disruptive transmission
projects to pass through vulnerable communities, creating a disproportionate burden laid upon
these communities. In the 2025 IRP, small scale renewable resources are open for selection during
capacity expansion optimization, allowing the model to weigh the balance of potentially higher
resource costs against the avoidance of large transmission projects, with an opportunity to also
account for the nonenergy benefits of local community resilience. The aforementioned addition of
non-price scoring metrics adds another link to restorative justice in downstream acquisition efforts.
PacifiCorp also provides funding to support assistance offerings to customers experiencing
financial hardships within the company's Washington service area. For example,the Low-Income
Bill Assistance (LIBA) program provides a discount to income eligible households year-round.
For another example,local agencies in Washington leverage PacifiCorp funding streams to provide
free weatherization services to income-qualifying homeowners and renters living in single-family
homes, mobile homes, or apartments. These offerings are presented to customers on the company
website alongside links to Project HELP and the Low-income Home Energy Assistance Program
(LIHEAP).20
In addition to remediation, key elements of restorative justice include:
• Community engagement:
Common to all tenets of energy justice, community engagement is a core principle
is actively involving vulnerable communities in discussions and decision-making
regarding new energy projects, ensuring their voices are heard and concerns
addressed.
• Transparency:
Energy justice cannot succeed without appropriate transparency, which supports
IRP public feedback and shapes the context of decision-making.
• Enhancing Grid Resilience and Reliability:
The concept of restorative justice involves accounting for current and historic
injustices related to existing energy systems and acting to remediate them. This
includes, for example, prioritization of grid hardening projects in areas subject to
more frequent and longer duration outages, or of greater climatological risk.
19 DOCKET UG-210755,Washington Utilities and Transportation Commission v. Cascade Natural Gas Corporation,
Final Order 09,p. 18.
20 See PacifiCorp's Bill payment assistance webpage for Washington: hLtps://www.pacificpower.net/my-
account/payments/bill-payment-assistance.html
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PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
The following sections describe how a long-run portfolio is optimized to meet CETA's clean
energy standards at least-cost, least-risk, while incorporating consideration for the equitable
distribution of benefits and reductions of burdens to highly impacted and vulnerable communities.
evelopmen
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.
Refer to Chapter 3 for an overview of environmental policy regulation,including Washington state
policies. Chapter 6 presents the base load forecast and existing resources represented in modeling.
Chapter 7 presents a complete list of proxy resource options available for endogenous selection.
Chapter 8 explains each step involved in the development and evaluation of resource portfolios.
Chapter 9 includes the preferred portfolio and list of specific resources selected to meet
Washington's compliance requirements and reliability needs.
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.
Resource Portfolio Development
As discussed in Chapter 8, PacifiCorp uses the PLEXOS long-term (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. Each portfolio is also evaluated in the short-term
(ST) model to establish system costs over the planning horizon. 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). Stochastic modeling is
also done using the ST model, and this process has been expanded to now include wind and solar
generation profiles, and energy efficiency profiles for weather-sensitive bundles, in addition to the
variables reflected in past IRPs. Appendix H (Stochastics) discusses the methodology for
developing the stochastic inputs for the 2025 IRP.
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.
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
Portfolio Integration and Resource Allocations
Since the filing of the 2021 IRP and inaugural CEIP, PacifiCorp has made strides in its modeling
process, particularly in regard to the consideration of multiple and competing state obligations.
The IRP process inherently represents a systemwide approach and produces a systemwide
preferred portfolio. In its inaugural CEIP, PacifiCorp layered on CETA compliance requirements
after an optimized portfolio was created for the system, inclusive of the social cost of greenhouse
gas (SCGHG) price policy. Since the filing of the 2021 IRP, more state-specific policies have
become considerations that the company must show are being met simultaneously.
The process of"portfolio integration" introduced in the 2025 IRP is a methodology under which
each state's set of requirements,obligations and resource needs is optimized for and then integrated
into a single portfolio of proxy resource selections. Every final integrated portfolio variant and
sensitivity,unless otherwise stated,reflects the optimized set of proxy resource selections to meet
each states' obligations.The 2025 IRP preferred portfolio of resources represents a set of resources
optimized to achieve CETA compliance as well as all other state requirements that PacifiCorp is
subject to. Refer to Chapter 8 for the details of the portfolio integration process. For Washington
customers, the base portfolio includes the SCGHG price policy assumption in the model runs and
in all resource decisions,and the final preferred portfolio reflects those selections. Finally,we also
show the preferred portfolio dispatched under SCGHG to capture energy-specific outcomes for
Washington customers, which are the basis for the clean energy interim targets depicted later in
this appendix.
Assumptions are made regarding cost-allocation of resources. In lieu of a multi jurisdictional
cost allocation protocol that extends past the 2020 Protocol (set to expire December 31, 2025),
all existing resources are assumed to be allocated(both in terms of costs and generation) in
accordance with the 2020 Protocol and Washington Inter-Jurisdictional Allocation Methodology
(WIJAM) indefinitely.21 In most cases, this means existing renewable resources are allocated to
Washington customers based on a forecast of their system-generation(SG) factor, which is
determined based on their relative jurisdictional load. In some instances, like for qualifying
facilities (QFs) existing resources are situs-allocated(100 percent)to Washington customers.
Washington also receives a different share of existing emitting resources that it participates in
(discussed in more detail in following sections). In regard to new proxy resource selections, it is
assumed that any new proxy resources selected to serve Washington need are situs allocated,
including both supply-side and demand-side resources.22 These resource allocation assumptions
underlie progress toward CETA clean energy targets, as explained in a later section.
Resource Adequacy
As described in 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
21 The 2020 Protocol was adopted by the Public Utility Commission of Oregon order no.20-024 on January 23,2020
(available online athlt2s://edocs.puc.state.or.us/efdocs/H"um1050haal6l935.pd ).
22 The only"proxy"resource selected in the 2025 IRP that is considered a system resource and is allocated based on
system generation factors is the Natrium nuclear demonstration project.
462

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
planning requirements within the LT model to account for shortfalls identified within the more
granular ST model.
Conservation Potential Assessment
New cost-effective energy efficiency measures and programs are among the new resource options
that are present in every portfolio described in the process above. These resources are first
identified through the development of a conservation potential assessment(CPA)which identifies
the magnitude and cost of all technically achievable energy savings opportunities in PacifiCorp's
service area over the next 20 years.
Several measures include quantified non energy impacts (NEI) netted against measure cost.
Examples include health benefits from avoided woodsmoke with installation of ductless heat
pumps,operations and maintenance cost savings with new lighting,and water savings for measures
which conserve water use as well as electricity use.2' For the past several IRP cycles, PacifiCorp
has contracted with Applied Energy Group (AEG) to conduct this assessment. A comprehensive
description of the study methodology, underlying assumptions, and results can be found on
PacifiCorp's website.24 Figure 0.2 shows cumulative achievable technical potential results from
the CPA for the Washington service area.
Fi ure 0.2—CPA Results for Washington: Cumulative Achievable Technical Potential
1,400
c 1,200 _
l7
� 1,000
800
an
c
600
a
Q 400 _
u 200
0 I _
2025 2027 2032 2042 2044
■ Residential ■Commercial ■ Industrial ■ Irrigation
The study results in nearly 30,000 individual efficiency measures which are then bundled into 27
groups for each of PacifiCorp's six states.
The output from the CPA serves as an input to the PLEXOS model which selects the optimal mix
of resources from the defined bundles to provide system adequacy in a least-cost, least-risk
manner. The conservation resources which are selected in the preferred portfolio become the cost-
effective conservation potential.
23See Volume II,Appendix E-CPA for details on NEI-measure mapping used in the CPA.
2'Available online at https://www.pacificorp.com/energ /y integrated-resource-plan/support.html
463

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Demand Response and Load Management Programs
Cost-effective demand response (DR) and load management resources are identified and selected
in a manner similar to conservation resources. The scope of the CPA also includes identification
of the technical potential for direct load control (DLC) demand response opportunities and for
potential new pricing programs. The methodology and all underlying assumptions and results for
these resources can also be found on PacifiCorp's website.25
DLC resources are differentiated by customer, technology, and duration. Sustained duration
resources are available for more than 20 minutes while short duration reflects load which can be
curtailed in greater quantity but for shorter duration such as for frequency response over 5-minute
increments where the customer is less likely to be impacted by the disruption.
The amount and cost of load curtailment or shift is characterized by customer type and type of end
use that is being controlled. The technical achievable potential is an input to the IRP model as a
resource option to be selected to meet system adequacy. DR selections by the model are cost
effective potential to be acquired as a part of the preferred portfolio.
Pricing programs include time-of-use rates, critical-peak pricing, and other behavioral pricing
tools. The third focus of the CPA is to quantify the technical potential and magnitude of demand
impacts possible through these pricing designs. The results are used to inform future rate design
concepts that are proposed with rate cases,but the IRP model is not used to determine the type and
amount of pricing programs as a part of the preferred portfolio.This is because all pricing programs
are designed to be cost effective to the system but may not be cost effective for the individual
customer to select. Therefore, setting targets for programs that only benefit the utility system but
not customers is not appropriate for the IRP but is analyzed and designed through other stakeholder
and regulatory processes.
Distributed Energy Resources
PacifiCorp provides customers in Washington access to an expanding number of distributed
energy resources (DER) offerings and correspondingly includes these in the company's planning
efforts. DERs include energy conservation, demand response, and load management (including
customer-sited batteries and transportation electrification (TE)), and distributed generation.
Planning for energy conservation and DR and load management is characterized in the CPA as
described above. DER program offerings are described in Appendix D.
PacifiCorp is continuing to expand its DR offerings in Washington and is adding new programs
and growing the amount of flex load capacity and use-cases represented across customer classes
and technologies. New programs include CoolKeeper, Wattsmart Batteries, and electric vehicle
DR. While total TE adoption is relatively low in PacifiCorp's service area compared to other parts
of Washington, it is still growing and the company offers a number of customer programs,
including grants, outreach and education, charging pilots for commercial and multifamily
customers, as well as public charging and highway corridor plans. PacifiCorp is currently
expanding its successful and innovative Wattsmart Battery program into Washington to promote
"Review PacifiCorp's 2025 CPA online at:ht!ps://www.pacificorp.com/energy/integrated-resource-
plan/support.html
464

PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
and incentivize the installation of individual batteries for system integration to facilitate grid
management.
New customer-sited generation is forecasted within the Distributed Generation Long-Term
Resource Assessment, which is included as Appendix L in the 2025 IRP. This assessment was
conducted by DNV for all states and for each distributed generation resource type including solar
photovoltaic(PV), small-scale wind,small-scale hydro,reciprocating engines,and micro-turbines.
The resource costs and state-specific policies and incentives are integrated into the forecast of
customer adoption of these resources across low, base, and high-case scenarios. The base case
results are netted against each state's load forecast.Washington distributed generation assumptions
are shown in Figure 0.3 and Figure 0.4.
Figure 0.3—Cumulative new distributed generation capacity installed by
scenario MW-AC ,Washington, 2018-2043
All Technologies
400
350
300
U
Q 250
a) 200
>
m 150
75
v 100
50 _
0
2022 Study Historical Low Base —High
465

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Figure 0.4—Cumulative new capacity installations by technology (MW-AC),
Washin ton base case, 2024-2043
400
350
Q 300
250
200
150
E
= 100
U
50
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
s— PV Only PV+Battery s—Wind s—Small Hydro
Reciprocating Engine s Micro Turbine — —2022
Transmission
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.
In support of the renewable resource additions identified for Washington in the 2025 preferred
portfolio, PacifiCorp has identified transmission options that will reinforce existing transmission
paths, allow for increased transfer capability, and will support the interconnection of new
renewables. A summary of PacifiCorp's identified transmission additions serving Washington is
shown in Table 0.1.
Table 0.1 —Transmission Selections Supporting Washington Resources' 2
Build
Export Import Interconnec Investment
2023 Cluster 1 Area 11:Willamette Valley 0 0 199 14 100% n/a n/a
2028 Cluster 1 Area 14:Summer Lake 400 400 400 111 100% Smmmer Lake Hemingway
2028 Cluster 1/2/3:Walla Walla 0 0 393 328 100% n/a n/a
2023 Serial/Cluster 1/2:Yakima 0 0 628 64 100% n/a n/a
2029 Cluster 2 Area 23:Willamette Valley 0 0 393 2 100% n/a n/a
2030 Cluster 2 Area 19:Summer Lake to Central Oregon 500 kV 1,500 1,500 670 1,283 100% Summer Lake Central OR
2030 Walla Walla-Yakima 230 kV 400 1 400 400 142 100% Walla Walla Yakima
2039 Walla Walla-Central Oregon 500 kV 1,500 1,500 670 1 1,463 1 100%1 Walla Walla I Central OR
Grand Total 3,800 3,800 3,753 1 3,406
'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.
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
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 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 preferred portfolio, integrates all system and state-specific resources into one 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 standards.
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 WIJAM for existing resources and generally assumed that these assumptions hold into
the future, in the absence of an agreed upon future allocation methodology.26 All new proxy
resources (renewable or non-emitting resources) that are determined within Washington's
jurisdictional base portfolio, are assumed to be acquired solely to meet Washington's needs and
are thus assumed to be situs-allocated. Resources acquired in other jurisdictional portfolios are
situs-allocated to those states. If there is a system proxy resource (non-emitting) selected, that
would be allocated to Washington customers on an SG basis. 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, nuclear and biodiesel
peakers.27 In summary,the resource allocation assumptions are:
26 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.
27 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".
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PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
1. Allocation of energy for all existing renewable resources (non-QFs), 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 benefits from Jim Bridger Units 1-2
after they convert to run on natural gas starting 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.
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. All existing
hydroelectric is presumed to be CETA-compliant, even where the company does not
currently get RECs for it.
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, 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 fossil generation (coal or gas-fueled resources) or unspecified market purchases
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 Utility Regulatory Policies Act of 1978 (PURPA).Zg 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
28
RCW I9.405.020(36)(a)
468

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
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.
rtfolio Resul
All portfolio results from the 2025 IRP are presented in Chapter 9. Table 9.3, specifically, shows
the Washington-allocated megawatts (MW) of resources selected in the preferred portfolio. Table
0.2 recasts the same information that is presented in Chapter 9, Table 9.3 but delineates which
incremental proxy resource selections for Washington are considered "situs" or 100 percent
allocated to Washington customers because they are selected only for Washington need (versus
Washington's share of a systemwide proxy resource). As Table 0.2 shows, all resource selections,
except for the single "nuclear" resource category, represent situs-allocated resources for
Washington customers. Table 9.3 also shows that up to 212 MW of the solar resources allocated
to Washington in 2030 could be accelerated to an earlier date.
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PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
470

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
Table 0.2 -Incremental Resource Additions for Washington Customers, by Resource Allocation Assumption
Ituremewal resource additions for Washington,by resource npe and pear
a acity,l\
Situs proxy resources 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
DS1f-Energy Efficiency 0 li 16 li 1' 18 18 i9 20 19 i9 15 13 12 11 11 10 8 280
DSM-Demand Response 0 15 2 2 - 8 - 6 1 1 1 - 1 - 14 51
Renewable Peaking - - - - - - - -
Renewable-Wind 5 149 313 7 87 to 44 9 0 94 12 5 - 24 758
Renewable-Utility Solar - - 56 45 423 45 60 101 56 3 - 0 0 139 26 3 - - 49 19 1,025
Renewable-Small Scale Solar - - - - - 0 - - 0
Renewable-Battery,<8 hour - - - 865 114 168 - - - - - - 129 67 7 12 - 5 - - 1,367
Renewable-Battery,24+hour - - - - - 238 3 3 4 3 4 4 4 4 4 4 4 5 5 5 5 298
System-shared prom resources
Nuclear 32 32
471

PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
472

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
In the near-term,the 2025 IRP preferred portfolio selects 254 megawatts (MW) of new renewable
resources situs to Washington customers, expected to come online by the end of 2029, including
153 MW of wind and 101 MW of utility-scale solar. In this same time frame, almost 1 gigawatt
(GW) of batteries (shorter-duration batteries, under 8 hours) are also selected to meet
Washington's resource adequacy and capacity needs. The portfolio also includes selections of 44
MW of additional energy efficiency selections and 17 MW of demand response.
Between 2030 and 2035, another 1,095 MW of renewable resources are selected. This includes
407 MW of wind and 688 of solar.An additional 168 MW of shorter-duration batteries are selected
plus 255 of longer duration batteries(24 hours and longer).Over these years,the model also selects
an additional I I I MW of energy efficiency and just 2 MW of demand response resources.
Over the entire 21-year planning horizon, through 2045 when CETA's zero-greenhouse gas
emitting standard begins, the preferred portfolio selects around 1.7 GW of new renewable
resources, over half of which is utility-scale solar, and the rest is wind. The portfolio also includes
significant battery selections totaling 1.6 GW. Total energy efficiency selections equate to 280
MW and demand-response is 51 MW.
The 10-year action plan to make progress towards CETA standards through the end of 2035
includes not only over 1 GW of new renewable resources,but significant storage capacity to help
address Washington customer's capacity needs, totaling just over 1,400 MW. The company will
continue to rely on conservation and demand-response as appropriate and efficient, which will be
refined in downstream processes as explained in later sections.
Washington Sensitivities
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." Because the base forecast
includes climate change, all of the IRP analysis reflects impacts related to climate change and a
separate sensitivity to include these impacts is not necessary. Refer to Appendix A for additional
regarding how climate change is incorporated into the base load forecast.
The Alternative Lowest Reasonable Cost portfolio, described in Volume I , Chapter 8, is defined
to be the portfolio of resources that would occur,but for CETA clean energy obligations.29 This is
a fully integrated portfolio that optimizes resource selections across all states' requirements but
does not necessarily meet CETA clean energy standards starting in 2030. The portfolio is still
determined under SCGHG for Washington resource selection.
Figure 0.5 presents the cumulative (at left) and incremental (at right) portfolio changes between
the alternative lowest reasonable cost and preferred portfolios. A positive value indicates an
increase in resources and a negative value indicates a decrease when a resource is reduced or
eliminated. The only significant change is a 780 MW reduction in renewable wind resources
included in the alternative lowest reasonable cost portfolio. This shows that a large portion of the
renewable wind resources included in the early window of the preferred portfolio is driven by the
need to comply with CETA clean energy obligations.
29 WAC 480-100-620(10)(a).
473

PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
Figure 0.5—Cumulative and Incremental Portfolio Changes,
Alternative Lowest Reasonable Cost less Preferred Portfolio
Cumulative Changes Incremental Portfolio Changes
Ioo 100
0 --- -------- ------ ° — — —
(100) (100)
(200) (200)
(300) (300)
(400) u(400)
(600) (600)
(700) (700)
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C—erbd G. Hydrogen Swage Pak. R­ble Pealing .Cm WGa Hydmga Swage Pak. Re.eu•able Peaking
The Maximum Customer Benefit portfolio,described in detail in Chapter 8,prioritizes the addition
of demand response and energy efficiency in Washington and removes Yakima and Walla Walla
transmission options. As a result, over 1 GW of small-scale renewables are added to Washington
as a replacement for utility-scale options.
Figure 0.6 presents the cumulative (at left) and incremental (at right) portfolio changes between
the maximum customer benefit and preferred portfolios. A positive value indicates an increase in
resources and a negative value indicates a decrease when a resource is reduced or eliminated. The
maximum customer benefit portfolio includes 172 MW of energy efficiency incremental to the
preferred portfolio and a reduction of 801 MW of wind resources. Not shown in Figure 0.6 is the
large shift from utility-scale solar to small-scale solar. The maximum customer benefit portfolio
includes 1,429 MW of incremental small-scale solar and a reduction of 1,429 MW of utility-scale
solar in Walla Walla and Yakima.
Figure 0.6—Cumulative and Incremental Portfolio Changes,
Maximum Customer Benefit less Preferred Portfolio
Cumulative Changes Incremental Portfolio Changes
400 300
200
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•Cemrorbd Ga H)d g-Swage Pak. R­b1ePeaking .Cm"dGas HvdmgeoSwage Peak. Raeaable Peaking
474

PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
Lean Energy Targets
RCW 19.405.040 and 19.405.050 set the 2025, 2030, and 2045 targets for electric utilities in
Washington to meet. Specifically, utilities must show that by December 31, 2025, all coal-fired
resources have 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 or non-emitting.
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
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, subject to conditions outlined in CETA.
The 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 0.7.
475

PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
Figure 0.7 -- Clean Energy Interim Targets for Washington Customers, 2025 through 2045
Clean Energy Targets
CMI.
250%
0 200%
N
a 12029 4-year
aG 147%152%152%153%150%150%155%
0 150% 136%136°h 140%140%
m 125%130°k
110%111%119%
b 100°a
a
100%Achieved
50% 46%
31% 33% 31% 34%
/ � � 111
'gam 0 0 0 0 101, 0 10, '01 '0,� Vq l '01
■ Neutrality Targets through2030 ■ 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. 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 0.3 reports updated interim targets for the Company's second CEIP planning period for the
years 2026-2029, reported as annual megawatt hours of energy rather than as percentages.
476

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
Table 0.3 —Clean energy interim targets for Washingon customers 2026-2029
2026 2027 2028 2029 Total
Retail Electric Sales
(Adjusted)' 4,023,917 4,160,614 4,297,349 4,268,516 16,750,396
Projected Renewable and
Nonernitting Energy 1,310,620 1,306,196 1,443,155 1,978,179 6,038,150
Net Retail Sales 2,713,297 2,854,418 2,854,194 2,290,338 10,712,246
Target Percentage 1 33% 1 31% 34% 1 46%
Interim Clean Energy Target 1 1,310,620 1 1,306,196 15443,155 1,978,179 6,038,150
'Retail electric sales less qualifying facilities generation
While the 2025 IRP and this CEAP must include a 10-year clean energy action plan, and the
preferred portfolio presents a pathway to compliance with CETA's 2030 energy standards,the IRP
is a steppingstone to the 2025 CEIP filing later this year. Refinements and additional analysis
completed as part of the CEIP process might lead to changes in the portfolio results for
Washington. The clean energy interim targets present here are used to verify and assess that
compliance is being achieved and planned for in the IRP process,but do not at this stage represent
final targets for the next CEIP planning period.Near-term interim targets,and other specific targets
and actions (for demand-side management resources), will be included in the 2025 CEIP.
Additionally, while the near-term interim targets do not show a drastic increase in the acquisition
of new clean energy resources before 2029, as compared to between 2029 and 2030,this a product
of the modeling assumptions. CETA targets are binding as of 2030, and unless resources prices
are expected to be significantly cheaper in the near-term, the model generally finds a just-in-time
approach to be least-cost. However,the company recognizes the potential risks of this strategy and
is open to procuring resources in amounts higher than what is indicated in this IRP action plan if
resources are economic and available to come online before the end of 2029. The latest completed
cluster study results show potential of over 1 GW of non-emitting resources in the queue and
located in Washington that could readily serve our service area, some of which have commercial
operation dates before the end of 2028. These resources include solar, solar and storage, a battery
storage, and a wind project.
Customer Benefits
Washington statute RCW 19.405.040(8) states that
"an electric utility must, consistent with the requirements of RCW 19.280.030 and
19.405.140, ensure that all customers are benefiting from the transition to clean energy:
Through the equitable distribution of energy and nonenergy benefits and reduction of
burdens to vulnerable populations and highly impacted communities; long-term and short-
term public health and environmental benefits and reduction of costs and risks; and energy
security and resiliency."
PacifiCorp presented its initial development of a customer benefit indicators (CBI) framework in
its inaguaral 2021 CEIP by identifying three key components to be answered: 1) identify key
communities who are experiencing disprorpationate challenges, 2)pinpoint chalenges that can be
reduced or improved by the utility and clean energy resources, and 3) develop metrics to track
477

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
progress relative to those challenges and benefits." With each planning cycle, PacifiCorp has
continued to refine and expand upond its initial CBI framework,and continues to do.Most notably,
the company has redefined its definition and measurement of vulnerable populations and has added
several CBIs and metrics to its framework since 2021. The most current CBI framework,reflective
of these iterative updates and improvements, and in response to settlement conditions from the
Revised 2021 CEIP, is depicted in the section that follows.
Customer Benefit Indicators
Table 0.4 provides PacifiCorp's current customer benefit indicators (CBIs) framework and
associated metrics.
Table 0.4.— PacifiCorp's CBI Framework
No. CBI Benefit Categories Metric(s)
Increase culturally a. Number of topics addressed in outreach in
and linguistically non-English languages
responsive outreach b.Number of impressions from non-English
and program outreach
communication Reduction of c. Percentage of responses to surveys in
I including increased burdens Spanish
availability of Non-energy benefits grams for which
translation services d.Number of pro
for all PacifiCorp PacifiCorp provides translation services or
Programs, including translated material
credit, collection, e.Number of languages PacifiCorp uses for
and payment. translated material
a.Number of workshops on energy related
Increase programs
community-focused Non-energy benefits b. Headcount of staff supporting program
2 Reduction of burden delivery in Washington who are women,
efforts and Public health minorities, and/or can show disadvantage[a]
investments
c.Number of public charging stations in
Named Communities
a.Number and percentage of
households/businesses, including Named
Communities,who participate in company
energy/efficient energy/efficiency programs
Increase b. Dollar value of energy efficiency
participation in Cost reduction expenditures[b]
company energy c.Number and percentage of households
3 and efficiency Reduction of burden Non-energy benefits that participate in billing assistance programs
programs and d.Number and percentage of
billing assistance Energy benefits households/businesses who participate/enroll
programs in demand response,load management, and
behavioral programs
e. Dollar value of demand response, load
management, and behavioral programs
expenditures
3o Pg.27 PacifiCorp's 2021 Revised CEIP filed in docket UE-210829 is available online at:
hLtps://apiproxy.utc.wa.,gov/cases/GetDocument?docID=277&year--2021&docketNumber=210829
478

PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
No. W CBI Benefit Categories Metrics)
Increase culturally a. Number of topics addressed in outreach in
and linguistically non-English languages
responsive outreach b.Number of impressions from non-English
and program outreach
communication Reduction of c.Percentage of responses to surveys in
I including increased burdens Spanish
availability of Non-energybenefits programs
translation services d.Number of ro rams for which
for all PacifiCorp PacifiCorp provides translation services or
Programs,including translated material
credit, collection, e.Number of languages PacifiCorp uses for
and payment. translated material
f.Number of residential appliances and
equipment rebates provided to Named
Community customers where known
g.Number of residential rebates provided to
customers residing in rental units
h. Investment and/or energy efficiency
savings in rental residential housing stock
Increase efficiency a.Number of households and small
of housing stock businesses that participate in company
4 and small Energy benefits ener /e ciency programs
businesses, b. Dollar value of energy efficiency
including low- expenditures[b]
income housing
Increase renewable a.Amount of renewables/non-emitting
resources servingWashington
5 energy resources and reduce Environmental b. Amount of Washington allocated
emissions greenhouse gas emission from Washington
allocated resources
a.Number and percent of customers
experiencing high energy burden by: highly
Decrease impacted communities,vulnerable populations,
households Cost Reduction of low-income bill assistance(LIBA) and Low-
6 experiencing high burden Income Weatherization participants, and other
energy burden residential customers; and average excess
burden per household. High energy burden is
defined as greater than or equal to six percent
of household annual income.
a.Number and percent of households using
Improve indoor air Public health Food as primary or secondary heating
7 quality Non-energy benefits b. Number and percent of non-electric to
electric conversions for Low-Income
Weatherization program
Reduce frequency Energy resiliency a. SAIDI, SAIFI, CAIDI and CEMIE'] scores
8 and duration of Risk reduction (rolling 7-year average) at area level including
energy outages Energy benefits and excluding major events
479

PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
No. Benefit Categories Metrics
Increase culturally a.Number of topics addressed in outreach in
and linguistically non-English languages
responsive outreach b.Number of impressions from non-English
and program outreach
communication Reduction of c.Percentage of responses to surveys in
I including increased burdens Spanish
availability of Non-energy benefits grams for which
translation services d.Number of pro
for all PacifiCorp PacifiCorp provides translation services or
Programs, including translated material
credit, collection, e.Number of languages PacifiCorp uses for
and payment. translated material
a.Number and percentage of residential
electric disconnections for nonpayment by
month,measured by location and demographic
information(zip code/census tract.known low-
Reduce residential income(KLI) customers,Vulnerable
9 customer Energy security Populations (where known),Highly Impacted
disconnections Communities, and for all customers in total)
b. Residential arrearages as reported
pursuant to Commission Order 04(Appendix
A Third Revised Term Sheet, Section J,Part 8
a-c
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
No. W CBI Benefit Categories Metrics)
Increase culturally a. Number of topics addressed in outreach in
and linguistically non-English languages
responsive outreach b.Number of impressions from non-English
and program outreach
communication Reduction of c.Percentage of responses to surveys in
1 including increased burdens Spanish
availability of Non-energybenefits programs
translation services d.Number of ro rams for which
for all PacifiCorp PacifiCorp provides translation services or
Programs,including translated material
credit, collection, e.Number of languages PacifiCorp uses for
and payment. translated material
a. Total MWh of distributed energy resources
5 MW and under,where benefits and control
of resources accrue to members of Named
Communities
b. Total MWh of energy storage resources 5
MW and under,where benefits and control of
the resource accrue to members of Named
Communities
c.Number(i.e., sites,projects, and/or
households) of distributed renewable
generation resources and energy storage
Increase Named resources,where benefits and control of the
10 Community clean Energy benefits resource accrue to members of Named
energy Communities,including
storage/backup/emergency powered centers for
emergencies.
d. Total MWh of energy savings from Energy
Efficiency programs,where benefits and
control of the savings accrue to members of
Named Communities
e. Where known, for a),b), c), and d) above,
PacifiCorp will specify whether the Named
Community resources are highly impacted
communities (HIC) and/or vulnerable
population and KLI
[a]In this metric, program delivery is defined as related to energy efficiency programs, with exception to the low-
income weatherization program.
[b]Energy efficiency expenditures include customer, partner, and direct install incentive payments and exclude all
other administrative or program costs.
[c] System Average Interruption Duration Index (SAIDI), System Average Interruption Frequency Index (SAIFI),
Customer Average Interruption Duration Index(CAIDI),Customers Experiencing Multiple Interruptions(CEMI).
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PACIFICORP—2025 IRP APPENDIX O—WASHINGTON CLEAN ENERGY ACTION PLAN
Non-Energy Benefit and Impacts
Since the 2021 IRP and inaugural 2021 CEIP, PacifiCorp has been expanding the ways it
incorporates NEIs into its program planning. One key enhancement in the 2025 IRP is PacifiCorp's
use of measure-specific NEI results rather than a flat proxy adder. The measure-specific results are
provided by DNV who contracted with PacifiCorp to conduct a detailed and comprehensive NEI
assessment. The company has shared out this research to stakeholders through DSM Advisory
Group meetings and has leveraged these inputs in the updated CPA.31 Another enhancement has
been to bring the discussion of NEIs into the context of the Biennial Conservation Plan (BCP) in
conjunction with the DSM Advisory Group.Additionally,for demand response,a literature review
was conducted to determine if there were any program-specific NEIs that could be leveraged. Since
no quantitative values were found in the literature review,PacifiCorp chose to include a 10%adder
to approximate NEI impacts for demand response. Moving forward, PacifiCorp plans to continue
conducting research on NEIs.
Several of the CBIs identified in the above CBI framework are intended to capture some form of
non-energy benefits or impacts, as described in the third column of Table 0.4. For example, CBIs
1, 2, 3 and 7 are intended to capture several different dimensions of potential NEIs. These CBIs
continue to be tracked and applied to appropriate business and program decisions.
Identifying Vulnerable Populations
Consistent with the settlement agreement reached in the 2021 CEIP,32 PacifiCorp met with a
combination of Washington interested parties and advisory group members in three workshops to
review and improve the company's approach to identifying and tracking vulnerable populations.
These workshops also considered multiple vulnerability factors that were set forth in Condition 14
of the settlement agreement.
The first of these workshops occurred in June 2024,which discussed Condition 14,the company's
process of identifying and tracking vulnerable populations and highlighted peer utility approaches
to identifying and tracking vulnerable populations.
The second vulnerable population workshop unveiled a modified vulnerable population
geographic approach, which incorporated vulnerable population criteria as provided by Equity
Advisory Group input and included settlement vulnerability factors.
The third vulnerable population workshop incorporated feedback received from the second
vulnerable population workshop into the modified vulnerable population geographic methodology,
31 Refer to the "2025 CPA - Appendix E - WA Non-Energy Impact Mapping" as part of the CPA supplemental
materials posted on the website,which maps the accrual of NEIs to various groups of measures available to customers
consistent with WAC 480-100-620(13):https://www.pacificorp.com/energy/integrated-resource-plan/support.html
12The Washington Utilities and Transportation Commission by order 06 in docket UE-2109829 approved the Full
Multi-Parry Settlement Agreement and approved PacifiCorp's Revised 2021 CEIP,subject to the conditions in the
settlement agreement.Available online at:
hLtps://apiproxy.utc.wa.,gov/cases/GetDocument?docID=592&year--2021&docketNumber=210829
482

PACIFICORP—2025 IRP APPENDIX 0—WASHINGTON CLEAN ENERGY ACTION PLAN
which included the addition of several new vulnerability criteria. The modified vulnerable
population methodology was adopted by the company in January 2025.33
The company's modified vulnerable population geographic methodology replicates the
Washington Department of Health (WDOH) —Highly Impacted Community (HIC) methodology
and uses a percentile ranking approach for the census tracts located within Pacific Power's
Washington service area. Unlike WDOH, Pacific Power's vulnerable population geographic
methodology uses a total of 38 criteria to determine if a census tract is vulnerable, rather than the
19 criteria used by WDOH.
The company's newly adopted vulnerable population geographic methodology results in 36 out of
the total 61 census tracts in the Washington service area as being considered vulnerable, whereas
the WDOH HIC approach results in a total of 20 census tracts being vulnerable. There is an overlap
of 19 census tracts that are considered vulnerable in both methodologies, resulting, a total of 37
census tracts in the Washington service area are now considered vulnerable when either
methodology is applied.
CETA requires utilities to pursue all cost-effective, reliable, and feasible conservation and
efficiency resources, and demand response; maintain and protect the safety, reliable operation,
and balancing of the electric system; and ensure that all customers are benefiting from the
transition to clean energy through the equitable distribution of energy and nonenergy benefits
and reduction of burdens to vulnerable populations and highly impacted communities; long-term
and short-term public health and environmental benefits and reduction of costs and risks; and
energy security and resiliency.
Supply-side
PacifiCorp will issue, as supported by the 2025 IRP and CEAP, a Request for Proposals (RFP) to
procure resources aligned with the 2025 IRP preferred portfolio and in compliance with
Washington laws, regulations and obligations that can achieve commercial operations by the end
of December 2029. The company is also refining and expanding its use of a non-price scoring
methodology to consider energy equity and relevant CBIs in its valuation and scoring of bids.34
Demand-side
Energy Efficiency Actions
CETA requires that the utility set a four-year conservation target for the current CEIP planning
period covering years 2026 through 2029. The 2025 IRP CETA-compliant portfolio, inclusive of
all Washington requirements, identified cost-effective, reliable, and feasible resources for
"The final vulnerable populations methodology was summarized and presented in a public CEIP meeting on
January 29,2025,meeting materials including the slides,notes and a recording can be found online at
https://www.pacificpower.net/community/washington-clean-energy-transformation-act-equity.html.
34 Pacific Power provided an introduction to the concepts of energy justice in its RFP process at a CEIP engagement
meeting on March 25,2025.The company will continue to refine this methodology and seek input and feedback from
its advisory group members and other interested parties.
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PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
informing the end-use efficiency portion of Washington's 2026-2027 Energy Independence Act
(EIA) conservation target. The actual targets will be documented in the 2026-2027 Biennial
Conservation Plan. These 2026-2027 targets will be included in the 2026-2029 Clean Energy
Implementation Plan and the targets for 2028-2029 will initially be the same as for years 2026-
2027 until the 2028-2029 Biennial Conservation Plan is complete and can provide an update to
the outer year targets. PacifiCorp will also revisit prior CEIP energy efficiency utility actions to
consider updates to the methodology for vulnerable populations and its application.
Demand Response Actions
PacifiCorp will also use the 2025 IRP CETA-compliant portfolio as the starting point to determine
the 2026-2029 target for its demand response portfolio. The final target may be modified from the
IRP results based on PacifiCorp's internal assessment of potential growth by individual programs,
and consultation with program administrators.
PacifiCorp has been in the process of substantially revising and expanding its portfolio of demand
response programs in Washington going into 2025. PacifiCorp continues to implement its plan in
the 2022-2025 CEIP through the launch of three new residential programs. At the same time, the
company has been leveraging lessons learned from implementation in 2023 and 2024 to improve
the overall performance of existing programs. In addition to these actions,PacifiCorp will take the
following steps to inform the specific targets for demand response to be peresnted in the 2026-
2029 CEIP:
• Establish 2026-2029 demand response target based on the final 2025 IRP CETA-compliant
portfolio, and individual program forecasts
• Estimate impact to date and likely future impact of planned and existing programs on HICs
and vulnerable populations
• Review individual programs to consider potential additional actions to increase delivery of
program benefits to named communities
Additional information regarding PacifiCorp's near-term actions,both incorporating these supply-
side and demand-side specific actions and broader actions to support community engagement,CBI
development, and other regulatory requirements are described in the final section in this appendix.
Public Participation Plid
PacifiCorp will file its next CEIP Public Participation Plan (PPP) to the Washington Utilities and
Transportation Commission on or before May 1, 2025. The PPP is a document that provides
information on the various tools and tactics the company has developed, or is in the process of
developing, for its public engagement spaces, utilizing feedback captured through its various
public engagement channels and feedback tracker. PacifiCorp's public participation strategy for
the 2025 CEIP will continue to build upon the following four pillars that support robust and
inclusive participation: (1) Engaging members of the public with appropriate outreach, methods,
timing, and language considerations; (2) Addressing barriers to participation; (3) Making data
accessible and available to members of the public and CEIP interested parties; and (4)
Incorporating leamings from existing advisory groups.
PacifiCorp takes pride in being able to offer a robust menu of stakeholder engagement
opportunities through its various meeting spaces. Each meeting space is unique in its design,group
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PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
goals, target audience and the prioritization of topics. This ensures there is wide coverage among
groups and topics and that PacifiCorp can offer an engagement option for all. Meeting spaces are
open to all, drawing a wide array of audience members from Washington-interested parties,
community-based organization representatives to members of the general public. Within each
space, PacifiCorp strives to create a safe atmosphere where all participants can engage in
constructive dialogue, ask questions, and provide feedback. Participants have the opportunity to
learn about different clean energy implementation plan topics and information and can expect
various opportunities and methods to collaborate throughout the year. PacifiCorp's engagement
meeting spaces support an engagement ecosystem that offers an option for each type of participant
so that they may engage with the company when and where it makes sense for them to do so.
PacifiCorp will continue to adapt its CEIP public participation process to ensure that it is open,
transparent, and accessible. The company will further embrace inclusive design and aim for
communication with interested persons to be proactive and easy to understand.
Action P1
Table 0.5 describes actions relevant to PacifiCorp's Washington Clean Energy Action Plan is a
format consistent with the broader systemwide action plan presented in Chapter 10 (Action Plan).
Each action item is categorized and described in a manner that can be tracked from one filing to
the next.
Table 0.5—Washington Clean Energy Action Plan Matrix
Action Item Existing Resource Actions
System Action Plan Items:
la • Refer to Chapter 10 (Action Plan) for general action items relevant to
the 2025 IRP.
New Resource Actions
2025 Washington-situs REP:
• PacifiCorp will issue, as supported by the 2025 IRP and CEAP, a
Request for Proposals (RFP)to procure resources aligned with the
2025 IRP preferred portfolio and in compliance with Washington
laws, regulations and obligations that can achieve commercial
2a operations by the end of December 2029.
Transmission:
• PacifiCorp will also continue to analyze and pursue transmission
projects for Washington, as appropriate, to support resources needed
for serving Washington load, reliability, and meeting CETA
objectives.
Demand-Side Management Actions
Energy Efficiency
• Pacific Power will submit the 2026-2027 Biennial Conservation Plan
(BCP)by November 1, 2025.
3a • Pacific Power will include 2026-2029 energy efficiency targets in the
2025 CEIP, in addition to revisiting energy efficiency utility actions to
consider updates such as to the methodology for capturing vulnerable
populations.
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PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
Demand Response
• Establish 2026-2029 demand response target based on the final 2025
IRP CETA-compliant portfolio and individual program forecasts
3b • Estimate impact-to-date and likely future impacts of planned and
existing programs on HICs and vulnerable populations
• Review individual programs to consider potential additional actions to
increase delivery of program benefits to named communities
Community Engagement
Public Participation Plan
• Pacific Power will file its next CEIP Public Participation Plan on or
4a before May I of 2025. The Public Participation Plan provides an update
on and forward look of Pacific Power's public participation engagement
activities in Washington.
Equity Advisory Group
• PacifiCorp streamlined the number of Equity Advisory Group (EAG)
meetings to complement the menu of Clean Energy Implementation
Plan meetings which will be available in 2025. The company
proposed a schedule which includes 9 sessions of Equity Advisory
Group (EAG), 3 of which are combined meetings with other
Washington advisory groups.
• Annual May One-on-Ones
o Build upon existing relational partnerships; meeting the Equity
Advisory Group members where they are in community
o Share updates and resources with one another
o Gain exposure to the different cultures within Pacific Power's
service area and through authentic encounters, identify
emerging barriers and opportunities to community energy
program participation
4b • Tooling and retooling advisory group members for increased
participation and greater clarity.
• Creating a repository of 101 level topic/concept presentations and
recordings.
• Design and deliver presentations which support and foster meaningful
engagement and shared understanding.
• Filling in the picture; bring in guest presenters, such as utility
commission staff to deliver Regulatory 101 presentations.
• Grow membership in the advisory group to balance representation from
service districts and communities.
• Collaborate with the communications team to improve web presence
and usability of the Pacific Power website
• The advisory group members will have opportunity to contribute
perspective and guidance on elements of the following reports and
filings:
o PacifiCorp 2025 Clean Energy Implementation Plan
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PACIFICORP-2025 IRP APPENDIX O-WASHINGTON CLEAN ENERGY ACTION PLAN
o PacifiCorp 2025 Public Participation Plan
o PacifiCorp Integrated Resource Plan through the Public Input
Process
o PacifiCorp Conservation Potential Assessment for 2025-2044
Community Benefit Indicators
• Pacific Power has proposed two new CBI metrics: S02 and NOx and
5a will continue to solicit input and feedback from its advisory groups
and interested parties and finalize the proposed metrics
• Pacific Power will continue to make progress on its CBI framework,
identifying any refinements to its current CBIs and proposed metrics
5b to work towards establishing a baseline and a transparent framework
to apply to resource procurement, planning, and other business
decisions, as relevant.
Regulatory Actions
2025 Clean Energy Implementation Plan
• Pacific Power will file its 2025 Clean Energy Implementation Plan
6a (CEIP)with the Washington Utilities and Transportation Commission
on October 01, 2025, with a draft provided for interested parties to
review and submit comments 45 days before filing.
Other CETA-related filings
6b • Pacific Power will file its 2025 CEIP progress report on July 1, 2025,
reporting on progress made towards its clean energy targets.
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PACIFICORP-2025 IRP APPENDIX 0-WASHINGTON CLEAN ENERGY ACTION PLAN
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
APPENDIX P - OREGON CLEAN ENERGY UPDATE
Introduction
PacifiCorp's 2025 Integrated Resource Plan presents a fully compliant approach to meeting
Oregon obligations through long-term resource planning, near-term actions, and ongoing
evaluation and execution. This appendix presents model outcomes, narratives, and reports on
progress to bridge the evolution from 2025 IRP systemwide analytics to the upcoming 2025 Clean
Energy Plan.
In the biannually filed IRP, the company calculates an optimal resource mix for Oregon
compliance under HB 2021, evaluating risks, costs, benefits, and continual progress against
targets. In years where a full IRP is not filed, the company evaluates its planning and progress
toward targets through an IRP Update. Both reports present annual positions for utility and small-
scale resources, energy efficiency and demand response, and project the least-cost, least-risk
strategy for the achievement of clean energy targets.
The optimization modeling used by PacifiCorp incorporates all state requirements,including those
associated with HB 2021, evaluating the type, size, location, and timing of resources on a proxy
basis.
In Oregon's share of the 2025 IRP preferred portfolio, significant renewable additions of 6,499
MW, of which 1,147 MW are projected to be small-scale or community-based renewable energy,
are supported by 3,819 MW of energy storage. This promotes the achievement of clean energy
targets, which in combination with PacifiCorp's large, interconnected grid and operational
excellence serves to underscore reliability and resiliency.
HB 202I's influence on the preferred portfolio lowers cumulative system emissions by nearly 100
million metric tons between 2030 and 2045,demonstrating planning effectiveness.With more than
two thousand model runs supporting 7 variants and 12 sensitivities, PacificCorp's 2025 IRP
preferred portfolio, and particularly Oregon's share of that portfolio, confidently demonstrates
progress toward"an affordable,reliable and clean electric system."
Key findings
1. Oregon will require 763 MW of new renewable resources, 381 MW of shorter-duration
batteries, and over 300 MW of demand-side management resources by the end of 2029.
2. By 2030, PacifiCorp's small-scale renewable resource obligation amounts to 675 MW of
small-scale renewable capacity.
3. By 2045, Oregon's share of the preferred portfolio includes almost 6.5 GW of new
renewable resources to meet its energy, capacity, and clean energy needs. This includes
over I GW of small-scale solar resources, and an additional 3.8 GW of batteries, over 2.6
GW of which is selected as longer-duration storage. Additionally, the preferred portfolio
includes 40 MW of renewable peaking resources added after 2040.
4. Oregon-allocated greenhouse gas emission fall 91.5 percent from baseline levels by 2030,
99.9 percent by 2035, and 100 percent by 2040.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Background
In 2021,Governor Brown signed House Bill 2021 (HB 2021)into law.HB 2021 defined ambitious
greenhouse gas reduction requirements for electric providers, while also directing utilities to
consider how to maximize additional benefits to communities. HB 2021 requires retail electricity
providers to reduce greenhouse gas emissions associated with electricity sold to Oregon consumers
by: 80%by 2030; 90%by 2035; and 100%by 2040.I
HB 2021 lays the groundwork for the transition to a clean,reliable, and sustainable energy future,
but also seeks to protect and support communities who are the most vulnerable and highly
impacted by the energy transition.
In service to these emissions reduction requirements, an electric company must develop a clean
energy plan (CEP) for meeting relevant targets concurrent with the development of its integrated
resource plan. Fundamental to PacifiCorp's approach in building a bridge from the IRP to the CEP
filing are utility and small-scale resource planning, distribution system planning, and community
emphasis. Community emphasis includes community benefit indicators, community-based
renewable energy, and engagement with community members through advisory groups.
The 2025 IRP presents an opportunity for stakeholders to engage with the portfolio results and
offer potential refinements to the path towards these clean energy targets. This Appendix P offers
a focused discussion around how the preferred portfolio is developed to comply with all Oregon
obligations, and to add insight into other activities that support the company's progress towards
and development of its clean energy targets.
Consistent with Order No. 25-090, Pacific Power will subsequently file its 2025 Clean Energy
Plan with the Public Utility Commission of Oregon on June 30, 2025. The 2025 CEP is expected
to align with modeling inputs, assumptions and results presented in this IRP, but will expand on
these analyses with additional narrative, analytics, and action plans. While the 2025 IRP preferred
portfolio presents a path to comply with HB 2021 emissions standards, this portfolio is still a
representation based on proxy resources and modeling assumptions. Additional information or
considerations could impact the timing and pace of resource selection and greenhouse gas
reduction over the next two decades. The 2025 CEP will include additional elements regarding
Oregon-specific portfolio sensitivities, cost impacts to Oregon customers, and other elements
considered under HB 2021.
The sections below discuss PacifiCorp's portfolio assumptions and results for Oregon-specific
resources, including small-scale renewables, greenhouse gas emissions, and transmission
resources, and detail additional actions and resources necessary to PacifiCorp's operations and
resource options in the state, including demand-side management, community-based renewable
energy, distribution system planning, and transportation electrification. The document concludes
with a discussion of PacifiCorp's community and stakeholder engagement processes, community
benefit indicators, and action plan to implement the findings from the 2025 IRP.
' ORS 469A.410.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Portfolio Assumptions
The 2025 IRP process serves as the basis for developing and identifying a long-run portfolio and
near-term action plan that will put the company on a path towards compliance with HB 2021
greenhouse gas reduction targets,the small-scale renewable target, and to ensure reliable and cost-
effective service for customers.
Refer to Volume I, Chapter 3 for an overview of environmental policy regulation, including
Oregon state policies. Chapter 6 presents the base load forecast and existing resources represented
in modeling. Chapter 7 presents a complete list of proxy resource options available for endogenous
selection. Chapter 8 explains each step involved in the development and evaluation of resource
portfolios. Chapter 9 includes the preferred portfolio and list of specific resources selected to meet
Oregon's compliance requirements and reliability needs.
Portfolio Integration and Resource Allocations
Since the filing of the 2023 IRP and CEP, PacifiCorp has made strides in its modeling process,
particularly regarding the consideration of multiple and competing state obligations. The IRP
process inherently represents a systemwide approach and produces a systemwide preferred
portfolio. In its inaugural CEP, PacifiCorp layered on HB 2021 considerations after a systemwide
optimized portfolio was created, which led to concerns that HB 2021 compliance was not
appropriately analyzed and could not be complied with in addition to other state policies.
The process of"portfolio integration"in the 2025 IRP is a methodology that optimizes each state's
requirements, obligations, and resource needs, and then integrates each into a single portfolio of
proxy resource selections. Every final integrated portfolio variant and sensitivity,unless otherwise
stated,reflects the optimized set of proxy resource selections to meet all state obligations.Relevant
here, the 2025 IRP preferred portfolio of resources represents a set of resources optimized to
achieve HB 2021 compliance, as well as all other state requirements that PacifiCorp is subject to.
Refer to Volume I, Chapter 8 for additional details of this portfolio integration process.
It is important to note that the 2025 IRP includes assumptions regarding resource cost-allocation.
In lieu of a multi jurisdictional cost allocation protocol that extends past the 2020 Protocol (set to
expire December 31, 2025), all existing resources are assumed to be allocated(both in terms of
costs and generation) in accordance with the 2020 Protocol indefinitely.2 In most cases, this
means existing resources are allocated to Oregon customers based on a forecast of their system-
generation(SG) factor, which is determined based on their relative jurisdictional load. In some
instances, like for qualifying facilities (QFs) or special customer contract resources, existing
resources are situs-allocated(100 percent) to Oregon customers. Regarding new proxy resource
selections, it is assumed that any new proxy resources selected to serve Oregon need are situs
allocated, including both supply-side and demand-side resources.3 These resource allocation
assumptions underlie progress toward HB 2021 clean energy targets and Oregon-allocated
greenhouse gas emissions, as explained below.
2 The 2020 Protocol was adopted by the Public Utility Commission of Oregon order no.20-024 on January 23,2020
(available online athqps:Hedocs.puc.state.or.us/efdocs/HAA/uml05Ohaal6l935.pd ).
3 The only"proxy"resource selected in the 2025 IRP that is considered a system resource and is allocated based on
system generation factors is the Natrium nuclear demonstration project.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Resource Adequacy
As described in Volume I, Chapter 8, the 2025 IRP helps ensure 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 long-term (LT) capacity expansion model to
account for shortfalls identified within the more granular short-term (ST) model that includes
hourly dispatch outcomes.
HB 2021 Greenhouse Gas Emissions: Methodology and Assumptions
HB 2021 directs the state's large investor-owned utilities to incrementally reduce greenhouse gas
emissions from baseline emissions associated with retail electricity sales. Baseline emissions are
defined as the average annual emissions of greenhouse gases for the years 2010, 2011, and 2012
associated with the electricity sold to retail electricity consumers, as reported to, and established
by the Oregon Department of Environmental Quality (ODEQ). The ODEQ's determination,
measured in million metric tons of carbon dioxide (MMT CO2e), and corresponding emissions
reductions for each target year, are reflected in Figure P.I below.
Fi ure PA —HB 2021 Emissions Targets for PacifiCor
educing Greenhouse Gas Emissions
BASELINE
80%
• BELOW BASELINE
90%
• BELOW BASELINE 100%
BELOW BASELINE
• _ 0 MMT
COZe
PacifiCorp calculates its greenhouse gas emissions for purposes of determining HB 2021 progress
according to applicable statutes, rules, and written guidance published by ODEQ. ODEQ is
responsible for measuring and verifying the greenhouse gas emissions that are included in a
utility's CEP and reporting these findings to the commission. Consistent with these
responsibilities, ODEQ published guidance for projecting and reporting emissions for HB 2021
492

PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
that leverages methodologies from the agency's longstanding Greenhouse Gas Reporting Program
under OAR 340,Division 215.4 In addition,ODEQ has published guidance that directs the utilities
to use unit and resource specific emission factors and default emission factors for the 2025 CEPS
In addition to emissions factors,ODEQ provided guidance for multi jurisdictional utility reporting,
adjusting for netting wholesale sales or non-retail electricity, accounting for transmission losses,
and accounting for electricity purchased from specified and unspecified sources.'
Table P.1 below provides detailed descriptions of the assumptions and authorities PacifiCorp relied
on when determining total forecasted utility emissions for compliance with HB 2021.
Table P.1 —Assumptions
Category -Assumption and Authority
Baseline Emissions In May 2022, ODEQ established PacifiCorp's
baseline emissions levels, and emissions
reductions necessary to achieve PacifiCorp's
emissions reduction requirements.'PacifiCorp
believes that ODEQ may have established an
incorrect baseline emissions level. However,the
company relies on the DEQ's determination in the
2025 IRP,without conceding its accuracy.
General Calculation Methodology PacifiCorp's initial calculation of projected
emissions,prior to any exclusions or special
treatment, is based on Oregon's long-standing
Greenhouse Gas Reporting framework established
in OAR 340-215 for annual actual emissions
reporting. ORS 469A.420(1)(b),468A.280.
Emission factor for existing specified resources ODEQ assigns emission factors to PacifiCorp's
existing facilities,by unit,based on historical data.
The DEQ assigned emission factors are available
online.
Emission Factors for future resources In cases where a facility or unit-specific emission
factor is either not available or applicable,DEQ
directs utilities to use default emission factors by
fuel type. When possible,these emission factors
are based on U.S. Environmental Protection
Agency's (EPA)2022 Greenhouse Gas Emission
Factors hub,which is available on the EPA's
website. When not available, emission factors
from EPA's 2020 Emissions &Generation
Resources Integrated Database(eGRID) Technical
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
hllps://www.oregon. og v/deg/ghgp/Documents/HB2021EFGuidance.pdf).
5 Oregon Department of Environmental Quality,"Greenhouse Gas Emission Factors for HB 2021 Electricity Sector
Emission Projections"(available at https://www.oregon.gov/deg/ghgp/Documents/HB2021-EmissionFactors.xlsx).
6 Oregon Department of Environmental Quality,"Multi jurisdictional Utilities:Instructions for reporting greenhouse
gas emissions"(available at hgps://www.oregon.gov/deq/M/Documents/GHGRP-MutlijurisdictionalProtocol.pdf).
7
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Guide were used. ODEQ's default emission
factors are available online.
Emissions for planned coal-to-natural gas Pursuant to OAR 340-215-0040(4) a utility may
converted resources petition ODEQ to approve in writing an
alternative calculation or method for determining
an emission factor,providing an explanation and
rationale for the alternative.
On March 20,2025,DEQ approved PacifiCorp's
petition to use an alternative calculation method
for determining the emission factor for planned
coal-to-natural gas converted resource. PacifiCorp
will use an emissions adjustment multiplier of
0.578 MTCO2e/megawatt-hour, applied to the
DEQ published unit specific emissions rate for
coal fired resources that are planned to convert to
natural gas. PacifiCorp's alternative is more
conservative than DEQ's published default
emission factors for natural gas fired resources
and estimates higher emissions from converted
coal-to-gas units based on more accurate
operational assumptions and lower efficiency of
converted units.
Emission factors for unspecified resources The default emission factor is 0.428
MTCO2e/megawatt-hour for energy originating
from an unspecified source. This includes
purchases from centralized market purchases such
as the Western Energy Imbalance Market. OAR
340-215-120(2)(a).
Transmission Losses Electricity suppliers must include a 2 percent
transmission loss correction factor when
calculating emissions from generation not
measured at the busbar. OAR 340-215-
1201 b B i .
Removal of non-retail sales According to ODEQ guidance, energy, and
emissions from the sale of wholesale power are
not included in annual Oregon emissions totals.
Rather,a utility must remove the energy and
emissions associated with those non-retail sales
from its calculations and reporting of emissions
associated with the electricity the utility supplied
to its Oregon retail customers. Utilities may
account for non-retail sales with 3 approaches,
based on the nature of each individual sale:
1) Sales of specific power:Non-retail sales
of a specific resource or set of resources
are accounted for by removing that power
and any associated emissions from a
utility's emissions reported to ODEQ.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
2) Sales of unspecified power: Unspecified
power purchased by a utility and then re-
sold to non-retail customers is removed
(both the power and emissions) from the
amount of unspecified power included in
a utility's emissions reported to ODEQ.
3) Sales of the utilities' overall resource mix:
Non-retail sales of a utility's power,
without specification of any particular
portion of the utility's portfolio, are
removed by proportionately subtracting it
across the utility's overall resource mix
for that year.
ODEQ Guidance: GHG Emissions Accounting for
House Bill 2021,Reporting, and projecting
emissions from electricity using DEQ
methodology
Multi-state jurisdictional reporting Oregon rules allow for multi jurisdictional utilities
like PacifiCorp to rely upon a cost allocation
methodology approved by the Oregon PUC for
allocating emissions associated with the
generation of electricity that serves Oregon
customers. OAR 340-215-0120(6)(c).
PacifiCorp's most current multi jurisdictional cost
allocation methodology approved by the Oregon
commission is the 2020 Protocol. While the 2020
Protocol does not extend through the planning
horizon of the 2025 CEP,the Company relies on
this allocation methodology for the planning
horizon.
Under the currently approved cost allocation
methodology,the utility reports a percentage of its
entire multi-state system emissions based on the
share of the power served in Oregon.
Under all cost allocation structures, it is assumed
that no coal is allocated to Oregon starting in 2030
consistent with ORS § 457.518, and that no
thermal resources or market purchases are
allocated to Oregon starting 2040.
ODEQ Multijurisdictional Utilities,Instructions
for Reporting Greenhouse Gas Emissions and
OAR 340-215-0120.
Exclusions Emissions from qualified facilities under the terms
of the Public Utility Regulatory Policies Act
(PURPA) and net metering programs are not
495

PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
regulated under HB 2021, and emissions from
these sources are excluded from ODEQ's
determination of relevant emissions. Yet the MWh
associated with these resources remain included in
the calculation. ORS 469A.435(3).
Small-scale Renewables
In addition to establishing greenhouse gas emissions reduction requirements, HB 2021 also
amended Oregon's small-scale renewable mandate included in ORS 469A.210, by postponing
compliance with the law until 2030, and increasing the target to 10 percent of PacifiCorp's
aggregate electrical capacity, from the prior 8 percent.
To determine PacifiCorp's SSR target, the company identified Oregon-allocated aggregate
electrical capacity in each year 2030 onwards and calculated a 10 percent small-scale requirement
based on that capacity. As shown in Table P.2 below, the 10 percent small-scale target in 2030
amounts to 675 MW.To address this need,the 2025 IRP preferred portfolio includes a slight excess
of small-scale resource capacity at 723 MW total SSR-qualifying resources, which is comprised
of existing SSR-eligible resources and future proxy resources.
PacifiCorp estimates it has 403 MW of existing resources in its nameplate capacity that fit the
definition of SSR. This leaves an additional need for 272 MW of small-scale proxy resources to
meet the target of 675 MW.8 This assumes that all eligible QFs that expire before 2030 renew at
100 percent nameplate capacity,which is slightly above the 75 percent historical renewal rate. The
2025 IRP preferred portfolio includes slightly more small-scale proxy resources, at 320 MW,
providing a small buffer to better ensure compliance.
Table P.2— Small-scale Resource Position in 2030
IMIEW
Oregon Small Scale Nameplate Credit
(Requirement) Notes
2030 (11")
(SIR)
Existing Resources
All Resources 3784 (3 7 8) Small-scale requirement is 10°o of existing nameplate
Small-scale 403 403 Existing small-scale eligible resources
Surplus(Need) 27 25 Excess existing small-scale resources*
Exstisnig+Incremental Proxy-Resources
All Resources 6-54 (675) Small-scale requirement is 1000 of total nameplate
Small-scale -2 723 1 Total small-scale eligible resources
Surplus'(Need) 5 3 48 Excess small-scale resources*
a This ten percent standard includes small-scale capacity in both the numerator(megawatts of small-scale generating
capacity), and in the denominator (megawatts of all generating capacity). As a result, even though the small-scale
capacity is 48 megawatts higher than the requirement of 675 MW, 53 megawatts of small-scale capacity could be
removed from the preferred portfolio while remaining in compliance,as the total capacity for all resources following
this modification(6,701 MW)would have a lower small-scale capacity requirement(670 MW).
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Portfolio Results
The sub-sections below discuss the 2025 IRP system and Oregon-specific resource selections,
resulting greenhouse gas emissions, and transmission and small scale and CBRE results.
Oregon Resource Selections
All portfolio results from the 2025 IRP are presented in Volume I,Chapter 9,including both system
and Oregon-specific resource selections.
Table 9.2, specifically, shows the Oregon-allocated megawatts (MW) of resources selected in the
preferred portfolio. Table P.3 recasts the same information that is presented in Chapter 9, Table
9.2 but delineates which incremental proxy resource selections for Oregon are considered situs, or
100 percent allocated to Oregon customers because they are selected only for Oregon need,versus
Oregon's share of a systemwide proxy resource.As the table shows, all resource selections,except
for the single nuclear resource category, are assumed to represent situs-allocated resources for
Oregon.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Table P.3 - Incremental resource additions for Oregon customers, by resource allocation assumption
Incremental resource additions fm•Ore on,be resource n e and year
Installed Ca acirv,'-%
Situs proxyresources 2025 2026
DSM-EnergN,Efficiency 97 101 107 114 115 110 113 108 109 111 110 106 102 116 123 107 114 92 90 2,044
DSM-Demand Response 0 48 16 7 5 I 3 3 11 11 4 23 4 9 8 153
Renewable Peaking19 4 18 40
- - - - - - - - - - - - - - - - - -
Renew-able-Wind 16 445 939 1 22 260 30 131 28 0 282 37 15 72 2,278
Renewable-Utility Solar 167 135 1,268 136 180 302 169 10 0 0 416 78 9 148 56 3,074
Renewable-Small Scale Solar 320 2 1s 26 21 30 132 0 309 110 143 36 1,147
Renewable-Battery,<8 hour 1 280 100 128 119 39 2101 20 47 46 107 55 1,152
Renewable-Batterv,24+hour 272 88 7 79 33 934 102 210 397 192 353 2,661
System-shared proxy msources
Nuclear 130 I30
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
In the near-term, the 2025 IRP preferred portfolio selects 763 MW of new renewable resources to
serve Oregon customers by the end of 2029, including 461 MW of utility-scale wind and 302 MW
of utility-scale solar resources. The portfolio also includes over 380 MW of battery storage coming
online in the same time period. Additionally, the portfolio optimizes DSM resources, picking 64
MW of new demand-response and 305 MW of energy efficiency resources by the end of 2029.
Between 2030 and 2035,the portfolio includes an additional 3.7 gigawatts(GW)plus of renewable
resources. This includes 1,222 MW of utility-scale wind and 2,065 MW of utility-scale solar,plus
417 MW of small-scale solar resource additions. During these years, there is also significant
additional storage selected: over 800 MW including both longer-duration batteries (over 24 hours)
and traditional shorter-duration batteries (under 8 hours) of 360 MW and 516 MW, respectively.
These years see a slightly smaller increase in new demand-response capacity, with only 19 MW
added,whereas energy efficiency selections increase by 669 MW.During this time frame,a system
nuclear resource of 500 MW nameplate capacity is also added, which Oregon customers would
receive a share of equivalent to 130 MW.
By the end of the 21-year planning horizon, over 2.2 GW of wind resources, 3 GW of utility-scale
solar and over 1.1 GW of small-scale solar are added to serve Oregon customers.Additionally, 3.8
GW of storage resources are added, including both shorter and longer-duration batteries. The
portfolio also selects nearly 2 GW of energy efficiency selections and 153 MW of demand-
response by the end of the period. This long-term portfolio of resources represents a pathway to
meet energy needs, resource adequacy requirements and clean energy targets for Oregon. And,
importantly,these Oregon incremental resources are in addition to the system resources identified
in the 2025 IRP that will be allocated to serve Oregon customers.
Greenhouse Gas Emissions
As described in the previous section,PacifiCorp relies on ODEQ methodologies to forecast its HB
2021 emissions based on its IRP results. The integrated portfolio methodology incorporated HB
2021 emissions reduction targets as part of Oregon's compliance obligations, ensuring they are
met through a least-cost,least-risk approach. The portfolio results indicate a significant downward
trend in Oregon-allocated greenhouse gas emissions, with a modest decline between 2025 and
2029,and a steeper reduction in 2030 onwards. These forecasted reductions are driven by the large
addition of proxy renewable and storage resources.
The modeling process, based on emission factors and the established methodology framework,
enables the endogenous selection of proxy resources and the optimized dispatch of resources and
market transactions. This approach ensures a resource portfolio that meets HB 2021 obligations
for Oregon customers. Figure P.2 confirms PacifiCorp's portfolio compliance with HB 2021,
though PacifiCorp notes that the resources allocated to Oregon exceed annual energy requirements.
Currently, regulations do not allow the company to specify sales on an Oregon-allocated basis or
by fuel type. If PacifiCorp was permitted to sell Oregon-allocated energy exceeding its annual
requirements from specific emitting resources, the company could further reduce emissions,
accelerate progress toward its HB 2021 targets, and lower costs for Oregon customers.
Achieving compliance with HB 2021 requires that (a) enough megawatt-hours of energy are
allocated to Oregon to meet every megawatt-hour of Oregon load on an annual basis, and(b) that
the emissions associated with those megawatt-hours do not exceed the emissions allowed under
499

PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
the emissions reduction target. Compliance with both requirements create a need for significant
new non-emitting generation. Additionally, Oregon's share of existing gas plants and some gas
conversions are modeled as distinct units that dispatch separately from the rest-of-system share of
these units.9
Each Oregon jurisdictional portfolio required that the model add enough megawatt-hours of new
non-emitting generation to meet a majority of Oregon load in each year after 2030, ensuring that
the emissions associated with any load not met with non-emitting generation does not exceed the
emissions reduction target. In addition, to represent the limit on Oregon-allocated emitting
generation, a model driver dispatch price starting at$100/ton in 2030 was applied to the emissions
generated by Oregon's share of gas plants.
Figure P.2 illustrates PacifiCorp's Oregon-specific greenhouse gas emissions trajectory, relative
to HB 2021 defined targets, based on the 2025 IRP preferred portfolio. While the 2023 IRP
preferred portfolio initially showed higher near-term emissions reductions,the 2025 IRP preferred
portfolio catches up to that trajectory by 2030 and ultimately exceeds it in the pace of emissions
reduction. The black dashed line represents the HB 2021 emissions reduction targets, which take
effect in 2030. The 2025 IRP preferred portfolio produces a compliant pathway achieving required
emission reductions from 2030 onward.10
Figure P.2—Oregon greenhouse gas emissions relative to HB 2021 targets
% Emissions Reduction Relative to Target
300%
------'
80% —--- -------
E 50M �
8 �
_`0 50% ,
4M
E 70%
20% '
10%
2025 2026 2027 2028 20:� 2030 2031 2032 2033 20 2035 2036 2037 20M 2039 2010 20M 2U2 2M 20 20 5
-- %Emissions Reduction Target—2023 IRP Preferred Portfolio—2025 IRP Preferred Portfolio
9 This modeling assumption allows the model to dispatch Oregon-allocated of natural gas units independently from
the share of the plant dispatched for other jurisdictions without a GHG constraint.This is a modeling assumption and
does not represent a specific strategy to dispatch Oregon-allocated natural gas generators in a specific way. Rather,
this strategy acts a proxy for various strategies,such as sites-allocation to Oregon of only a few natural gas generators
which could then be dispatched with a presumed GHG constraint.
10 See Appendix M,stakeholder feedback form#61 (Public Utility Commission of Oregon)
500

PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Small-Scale and Community-Based Renewables
As described in a prior section and depicted in Table P.2,the 2025 IRP preferred portfolio showed
a small-scale resource need of 675 MW by 2030. PacifiCorp plans to comply with the SSR targets
with a mix of existing qualifying resources and new proxy small-scale resources that will be
acquired, likely through requests for proposals (RFP) issued to market. As previously shown in
Table P.3, significant proxy small-scale resources are added across the planning period. Small-
scale resources, while required to meet the SSR target, are also available to be selected by the
model to meet energy needs. A total of 1,147 MW of small-scale solar resources are selected over
the planning horizon.
The company anticipates that some number of the proxy small-scale resources could be, and will
be met, with community-based renewable energy (CBRE) projects. However, at the level of
granularity the model possesses, there is no significant distinction between the two types of
resources, other than potentially assuming some additional benefits are generated by CBREs
relative to other small-scale renewables. CBREs, and the company's broader strategy to encourage
and foster them is described in more detail in a later section.
Transmission
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.
In support of the renewable resource additions identified for Oregon in the 2025 preferred
portfolio, PacifiCorp has identified transmission options that will reinforce existing transmission
paths, allow for increased transfer capability, and will support the interconnection of new
renewables. A summary of PacifiCorp's identified transmission additions serving Oregon and
Oregon-allocated resources is shown in Table PA below:
Table PA - Transmission Selections Supporting Oregon Resources1,2
Build
Export Import Interconnec Investment
2028 Cluster 1 Area 11:Willamette Valley 0 0 199 14 100% n/a n/a
2028 Cluster 1 Area 14:Summer Lake 400 400 400 111 100% Summer Lake Hemingway
2028 Cluster 1/2/3:Walla Walla 0 0 393 328 100% n/a n/a
2028 Serial queue:Central Oregon 0 0 152 4 100% n/a n/a
2029 Cluster 2 Area 23:Willamette Valley 0 0 393 2 100% n/a n/a
2030 Cluster 2 Area 19:Summer Lake to Central Oregon 500 kV 1,500 1,500 670 1,283 100% Summer Lake Central OR
2030 Walla Walla-Yakima 230 kV 400 400 400 142 100%1 Walla Walla Yakima
2031 Serial through Cluster 1 Area 13:Southern Oregon 0 0 231 42 100% n/a n/a
2032 Cluster 1 Area 12:Southern Oregon 0 0 300 303 100% n/a n/a
2033 Cluster 2 Area 18:Central Oregon 500 kV Substation 0 0 518 372 100% n/a n/a
2039 Walla Walla-Central Oregon 500 kV 1,500 1,500 670 1,463 100% Walla Walla Central OR
Grand Total 3,800 3,800 4,326 4,064
'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.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Impacts of Oregon Compliance
The Utah, Idaho, Wyoming, and California (UIWC)jurisdictional portfolio optimized under the
medium natural gas,no carbon(MN)price-policy scenario selects a portfolio for the entire system
but does not model compliance with HB 2021, so it was selected as the basis for comparison with
the preferred portfolio. Given that the UIWC jurisdictional portfolio does not model compliance
with Washington's Clean Energy and Transformation Act (CETA) clean energy standards, some
of the differences between the UIWC portfolio and the preferred portfolio may not specifically
reflect compliance associated with HB 2021.
Figure P.3 presents the differences between the resource selections in the UIWC portfolio and the
preferred portfolio. A positive value indicates an increase in resources and a negative value
indicates a decrease when a resource is reduced or eliminated. In the absence of Oregon
compliance requirements (and Washington compliance requirements),the quantity of utility-scale
renewable wind and solar resources included in the portfolio decreases by 5,944 MW, and the
quantity of storage resources decreases by almost 2,000 MW.
Figure P.3—Cumulative and Incremental Portfolio Changes,
UIWC Portfolio Less Preferred Portfolio
Cumulative Changes Incremental Portfolio Changes
2,000 1,000
500
(4000) (500) '
'O (4,000) 01000) MEMOS
(6,000) 4(2,000)
r� (8,000) (2,500)
(3,000)
(l0.0� (3xO)
(12,000)
.coal .Gas .QF .Hydro .coat .Gas .QF •Hvdm
■Nudear ■Hydro Stange ■Battery ■Solar .Nudear .Hydro Storage .Battery .Solar
.Wind .Geod..al .EncgyEfficimcy .Demand Response .Wind hermal .Energy=Jr.wxy .Demand Response
•Cmveriad Gm •Hydrogen Storage Peaker Renewable Peeking .Com-erted Gas Hydrogen Storage Peaker Renewable Peaking
Figure PA compares the costs in the ST model dispatched under MN between the UIWC portfolio
and the preferred portfolio. A negative value indicates that the UIWC portfolio has lower costs
than the preferred portfolio. In the absence of Oregon(and Washington)compliance requirements,
the UIWC portfolio is substantially cheaper than the preferred portfolio, reaching 2 billion in
reduced costs by the end of the horizon. Although this difference in system costs is not fully
attributable to Oregon compliance requirements, it suggests that the costs of compliance are
significant. Further analysis in the 2025 CEP will assess the Oregon-allocated incremental cost of
HB 2021 compliance.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Figure PA—UIWC Portfolio Less Preferred Portfolio System Cost
Net Difference In Total System Cost
$500 -
$o
($500)
($1,500) ($2.000)
($2,500)
oti�' otil0 oti^ oti�' oti�' o"�° o'�� o"�� o'��' o"��` o"��' o"�IO o"^ o"�� o"�� o°° N
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
Net Cost/(Benefit) ——— Cumulative PvRR(d)
Figure P.5 compares the system emissions in the preferred portfolio to the system emissions in the
UIWC portfolio. In the absence of compliance with HB2021, total portfolio emissions are
significantly higher than in the preferred portfolio from 2030 onwards. This impact on emissions
is a result of both HB 2021 constraints on Oregon-allocated greenhouse gas emissions but is also
in-part, the result of large renewable resource additions selected to serve Washington customers.
Both state-specific clean energy standards appear to drive emissions down compared to what
would otherwise occur.I I
" See Appendix M,stakeholder feedback form#61 (Public Utility Commission of Oregon)
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Figure P.5 — Emissions comparison of HB 2021-compliant preferred portfolio with non-
compliant UIWC jurisdictional portfolio
IRP CO2e Emissions Comparison
30
25
a�
0
U
20
0
U
15
10
5
0
(O I, c0 O O .-1 N M V V) W I, co M O -4
N N N N N M M M M M M M M M M V V V V V V
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
■Without HB2021 Compliance
■Preferred Portfolio
PacifiCorp's April 1, 2024, Planning Supplement12 identified several strategies that could be used
to reduce emissions and produce a compliant portfolio. The status of these strategies within the
modeling for the 2025 IRP" is summarized below:
- Existing resources: Oregon is allocated shares of existing resources based on the 2020
Protocol that is currently in effect. This is largely unchanged since the 2023 IRP Update.
- QF generation for compliance: Based on discussions with the Oregon Department of
Environmental Quality, PacifiCorp is now including all QF generation as non-emitting
energy when evaluating its resource supply relative to Oregon load.
- IRP selections: the portfolio without HB 2021 compliance, discussed in Figure P.3,
contains significant clean resource additions which would reduce emissions, analogous to
what was identified in the 2023 IRP Update,though this is much less than what is necessary
for HB 2021 compliance.
12 PacifiCorp's Oregon Planning Supplement, date April 1, 2024. Docket No. LC-82. Available online at:
hllps://gpps.puc.state.or.us/edockets/docket.asp?DocketlD=23647
13 See Appendix M,stakeholder feedback form#61 (Oregon Public Utility Commission).
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
- Additional clean resources: The PLEXOS model selects resources based on Oregon's
energy requirements and the additional clean resources allocated to Oregon in the preferred
portfolio,and the additional clean resources represented in Figure P.3 ensure that Oregon's
annual energy requirements are met.In the 2023 IRP Update,resources allocated to Oregon
were not sufficient to meet Oregon's load on an annual basis and emissions were attributed
to the shortfall based on the emissions rate for unspecified market purchases.
- Reduce natural gas dispatch: The inclusion of a model driver dispatch price reduces the
model's relative economics for Oregon's share of gas-fired resources in 2030-2039. That
driver starts at $100/ton in 2030 and escalates over time. Because it is applied on a per ton
basis, units with the highest emissions rate are likely to be impacted the most, so gas
conversion units would be influenced more than relatively efficient combined cycle
combustion turbines. Studies to evaluate reduced dispatch drivers could improve the
economics of the HB 2021 compliance portfolio, by allowing for economic generation at
a level that results in emissions that are close to the required level,rather than significantly
exceeding it.
Reduce market emissions rate: Oregon continues to be allocated a system share of market
purchases in accordance with the 2020 Protocol through 2035. Thereafter, the emissions
associated with market purchases would exceed the total allowed emissions, so the
associated energy and resulting emissions have not been allocated to Oregon from that
point forward. Access to a (mostly) clean energy market would be necessary at that point
in time and could be valuable as early as 2030.
additional Actions and Resour
The sub-sections below discuss additional PacifiCorp actions and resource that are not necessarily
driven by the 2025 IRP process or IRP outcomes yet are nonetheless integral to the company's
resource portfolio and system operations. These include PacifiCorp's actions and resources
regarding: Demand-Side Management, Community-Based Renewable Energy, Distribution
System Planning, and Transportation Electrification.
Demand-Side Management
Energy Efficiency
The Energy Trust of Oregon (ETO) is an independent nonprofit organization dedicated to
promoting energy efficiency and renewable energy solutions for customers of participating utilities
in Oregon. Since 2002, PacifiCorp has collaborated with ETO to implement energy efficiency
programs within its Oregon service area, in accordance with ORS 757.612 and ORS 757.054.
These programs are funded through two tariffs: Oregon Schedule 291, which supports energy
efficiency initiatives, and Oregon Schedule 292,which funds renewable energy efforts.
PacifiCorp maintains two agreements with ETO to facilitate this partnership:
1. The Energy Efficiency and Renewable Energy Programs Funding Agreement, which
governs the allocation of collected funds to ETO for program delivery and establishes
performance expectations for energy savings and renewable energy development.
2. The Consumer Information Transfer Agreement, which enables ETO to access necessary
utility data to support program implementation,participation tracking, and energy savings
verification.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Looking ahead to 2025, PacifiCorp will continue working with ETO to review their proposed
inaugural Multi-Year Plan (MYP). This plan will establish ETO's energy efficiency targets and
associated budgets for the five-year period from 2026 to 2030, ensuring alignment with statewide
energy goals and utility resource planning efforts. Through this ongoing collaboration,PacifiCorp
aims to support effective program delivery while ensuring cost-effective investments that benefit
customers and contribute to broader energy policy objectives.
Demand Response
PacifiCorp has been aggressively growing its demand response portfolio in Oregon for several
years. The company expanded the long-running Irrigation Load Control pilot to a full customer
program in 2022, and since that time has launched three additional programs targeting the
commercial, industrial, and residential sectors. PacifiCorp's DR programs are carefully designed
to provide a range of grid management services,while meeting the needs of the customer segment
and end-use targeted. The current portfolio includes the following programs:
• Irrigation Load Control, launched in 2023, which used a program-provided load control
switch for peak management during the summer season.
• Wattsmart Business Demand Response, launched in 2023, which enrolls loads at the
customer meter to provide peak management,contingency reserves,or frequency response
resources. Control mechanisms vary from manual control to full automation.
• Wattsmart Battery, scheduled to launch in 2025,which dispatches residential batteries for
various demand response applications.
• Cool Keeper, scheduled to launch in 2025, which uses a load control switch to curtail the
compressor on residential cooling equipment for peak load reduction,contingency reserve,
and frequency response needs during the summer colling season.
• Wattsmart Drive,scheduled to launch in 2025,which uses EV telematics to curtail charging
for demand response. This program was originally included as part of the Transportation
Electrification Plan but is now managed as part of the DR portfolio.
In addition, the company offers time-of-use rates for all customer classes that contribute to our
strategy to manage loads effectively.
The company expects to continue to grow this portfolio of programs as indicated by our IRP
planning process. In the forthcoming 2025 CEP, PacifiCorp will establish a forecast for total
capacity available through our DR portfolio based on the results of the 2025 IRP, and feedback
from our partners and stakeholders.
Community-Based Renewable Energy
Community-Based Renewable Energy (CBRE) projects are energy systems that interconnect to
utility distribution or transmission assets, and may be combined with microgrids, storage systems,
demand response measures, or energy-related infrastructure that promotes climate resiliency.
Additionally, CBRE projects must: (1) directly benefit particular communities through
community-benefit agreements or direct ownership by local government, nonprofit entities, or
federally recognized Indian tribes; or (2) increase resiliency or community stability, local jobs,
economic development, or direct energy cost savings to families and small businesses. A utility's
Clean Energy Plan (CEP) must examine both the costs and opportunities that CBRE projects can
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
potentially provide when determining what mix of resources are most appropriate to offset energy
generated from fossil fuels.
ODOE was directed by House Bill (HB) 2021 to convene a work group to examine opportunities
to encourage the development of small-scale renewable and CBRE projects, including how either
could contribute to economic development and local energy resilience, as well as the potential rate
impacts of developing small-scale renewables and CBRE projects. ODOE convened the
workgroup in December 2021, which included a broad spectrum of representatives from various
sectors and stakeholder groups and delivered its Study on Small-Scale and Community-Based
Renewable Energy Projects (ODOE Study) to the Oregon Legislature in September 2022.
The ODOE work group was not able to reach consensus on specific recommendations for the
study. Instead,the work group generally agreed that small-scale renewable and CBRE projects can
play a role in addressing climate change, achieving state energy and climate goals, reducing
impacts on land and natural resources, supporting local economic development, and providing
local energy resilience for communities and organizations. While small-scale renewable and
CBRE projects "can have unique benefits that are customized to meet local and community
expectations and goals,"the ODOE Study cautioned that the "individualized nature of these types
of projects also make it difficult to provide an overarching assessment on the energy,
environmental, economic, and social benefits and challenges of small-scale and community-based
projects writ large."This is because these types of projects"involve trade-offs, and for small-scale
and community-based projects those trade-offs will vary significantly but will also be more
flexible to address community or local concerns and needs."
The ODOE Study acknowledged the"the potential for increasing rate pressure on utility customers
when discussing the costs of incentivizing small-scale and community-based renewable energy
project development and agreed that future policy decisions should be based on a principle of
equitable distribution of costs and benefits."This is because there were"differing perspectives on
the appropriateness of using regulated utility rates to pay for benefits that do not necessarily
contribute to delivery of safe and reliable service at just and reasonable rates for all electricity
customers." Accordingly, the ODOE Study concluded that "policymakers will need to consider
the difference between economic and other societal and local benefits versus utility system
benefits" when evaluating the overall value of small-scale renewable and CBRE projects in
meeting the goals of HB 2021.
Pilot Program
In advance of policy-maker outcomes stemming from the ODOE study,PacifiCorp has developed
an ongoing strategy for CBREs that centers Oregon communities and is largely informed by
stakeholder input. This effort is exemplified in the structure of the CBRE-RH Pilot, which
advances projects in various stages of development with three separate but potentially overlapping
pathways of support. For its part, a key intended outcome of the three-year Pilot is a better
understanding of the true costs and quantifiable benefits of CBRE projects.
Community-Based Renewable Energy — Resilience Hub (CBRE-RH) Pilot Update: HB 2021
directed Oregon utilities to examine opportunities to encourage the development of community-
based renewable energy projects,including how they can contribute to economic development and
local energy resilience.PacifiCorp considered the use of a Pilot program to advance CBRE projects
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
in its inaugural Oregon Clean Energy Plan and has since revised and refined the model.PacifiCorp
filed for approval to operate this CBRE-RH Pilot within docket ADV 1637 on July 30, 2024
(Advice Letter Number 24-014). The Pilot was approved with a start date of September 20, 2024.
As of the time of this writing,the utility has held 26 meetings with leaders of communities as well
as project managers interested in advancing community resilience through CBRE projects. The
Company has also corresponded with 17 of the 19 projects that have received ODOE C-REP
construction grant awards and 9 of the 20 recipients of C-REP planning grant awards, all of whom
are in various stages of development. Additionally, two letters of commitment for grant match
funding have now been provided to a federally recognized Oregon Tribal Nation seeking IIJA
Formula Grant funding.
Table P.5 - Cost per kW of CBRE Projects Awarded Grant Funding b ODOE
Location kW Gen kW Storage Grant Award $/kW Gen
Mosier 125 125 $ 598,438.00 $ 4,787.50
Pendleton 240 500 $ 1,816,424.00 $ 7,568.43
Klamath Falls 45 25 $ 999,424.00 $ 22,209.42
Madras 51 0 $ 70,360.00 $ 1,379.61
Hood River 100 0 $ 500,000.00 $ 5,000.00
Gates 61 125 $ 312,852.00 $ 5,128.72
Talent 202 250 $ 1,000,000.00 $ 4,950.50
Bend 828 50 $ 1,000,000.00 $ 1,207.73
Talent 67 10 $ 116,623.00 $ 1,740.64
Madras 1140 0 $ 1,000,000.00 $ 877.19
Madras 108 240 $ 1,000,000.00 $ 9,259.26
Bend 985 0 $ 1,000,000.00 $ 1,015.23
Corvallis 249 240 $ 999,000.00 $ 4,012.05
Talent 108 440 $ 1,000,000.00 $ 9,259.26
Roseburg 800 0 $ 1,000,000.00 $ 1,250.00
Roseburg 50 186 $ 870,870.00 $ 17,417.40
Roseburg 440 0 $ 1,000,000.00 $ 2,272.73
$ 5,843.27
IRP Analysis
PacifiCorp analyzed the effects of adding 100 MW of CBRE solar projects across Oregon locations
in 2030. The CBRE solar projects were assumed to operate at the same capacity factor and receive
the same average locational marginal price identified in the 2025 IRP preferred portfolio for small-
scale solar in Central Oregon, Southern Oregon, Willamette Valley, and Walla Walla. The cost
per kW of CBRE projects awarded grant funding by ODOE, as shown in Table P.5 above, and the
retail rate for the Oregon Community Solar Program were used to calculate total project costs. The
table below presents the results of the analysis.
Including the CBRE solar projects in the 2025 IRP preferred portfolio is forecasted to increase the
total PVRR by $181 million. In Table P.6 the column labeled `Breakeven $/MWh of Benefit"
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
provides the minimum hourly value that would need to be assigned to the CBRE projects to make
the net effect on costs zero. CBRE solar projects may provide significant benefits that are not
directly considered in this analysis, including system reliability and community energy resilience.
Table P.6-Estimated costs Re uired to Breakeven on CBRE Projects
Net Revenue Total Costs Net Benefit/ Breakeven $/MWh of
Year (Cost)
($millions) ($millions) $millions Benefit
2030 4.7 29.0 -24.3 100.6
2031 4.4 29.0 -24.6 102.0
2032 3.5 28.7 -25.2 105.5
2033 3.1 28.6 -25.6 107.2
2034 2.8 28.4 -25.6 108.2
2035 3.1 29.1 -26.0 107.5
2036 3.0 29.1 -26.1 107.7
2037 3.2 29.1 -25.9 107.0
2038 3.2 29.1 -25.9 106.7
2039 3.0 29.1 -26.2 108.1
2040 3.8 29.1 -25.4 103.7
2041 4.1 29.2 -25.0 102.1
2042 5.0 29.1 -24.1 98.7
2043 5.9 29.1 -23.3 95.5
2044 6.2 29.1 -22.9 93.7
2045 6.2 28.9 -22.7 93.5
Distribution System Planning
Distribution System Planning (DSP) was first approved in 2019 under UM 2005. On November
13,2024,revisions to the DSP guidelines were approved. PacifiCorp will submit its updated filing
by March 31,2025. The goal of DSP is to promote transparency and inclusion by fostering a shared
understanding with stakeholders regarding the current state of distribution systems and near- and
long-term plans, including the exploration of nontraditional solutions. As part of this process, we
will host four stakeholder workshops, all of which are open to the public. Workshop dates and
materials will be sent in advance to our mailing list and posted on our website. These workshops
will provide an opportunity to share information and gather feedback. Workshop dates, materials,
recordings of past sessions, and an option to join our mailing list are available on PacifiCorp's
Oregon Distribution System Planning webpage.I4
14 Review the Oregon DSP webpage online at hgps://www.pacificpower.net/community/oregon-distribution-system-
planning html.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Transportation Electrification
PacifiCorp filed its 2023-2025 Transportation Electrification Plan (TEP) in May of 2023.15 The
Public Utility Commission of Oregon approved the final TEP in July 2023.16 Over the last two
years, PacifiCorp has been delivering a portfolio of programs and pilots that offer a range of
support to different sectors working towards transportation electrification. This included support
for residential, commercial, and multifamily customers as well as customers pursuing
electrification of fleets and medium-duty vehicles (MDVs) and heavy-duty vehicles (HDVs),
collectively referred to as MHDVs. The following is a summary of ongoing transportation
electrification efforts and programs:
o Electric Vehicle Supply Equipment(EVSE) Rebate Pilot Program. Launched in June of
2022, this program delivers rebates to residential, income-eligible, commercial, and
multifamily customers to install Level 2 chargers within residences, workplaces, and
multifamily units. At the end of 2024, over 1400 rebates have been issued.
o Outreach and Education Pilot Program. Provides future Electric Vehicle (EV) drivers
with greater awareness and understanding of the benefits of electric transportation
through work force development, dealership engagement, outreach and educational
platforms,ride, and drive events and more. This program was also launched in June of
2022."
o Grant Programs. Pacific Power has distributed more than $6.5 million in Electric
Mobility Grants to Oregon communities since 2020. PacifiCorp facilitates 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.18
o Fleet Make Ready Pilot Program. Offers a behind-the-meter(BTM) custom incentive to
fleet customers that will support all make-ready infrastructure focused on commercial
customers and inclusive of all vehicle class types and launched in early 2024.
o Public Utility-Owned Infrastructure Pilot Program. Launched in Q3 of 2023, PacifiCorp
will deploy utility-owned publicly available charging infrastructure located in
underserved communities.
o Residential Managed Charing Pilot Program. Actively manages electric vehicle loads
through vehicle-and charger-enable protocols to shift charging load to off-peak times and
anticipated to launch in Q2 of 2025.
15 Pacific Power.(May 2023).Pacific Power Final Oregon Transportation Electrification Plan.
edocs.puc.state.or.us/efdocs/HAH/um2056hah 104112.12df
16 Order No.23-257(2023).Pacific Power Oregon Transportation Electrification Plan.Available online at:
hllps:Hgpps.puc.state.or.us/orders/2023ords/23-257.pd
17 Advice No.21-016.(2021).(Docket No.ADV 1288/Advice No.21-016)New Residential Charging Pilot(Schedule
117),New Nonresidential Charging Pilot(Schedule 118), and Extension of the Outreach and Education Pilot.ADV
1288 21-016 Eff 8-25-2021 filed 7-20-21 RA3 signed.pdf(state.or.us)
18 UM 1826. (2017) Staff Investigation Electric Utility Participation in Clean Fuels. State of Oregon: Public Utility
Commission of Oregon
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
Community and Stakeholder Engagement
Advisory Groups
In addition to PacifiCorp's IRP community and stakeholder engagement processes, PacifiCorp's
Community Benefits and Impacts Advisory Group and Tribal Nations Community Benefits and
Impacts Advisory Group members advise the company on elements related to its Clean Energy
Plan and other plans and programs. Matters of importance as expressed across engagement spaces
by members include:
• Costs and potential bill increases are the primary concerns, alongside the transition to
cleaner energy, and advisory groups are committed to addressing these challenges. Many
participants are also concerned about the dependability of renewable resources and the
potential impact of materials required for clean energy technology.
• Advisory group members have expressed a need to see input in the advisory space
translated into action or meaningful community benefits.
• Partnerships are key to advancing actions for greater community benefits and include the
sharing of general program information and program opportunities for greater accessibility.
• More information and learning tools are needed to support a shared and foundational
understanding of utility systems and the regulatory environment.
• A more transparent and user-friendly way forward is needed for members to understand
the intersections of regulatory processes.
• Access to funds to add capacity for participation in programs and offerings resulting from
clean energy planning is a continued need.
When PacifiCorp filed its initial engagement strategy with the Commission on April 21, 2022, the
company proposed a hybrid stakeholder engagement model that relied on existing engagement
processes related to the IRP process and developed new processes through the formation of an
Oregon equity advisory group (CBIAG). The company's vision for moving forward is to continue
a single state-wide engagement group representing the lived experiences and perspectives of
communities and customers within our service territory—the CBIAG.
Through the CBIAG, PacifiCorp plans to continue seeking direct stakeholder feedback to build an
inclusive and accessible process for consultation and collaboration. This includes increasing
participation from communities that have not traditionally participated in utility planning
processes, providing the company with a better understanding of community needs and
perspectives, identifying barriers to participation and providing input on how to address these
barriers, acting as a conduit to exchange information and ideas between the company and
stakeholder communities, and assisting with community outreach.
The CBIAG consists of 10 individuals and/or organizations representing the lived experiences,
interests, and perspectives of the communities and customers within PacifiCorp's Oregon service
territory. Consistent with the definition of Environmental Justice communities within HB 2021,
communities identified for inclusion/representation include communities of color, communities
experiencing lower incomes, tribal communities, rural communities, coastal communities,
communities with limited infrastructure, and other communities traditionally underrepresented in
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
public processes and adversely harmed by environmental and health hazards, including seniors,
youth, and persons with disabilities.
PacifiCorp also developed and formed a Tribal Nations Community Benefits and Impacts
Advisory Group series, which supports and fosters collaboration, consultation, and shared
understanding of Federal, State, and local programs, policies, and grants. The engagement series
was formatted by informed feedback from outreach to Oregon Tribal members with whom
PacifiCorp had an existing relationship and through new Tribal Nations relationship building.
PacifiCorp plans to directly engage Tribal communities located within/connected to the company's
service in conversations about the most effective means of obtaining their input when preparing
for a clean energy future. PacifiCorp agrees that robust consultation with sovereign Tribal
governments and communities is critical to understanding each Tribe's concerns and perspectives.
As the scale of service and associated relationships varies between PacifiCorp and the Tribes it
serves, understandably, there will likely be varied levels of engagement.
PacifiCorp continues delivering the Oregon Tribal Nations Engagement Series, focusing on equity
and a clean energy future in Oregon per Oregon House Bill 2021. Through this external
engagement and informational series, we plan to continue seeking direct feedback to build an
inclusive and accessible process for consultation and collaboration. Through engagement with
interested parties,PacifiCorp intends to continue seeking direct feedback to build an inclusive and
accessible process of dialogue and cooperation.
General Stakeholder Engagement
Leading up to the filing of PacifiCorp's first clean energy plan,the company identified the need to
initiate a complementary and educational CEP engagement series to support existing engagements
and to more intentionally provide the time and space to dive into key clean energy planning topics.
Although PacifiCorp has various dedicated engagement spaces that support clean energy planning
engagement, the CEP engagement series was developed to focus on PacifiCorp's Oregon CEP
filing and regulatory requirements.
The CEP engagement series is designed to provide access to a more technical audience that is
actively engaged in PacifiCorp's clean energy planning and integrated resource planning
processes, so that PacifiCorp can directly solicit feedback on elements of the company's plan.
Oregon CEP engagement series meetings have drawn participation from different groups such as
the Public Utility Commission of Oregon Staff (Staff), environmental and justice advocates,
members of PacifiCorp's CBIAG and Tribal Nations CBIAG, community-based organization
representatives and general members of the public. The CEP engagement series continues through
2025, to socialize PacifiCorp's CEP and to provide additional opportunities for community and
stakeholder input on elements of the plan. Unless communicated otherwise, CEP engagement
series meetings are recorded for expanded accessibility and notes from each meeting are shared on
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
Pacific Power's Oregon CEP webpage in both English and Spanish following each individual
session.I9
As PacifiCorp approaches its next clean energy plan cycle, it will continue to offer engagement
opportunities to connect and provide feedback on key CEP topics and other related areas of
interest. Additionally, engagement activities will continue to adapt in response to input and
learnings to further inclusion, accessibility, and the collaboration of diverse participating
audiences.
Community Benefit Indic
As discussed in the 2023 Clean Energy Plan, Community Benefits Indicators (CBIs) are designed
to demonstrate the impact of PacifiCorp's proposed programs, actions, and investments.
PacifiCorp defines CBIs as the desired outcome that utility actions could either incentivize,
influence, or cause. Each CBI identifies a desired outcome, while metrics allow for PacifiCorp to
monitor progress at achieving these outcomes. Each CBI presented in the table below has been
grouped into one of five categories, which are defined below.
• Resilience (System & Community): Resilience refers to the ability of power systems to
endure and quickly restore power delivery to customers after significant disruptions. These
disruptions can include deliberate attacks, accidents, or natural events like earthquakes or
catastrophic wildfires. Producing resilience metrics at the census tract level can help to
demonstrate how resilient PacifiCorp's system is at a community-level and support
development of resilience programs that target vulnerable communities.
• Health and Community Well-Being: Access to energy is crucial for meeting basic human
needs. For instance, utility disconnections may occur when customers prioritize other
essentials, such as rent, food, or prescription medications, overpaying utility bills.
Monitoring disconnections by census tract can help identify communities facing challenges
in maintaining their well-being.
• Environmental Impacts: Reducing emissions improves air quality, leading to better health
outcomes for communities by reducing respiratory illnesses and other pollution-related
diseases. Tracking emissions will help PacifiCorp meet HB 2021 targets and monitor the
impact of its power generation activities on communities, particularly those that are
vulnerable.
• Energy Equity: Energy equity is the concept that all members of society should be able to
afford and have access to a necessary and basic supply of energy. Tracking metrics like
energy burden and energy efficiency program accessibility can help the company develop
support mechanisms for vulnerable customers to reduce the financial strain that may be
imposed by the transition to clean energy.
• Economic Impacts: Tracking the economic impacts of its clean energy investments helps
PacifiCorp ensure that projects support equitable benefits for all communities. These
include, for example, local job creation, workforce development and increased spending
on diverse businesses.
Table P.7 depicts PacifiCorp's interim CBI framework. This CBI framework was initially
presented in the 2023 CEP but continues to be reevaluated and expanded upon. This framework is
19 Pacific Power's CEP engagement series information can be found online at
hiips://www.pacificpower.net/communi /oregon-clean-energ_y-plan.html.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
not considered final as the company continues to work out what are the best CBIs and metrics that
can be tracked by the utility and that represent significant impacts to communities.
Table P.7—Interim CBI Framework
CBI Category CBI AM
Improve resilience of SAIDI, SAIFI and CAIDI at area level
Resilience vulnerable communities during including major events
(System& energy outages
Community) Reduce frequency and duration
Energy Not Served(ENS)
of energy outages
Health and Decrease residential Number of residential disconnections by
Community disconnections census tract
Well-Being
Environmental Increase energy from non- Amount of Oregon-allocated renewable
Impacts emitting and renewable and non-emitting energy(MWh)
resources
Reduce CO2 equivalent Amount of Oregon CO2 equivalent
emissions
emissions, MT CO2e
PROPOSED -Reduce S02 Amount of S02 and NOx emissions
and NOx emissions produced 20
Decrease proportion of
Energy Equity households experiencing high Average energy burden by census tract
energy burden
Increase housing and small Average energy burden for low-income
business energy efficiency for customers,bill assistance participants and
vulnerable communities Tribal members
Reduce barriers to participation Count of customers participating in
in energy efficiency programs business and residential incentive
for vulnerable communities programs
DSM program delivery staff Headcount of DSM program delivery staff
and grants and grants awarded
Public charging stations Count of public charging stations installed
in PacifiCorp territory
Pre-apprenticeship and Headcount of participants in pre-
Economic educational program apprenticeship programs
Impacts artici ation
Resource development Headcount of local and state workers
workforce during facility construction
Spend on Disadvantaged Business
Diverse business expenditures Enterprise (DBE), tribal,women, minority,
and/or veteran-owned resources during
facility construction
21 Already reported to United States Environmental Protection Agency(EPA)under the Clean Air Markets Program
Data(CAMPD)program and as part of PacifiCorp's Environmental, Social,and Governance(ESG)reporting.
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
From the above CBI framework, most of the CBIs are considered informational, or qualitative,
and can be tracked over a measure of time to help indicate if the company's collective and long-
term actions are improving benefits to the communities it serves. Some of the CBIs are considered
portfolio CBIs in that they can be specifically quantified based on IRP portfolio results and can
help inform portfolio selections or impacts across sensitivities. The CBIs under the "resilience"
category are specific to Community Based Renewable Energy(CBRE)projects that are discussed
further in the next section.
Portfolio CBIs that can be quantified and reported from portfolio outcomes are energy not served
(ENS), Oregon-allocated emissions (CO2e, S02 and NOx), and Oregon-allocated renewable
energy.21 In the forthcoming 2025 CEP filing,PacifiCorp will present a broader range of portfolio
sensitivities and results with an Oregon-allocated costs, benefits and nonenergy outcomes as
represented by the portfolio CBIs.
Additionally, PacifiCorp continues to progress its use of nonprice scoring methodologies to
incorporate the use of relevant CBIs in future bid evaluation and selection for new supply-side
resources.
Action Plan
The 2025 IRP, Volume I, Chapter 10 presents a near-term action plan identifying steps that
PacifiCorp will take over the next two-to-four years to deliver resources in the preferred
portfolio. This action plan includes action items for existing resources, new resources,
transmission, DSM management resources, short-term firm market purchases, and the purchase
and sale of renewable energy credits (RECs).
The action matrix in Table P.8 is an Oregon-specific view that expands upon the systemwide
action plan to include other actions that broadly support the company's progress and fulfillment
of HB 2021 goals, such as community and stakeholder engagement, activities related to CBIs,
and forthcoming regulatory filings and actions.
Table P.8—Ore on Clean Energy Plan Action Matrix
Action Item Existing Resource Actions
Natural Gas Emissions Compliance Strate ies:
• The 2025 IRP indicates that changes in accounting and/or dispatch of
existing natural gas resources may be a beneficial element of Oregon's
HB 2021 compliance strategy and to align with evolving state policies. A
la 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 2030.22
2'The CBIs tracking local pollution emissions outcomes,specifically sulfur dioxide(S02)and nitrogen oxides(NOx),
are recently proposed CBIs that would be additions to PacifiCorp's CBI framework. These new CBI metrics were
introduced in a recent CEP engagement meeting and will be workshopped with advisory group members and other
interested parties before being finalized.
22 This action is repeated from 2025 IRP,Volume I,Chapter 10—Action Plan.
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
New Resource Actions
Small-scale renewables RFP:
• PacifiCorp will issue as supported by the 2025 IRP, a small-scale
7 renewable resource specific Request for Proposals.
• PacifiCorp will continue to investigate, develop, and pursue other
2a strategies, as outlined in its SSR Acquisition Strategy filed concurrently
with this IRP, to increase its small-scale and community-based resources.
ransmission•
• PacifiCorp will also continue to analyze and pursue transmission projects
for Oregon, as appropriate, to support resources needed for serving
Oregon load, reliability, and meeting CEP objectives.
2025 Ore on-situs RFP:
• PacifiCorp will issue, as supported by the 2025 IRP, a Request for
2b Proposals to procure resources aligned with the 2025 IRP preferred
portfolio and in compliance with Oregon laws, regulations and obligations
that can achieve commercial operations by the end of December 2029.
Demand-Side Management (Actions)
Ener2y Efficient
• In 2025, PacifiCorp will continue collaborating with the Energy Trust of
Oregon (ETO)to review their proposed inaugural Multi-Year Plan(MYP)
that will establish their energy efficiency targets and corresponding
3a budgets for the next five-year period(2026-2030).
• Though ETO implements energy efficiency within PacifiCorp's Oregon
service area, PacifiCorp will continue supporting those program efforts
and endorses their aim to deliver cost-effective benefits to our customers.
Demand Response
• PacifiCorp will continue to expand its portfolio of DR programs in 2025,
both by growing the available capacity in existing programs and launching
new programs.
3b • In the 2025 update to the Clean Energy Plan, PacifiCorp will set annual
goals and milestones for actions the company will take to grow available
capacity in the demand response portfolio.
• In 2025, PacifiCorp will review individual programs to consider potential
additional actions to continuously improve delivery of programs.
Community-Based Renewable Energy Actions
• PacifiCorp is considering a Blue Sky Grant Program"Go-Back" strategy.
• PacifiCorp will track additional pathways and opportunities to stack
4a benefits and dovetail support for CBREs (e.g.: HB 2066, ODOE
Solar+Storage Rebate expansion, ODHS OREM Resilience Hub Grant
Program)
Community Engagement
dvisory Groups
5a • Pacific Power has sixteen planned Community Benefits and Impacts
Advisory Group CBIAG sessions in 2025. Eight of these will be
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PACIFICORP—2025 IRP APPENDIX P—OREGON CLEAN ENERGY UPDATE
specifically offered to the Tribal Nations Community Benefits and
Impacts Advisory Group and will include an update on various elements
of the Clean Energy Plan.
CEP En a ement Series
• Pacific Power will continue to offer Oregon Clean Energy Plan
Engagement Series meetings,with four regular sessions scheduled in
5b 2025, with opportunity for additional special meetings as requested or
required, as an avenue for expanded learning and dialogue on key clean
energy planning topics.
Community Benefit Indicators
• Pacific Power has proposed two new CBI metrics: S02 and NOx and will
6a continue to solicit input and feedback from its advisory groups and
interested parties and finalize the proposed metrics
• Pacific Power will continue to make progress on its CBI framework,
identifying any refinements to its current CBIs and proposed metrics to
6b work towards establishing a baseline and a transparent framework to
apply to resource procurement,planning, and other business decisions, as
relevant.
Regulatory Actions
Rulemakin En a ement
• Pacific Power will engage with ODEQ in any upcoming relevant
rulemakings to address changes to the methodology and calculations of
greenhouse gas emissions for purposes of demonstrating progress towards
7a clean energy targets. Under current ODEQ rules, if Pacific Power's
generation exceeds load, specified sales must reflect a proportionate share
of the system, not individual resources. However, the ability to
demonstrate compliance with clean energy targets through the specified
sales of emitting resources may have additional benefits for Oregon
customers.
2025 Clean Enemy Plan:
7b • Pacific Power will file its 2025 Clean Energy Plan (CEP) with the Public
Utility Commission of Oregon on June 30, 202521
23 The Public Utility Commission of Oregon issued order no.25-090 on March 5,2025 granting Pacific Power an
extension to file its 2025 Clean Energy Plan 90 days after the 2025 IRP(available online at
hllps://qpps.puc.state.or.us/orders/2025ords/25-090.pd
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PACIFICORP-2025 IRP APPENDIX P-OREGON CLEAN ENERGY UPDATE
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PACIFICORP—2025 IRP APPENDIX R—OREGON RPS 2025 RENEWABLE PLAN
APPENDIX R - OREGON RENEWABLE PORTFOLIO
STANDARD 2025 RENEWABLE PLAN
INTRODUCTI
In accordance with Oregon Revised Statute (ORS) 469A.075, PacifiCorp, d/b/a Pacific Power
(Company or PacifiCorp), respectfully submits its 2025 Renewable Plan to the Public Utility
Commission of Oregon(the Commission) as part of the 2025 Integrated Resource Plan(IRP).
This 2025 Renewable Plan represents a continuation of the Company's previously submitted
Renewable Portfolio Standard Implementation Plans (RPIPs). Oregon House Bill (HB) 3161,
which went into effect on January 1, 2024, amended ORS 469A.075 to eliminate the requirement
for a separate RPIP submission, and instead now requires a utility subject to the Renewable
Portfolio Standards (RPS) to submit, as part of the IRP, a renewable plan demonstrating how it
will comply with the RPS. In response to the passage of HB 3161, on December 28, 2023, the
Commission issued Order No. 23-484.' The order repealed OAR 860-083-0400, which formerly
established the process for submitting a standalone RPIP, and amended the definition of
"Integrated resource plan" in OAR 860-083-0010(22) to be consistent with the statutory
elimination of a separate, standalone, RPIP filing. In addition, the order directs commission staff
to work with interested persons toward the resolution of issues resulting from the inclusion of
renewable portfolio implementation plans as part of the IRP process in a collaborative, separate
docket or process.
Although a separate docket has not been established to work toward resolution of outstanding
implementation issues created by HB 3161, PacifiCorp and Commission Staff discussed the
required content of this 2025 Renewable Plan and PacifiCorp's timing concerns with incremental
cost calculations in the 2025 Renewable Plan with the IRP. On January 14, 2025, PacifiCorp filed
a Petition for Partial Term Wavier of OAR 860-083-0100, Renewable Plan Incremental Costs
Calculation, and Related Requirements.2 And, on March 18, 2025, the Commission issued Order
No. 25-108 approving the waiver.3 The Commission's order directs PacifiCorp with respect to the
2025 Renewable Plan as follows:
- Partially waives the incremental cost rule, subparts OAR 860-083-0100(1)(a), (g), (h),
(2)(b), (7), and (9)(d) as applied to any resource whose incremental cost has been
previously determined in an RPIP;
- Allows the complete submission of the renewable plan, including the incremental cost
calculations,within 90 days of filing the 2025 IRP; and
- Excludes the Low CO2 and Medium Proxy Plant fuel cost scenario from the list of
required fuel cost scenarios.
'https:Happs.puc.state.or.us/orders/2023ords/23-484.pdf
2 https://edocs.puc.state.or.us/efdocs/HAA/haa334228025.pdf
3 https:Happs.puc.state.or.us/orders/2025ords/25-108.pdf
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PACIFICORP—2025 IRP APPENDIX R—OREGON RPS 2025 RENEWABLE PLAN
In addition, Commission Staff s memorandum in support of PacifiCorp's petition for a partial
waiver acknowledges that it has not yet formally addressed questions regarding the content, scope,
and submission of renewable plans as recommended in Order No. 23-484, following the adoption
of HB 3161.4 PacifiCorp is encouraged by Commission Staffs commitment to address these issues
"before the end of 2025 through either workshops or opening a docket."PacifiCorp looks forward
to continuing to work with Commission Staff to address issues of renewable plan implementation.
Consistent with this direction from the Commission, PacifiCorp respectfully submits this 2025
Renewable Plan in two steps. This first portion of the 2025 Renewable Plan summarizes
PacifiCorp's methodology for planning compliance with the RPS, summarizes the applicable
statutes and rules, lists the annual targets for acquisition and use of qualifying electricity based on
2025 IRP forecasted retail sales, and lists the resources available to PacifiCorp to plan for
compliance during the 2025-2029 planning period. PacifiCorp will submit the second part of the
2025 Renewable Plan within 90 days of the filing of this IRP and it will include the estimated cost
of meeting the annual targets, based on the incremental cost calculations.
This 2025 Renewable Plan shows that PacifiCorp intends to meet Oregon Renewable Portfolio
Standard (RPS) targets during compliance years 2025-2029 with a combination of bundled and
unbundled renewable energy certificates (RECs) from existing Oregon-eligible renewable
resources and resources under development that are anticipated to be Oregon RPS-eligible.
2025 Renewable Plan Methodology and Assumptions
Unless stated otherwise, PacifiCorp prepared this 2025 Renewable Plan consistent with
information from PacifiCorp's 2023 Renewable Portfolio Implementation Plan (RPIP) and its
2025 Integrated Resource Plan (IRP), including load forecasts and projected resources. The
Company's IRP process and its filed documentation are based on the best available information at
the time the IRP was prepared. PacifiCorp's 2025 IRP Action Plan represents a road map for
implementation of the preferred portfolio. Consistent with the 2025 IRP Action Plan and preferred
portfolio, this 2025 Renewable Plan includes new utility-owned or contracted wind resources as
well as new utility-owned or contracted solar resources in 2028 and 2029. Economic and
regulatory environments are continually changing, and PacifiCorp may modify its plans as state
and federal legislation and regulations evolve. Such changes may materially impact resource
acquisitions and the timing of those acquisitions.
In this 2025 Renewable Plan, the Company incorporated the Community Solar Program
subscription sales and deducted those from the Oregon retail sales for the purpose of calculating
the RPS target, pursuant to OAR 860-088-0150 (1). The Company included renewable resources
that have been acquired or are under contract and received Oregon Department of Energy(ODOE)
certification to qualify as eligible for the Oregon RPS. In addition, the plan includes resources
anticipated to receive certification as eligible for the Oregon RPS under ORS 469A.025. Finally,
the plan also assumes that all qualifying resources will be recertified with ODOE to maintain
eligibility through the 2025-2029 planning period. The existing qualifying resources and resources
4 https:Happs.puc.state.or.us/orders/2025ords/25-108.pdf
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PACIFICORP-2025 IRP APPENDIX R-OREGON RPS 2025 RENEWABLE PLAN
under development will enable PacifiCorp to meet the 2025-2029 Oregon RPS targets. This 2025
Renewable Plan assumes that PacifiCorp will use its bank of bundled RECs and that the Company
will not purchase additional unbundled RECs to meet RPS targets in the 2025-2029 reporting
period.
PacifiCorp plans to comply with the Oregon RPS using both bundled and unbundled RECs.
Furthermore, this 2025 Renewable Plan assumes that RECs with the oldest vintage dates will be
used first for RPS compliance before RECs with a newer vintage date. PacifiCorp does not plan to
use any bundled RECs issued between January 1 through March 31 of the year following the
compliance year or alternative compliance payments.
Applicable Requirements
This 2025 Renewable Plan is guided by requirements in statute, rule, and previous Commission
orders, including:
ORS 469A.075(2), which states that a plan for meeting the requirements of the RPS must
contain:
(a) Annual targets for acquisition and use of qualifying electricity; and
(b) The estimated cost of meeting the annual targets,including the cost of transmission,
the cost of firming, shaping and integrating qualifying electricity, the cost of
alternative compliance payments and the cost of acquiring renewable energy
certificates.
OAR 860-083 establishes renewable portfolio standard rules, including OAR 860-083-
0100, which directs regulated entities on how to calculate incremental costs of renewable
resources compared to a proxy plant. This incremental cost calculation is used to show
the estimated cost of meeting the annual targets, as required by ORS 469A.075(2)(b).
Finally, while there are no rules that proscribe the specific proxy plant scenarios,
previous Commission orders have established the following scenarios applicable to this
2025 Renewable Plan:
• Medium carbon dioxide (CO2) and low proxy plant fuel costs
• Medium CO2 and medium proxy plant fuel costs
• Medium CO2 and high proxy plant fuel costs
• High CO2 and medium proxy plant fuel costs
• No CO2 and medium proxy plant fuel costs
• Maximized use of unbundled RECs
The Commission established and amended the required scenarios in Commission Order Nos. 1I-
440, 14-267 and 25-108. A full explanation and description of these scenarios are included in
Chapter 8.
Using the forecasts provided in the 2025 IRP's preferred portfolio and action plan,PacifiCorp will
demonstrate compliance with the authorities listed above and show both annual targets for
acquisition and use of qualifying electricity, and the estimated cost of meeting annual RPS targets
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PACIFICORP-2025 IRP APPENDIX R-OREGON RPS 2025 RENEWABLE PLAN
during the 2025-2029 planning period,in the second part of the 2025 Renewable Plan,filed within
90 days of the 2025 IRP.
ANNUAL TARGETS
The 2025 IRP prepares a forecast of the Oregon retail sales and is provided in Appendix A (Load
Forecast). Table R.1 below provides the RPS compliance percentage target,the forecasted Oregon
retail sales, the amount of energy associated with the Community Solar Program projects, and the
estimated annual megawatt-hour(MWh) targets for each year in the 2025 Renewable Plan.
Table R.1 —Oregon RPS Target Data
2025 2026 2027 2028 2029
Applicable RPS % 27% 27% 27% 27% 27%
as a percentage of
Electricity Sold
Oregon Retail 14.316,773 14,420,803 14,401,692 14,397,746 14,342,388
Sales Forecast
MWh
Community Solar 67,135 66,773 66,464 66,176 65,867
Program MWh
Target retail sales 14,249,638 14,354,030 14,335,228 14,331,570 14,276,521
is calculated by
subtracting the
MWh from the
Community Solar
Program from total
retail sales.
Estimated Oregon 3,847,402 3,875,588 3,870,512 3,869,524 3,854,661
RPS Target
(MWh)
OREGON RPS ELIGIBLE RESOURCES
Generating facilities that have been certified by ODOE as eligible for the Oregon RPS program
and resources that are under development and expected to be certified as eligible for the Oregon
RPS program during the 2025-2029 planning period are listed in Table R.2. The generating
facilities, either owned by PacifiCorp or under contract, are expected to provide RECs for
compliance with the Oregon RPS during the 2025-2029 planning period. Table R.2 provides the
facility name, the facility's energy source, the state where the facility is located, the status of the
facility as either new or existing, and the when the facility became or is expected to become
operational. A new facility is one whose incremental cost has not yet been calculated in a previous
RPIP. An existing facility is one whose incremental cost has been calculated in a previous RPIP.
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PACIFICORP—2025 IRP APPENDIX R—OREGON RPS 2025 RENEWABLE PLAN
Table R.2 — Oregon RPS Generating Facilities and Resources
Energy Source Generating Facility State 0 Commercial
peration
BIOGAS Hill Air Force Base PPA UT 2005
BIOMASS Roseburg Forest Products—Dillard PPA* OR 2019
GEOTHERMAL Blundell II UT 2007
WIND Anticline PPA* WY 2024
Boswell PPA* WY 2024
Campbell Hill-Three Buttes PPA WY 2009
Cedar Creek PPA* ID 2024
Cedar Springs Wind,LLC PPA WY 2020
Cedar Springs Wind III,LLC PPA WY 2020
Cedar Springs II WY 2020
Cedar Springs IV PPA WY 2025
Combine Hills PPA OR 2003
Dunlap I WY 2010
Ekola Flats Wind WY 2020
Foote Creek I WY 1999
Foote Creek III* WY 2024
Foote Creek IV* WY 2024
Glenrock WY 2008
Glenrock III WY 2009
Goodnoe Hills WA 2008
High Plains WY 2009
Latigo PPA WY 2016
Leaning Juniper I OR 2006
Marengo WA 2007
Marengo II WA 2008
Meadow Creek—Five Pine PPA* ID 2012
Meadow Creek—North Point PPA* ID 2012
McFadden Ridge WY 2009
Mountain Wind Power PPA WY 2008
Mountain Wind Power II PPA WY 2008
Pioneer Wind WY 2016
Rock Creek I WY 2025
Rock Creek II WY 2025
Rock River I* WY 2024
Seven Mile Hill I WY 2008
Seven Mile Hill II WY 2008
TB Flats Wind I-II WY 2021
Top of the World PPA WY 2010
Wolverine Creek PPA ID 2006
Proxy Wind OR Various
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PACIFICORP-2025 IRP APPENDIX R-OREGON RPS 2025 RENEWABLE PLAN
HYDRO Ashton ID 1917
Big Fork MT 1929
Clearwater 1 OR 1953
Clearwater 2 OR 1953
Copco 1 CA 1918
Cutler UT 1927
Fish Creek OR 1952
Grace ID 1908
JC Boyle OR 1958
Lemolo 1 OR 1955
Lemolo 2 OR 1956
Oneida ID 1915
Pioneer UT 1897
Prospect 2 OR 1928
Prospect 3 OR 1932
Slide Creek OR 1951
Soda ID 1924
Soda Springs OR 1952
Toketee OR 1950
Yale WA 1953
SOLAR Black Cap PPA OR 2012
Oregon Solar Incentive Program-Central Oregon(CO 1) OR 2010
Oregon Solar Incentive Program-Central Oregon(CO 2) OR 2011
Oregon Solar Incentive Program-Central Oregon(CO 3) OR 2013
Oregon Solar Incentive Program-Central Oregon(CO 4) OR 2016
Oregon Solar Incentive Program-Columbia River(CR 1) OR 2011
Oregon Solar Incentive Program-Columbia River(CR 2) OR 2014
Oregon Solar Incentive Program-Eastern Oregon(EO 1) OR 2010
Oregon Solar Incentive Program-Eastern Oregon(EO 2) OR 2011
Oregon Solar Incentive Program-Portland Oregon(PO 1) OR 2010
Oregon Solar Incentive Program-Portland Oregon(PO 2) OR 2013
Oregon Solar Incentive Program-Portland Oregon(PO 3) OR 2016
Oregon Solar Incentive Program-Southern Oregon(SO 1) OR 2010
Oregon Solar Incentive Program-Southern Oregon(SO 2) OR 2011
Oregon Solar Incentive Program-Southern Oregon(SO 3) OR 2011
Oregon Solar Incentive Program-Southern Oregon(SO 4) OR 2012
Oregon Solar Incentive Program-Southern Oregon(SO 5) OR 2012
Oregon Solar Incentive Program-Southern Oregon(SO 6) OR 2013
Oregon Solar Incentive Program-Southern Oregon(SO 7) OR 2013
Oregon Solar Incentive Program-Southern Oregon(SO 8) OR 2013
Oregon Solar Incentive Program-Southern Oregon(SO 9) OR 2013
Oregon Solar Incentive Program-Southern Oregon(SO 10) OR 2014
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PACIFICORP-2025 IRP APPENDIX R-OREGON RPS 2025 RENEWABLE PLAN
Oregon Solar Incentive Program-Southern Oregon(SO 11) OR 2014
Oregon Solar Incentive Program-Southern Oregon(SO 12) OR 2015
Oregon Solar Incentive Program-Southern Oregon(SO 13) OR 2016
Oregon Solar Incentive Program-Willamette Valley(WV 1) OR 2010
Oregon Solar Incentive Program-Willamette Valley(WV 2) OR 2011
Oregon Solar Incentive Program-Willamette Valley(WV 3) OR 2012
Oregon Solar Incentive Program-Willamette Valley(WV 4) OR 2013
Oregon Solar Incentive Program-Willamette Valley(WV 5) OR 2013
Oregon Solar Incentive Program-Willamette Valley(WV 6) OR 2013
Oregon Solar Incentive Program-Willamette Valley(WV 7) OR 2014
Oregon Solar Incentive Program-Willamette Valley(WV 8) OR 2015
Oregon Solar Incentive Program-Willamette Valley(WV 9) OR 2015
Oregon Solar Incentive Program-Willamette Valley(WV 10) OR 2017
Lakeview OR 2012
Lakeview II OR 2013
Oregon Solar Incentive Program-(Joseph Community)Wallowa OR 2011
County
Powell Butte OR 2014
Crook County Solar OR 2014
Confederated Tribes of Warm Springs(CTWS) OR 2014
Solwatt OR 2012
Solwatt II OR 2014
Bourdet OR 2014
Bourdet II OR 2016
Keeton 1 OR 2016
Keeton 2 OR 2016
Hammerich 1 OR 2016
Hammerich 2 OR 2016
Pavant Solar II LLC PPA UT 2016
Pavant Solar,LLC PPA UT 2015
Enterprise Solar,LLC PPA UT 2016
Adams Solar Center,LLC PPA OR 2018
Bear Creek Solar Center,LLC PPA OR 2018
Bly Solar Center,LLC PPA OR 2018
Elbe Solar Center,LLC PPA OR 2018
Chiloquin Solar PPA* OR 2018
Granite Mountain—East PPA* UT 2016
Granite Mountain—West PPA* UT 2016
Iron Springs Solar PPA* UT 2016
Klamath Falls Solar 2(Ewauna Solar)PPA* OR 2017
Norwest Energy 9(Pendleton)PPA* OR 2018
Oregon Solar Land Holdings(OLSH)PPA* OR 2017
OR Solar 2,LLC(Agate Bay Solar)PPA* OR 2020
525

PACIFICORP—2025 IRP APPENDIX R—OREGON RPS 2025 RENEWABLE PLAN
OR Solar 3,LLC(Turkey Hill Solar)PPA* OR 2017
OR Solar 5,LLC(Merrill Solar)PPA* OR 2018
OR Solar 6,LLC(Lakeview Solar)PPA* OR 2017
OR Solar 8,LLC(Dairy Solar)PPA* OR 2018
Orchard Wind Farm 1,LLC PPA* OR 2020
Orchard Wind Farm 2,LLC PPA* OR 2020
Orchard Wind Farm 3,LLC PPA* OR 2020
Orchard Wind Farm 4,LLC PPA* OR 2020
Sage Solar 1 PPA WY 2019
Sage Solar 2 PPA WY 2019
Sage Solar 3 PPA WY 2019
Skysol Solar PPA* OR 2023
Sweetwater Solar PPA WY 2018
Tumbleweed Solar PPA* OR 2017
Woodline Solar PPA* OR 2017
Proxy Solar OR I Various
*Indicates resource has not been included in previous Oregon Renewable Portfolio Standard Implementation Plans.In some cases,
PacifiCorp may only receive RECs for a portion of the term of the contract.
INCREMENTAMT10STS
Pursuant to Order No.25-108,within 90 days of the filing of PacifiCorp's 2025 IRP,the Company
will provide the estimated cost of meeting the annual targets, including the cost of transmission,
the cost of firming, shaping and integrating qualifying electricity, the cost of alternative
compliance payments and the cost of acquiring renewable energy certificates.
526

PACIFICORP-2025 IRP APPENDIX Z-ACRONYMS
APPENDIX Z - 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
527

PACIFICORP-2025 IRP APPENDIX Z-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
528

PACIFICORP-2025 IRP APPENDIX Z-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
529

PACIFICORP-2025 IRP APPENDIX Z-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
530

PACIFICORP-2025 IRP APPENDIX Z-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
MW=Megawatt
MWh=megawatt hour
531

PACIFICORP-2025 IRP APPENDIX Z-ACRONYMS
$MWh= dollars per megawatt hour
NAAQS =National Ambient Air Quality Standards
NAPEE=National Action Plan for Energy-Efficiency
NCM=nickel cobalt manganese (sub-chemistry of Li-Ion)
NEEA=Northwest Energy Efficiency Alliance
NEEP=Northeast Energy Efficiency Partnerships
NEMA=National Electrical Manufacturer's Association
NEMS =National Energy Modeling System
NERC =North American Electric Reliability Corporation
NH3 =Ammonia
NOAAF =National Oceanic and Atmospheric Administration Fisheries
NRC=Nuclear Regulatory Commission
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
532

PACIFICORP-2025 IRP APPENDIX Z-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
533

PACIFICORP-2025 IRP APPENDIX Z-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
534

PACIFICORP-2025 IRP APPENDIX Z-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= small-scale renewable (note SSR is not used for `supply-side resource')
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
535

PACIFICORP-2025 IRP APPENDIX Z-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
536