202204042021 IRP Update.pdf

ROCKY MOUNTAIN
POWER
ij 1407 W North Temple, Suite 330
Salt Lake City, Utah 84114
, . .: ;,i'il "'i, Pii 3: 2T
April4,2022
YIA ELECTRONIC FILING
Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
I l33l W Chinden Blvd
Building 8 Suite 20lA
Boise,Idaho, 83714
RE: CASE NO. PAC-E-21-19 - PACIFICORP'S APPLICATION FOR
ACKNOWLEDGEMENT OF TIJE 2O2I INTEGRATED RESOURCE PLAN
Dear Ms. Noriyuki:
Please find enclosed PacifiCorp's2021Integrated Resource Plan Update ("2021 IRP Update").
Copies of the 2021 IRP Update are also available electronically on PacifiCorp's website, at
www.pacificorp.com/irp. Confidential and non-confidential workpapers for the 2021 IRP Update
will be made available in BOX, and a separate email will be sent with the password to access this
data.
PacifiCorp's2021IRP Update provides a number of updates including a description of resource
planning, procurement activities, an updated load and resource balance, an updated resource
portfolio reflecting updates to load forecast and other model inputs, and a status update on action
plan items from the 2021 IRP.
All formal correspondence and data requests regarding this filing should be addressed as follows:
By E-mail (prefened):datarequest@pacifi corp.com
[e-mail]
ted.weston@pacifi corp.com
emi l),.wesener@Paci fi corP.com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Affairs Manager, at (801)
220-2963.
April4,2022
Page2
Senior Vice Presidenq Regulation
Enclosures
cc:Jim Yost,Idaho Govemor's Office
Benjarnin Otto, Idatro Conservation League
Mark Stokes, Idaho Power Company
Teni Carloclq Idaho Public Utilities Commission staff
Riley Newton, Idaho Fublic Utilities Commission staff
TJBudge, Monsanto
Nancy Kelly, Western Resource Advocates
Rose Monahan, Sierra Club
Ana Boyd, Sierra Club
Meant for bleeds only! Always bleed this trigon at .125”
2021 Integrated Resource Plan Update
MARCH 31, 2022

This 2021 Integrated Resource Plan Update 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
[phone]
[e-mail]
www.pacificorp.com

Cover Photos (Top to Bottom):
Pavant III Solar Plant
Marengo Wind Project
Transmission Line - Wyoming
Panguitch Solar & Battery Storage
PACIFICORP – 2021 IRP TABLE OF CONTENTS

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TABLE OF CONTENTS

TABLE OF CONTENTS ................................................................................................ i

INDEX OF TABLES .................................................................................................... iv

INDEX OF FIGURES ...................................................................................................vi

CHAPTER 1 – EXECUTIVE SUMMARY…………………………………………………………..……………….1
PACIFICORP’S VISION ..................................................................................................................................................... 1
The time is now .................................................................................................................................................... 1
Delivering on our promise .................................................................................................................................... 1
PUTTING OUR CUSTOMERS AT THE CENTER OF EVERYTHING WE DO .......................................................................................... 2
Our customer-centered vision embodies four core themes: ................................................................................ 2
2021 IRP UPDATE ROADMAP ......................................................................................................................................... 2
PACIFICORP’S INTEGRATED RESOURCE PLAN APPROACH ...................................................................................... 3
2021 IRP UPDATE PREFERRED PORTFOLIO HIGHLIGHTS ......................................................................................... 4
NEW SOLAR RESOURCES ................................................................................................................................................. 8
NEW WIND RESOURCES .................................................................................................................................................. 8
NEW STORAGE RESOURCES.............................................................................................................................................. 9
OTHER NON-EMITTING RESOURCES .................................................................................................................................. 9
DEMAND-SIDE MANAGEMENT ......................................................................................................................................... 9
WHOLESALE POWER MARKET PRICES AND PURCHASES ....................................................................................................... 11
COAL AND GAS RETIREMENTS/GAS CONVERSIONS ............................................................................................................. 12
CARBON DIOXIDE EMISSIONS ......................................................................................................................................... 13
RENEWABLE PORTFOLIO STANDARDS ............................................................................................................................... 14

CHAPTER 2 – INTRODUCTION ………………………………………………………………………………….17

CHAPTER 3 – THE PLANNING ENVIRONMENT ……………………………………………………………….19
FEDERAL POLICY UPDATE ..................................................................................................................................... 19
FEDERAL CLIMATE CHANGE LEGISLATION .......................................................................................................................... 19
NEW SOURCE PERFORMANCE STANDARDS FOR CARBON EMISSIONS – CLEAN AIR ACT § 111(B) ................................................ 19
CARBON EMISSION GUIDELINES FOR EXISTING SOURCES – CLEAN AIR ACT § 111(D) ................................................................ 19
CREDIT FOR CARBON OXIDE SEQUESTRATION – INTERNAL REVENUE SERVICE (IRS) § 45Q ........................................................ 19
CLEAN AIR ACT CRITERIA POLLUTANTS – NATIONAL AMBIENT AIR QUALITY STANDARDS ........................................................... 20
REGIONAL HAZE .......................................................................................................................................................... 22
Utah Regional Haze ............................................................................................................................................ 22
Wyoming Regional Haze .................................................................................................................................... 24
Arizona Regional Haze ....................................................................................................................................... 26
Colorado Regional Haze ..................................................................................................................................... 26
MERCURY AND HAZARDOUS AIR POLLUTANTS ................................................................................................................... 26
COAL COMBUSTION RESIDUALS ...................................................................................................................................... 27
WATER QUALITY STANDARDS ......................................................................................................................................... 28
Cooling Water Intake Structures ........................................................................................................................ 28
Effluent Limit Guidelines .................................................................................................................................... 29
2015 TAX EXTENDER LEGISLATION ................................................................................................................................. 30
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STATE POLICY UPDATE ......................................................................................................................................... 31
CALIFORNIA ................................................................................................................................................................ 31
OREGON .................................................................................................................................................................... 32
WASHINGTON ............................................................................................................................................................. 33
UTAH ........................................................................................................................................................................ 33
WYOMING ................................................................................................................................................................. 34
GREENHOUSE GAS EMISSION PERFORMANCE STANDARDS ................................................................................................... 35
ENERGY GATEWAY TRANSMISSION PROGRAM PLANNING .................................................................................. 35
ENERGY GATEWAY TRANSMISSION PROJECT UPDATES ........................................................................................................ 36
Wallula to McNary (Segment A) ........................................................................................................................ 36
Gateway West (Segments D and E) .................................................................................................................... 37
Gateway West (Segment E)................................................................................................................................ 37
Gateway South (Segment F) ............................................................................................................................... 37
Boardman to Hemingway (Segment H) ............................................................................................................. 38
In-Service Dates .................................................................................................................................................. 38
REGIONAL MARKETS ............................................................................................................................................ 39

CHAPTER 4 – LOAD-AND-RESOURCE BALANCE …………………………………………………………….41
INTRODUCTION ................................................................................................................................................... 41
SYSTEM COINCIDENT PEAK LOAD FORECAST ....................................................................................................... 41
WIND AND SOLAR QUALIFYING FACILITY RESOURCE UPDATES ............................................................................ 42
UPDATED CAPACITY LOAD-AND-RESOURCE BALANCE ......................................................................................... 42
LOAD-AND-RESOURCE BALANCE COMPONENTS ................................................................................................................. 42
Existing Resources .............................................................................................................................................. 43
Obligation ........................................................................................................................................................... 44
System Position .................................................................................................................................................. 45
CAPACITY BALANCE DETERMINATION AND RESULTS ............................................................................................................ 45
Methodology ...................................................................................................................................................... 45
Capacity Balance Results .................................................................................................................................... 46
ENERGY BALANCE DETERMINATION ................................................................................................................................. 52
Methodology ...................................................................................................................................................... 52
ENERGY BALANCE RESULTS ............................................................................................................................................ 53

CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE ….……………………………………………….55
GENERAL ASSUMPTIONS ..................................................................................................................................... 55
INFLATION RATES ......................................................................................................................................................... 55
DISCOUNT FACTOR ....................................................................................................................................................... 55
FRONT OFFICE TRANSACTIONS (FOTS) ............................................................................................................................ 55
STOCHASTIC PARAMETERS ............................................................................................................................................. 56
FLEXIBLE RESERVE STUDY .............................................................................................................................................. 56
NATURAL GAS AND POWER MARKET PRICE UPDATES ......................................................................................... 56
CARBON DIOXIDE EMISSION POLICY .................................................................................................................... 57
SUPPLY-SIDE RESOURCES ..................................................................................................................................... 58
MODELING ENHANCEMENTS AND RESOURCE UPDATES ...................................................................................... 63
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DEMAND SIDE MANAGEMENT ........................................................................................................................................ 63
2020 ALL-SOURCE REQUEST FOR PROPOSALS RESOURCES (2020AS RFP) ............................................................................. 63
OTHER CONTRACTS ...................................................................................................................................................... 63

CHAPTER 6 – PORTFOLIO DEVELOPMENT ……………….….……………………………………………….65
INTRODUCTION ................................................................................................................................................... 65
2021 IRP UPDATE PREFERRED PORTFOLIO ........................................................................................................... 65
KEY UPDATES .............................................................................................................................................................. 65
PORTFOLIO OUTCOMES................................................................................................................................................. 65
Present Value Revenue Requirement (PVRR) ..................................................................................................... 66
Load Increase ..................................................................................................................................................... 67
Transmission Acceleration ................................................................................................................................. 67
New Solar Resources .......................................................................................................................................... 69
New Wind Resources .......................................................................................................................................... 70
New Storage Resources ...................................................................................................................................... 70
Other Non-Emitting Resources ........................................................................................................................... 71
Demand-Side Management ............................................................................................................................... 71
Market Activity ................................................................................................................................................... 72
Coal and Gas Retirements/Gas Conversions ...................................................................................................... 72
CARBON DIOXIDE EMISSIONS .............................................................................................................................. 81
RENEWABLE PORTFOLIO STANDARDS ................................................................................................................. 82
WASHINGTON CLEAN ENERGY TRANSFORMATION ACT ...................................................................................... 85
OREGON CLEAN ENERGY PLAN ............................................................................................................................ 87
PROJECTED ENERGY MIX ..................................................................................................................................... 87
ADDITIONAL STUDIES .......................................................................................................................................... 88
Boardman-to-Hemingway Variant (No B2H) ..................................................................................................... 89
Energy Gateway South and Sub-Segment D.1 Variant (No GWS) ...................................................................... 91
2020AS RFP Variant (No RFP) ............................................................................................................................. 93
REGIONAL HAZE HUNTER-HUNTINGTON SENSITIVITY .......................................................................................................... 95

CHAPTER 7 – ACTION PLAN UPDATE …………………….….……………………………………………….97

APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS ………………..………………..………………109

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INDEX OF TABLES

CHAPTER 1 – EXECUTIVE SUMMARY
TABLE 1.1 – TRANSMISSION UPGRADE CHANGES IN THE 2021 IRP UPDATE PREFERRED PORTFOLIO COMPARED TO THE 2021 IRP
PREFERRED PORTFOLIO ..................................................................................................................................... 6
TABLE 1.2 – TRANSMISSION PROJECTS INCLUDED IN THE 2021 IRP UPDATE PREFERRED PORTFOLIO ........................................ 7

CHAPTER 2 – INTRODUCTION

CHAPTER 3 – THE PLANNING ENVIRONMENT
TABLE 3.1 – TAX EXTENDER LEGISLATION AND PHASEOUT OF PTC AND ITC ....................................................................... 31
TABLE 3.2 - ENERGY GATEWAY SEGMENT IN-SERVICE DATES .......................................................................................... 39

CHAPTER 4 – LOAD-AND-RESOURCE BALANCE
TABLE 4.1 – NEW POWER PURCHASE AGREEMENTS ...................................................................................................... 42
TABLE 4.2 – SUMMER PEAK - SYSTEM CAPACITY LOAD AND RESOURCE BALANCE WITHOUT RESOURCE ADDITIONS, 2021 IRP
UPDATE (2022-2031) (MEGAWATTS) ............................................................................................................. 47
TABLE 4.3 – WINTER PEAK – SYSTEM CAPACITY LOAD AND RESOURCE BALANCE WITHOUT RESOURCE ADDITIONS, 2021 IRP
UPDATE (2022-2031) (MEGAWATTS) ............................................................................................................ 49

CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE
TABLE 5.1 - MAXIMUM AVAILABLE FRONT OFFICE TRANSACTION QUANTITY BY MARKET HUB .............................................. 56
TABLE 5.2 - 2021 IRP UPDATE SUPPLY SIDE RESOURCES ............................................................................................... 61
TABLE 5.3 – 2021 IRP UPDATE SUPPLY SIDE RESOURCES .............................................................................................. 61
TABLE 5.4 – 2021 IRP UPDATE SUPPLY SIDE RESOURCES .............................................................................................. 62

CHAPTER 6 – PORTFOLIO DEVELOPMENT
TABLE 6.1 – COST AND RISK PORTFOLIO SUMMARY ...................................................................................................... 66
TABLE 6.2 – TRANSMISSION UPGRADE CHANGES IN THE 2021 IRP UPDATE PREFERRED PORTFOLIO COMPARED TO THE 2021 IRP
PREFERRED PORTFOLIO ................................................................................................................................... 68
TABLE 6.3 – TRANSMISSION PROJECTS INCLUDED IN THE 2021 IRP UPDATE PREFERRED PORTFOLIO ...................................... 69
TABLE 6.4 – COMPARISON OF 2021 IRP UPDATE WITH 2021 IRP PREFERRED PORTFOLIO (MEGAWATTS) ............................. 75
TABLE 6.5 – 2021 IRP UPDATE SUMMER CAPACITY LOAD AND RESOURCE BALANCE (MEGAWATTS) ..................................... 77
TABLE 6.6 – 2021 IRP UPDATE WINTER CAPACITY LOAD AND RESOURCE BALANCE (MEGAWATTS) ...................................... 79
TABLE 6.7 – PVRR(D) OF THE 2021 IRP UPDATE PORTFOLIO RELATIVE TO THE BASE PORTFOLIO UNDER VARYING PRICE-POLICY
SCENARIOS ................................................................................................................................................... 86
TABLE 6.8 – BASE CASE VARIANT PORTFOLIOS ............................................................................................................. 89
TABLE 6.9 – COST AND RISK SUMMARY OF VARIANT PORTFOLIOS .................................................................................... 89
TABLE 6.10 – PVRR(D) OF THE NO B2H PORTFOLIO RELATIVE TO THE BASE PORTFOLIO UNDER VARYING PRICE-POLICY
SCENARIOS ................................................................................................................................................... 91
TABLE 6.11 – PVRR(D) OF THE NO GWS PORTFOLIO RELATIVE TO THE BASE PORTFOLIO UNDER VARYING PRICE-POLICY
SCENARIOS ................................................................................................................................................... 93
TABLE 6.12 – PVRR(D) OF THE NO RFP PORTFOLIO RELATIVE TO THE BASE PORTFOLIO UNDER VARYING PRICE-POLICY
SCENARIOS ................................................................................................................................................... 95
TABLE 6.13 – COST AND RISK SUMMARY OF REGIONAL HAZE HUNTER-HUNTINGTON SENSITIVITY ......................................... 95

CHAPTER 7 – ACTION PLAN UPDATE
TABLE 7.1 – 2021 IRP ACTION PLAN STATUS UPDATE................................................................................................... 97
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APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS
TABLE A.1 – FORECASTED ANNUAL LOAD GROWTH, 2022 THROUGH 2031 (MEGAWATT-HOURS), AT ................................ 109
TABLE A.2 - FORECASTED ANNUAL COINCIDENT PEAK LOAD (MEGAWATTS) AT GENERATION, PRE- ...................................... 110
TABLE A.3 – ANNUAL LOAD GROWTH CHANGE: 2021 IRP UPDATE FORECAST LESS 2021 IRP FORECAST (MEGAWATT-HOURS) AT
GENERATION, PRE-DSM ............................................................................................................................... 110
TABLE A.4 – ANNUAL COINCIDENT PEAK GROWTH CHANGE: 2021 IRP UPDATE FORECAST LESS 2017 IRP FORECAST
(MEGAWATTS) AT GENERATION, PRE-DSM ..................................................................................................... 111
TABLE A.5 – SYSTEM ANNUAL RETAIL SALES FORECAST 2022 THROUGH 2031 (MEGAWATT-HOURS), POST-DSM ................ 111
TABLE A.6– FORECASTED RETAIL SALES GROWTH IN OREGON, POST-DSM ..................................................................... 112
TABLE A.7 – FORECASTED RETAIL SALES GROWTH IN WASHINGTON, POST-DSM ............................................................. 112
TABLE A.8 – FORECASTED RETAIL SALES GROWTH IN CALIFORNIA, POST-DSM ................................................................. 113
TABLE A.9 – FORECASTED RETAIL SALES GROWTH IN UTAH, POST-DSM ......................................................................... 113
TABLE A.10 – FORECASTED RETAIL SALES GROWTH IN IDAHO, POST-DSM ...................................................................... 114
TABLE A.11 – FORECASTED RETAIL SALES GROWTH IN WYOMING, POST-DSM ................................................................ 114

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INDEX OF Figures

CHAPTER 1 – EXECUTIVE SUMMARY
FIGURE 1.1 – KEY ELEMENTS OF PACIFICORP’S 2021 IRP APPROACH ................................................................................ 4
FIGURE 1.2 – 2021 IRP UPDATE PREFERRED PORTFOLIO (ALL RESOURCES) ........................................................................ 5
FIGURE 1.3 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW SOLAR CAPACITY .................................................................. 8
FIGURE 1.4 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW WIND CAPACITY .................................................................. 8
FIGURE 1.5 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW STORAGE CAPACITY .............................................................. 9
FIGURE 1.6 – 2021 IRP UPDATE OTHER NON-EMITTING RESOURCES CAPACITY .................................................................. 9
FIGURE 1.7 – FORECASTED ANNUAL LOAD (GWH) (BEFORE INCREMENTAL ENERGY EFFICIENCY SAVINGS) .............................. 10
FIGURE 1.8 -- FORECASTED ANNUAL COINCIDENT PEAK LOAD (MW) ............................................................................... 10
FIGURE 1.9 – 2021 IRP UPDATE PREFERRED PORTFOLIO ENERGY EFFICIENCY (CLASS 2 DSM) AND DIRECT LOAD CONTROL
CAPACITY (CLASS 1 DSM) .............................................................................................................................. 11
FIGURE 1.10 – COMPARISON OF POWER PRICES AND NATURAL GAS PRICES IN RECENT IRPS ................................................ 11
FIGURE 1.11 – 2021 IRP UPDATE MARKET ACTIVITY COMPARISON TO 2021 IRP STUDIES ................................................. 12
FIGURE 1.12 – 2021 IRP UPDATE PREFERRED PORTFOLIO CO2 EMISSIONS AND PACIFICORP CO2 EQUIVALENT EMISSIONS
TRAJECTORY ................................................................................................................................................. 14
FIGURE 1.13 – ANNUAL STATE RPS COMPLIANCE FORECAST .......................................................................................... 15

CHAPTER 2 – INTRODUCTION

CHAPTER 3 – THE PLANNING ENVIRONMENT
FIGURE 3.1 – ENERGY GATEWAY MAP ........................................................................................................................ 36

CHAPTER 4 – LOAD-AND-RESOURCE BALANCE
FIGURE 4.1 - FORECASTED ANNUAL LOAD (GWH) ........................................................................................................ 41
FIGURE 4.2 – FORECASTED ANNUAL COINCIDENT PEAK LOAD (MW) ............................................................................... 42
FIGURE 4.3 – SUMMER SYSTEM CAPACITY POSITION TREND ........................................................................................... 51
FIGURE 4.4 – WINTER SYSTEM CAPACITY POSITION TREND ............................................................................................ 52
FIGURE 4.5 – SYSTEM AVERAGE MONTHLY ENERGY POSITIONS ....................................................................................... 53

CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE
FIGURE 5.1 – NOMINAL WHOLESALE ELECTRICITY AND NATURAL GAS PRICE SCENARIOS ...................................................... 57
FIGURE 5.2 – MEDIUM, HIGH AND SOCIAL COST OF GREENHOUSE GAS CO2 PRICES ........................................................... 58

CHAPTER 6 – PORTFOLIO DEVELOPMENT
FIGURE 6.1 – CUMULATIVE INCREASE/(DECREASE) IN 2021 IRP UPDATE AND ................................................................... 66
FIGURE 6.2 – ANNUAL PRESENT VALUE REVENUE REQUIREMENT COMPARISON ................................................................. 67
FIGURE 6.3 – LOAD FORECAST COMPARISON ............................................................................................................... 67
FIGURE 6.4 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW SOLAR CAPACITY ................................................................ 70
FIGURE 6.5 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW WIND CAPACITY ................................................................ 70
FIGURE 6.6 – 2021 IRP UPDATE PREFERRED PORTFOLIO NEW STORAGE CAPACITY ............................................................ 71
FIGURE 6.7 – 2021 IRP UPDATE OTHER NON-EMITTING RESOURCES CAPACITY ................................................................ 71
FIGURE 6.8 – 2021 IRP UPDATE PREFERRED PORTFOLIO ENERGY EFFICIENCY (CLASS 2 DSM) AND DIRECT LOAD CONTROL
CAPACITY (CLASS 1 DSM) .............................................................................................................................. 72
FIGURE 6.9 – 2021 IRP UPDATE MARKET ACTIVITY COMPARISON TO 2021 IRP STUDIES ................................................... 72
FIGURE 6.10 – 2021 IRP UPDATE PREFERRED PORTFOLIO COAL RETIREMENTS/GAS CONVERSIONS ...................................... 73
FIGURE 6.11 – 2021 IRP PREFERRED PORTFOLIO CO2 EMISSIONS AND PACIFICORP CO2 EQUIVALENT EMISSIONS TRAJECTORY . 81
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FIGURE 6.12 – 2021 IRP UPDATE MONTHLY CO2 ....................................................................................................... 82
FIGURE 6.13 – ANNUAL STATE RPS COMPLIANCE FORECAST .......................................................................................... 84
FIGURE 6.14 - 2021 IRP UPDATE INTERIM TARGETS .................................................................................................... 87
FIGURE 6.15 – PROJECTED ENERGY MIX WITH 2021 IRP UPDATE PREFERRED PORTFOLIO RESOURCES .................................. 88
FIGURE 6.16 – INCREASE/(DECREASE) IN PROXY RESOURCES WHEN THE B2H TRANSMISSION LINE IS ELIMINATED FROM THE BASE
PORTFOLIO ................................................................................................................................................... 90
FIGURE 6.17 - INCREASE/(DECREASE) IN SYSTEM COSTS WHEN THE B2H TRANSMISSION LINE IS ELIMINATED FROM THE BASE
PORTFOLIO ................................................................................................................................................... 90
FIGURE 6.18 – INCREASE/(DECREASE) IN PROXY RESOURCES WHEN THE GWS AND D.1 TRANSMISSION LINES ARE ELIMINATED
FROM THE BASE PORTFOLIO ............................................................................................................................. 92
FIGURE 6.19 – INCREASE/(DECREASE) IN SYSTEM COSTS WHEN THE GWS AND D.1 TRANSMISSION LINES ARE ELIMINATED FROM
THE BASE PORTFOLIO ..................................................................................................................................... 92
FIGURE 6.20 – INCREASE/(DECREASE) IN PROXY RESOURCES WHEN 2020AS RFP RESOURCES ARE ELIMINATED FROM THE BASE
PORTFOLIO ................................................................................................................................................... 94
FIGURE 6.21 – INCREASE/(DECREASE) IN SYSTEM COSTS WHEN RFP PROJECTS AND GWS AND D.1 TRANSMISSION LINES ARE
ELIMINATED FROM THE BASE PORTFOLIO ........................................................................................................... 94

CHAPTER 7 – ACTION PLAN UPDATE

APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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CHAPTER 1 – EXECUTIVE SUMMARY
PacifiCorp submitted its 2021 Integrated Resource Plan (IRP) to state regulatory commissions on
September 1, 2021. That plan provides a framework for future actions that PacifiCorp will take to
provide reliable and reasonably priced service for its customers through the least-cost, least-risk
resource portfolio. The 2021 IRP Update reflects resource planning and procurement activities that
have occurred since the 2021 IRP and presents an updated load-and-resource balance and an
updated resource portfolio consistent with changes in the planning environment. The 2021 IRP
Update also provides a status update for the action plan filed with the 2021 IRP. In presenting the
updated load-and-resource balance and updated resource portfolio, PacifiCorp highlights changes
in the 2021 IRP Update preferred portfolio relative to the 2021 IRP preferred portfolio which
covers the 2021 to 2040 planning horizon. Consistent with the 2021 IRP, the 2021 IRP Update
preferred portfolio demonstrates reliable service will be maintained with investment in
transmission infrastructure, the conversion of two coal units to natural gas peaking units, growth
in demand response programs, the addition of advanced nuclear resources, the addition of energy
storage resources, and over the long term, the addition of non-emitting peaking resources.
PacifiCorp’s Vision
The time is now

At PacifiCorp, we share a vision with our customers and communities in which clean energy from
across the West powers jobs and innovation. This bold vision has guided our work for years. Most
recently, it took shape in our 2017, 2019 and 2021 IRPs, in which we outlined an ambitious path
to substantially increase our renewable energy capacity, evolving our existing portfolio and
connecting supply with demand through an expanded, modernized transmission system.

Delivering on our promise

The power of the West lies in its diversity: windswept plains and high deserts, the sun-soaked
Great Basin, and rivers fed by rain and mountain snow. Taken together, these reserves of wind,
solar and hydro power can help meet the growing and changing needs of homes and businesses
throughout the West, cleanly, reliably and affordably.

Yet, capturing this power alone is not enough. To unlock the full promise of these abundant
resources, we must add transmission and storage capacity, unlock customer demand response
resources with a modernized grid, and replace retiring thermal resources with non-emitting
resources like advanced nuclear, to connect the West to its energy future—built on a resilient,
hardened, adaptable grid that safely delivers power when and where it’s needed.

PacifiCorp’s 2021 IRP Update remains a roadmap for action and reinforces the significant progress
toward the goals laid out in the 2017, 2019 and 2021 IRPs. The 2021 IRP Update also confirms
the benefits of critical investments in expanded and modernized transmission, renewable energy,
storage, demand response and advanced nuclear resources.

PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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Our integrated system connects and brings new opportunities to the West, building on a foundation
of infrastructure designed to handle extreme weather and enhance the energy resilience of
communities from the Pacific Coast to the Rocky Mountains, all while continuing to deliver energy
solutions for our customers at prices that are below national and regional averages.

As our 2021 IRP Update shows, this expanded, modernized transmission system will connect
supply with demand from east to west and from north to south, serving as the backbone of the
West for the hundreds of energy providers that serve our region alongside PacifiCorp.
Putting our customers at the center of everything we do
At PacifiCorp, we’re committed to meeting the demands of our customers and communities
throughout the West to deliver safe, affordable, clean energy and a resilient, modern grid.

Together with the communities we serve and our regional partners, it is time to act, with targeted,
strategic investments that will position us to continue delivering affordable, reliable power.

Our customer-centered vision embodies four core themes:

Reliable Power: We strive to deliver energy safely during all hours, and plan extensively to ensure
that we have sufficient supply and ability to deliver to the communities we serve. We understand
that electricity is an essential service, and work around the clock to ensure that we are dependable,
and communities can rely on us.

Resilient Infrastructure: We live in times of rapid change, with more extreme weather and
challenging conditions. We are working to minimize disruptions, implement strategies to recover
quickly when they occur, and deploy upgrades that will strengthen our critical infrastructure.

Affordable Prices: PacifiCorp is proud to be one of the lowest-cost electricity providers in the
nation and the region. As we plan for our next generation of resources, we are prioritizing resources
that add value and keep customer prices low.

Clean Energy: Through strategic, customer-focused investments in diverse resources, PacifiCorp
remains committed to reducing carbon emissions, system-wide, by 74 percent from 2005 levels by
2030. Although a higher load forecast has driven an increase in emissions based on this IRP
Update, primarily in the last 10 years of the 20-year study period, the 2021 IRP Update resource
plan includes continued significant new renewable additions among other diverse, advanced
technologies to keep us on that path and achieve even deeper decarbonization beyond 2030. The
higher load forecast can be viewed as a less extreme version of the S01 High Load sensitivity from
the 2021 IRP, driving a similar trajectory. However, PacifiCorp fully anticipates that additional
transmission and resource options explored in the 2023 IRP will counter the immediate appearance
on an uptick in emissions outcomes.
2021 IRP Update Roadmap
The 2021 IRP Update continues to fulfill on PacifiCorp’s bold vision for the West between now
and 2040 and stays on course to achieve a clean, resilient and affordable energy future that
PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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leverages the abundant, diverse, clean energy resources that the West can offer through a
modernized and expanded grid.

• Continue our growth into a grid powered by clean energy:
o 4,685 MW from energy efficiency programs
o 5,297 MW of new solar resources (most paired with storage)
o 4,160 MW of new wind resources
o 5,546 MW of storage resources, including battery storage co-located with solar,
standalone battery storage and pumped hydro storage resources
o 978 MW of direct load control programs
o 500 MW of advanced nuclear (the Natrium TM reactor demonstration project) in
2028, with an additional 1,000 MW of advanced nuclear over the long-term
o 1,237 MW of non-emitting peaker resources

• Connect and optimize these diverse, clean resources across the West with a
strengthened and modernized transmission network that ensures resilient service,
reduces costs and creates maximum opportunities for our communities to thrive
(incremental to projects already online):
o 416 miles of new transmission from the new Aeolus substation near Medicine
Bow, Wyoming, to the Clover substation near Mona, Utah (Energy Gateway
South)
o 59 miles of new transmission from the Shirley Basin substation in southeastern
Wyoming to the Windstar substation near Glenrock, Wyoming (Energy Gateway
West Sub-Segment D.1)
o 290 miles of new transmission from the Boardman substation in north central
Oregon to the Hemingway substation in south central Idaho

PacifiCorp’s Integrated Resource Plan Approach
PacifiCorp has been making progress in its efforts to bring the best of the West to its customers.
In September 2021, the 2021 IRP set forth a clear path to provide reliable and reasonably priced
service to its customers. The analysis supporting this plan helps PacifiCorp, its customers, and its
regulators understand the effect of both near-term and long-term resource decisions on customer
bills, the reliability of electric service PacifiCorp customers receive, and changes to emissions
from the generation sources used to serve customers. In the 2021 IRP Update, PacifiCorp presents
a preferred portfolio that continues to build 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. All of this can be achieved by maintaining
reliable service with incremental investments in transmission infrastructure and other non-emitting
flexible resources capable of shaping and responding to changes in energy from an increasing
supply of wind and solar resources.

The primary objective of an IRP is to identify the best mix of resources to serve customers in the
future. The best mix of resources is identified through analysis that measures cost and risk. The
least-cost, least-risk resource portfolio—defined as the “preferred portfolio”—is the portfolio that
can be delivered through specific action items at a reasonable cost and with manageable risks,
PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

4

while considering customer demand for clean energy and ensuring compliance with state and
federal regulatory obligations.

The 2021 IRP Update serves as a checkpoint to the recent IRP roadmap to ensure that changes in
the planning environment are considered in between the full IRP planning process that is
completed every two years, thus providing guidance as to constantly evolving trends and events
which may ultimately impact our customers.

As depicted in Figure 1.1, PacifiCorp’s 2021 IRP and this 2021 IRP Update were developed by
working through five fundamental planning steps that began with development of key inputs and
assumptions to inform the modeling and portfolio evaluation process. The optimization of the
updated preferred portfolio allows for a new endogenous selection of retirements, transmission
and resources to meet projected gaps in the updated load and resource balance, characterized by
the type, timing, and location of new resources in PacifiCorp’s system. Options for the 2021 IRP
Update considered a wide range of potential coal retirement dates, options to convert to gas or to
retrofit for carbon capture utilization and sequestration for certain coal units, and other planning
uncertainties.

PacifiCorp then developed key variants of the updated preferred portfolio, focusing on three
variant studies from the 2021 IRP which address large transmission projects and significant
volumes of associated resources. 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
the comparative cost, risk, reliability, and emission levels. This resource portfolio analysis
ultimately informed selection of the least-cost and least-risk portfolio and the 2021 IRP Update
preferred portfolio.

Figure 1.1 – Key Elements of PacifiCorp’s 2021 IRP Approach

2021 IRP Update Preferred Portfolio Highlights
Figure 1.2 shows that PacifiCorp’s 2021 Update preferred portfolio continues to include
substantial new renewables, facilitated by incremental transmission investments, demand-side
management (DSM) resources, significant storage resources, and continues to show support for
advanced nuclear and non-emitting peaker resources.

By the end of 2024, the 2021 IRP Update preferred portfolio includes the 2020 All-Source Request
for Proposals (RFP) final shortlist resources. These projects include 1,792 MW of wind, 1,150
MW of solar additions, and 639 MW of battery storage capacity—439 MW paired with solar and
PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

5

a 200 MW standalone battery.1 During this time, the Update preferred portfolio also includes the
acquisition and repowering of Rock River I (49 MW) and Foote Creek II-IV (43 MW) wind
projects located in Wyoming. Through the end of 2026, the 2021 IRP Update preferred portfolio
includes an additional 597 MW of wind and an additional 600 MW solar co-located with storage.
The 2021 IRP Update preferred portfolio includes the 500 MW advanced nuclear NatriumTM
demonstration project, which will come online by summer 2028. Through 2040, the 2021 IRP
Update preferred portfolio includes 1,000 MW of additional advanced nuclear resources and 1,237
MW of non-emitting peaking resources.

Over the 20-year planning horizon, the 2021 IRP Update preferred portfolio includes 4,160 MW2
of new wind and 5,297 MW of new solar co-located with storage.

Figure 1.2 – 2021 IRP Update Preferred Portfolio (All Resources)

To facilitate the delivery of new renewable energy resources to PacifiCorp customers across the
West, the updated preferred portfolio includes necessary transmission investments. Specifically,
the portfolio includes the Energy Gateway South transmission line - a new 416-mile high-voltage
500-kilovolt transmission line and associated infrastructure running from the new Aeolus
substation near Medicine Bow, Wyoming, to the Clover substation near Mona, Utah. The 2021
Update preferred portfolio also includes the Energy Gateway West Subsegment D.1 project - a
new 59-mile, high-voltage (230-kilovolt) transmission line from the Shirley Basin substation in
southeastern Wyoming to the Windstar substation near Glenrock, Wyoming. Both transmission
lines will come online by the end of 2024.

1 The reported capacity for RFP solar resources reflects their expected maximum output after degradation in their first
full year of operation.
2 This figure includes 160 MW of hybrid wind located in Yakima Washington as part of CETA compliance
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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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The 2021 IRP Update preferred portfolio also includes a 290-mile high-voltage 500-kilovolt
transmission line known as Boardman-to-Hemingway, which connects those respective
substations in Oregon and Idaho, which will come online in 2026. Further, the portfolio includes
near-term and long-term transmission upgrades across the system that will facilitate continued and
long-term growth in new resources needed to serve our customers.

A higher load forecast drives new and accelerated transmission in the updated preferred portfolio.
Table 1.1 reports changes in transmission selections relative to the 2021 IRP. Four transmission
paths are accelerated and two new paths are selected, adding 300 MW of interconnection capability
to the system. One transmission upgrade, Portland North coast to Willamette Valley, is delayed in
the back 10 years of the model horizon. Finally, one transmission path, Portland North Coast to
Southern Oregon, is removed, partly offset by the accelerations, particularly of the Central Oregon
to Willamette Valley transmission line, as well as the additional transmission options.

Table 1.1 – Transmission Upgrade Changes in the 2021 IRP Update Preferred Portfolio
Compared to the 2021 IRP Preferred Portfolio1
1 – Negative values in the “Change” column indicates the number of years of acceleration compared to the 2021 IRP Preferred
Portfolio.

Table 1.2 summarizes the incremental transmission projects in the 2021 IRP Update preferred
portfolio.
Upgrade Export Capacity 2021 Update Year 2021 IRP Year Change
CON Central OR > TxCON 2027 100 2030 2037 -7
CON Yakima > TxCON 2027a 180 2029 2030 -1
CON Yakima > TxCON 2027b 100 2029 -New
INC Central OR > Willamette Valley 2037 1500 2037 2040 -3
INC Portland North Coast > Southern Oregon 2037 1500 -2040 Removed
INC Portland North Coast > Willamette Valley 2032 450 2038 2032 6
INC Utah South > Utah North 2032 800 2032 2033 -1
INC Walla Walla - WA > Yakima 2030 200 2030 -New
PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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Table 1.2 – Transmission Projects Included in the 2021 IRP Update Preferred Portfolio1,2,*
1 - TTC = 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 - Energy Gateway South is modeled in the 2021 IRP Update as a contingent option with bids in the 2020 All-Source
Request for Proposals. Other transmission options prior to 2026 are not modeled as transmission requirements and
costs are accounted for in the 2020 All-Source Request for Proposals transmission cluster study for all other resource
bids.
* - Reclaimed transmission is committed with resources with a commercial operation date later than the date of
retirement.
PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

8

New Solar Resources
As reported in Figure 1.3, the 2021 IRP Update preferred portfolio includes 1,709 MW of new
solar by the end of 2024 and 2,309 MW by the end of 2026, with additions of 5,297 MW through
2040. Accounting for a 153 MW reduction in resources associated with the 2020 AS RFP, the
2021 IRP Update includes 833 MW more new solar capacity by the end of 2031 compared to the
2021 IRP preferred portfolio. After 2031, driven by more efficient higher cost transmission and
energy efficiency gains, solar additions are ultimately reduced 730 MW by 2040.

Figure 1.3 – 2021 IRP Update Preferred Portfolio New Solar Capacity*
* 2021 IRP Update solar capacity shown in the figure includes solar resources coming via the 2020 All-Source Request
for Proposals by the end of 2024. Resources are shown in the first full year of operation (the year after the year-online
dates). The reported capacity for the 2020 All-Source Request for Proposals solar resources reflects their expected
maximum output after degradation in their first full year of operation.
New Wind Resources
As shown in Figure 1.4, by the end of 2024, PacifiCorp’s 2021 IRP Update preferred portfolio
includes 1,815 MW of new wind generation resulting from the 2020 All-Source RFP and the
acquisition and repowering of Rock River I (49 MW) and Foote Creek II-IV (43 MW). Through
the end of 2026, the 2021 IRP Update preferred portfolio includes an additional 2,363 MW of new
wind and more than 4,000 MW of new wind by 2040. Relative to the 2021 IRP, 2021 IRP Update
wind additions are mostly reduced or flat through 2037, and ultimately increase by 348 MW of
new wind by the end of 2040.

Figure 1.4 – 2021 IRP Update Preferred Portfolio New Wind Capacity*
*Note: Wind additions shown are incremental to Energy Vision 2020 and other projects that have come online over
the past few years. Resources are shown in the first full year of operation (the year after year-end online dates).
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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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New Storage Resources
New storage resources in the 2021 IRP Update preferred portfolio are summarized in Figure 1.5.
The updated portfolio includes nearly 639 MW of battery storage by the end of 2024 – 200 MW
of which is a standalone battery and the remaining portion paired with solar resources resulting
from the 2020 All-Source RFP. Through 2040, the 2021 IRP includes 4,146 MW of storage co-
located with solar resources, 900 MW of standalone battery, and 500 MW of pumped hydro.

Figure 1.5 – 2021 IRP Update Preferred Portfolio New Storage Capacity*
*Note: Resources are shown in the first full year of operation (the year after the year-end online dates).
Other Non-Emitting Resources
The 2021 IRP was the first to include new advanced nuclear and non-emitting peaking resources
as part of its least-cost, least-risk preferred portfolio. The 2021 IRP Update continues to select
these resources. As shown in Figure 1.6, the 500 MW advanced nuclear NatriumTM demonstration
project is projected to come online by summer 2028. Through 2040, the 2021 IRP Update preferred
portfolio includes 1,500 MW of advanced nuclear resources and 1,237 MW of non-emitting
peaking resources.

Figure 1.6 – 2021 IRP Update Other Non-Emitting Resources Capacity*
*Note: Resources are shown in the first full year of operation (the year after the year-end online dates).
Demand-Side Management
PacifiCorp evaluates new DSM opportunities, which includes both energy efficiency and direct
load control programs, as a resource that competes with traditional new generation and wholesale
power market purchases when developing the IRP Update preferred portfolio. Figure 1.7 shows
that PacifiCorp’s load forecast before incremental energy efficiency savings has increased relative
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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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to projected loads used in the 2021 IRP. On average, forecasted system load is up 1.9 percent and
forecasted coincident system peak is up 2.1 percent when compared to the 2021 IRP. Over the
planning horizon, the average annual growth rate, before accounting for incremental energy
efficiency improvements, is 1.28 percent for load and 0.85 percent for peak. Changes to
PacifiCorp’s load forecast are driven by higher projected demand from data centers driving up the
commercial forecast.

Figure 1.7 – Forecasted Annual Load (GWh) (Before Incremental Energy Efficiency
Savings)

Figure 1.8 -- Forecasted Annual Coincident Peak Load (MW)

PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

11

DSM resources continue to play a key role in PacifiCorp’s resource mix. The chart to the left in
Figure 1.9 compares total energy efficiency capacity savings in the 2021 IRP Update preferred
portfolio relative to the 2021 IRP preferred portfolio and includes 4,685 MW by the end of the
planning period. This increase is attributed to the reductions in demand response, combined with
the alignment of energy efficiency to load, both described in Chapter 5 – Modeling Updates. For
the 2021 IRP Update, selections of demand response have been scaled back to realistic targets,
which is responsible for decreases shown on the right-hand side of Figure 1.9. Demand response
selections in the 2021 IRP Update total nearly 1,000 MW over the 20-year horizon. By the end of
2040 and relative to the 2021 IRP preferred portfolio, energy efficiency selection increases by
nearly 400 MW, whereas demand response selections are reduced by more than 1,400 MW.

Figure 1.9 – 2021 IRP Update Preferred Portfolio Energy Efficiency (Class 2 DSM) and
Direct Load Control Capacity (Class 1 DSM)

Wholesale Power Market Prices and Purchases
Figure 1.10 summarizes the three wholesale electricity price forecasts and three natural gas price
forecasts used in the Base and scenario cases for the 2021 IRP Update. As shown, low and medium
power and gas prices are higher in the near term. All three power price scenarios trend higher
beginning in 2024, but generally escalate at different increasing rates. Additional detail regarding
power and gas prices is provided in Chapter 5 – Modeling and Assumptions Update.

Figure 1.10 – Comparison of Power Prices and Natural Gas Prices in Recent IRPs

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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

12

Figure 1.11 compares market purchases and sales among the 2021 IRP preferred portfolio, the
2021 IRP S01 High Load sensitivity and the 2021 IRP Update. While the 2021 IRP Update
averages approximately 500 GWh additional sales annually compared to the 2021 IRP preferred
portfolio or the 2021 IRP High Load scenario, offsetting purchases are higher in some years,
particularly 2032 to 2037. On average, 2021 IRP Update purchase increase by an average of 200
MW annually on a purely volumetric basis. Given near-term concerns over resource adequacy,
generally lower market purchases in 2021 IRP Update portfolio in the first 5 years are viewed
favorably.

Figure 1.11 – 2021 IRP Update Market Activity Comparison to 2021 IRP Studies

Coal and Gas Retirements/Gas Conversions
Coal resources have been an important resource in PacifiCorp’s resource portfolio for many years.
PacifiCorp’s coal resources will continue to play a pivotal role in following fluctuations in
renewable energy as the remaining coal units approach retirement dates. The 2021 IRP Update
yields the same retirement timing as seen in the 2021 IRP. Driven in part by ongoing cost pressures
on existing coal-fired facilities and cost-effective new resource alternatives, of the 22 coal units
currently serving PacifiCorp customers, the preferred portfolio includes retirement of 14 of the
units by 2030 and 19 of the 22 units by the end of the planning period in 2040.

Coal unit retirements scheduled under the preferred portfolio include:
• 2023 = Jim Bridger Units 1-2, converted to natural gas peakers
• 2025 = Naughton Units 1-2
• 2025 = Craig Unit 1
• 2025 = Colstrip Units 3-4
• 2027 = Dave Johnston Units 1-4
• 2027 = Hayden Unit 2
• 2028 = Craig Unit 2
• 2028 = Hayden Unit 1
• 2036 = Huntington Units 1-2
• 2037 = Jim Bridger Units 3-4
• 2039 = Wyodak
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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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In addition to the coal unit retirements outlined above, the preferred portfolio reflects 1,554 MW
natural gas retirements through 2040. This includes Naughton Unit 3 at the end of 2029, Gadsby
at the end of 2032, Hermiston at the end of 2036, and Jim Bridger Units 1 and 2 at the end of 2037.
Carbon Dioxide Emissions
While the 2021 IRP Update preferred portfolio reflects PacifiCorp’s on-going efforts to provide
cost-effective clean-energy solutions for our customers, increased load has driven thermal dispatch
and therefore emissions higher based on currently modeled resource options and assumptions.
Portfolio emissions and costs due to the higher load forecast present a less extreme version of the
S01 High Load sensitivity from the 2021 IRP.

PacifiCorp’s emissions have been declining and are expected to continue to decline related to
several factors including PacifiCorp’s participation in the energy imbalance market, which reduces
customer costs and maximizes use of clean energy; PacifiCorp’s on-going transition to clean-
energy resources including new renewable resources, new advanced nuclear resources, new non-
emitting resources, storage, transmission, and Regional Haze compliance that capitalizes on
flexibility. Input updates and additional transmission and resource options in the 2023 IRP are
expected to allow economic emissions reductions not available to the 2021 IRP Update and in the
absence of a full IRP cycle.

The chart on the left in Figure 1.12 compares projected annual CO2 emissions between the 2021
IRP update and 2021 IRP preferred portfolios. In this graph, emissions are not assigned to market
purchases or sales.

The chart on the right in Figure 1.12 includes historical data, assigns emissions at a rate of 0.4708
tons CO2 equivalent per MWh to market purchases (with no credit to market sales), includes
emissions associated with specified purchases, and extrapolates projections out through 2050. This
graph demonstrates that relative to a 2005 baseline, 2021 IRP Update preferred portfolio system
CO2 equivalent emissions are down 49 percent in 2025, 69 percent in 2030, 78 percent in 2035,
88 percent in 2040, 94 percent in 2045, and 100 percent in 2050.

PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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Figure 1.12 – 2021 IRP Update Preferred Portfolio CO2 Emissions and PacifiCorp CO2
Equivalent Emissions Trajectory*

*Note: PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2020 from owned facilities,
specified sources and unspecified sources. From 2022 through the end of the twenty-year planning period in 2040,
emissions reflect those from the 2021 IRP Update preferred portfolio with emissions from specified sources reported
in CO2 equivalent. Beyond 2040, emissions reflect the rolling average emissions of each resource from the 2021 IRP
update preferred portfolio through the life of the resource. The emissions trajectory does not incorporate clean energy
targets set forth in Oregon House Bill 2021 or any other state-specific emissions trajectories. PacifiCorp expects these
targets, and an Oregon-specific emissions trajectory, to be incorporated following the 2023 integrated resource plan
when PacifiCorp is required under the bill to file a Clean Energy Plan.
Renewable Portfolio Standards
Figure 1.13 shows PacifiCorp’s renewable portfolio standard (RPS) compliance forecast for
California, Oregon, and Washington after accounting for new renewable resources in the preferred
portfolio. While these resources are included in the preferred portfolio as cost-effective system
resources and are not included to specifically meet RPS targets, they nonetheless contribute to
meeting RPS targets in PacifiCorp’s western states.
Oregon RPS compliance is achieved through 2040 with the addition of new renewable resources
and transmission in the 2021 IRP Update preferred portfolio. Consistent with the 2021 IRP, in the
2021 IRP Update, Washington RPS compliance is achieved with the benefit of increased system
renewable resources beginning 2022 as well as additional resources procured that meet the state’s
Clean Energy Transformation Act. Under PacifiCorp’s 2020 Protocol, and the Washington
Interjurisdictional Allocation Methodology, Washington’s RPS position is improved by receiving
a system share of renewable resources across the PacifiCorp’s system.
The California RPS compliance position will be met with owned and contracted renewable
resources, as well as REC purchases throughout the study period. The ramping RPS requirement
results in an increased need for unbundled REC purchases to meet the annual and compliance
period targets in 2021-2040. New renewable resources and transmission in the 2021 IRP update
preferred portfolio mitigate that shortfall, but the company has made a 120,000 REC purchase
towards compliance period 4, years 2021-2024, and will continue to evaluate the need for
unbundled RECs and issue RFPs to meet its state RPS compliance requirements as needed.
While not shown in Figure 1.13, PacifiCorp meets the Utah 2025 state target to supply 20 percent
of adjusted retail sales with eligible renewable resources with existing owned and contracted
resources and new renewable resources and transmission in the 2021 IRP Update preferred
portfolio.
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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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Figure 1.13 – Annual State RPS Compliance Forecast

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PACIFICORP – 2021 IRP CHAPTER 1 – EXECUTIVE SUMMARY

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PACIFICORP – 2021 IRP UPDATE CHAPTER 2 – INTRODUCTION
17

CHAPTER 2 – INTRODUCTION
This 2021 IRP Update describes resource planning activities following the filing of the 2021 IRP
on September 1, 2021 and presents an updated load-and-resource balance, an updated preferred
portfolio consistent with changes in the planning environment and provides a status update on the
action plan filed with the 2021 IRP. In presenting the updated load and resource balance
assessment and updated preferred portfolio, PacifiCorp describes changes relative to the 2021 IRP.

PacifiCorp’s 2021 IRP Update preferred portfolio reflects updates to load, existing resources,
signed contracts and modeling improvements. The 2021 IRP Update also includes an update to
certain variant analysis conducted in the 2021 IRP related to portfolio analysis of major
transmission projects and related resources including Energy Gateway South and D.1, Boardman-
to-Hemingway and the 2020 All Source Request for Proposals final shortlist projects.

Chapter 1 of the 2021 IRP Update provides an executive summary focused on the updated
preferred portfolio. Chapter 3 describes the current planning environment, load updates, resource
updates, state and federal policy updates, transmission upgrades and recent changes in the Western
Resource Adequacy Program. Chapter 4 provides updated load-and-resource balance information.
Chapter 5 describes changes to key inputs and assumptions relative to those used for the 2021 IRP.
Chapter 6 presents the updated preferred portfolio, variant studies, a regional haze study and
additional bookend price-policy studies for information. A status update on the 2021 IRP Action
Plan is provided in Chapter 7. The Appendix provides additional load forecast details.

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CHAPTER 3 – THE PLANNING ENVIRONMENT
Federal Policy Update
Federal Climate Change Legislation
To date, no federal legislative climate change proposal has been passed by the U.S. Congress.
Federal climate change legislation is not anticipated in the near term but remains possible in the
mid- to long-term.
New Source Performance Standards for Carbon Emissions – Clean Air Act
§ 111(b)
New Source Performance Standards (NSPS) are established under the Clean Air Act for certain
industrial sources of emissions determined to endanger public health and welfare. On October 23,
2015, the U.S. Environmental Protection Agency (EPA) finalized a rule limiting carbon emissions
from coal-fueled and natural-gas-fueled power plants. New natural-gas-fueled power plants can
emit no more than 1,000 pounds of carbon dioxide (CO2) per megawatt-hour (MWh). New coal-
fueled power plants can emit no more than 1,400 pounds of CO2/MWh. The final rule largely
exempts simple cycle combustion turbines from meeting the standards. On December 6, 2018, the EPA
proposed to revise the NSPS for greenhouse gas emissions from new, modified, and reconstructed
fossil fuel-fired power plants. EPA’s proposal would replace EPA’s 2015 determination that carbon
capture and storage technology was the best system of emissions reduction for new coal units. The
comment period for the proposed revisions closed in March 2019. In January 2021, the EPA issued the
final rule. However, in April 2021, at the request of the EPA as directed by the Biden Administration,
the D.C. Circuit vacated and remanded the January 2021 final rule.
Carbon Emission Guidelines for Existing Sources – Clean Air Act § 111(d)
On August 3, 2015, EPA issued a final rule, referred to as the Clean Power Plan (CPP), regulating
CO2 emissions from existing power plants.

On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP suspending implementation
of the rule pending the outcome of the merits of litigation before the D.C. Circuit Court of Appeals.
On October 10, 2017, EPA proposed to repeal the CPP and on August 21, 2018, proposed the
Affordable Clean Energy (ACE) rule to replace the CPP. The ACE rule sets forth a list of
“candidate technologies” that states can use to reduce greenhouse gas emissions at coal-fueled
power plants. The ACE rule was finalized June 19, 2019, replacing the CPP. On January 19, 2021,
the D.C. Circuit vacated the ACE rule and directed the EPA to proceed with new rulemaking for
the control of carbon emissions from electric utility coal-fired boilers.

Credit for Carbon Oxide Sequestration – Internal Revenue Service (IRS) § 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
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per metric ton (tonne) of qualified carbon oxide captured and sequestered.1 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.2 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
captured annually and is available for 12 years from the date the carbon capture equipment is originally
placed into service.3
Clean Air Act Criteria Pollutants – National Ambient Air Quality Standards
The Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) for six
criteria pollutants that have the potential of harming human health or the environment. The
NAAQS are rigorously vetted by the scientific community, industry, public interest groups, and
the general public, and establish the maximum allowable concentration allowed for each “criteria”
pollutant in outdoor air. The six pollutants are carbon monoxide, lead, ground-level ozone,
nitrogen dioxide (NOX), particulate matter (PM), and sulfur dioxide (SO2). The standards are set
at a level that protects public health with an adequate margin of safety. All states are required to
develop a state implementation plan (SIP) to implement the NAAQS, and that plan must be
approved by EPA. The plan must provide for implementation, maintenance, and enforcement of
the NAAQS for each pollutant, with more specific requirements and limits imposed on states that
fail to achieve the NAAQS for a particular pollutant. SIPs must also contain adequate provisions
to prevent emissions that significantly contribute to nonattainment of the NAAQS in any other
state.

In October 2015, EPA issued a final rule modifying the standards for ground-level ozone from
75 parts per billion (ppb) to 70 ppb. On November 16, 2017, the EPA designated all counties where
PacifiCorp’s coal facilities are located (Lincoln, Sweetwater, Converse and Campbell Counties in
Wyoming; and Emery County in Utah) as attainment/unclassifiable. On June 4, 2018, the EPA
designated two areas in Utah as Marginal Nonattainment: Salt Lake County and three neighboring
counties (Northern Wasatch Front) where the PacifiCorp Gadsby facility is located, and part of
Utah County (Southern Wasatch Front) where the PacifiCorp Lake Side facility is located. A
marginal designation is the least stringent classification for an ozone nonattainment area and does
not require a formal nonattainment SIP. Utah submitted its strategy for meeting the standard to
EPA in May of 2021. The Wasatch Front was required to attain the ozone standard by August 3,
2021. Recent monitoring data indicates that the Southern Wasatch Front nonattainment area has
attained the standard, and Utah has initiated the process for redesignation to attainment for this
area. However, recent monitoring data indicates that the Northern Wasatch Front nonattainment
area will not attain the ozone standard by that date and will be bumped up to moderate
classification in 2022.

1 Before February 9, 2018, the tax credit was strictly for CO2.
2 The tax credit reaches $35/tonne and $50/tonne in 2026.
3 For an electric generating facility, a minimum of 500,000 tonnes of qualified carbon oxide must be captured per
year to receive the 45Q tax credit. Construction of the qualified facility must begin before January 1, 2026.
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On March 11, 2022, the Environmental Protection Agency released a pre-publication version of
its "Ozone Transport Rule" (also called Good Neighbor Rule or Cross-State Air Pollution Rule),
which contains proposed revisions intended to address ozone transport between states. The rule is
focused on reductions of nitrogen oxides, precursors to ozone formation, and covers 26 states. Four
states, including Wyoming and Utah, are included in the cross-state program for the first time.

Under the proposed rule, beginning in 2023, trading allowances and emissions budgets would be
set to achieve reductions from current emissions through immediately available measures. Starting
in May of 2026, emissions budgets would be set for coal-fired units at levels achievable by the
installation of selective catalytic reduction (SCR) controls. Daily emission “backstop” limits for
units with SCR will become effective in 2027.

PacifiCorp is evaluating the pre-publication version of the proposed rule and its potentially
significant impacts on coal-fired power plants in both Utah and Wyoming as first-time participants
in the trading program. PacifiCorp anticipates submitting comments as part of the public comment
process. The public comment process will commence when the proposed rule is published in the
Federal Register and run for 60-days. Further review of the lengthy and complex OTR is needed
to determine how it will impact specific Utah and Wyoming facilities. However, on initial review,
it appears that emissions levels for coal-fired units without SCR could be significantly impacted
starting in 2026, while existing natural gas units will not experience significant reduction
requirements from 2021 levels. The rule has yet to be formally proposed and could change before
its expected finalization in late 2022 or early 2023.

In April 2017, the EPA Administrator signed a final action to reclassify the Salt Lake City and
Provo PM2.5 nonattainment area from moderate to serious. PacifiCorp’s Lake Side and Gadsby
facilities were identified as major sources subject to Utah’s serious nonattainment area SIP for
PM2.5 and PM2.5 precursors. On April 27, 2017, PacifiCorp submitted a best-available control
measure technology analysis for Lake Side and Gadsby to the Utah Division of Air Quality for
review. PacifiCorp proposed ammonia limits for the Gadsby and Lake Side facilities. On January
2, 2019, the Utah Air Quality Board adopted source specific emission limits and operating
practices in the SIP which incorporated the current emission and operating limits for the Lake Side
and Gadsby facilities. On November 6, 2020, EPA proposed approval to redesignate the Salt Lake
City and Provo nonattainment areas for PM2.5 as attainment. The rulemaking was delayed by
corrections issued in May of 2021 and has not yet been finalized.

On January 9, 2018, EPA published the results for the air quality designations for the 2010 SO2
primary NAAQS-Round three in the Federal Register. The Utah county of Emery, where
PacifiCorp’s Hunter and Huntington Generation Stations are located, was classified as
attainment/unclassifiable. The Wyoming counties of Campbell and Lincoln, where PacifiCorp’s
Wyodak and Naughton generation stations are located, were classified as
attainment/unclassifiable. The eastern portion of Sweetwater County, where PacifiCorp’s Jim
Bridger generation station is located, was classified as attainment/unclassifiable. PacifiCorp’s Jim
Bridger facility has conducted on-site ambient SO2 monitoring to demonstrate compliance and is
currently working with the state and federal agencies to terminate the monitoring site. On March
26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard.
Included in this round was designation of Converse County, Wyoming as an
attainment/unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in
Converse County. PacifiCorp facilities located in areas classified as attainment/unclassifiable will
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be required to demonstrate ongoing compliance by performing modeling every three years using
actual facility emission data.
Regional Haze
EPA’s regional haze rule, finalized in 1999, requires states to develop and implement plans to
improve visibility in certain national park and wilderness areas. On June 15, 2005, EPA issued
final amendments to its regional haze rule to require emission controls known as the 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,
SO2, certain volatile organic compounds, and ammonia. The 2005 amendments included final
guidelines, known as BART guidelines, for states to use in determining which facilities must install
controls and the type of controls the facilities must use. States were given until December 2007 to
develop their implementation plans, in which states were responsible for identifying the facilities
that would have to reduce emissions under BART guidelines, as well as establishing BART
emissions limits for those facilities. States are also required to periodically update or revise their
implementation plans to reflect current visibility data and an effective long-term strategy for
achieving reasonable progress toward visibility goals. In January 2017, EPA issued a final rule
updating requirements for the first periodic update to the SIP. EPA required states to submit their
second periodic SIP update by July 31, 2021, unless granted an extension.

The regional haze rule is intended to achieve natural visibility conditions by 2064 in specific
National Parks and Wilderness Areas, many of which are in the western United States where
PacifiCorp owns and operates several coal-fired generating units (Utah, Wyoming, Colorado and
Montana as well as Arizona, where a PacifiCorp-owned coal unit ceased operating in 2020).

On August 20, 2019, EPA issued a final guidance document on the technical aspects of developing
regional haze SIPs for the second implementation period of the Regional Haze Program. EPA
issued additional guidance through a memorandum on July 8, 2021, that emphasizes the 4-factor
reasonable progress analysis for the second planning period and the reduced weight of visibility as
a factor in the second planning period.

Utah Regional Haze
In May 2011, the state of Utah issued a regional haze SIP requiring the installation of SO2, NOX
and PM controls on Hunter Units 1 and 2 and Huntington Units 1 and 2. In December 2012, the
EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOX and PM
portions. EPA’s approval of the SO2 SIP was appealed by environmental advocacy groups to the
Tenth Circuit Court of Appeals (“Tenth Circuit” or “Court"). In addition, PacifiCorp and the state
of Utah appealed EPA’s disapproval of the NOX and PM SIP. PacifiCorp and the state’s appeals
were dismissed, and EPA’s approval of the SO2 SIP was upheld by the Tenth Circuit. In June 2015,
the state of Utah submitted a revised SIP to EPA for approval with an alternative BART NOX
analysis incorporating a requirement for PacifiCorp to retire Carbon Units 1 and 2, crediting NOX
controls previously installed on Hunter Unit 3, and concluding that no incremental controls
(beyond those included in the May 2011 SIP and already installed) were required at the Hunter
and Huntington units. On June 1, 2016, EPA issued a final rule to partially approve and partially
disapprove Utah’s regional haze BART NOx SIP and propose a federal implementation plan (FIP).
The FIP required the installation of selective catalytic reduction (SCR) controls by August 4, 2021,
at four of PacifiCorp’s units in Utah: Hunter Units 1 and 2 and Huntington Units 1 and 2. On
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September 2, 2016, the state of Utah and PacifiCorp filed petitions for administrative and judicial
review of EPA’s final rule, followed by a motion to stay the effective date of the final rule.

On June 30, 2017, Utah and PacifiCorp provided new information to EPA, again requesting
reconsideration. EPA responded on July 14, 2017, indicating its intent to reconsider its FIP. EPA
also filed a motion with the Tenth Circuit to stay EPA’s FIP and hold the litigation in abeyance
pending the rule’s reconsideration. On September 11, 2017, the Tenth Circuit granted the petition
for stay and the request for abatement. The compliance deadline of the FIP and the litigation were
stayed pending EPA’s reconsideration, and EPA was required to file periodic status reports with
the Court.

Utah and PacifiCorp worked with EPA to develop a revised Utah Regional Haze SIP, based on the
new Comprehensive Air Quality Model with Extensions (CAMx) modeling. The Utah Air Quality
Board approved the revised SIP on June 24, 2019, and the SIP Revision was submitted to EPA for
review on July 3, 2019. On December 3, 2019, Utah submitted a supplement to EPA with a minor
SIP revision relating to PM 2.5.

On January 10, 2020, the EPA published its proposed approval of the Utah SIP Revision and
withdrawal of the FIP requirements for the installation of SCR on Hunter Units 1 and 2 and
Huntington Units 1 and 2. After receiving public comments and holding a public hearing in the
Price area on February 12, 2020, EPA issued final approval of the Utah SIP Revision and FIP
withdrawal on November 27, 2020. The final rule credits existing NOX emission controls at the
Hunter and Huntington plants as well as NOX and PM emission reductions provided by the closure
of the Carbon plant in 2015. Based on the newly approved plan, EPA also withdrew the 2016 FIP
requirements to install selective catalytic reduction (SCR) control technology on Hunter Units 1
and 2 and Huntington Units 1 and 2. On January 11, 2021, the Tenth Circuit granted Utah,
PacifiCorp, and EPA’s motion to dismiss the Utah regional haze petitions.

Environmental advocacy groups filed a petition for review, objecting to the revised Utah regional
haze SIP on January 19, 2021, in the Tenth Circuit. At EPA’s request, the Tenth Circuit abated the
petition on February 4, 2021, while EPA considered the petition under the new Biden
administration’s guidelines. The state of Utah, PacifiCorp and co-owners of the Hunter plant filed
motions to intervene. EPA notified the court that it would defend the revised Utah regional haze
SIP, and the court granted intervention to Utah and PacifiCorp in December of 2021. The parties
scheduled briefing, and HEAL Utah submitted its opening brief on February 8, 2022, challenging
the legitimacy of the states’ modeling as well as crediting emissions from the Carbon plant
retirement and requesting reinstatement of the FIP and the SCR requirement at Hunter Units 1 and
2 and Huntington Units 1 and 2. EPA’s response brief is due April 5, 2022, with briefs from Utah
and PacifiCorp to follow on May 3, 2022.

The Western Regional Air Partnership (WRAP) developed modeling for the state’s use for the
implementation of the second planning period. Utah used a ‘Q/d’ screening level of 10 to determine
which sources to evaluate for reasonable progress controls under the rule. On April 21, 2020,
PacifiCorp submitted a Regional Haze Reasonable Progress Analysis for the second planning
period to the Utah Department of Environmental Quality (Utah DEQ) for PacifiCorp’s Huntington
and Hunter plants. The analysis was requested by the State as part of its second planning period
SIP (2PP SIP) development process. PacifiCorp’s analysis included a proposal to implement
reasonable progress emission limits for NOx and SO2 on the Hunter and Huntington units to meet
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second planning period requirements. On October 20, 2020, PacifiCorp submitted a follow-up
letter in response to questions from the Utah DEQ about proposed emission reductions and costs
for control technology.
The state is on track to submit a final implementation plan to the state air quality board in March
or April 2022 and plans to submit the final state-approved implementation plan to the
Environmental Protection Agency late summer/early fall of 2022.

Wyoming Regional Haze
On January 30, 2014, EPA issued a final rule partially approving and partially disapproving the Wyoming
SIP. The final rule required installation of the following NOX and PM controls at PacifiCorp facilities
for regional haze first planning period:

• Naughton Units 1 and 2: low-NOX burners (LNB)/over-fired air (OFA) as BART
• Naughton Unit 3 by December 31, 2014: SCR equipment and a baghouse, BART
• Jim Bridger Units 1 – 4: LNB/separated over-fired air (SOFA), BART
• Jim Bridger Unit 3 by December 31, 2015: SCR equipment, long-term strategy (LTS)
• Jim Bridger Unit 4 by December 31, 2016: SCR equipment, LTS
• Jim Bridger Unit 2 by December 31, 2021: SCR equipment, LTS
• Jim Bridger Unit 1 by December 31, 2022: SCR equipment, LTS
• Dave Johnston Unit 3: SCR within five years or a commitment to shut down in 2027,
BART
• Dave Johnston Unit 4: LNB/OFA, BART
• Wyodak: SCR equipment within five years, BART

Wyodak – PacifiCorp and the state of Wyoming petitioned EPA’s final action on Wyodak, which
required SCR. PacifiCorp and the state of Wyoming successfully requested a stay of EPA’s final
rule relating to the Wyoming SIP, pending resolution of the petition. PacifiCorp subsequently
submitted a request for reconsideration to EPA and is currently engaged in a settlement process
with EPA and Wyoming. The EPA, state of Wyoming and PacifiCorp signed a Settlement
Agreement for Wyodak on December 16, 2020, removing the requirement to install SCR in lieu
of monthly and annual NOX emission limits. EPA published the Settlement Agreement in the
Federal Register requesting public comment on January 4, 2021. PacifiCorp submitted formal
comments to the EPA on March 5, 2021, in support of the Wyodak Settlement Agreement. The
public comment period was extended through July 6, 2021. EPA did not proceed with final
approval of the Settlement Agreement and is currently engaged with Wyoming and PacifiCorp
regarding alternative paths for resolution.

Naughton – In its 2014 rule, EPA approved Wyoming’s determination that BART for Units 1 and
2 was LNB/OFA. EPA also indicated support for the conversion of Naughton Unit 3 to natural gas
in lieu of retrofitting the unit with SCR and stated that it would expedite consideration of the gas
conversion once the state of Wyoming submitted the requisite SIP amendment. Wyoming
submitted its regional haze SIP amendment regarding Naughton Unit 3 to EPA on November 28,
2017. On March 7, 2017, Wyoming issued PacifiCorp a permit for Naughton Unit 3’s conversion
to natural gas, extending the requirement to cease coal firing to no later than January 30, 2019.
PacifiCorp ceased coal operation on Naughton Unit 3 on January 30, 2019. EPA’s final rule
approval of Wyoming’s SIP revision for Naughton Unit 3 gas conversion was published in the
Federal Register on March 21, 2019, with an effective date of April 22, 2019. Naughton Unit 3
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currently operates on natural gas. Environmental groups petitioned EPA’s approval of LNB/OFA
as BART for Units 1 and 2 in the Tenth Circuit. The petition was stayed by the Court and remains
stayed. The environmental groups have participated in on-going mediation with Wyoming,
PacifiCorp and EPA to settle the Naughton claims.

Jim Bridger – PacifiCorp installed SCR on Jim Bridger Units 3 and 4 by 2015 and 2016, the dates
required by Wyoming state law as well as the 2014 SIP. On February 5, 2019, PacifiCorp
submitted to Wyoming an application and proposed SIP revision instituting plant-wide variable
average monthly-block pound per hour NOX and SO2 emission limits, in addition to an annual
combined NOX and SO2 limit, on all four Jim Bridger units in lieu of the requirement to install
SCR on Units 1 and 2. The proposed SIP revision demonstrates that the proposed limits are more
cost effective while leading to better modeled visibility than the SCR installation on Units 1 and 2
required in the federally approved SIP.

Wyoming’s proposed approval of the SIP revision was published for public comment July 20,
2019, through August 23, 2019. On May 5, 2020, the Wyoming Department of Environmental
Quality issued permit P0025809 with PacifiCorp’s proposed monthly and annual NOX and SO2
emission limits. Under the permit, the new emissions limits become effective January 1, 2022.
Wyoming submitted a corresponding regional haze SIP revision to EPA on May 14, 2020. After
initially signaling that the SIP revision had been approved by EPA Region 8 in November of 2020,
EPA did not finalize the approval by publication in the Federal Register after an administration
change. EPA failed to act upon the SIP revision by November 14, 2021, as required by law. EPA,
PacifiCorp and Wyoming worked to find a solution for the unresolved SIP revision and the pending
January 1, 2022, SCR requirement.

Using authority granted by the Clean Air Act, the Governor of Wyoming issued a temporary
emergency order on December 27, 2021, suspending the current state implementation plan
requirement for Jim Bridger Unit 2 to install SCR by December 31, 2021. The suspension was
issued for the full four months allowed by the act due to EPA’s failure to act on the SIP revision
submitted by Wyoming in 2020, by November 14, 2021. EPA published a proposed disapproval
of Wyoming’s SIP revision on January 18, 2022, commencing a 30-day public comment period.
Discussions between EPA, Wyoming, and PacifiCorp regarding the SIP revision and regional haze
compliance at Jim Bridger are ongoing. The Wyoming district court approved a consent decree
between PacifiCorp and Wyoming on February 14, 2022, to resolve regional haze compliance
issues for the Jim Bridger plant. The consent decree enables PacifiCorp to continue operation of
Jim Bridger units 1 and 2 until they are converted to natural gas in 2024. The consent decree
commits Wyoming to processing a state implementation plan revision with post-conversion
emission limits in a timely manner.
WRAP performed modeling for the state to use for the implementation of the second planning
period. On March 31, 2020, PacifiCorp submitted a four-factor reasonable progress analysis to
Wyoming which analyzed PacifiCorp’s Naughton, Jim Bridger, Dave Johnston, and Wyodak
plants. The four-factor analysis was used by the state in its development of the SIP for the regional
haze second planning period (2PP SIP). The state of Wyoming issued its proposed 2PP SIP for
public comment on February 18, 2022, and held a public hearing on March 23, 2022 to receive
comments on their proposed plan. PacifiCorp participated in the hearing and provided verbal and
written comments. It is estimated that the state will submit a final state-approved implementation
plan to the U.S. Environmental Protection Agency in April 2022. In February of 2022
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environmental groups submitted a 60-day notice of intent to sue EPA to take action against states
that have missed the deadline to submit their second planning period SIPs.

Arizona Regional Haze
The state of Arizona issued a regional haze SIP requiring, among other things, the installation of
SO2, NOX and PM controls on Cholla Unit 4, which is owned by PacifiCorp and operated by
Arizona Public Service. EPA approved, in part, and disapproved, in part, the Arizona SIP and
issued a FIP requiring the installation of SCR equipment on Cholla Unit 4. PacifiCorp filed an
appeal regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as
related to their interests. For the Cholla FIP requirements, the Ninth Circuit Court of Appeals
stayed the appeals while parties attempted to agree on an alternative compliance approach.

In July 2016, the EPA issued a proposed rule to approve an alternative Arizona SIP, which included
the option to convert Cholla 4 to a natural gas-fired unit or retire the unit by in 2025. EPA approved
the revised SIP on March 27, 2017. The final action allowed Cholla Unit 4 to utilize coal until
April 30, 2025, with an option to convert to gas by July 31, 2025. Cholla Unit 4 was retired in
December 2020.

Colorado Regional Haze
The Colorado regional haze SIP required SCR controls at Craig Unit 2 and Hayden Units 1 and 2,
which were installed by the required dates, and the installation of selective non-catalytic reduction
(SNCR) technology at Craig Unit 1. Environmental groups appealed EPA’s action, and PacifiCorp
intervened in support of EPA. In July 2014, parties to the litigation, other than PacifiCorp, entered
into a settlement agreement that required installation of SCR equipment at Craig Unit 1 in 2021.
This was incorporated into a regional haze SIP revision that was approved by EPA in 2015. EPA
approved a modified SIP on July 5, 2018, that requires Craig Unit 1 to retire by December 31, 2025,
or, to convert the unit to natural gas by August 31, 2023.

Colorado’s regional haze SIP for the second planning period were adopted in phases in 2020 and
2021 by the Colorado Air Quality Control Commission. The SIP includes retirements of Craig
Units 1 and 2 by 2025 and 2028, respectively, and Hayden Units 1 and 2 by 2028 and 2027,
respectively.
Mercury and Hazardous Air Pollutants
The Mercury and Air Toxics Standards (MATS) became effective April 16, 2012. The MATS rule
requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid
gases and other non-mercury hazardous air pollutants. Existing sources were required to comply
with the new standards by April 16, 2015. However, individual sources may have been granted up
to one additional year, at the discretion of the Title V permitting authority, to complete installation
of controls or for transmission system reliability reasons. By April 2015, PacifiCorp had taken the
required actions to comply with MATS across its generation facilities. On April 25, 2016, the EPA
published a Supplemental Finding that determined that it is appropriate and necessary to regulate under
the MATS rule which addressed the Supreme Court decision.

On February 7, 2019, the EPA published a reconsideration of the Supplemental Finding in which it
proposed to find that it is not appropriate and necessary to regulate hazardous air pollutants, reversing
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the Agency’s prior determination. In May 2020, the EPA published its decision to repeal the
appropriate and necessary findings in the MATS rule regarding regulation of electric utility steam
generating units, and to retain the rule’s current emission standards. The rule took effect in July 2020.
Several petitions for review were filed in the D.C. Circuit by parties challenging and supporting the
EPA's decision to rescind the appropriate and necessary finding. On February 9, 2022, the EPA
proposed to revoke the May 2020, decision that is not appropriate and necessary to regulate under
Section 112 and reaffirm the April 2016 finding.
Coal Combustion Residuals
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal
combustion byproducts under the Resource Conservation and Recovery Act (RCRA). The final rule
became effective October 19, 2015. The final rule regulates coal combustion byproducts as non-
hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the
disposal of coal combustion residuals (CCR). Under the final rule, surface impoundments and
landfills utilized for coal combustion byproducts may need to be closed unless they can meet the
more stringent regulatory requirements. The final rule requires regulated entities to post annual
groundwater monitoring and corrective action reports. The first of these reports was posted to
PacifiCorp’s coal combustion rule 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 became effective in October 2015, nine surface impoundments and four landfills were in operation
and subject to the final rule. Since that time, three surface impoundments have been closed under the
CCR rules and two are in the process of closure.

Multiple parties filed challenges over various aspects of the final rule in 2015, resulting in settlement
of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive
surface impoundments to regulation. In response to legal challenges and court actions, EPA, in March
2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the
agency. The proposal included provisions that establish alternative performance standards for owners
and operators of CCR units located in states that have approved permit programs or are otherwise
subject to oversight through a permit program administered by the EPA. The first phase of the CCR
rule amendments was made effective in August 2018 (the "Phase 1, Part 1 rule"). In addition to
adopting alternative performance standards and revising groundwater performance standards for
certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined
ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's
aquifer location restrictions to October 2020.

Following the March 2019 submittal of competing motions from environmental groups, EPA finalized
its Holistic Approach to Closure: Part A rule ("Part A rule") in September 2020. The rule reclassified
compacted-soil lined surface impoundments from "lined" to "unlined," established a deadline of April
11, 2021, by which all unlined surface impoundments must initiate closure, and revised the alternative
closure provisions to grant facilities additional time to initiate closure in order to manage CCR and
non-CCR waste streams either due to a lack of alternative capacity or due to a commitment to close
the coal-fueled operating unit and complete closure of unlined impoundments by a date certain. The
Part A rule also revised certain requirements regarding annual groundwater monitoring and corrective
action reports and publicly accessible CCR internet sites. A provision in Part A allows demonstrations
to be submitted to the EPA allowing for operation of unlined CCR ponds beyond the April 11, 2021,
deadline for initiation of closure. The demonstrations were allowed to be submitted for: (1) a site-
specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023;
and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and
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complete ash pond closure activities by October 17, 2028. PacifiCorp has submitted alternative
closure demonstrations for the Naughton South Ash Pond and the Jim Bridger FGD Pond 2, submitted
in November 2020. Approval of these demonstrations was anticipated in first quarter 2021 prior to
the April 11, 2021, cease receipt of waste date, but has not been granted as of February 2022. On
January 11, 2022, PacifiCorp received notice from the EPA that the Jim Bridger and Naughton
demonstrations have been determined to be complete and the April 11, 2021, cease receipt of waste
deadline is tolled until the EPA issues a final decision.

On October 16, 2020, the EPA released the pre-publication version of the final Holistic Approach to
Closure: Part B rule ("Part B rule"). The Part B rule finalizes a two-step process, as set forth in the
March 2020 proposal, allowing facilities to request approval to continue operating an existing unlined
CCR surface impoundment with an alternate liner system. The other provisions that were contained in
the Part B proposal, including (1) options to use CCR during closure of a CCR unit, (2) an additional
closure-by-removal option and (3) new requirements for annual closure progress reports, were not
finalized with the Part B rule. These options will be addressed by the EPA in a subsequent rulemaking
action. In addition to the Part A and Part B rules, the EPA has proposed the Phase II rule, the federal
CCR permit program rule, and the advanced notice of proposed rulemaking for legacy impoundments.
Until the proposals are finalized and fully litigated, PacifiCorp cannot determine whether additional
action may be required.

Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' CCR
permit programs should comply with the requirements of the final rule as authorized under the
December 2016 Water Infrastructure Improvements for the Nation Act. To date, none of the states in
which PacifiCorp operates has submitted an application to the EPA for approval of state permitting
authority. The state of Utah adopted the federal final rule in September 2016, which required
PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that
the state of Utah will submit an application to EPA for approval of CCR permit program prior to the
end of 2022. In 2019, the state of Wyoming proposed to adopt state rules which incorporate the final
federal rule by reference. Wyoming finalized its rule in late 2020 and is waiting on legislative approval,
likely in 2022, before submitting an application to the EPA to implement a state permit program.
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 U.S. through a program that regulates, among other
things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling-
water-intake structures reflect the “best technology available for minimizing adverse
environmental impact” to aquatic organisms. In May 2014, EPA issued a final rule, effective
October 2014, under § 316(b) of the Clean Water Act to regulate cooling-water intakes at existing
facilities. The final rule established requirements for electric-generating facilities that withdraw
more than two million gallons per day, based on total design intake capacity, of water from waters
of the U.S. and use at least 25 percent of the withdrawn water exclusively for cooling purposes.
PacifiCorp’s Dave Johnston generating facility withdraws more than two million gallons per day
of water from waters of the U.S. for once-through cooling applications. Jim Bridger, Naughton,
Gadsby, Hunter, and Huntington generating facilities currently use closed-cycle cooling towers
but withdraw more than two million gallons of water per day. The rule includes impingement (i.e.,
when fish and other aquatic organisms are trapped against screens when water is drawn into a
facility’s cooling system) mortality standards and entrainment (i.e., when organisms are drawn
PACIFICORP – 2021 IRP UPDATE CHAPTER 3 – THE PLANNING ENVIRONMENT
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into the facility) standards. The standards will be set on a case-by-case basis to be determined
through site-specific studies and will be incorporated into each facility’s discharge permit.

Rule-required permit application requirements (PARs) have been submitted to the appropriate
permitting authorities for the Jim Bridger, Naughton, Gadsby, Hunter and Huntington plants. As the
five facilities utilize closed-cycle recirculating cooling water systems (cooling towers) exclusively for
equipment cooling, it is expected that state agencies will require no further action from PacifiCorp to
comply with the rule-required standards.

Because Dave Johnston utilizes once-through cooling with withdrawal rates greater than 125 million
gallons per day, the facility has been required to conduct more rigorous permit application
requirements. The Dave Johnston permit application requirements were submitted to the Wyoming
Water Quality Division on May 31, 2019. The application proposed that no modifications to the intake
structure were required; however, upon review of the submittal and subsequent issuance of a draft
permit for public notice, the Water Quality Division has indicated that PacifiCorp may be required to
select and implement an approved 316(b) impingement mortality compliance option by December 31,
2023. As the final Dave Johnston Wyoming Pollutant Discharge Elimination System permit has yet to
be issued which is expected to include 316(b) impingement mortality (IM) compliance requirements,
it is anticipated that the December 31, 2023, IM technology implementation date will be adjusted to
compensate for the actual permit issuance date.

As of March 2022, the Wyoming and Utah regulatory agencies have yet to make 316(b)
compliance determinations for the site-specific permit application requirements which were
provided to the agencies for each PacifiCorp rule-affected facility.

Effluent Limit Guidelines
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam
electric power generating sector which, among other things, regulate the discharge of bottom ash
transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning
wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's
concerns that the addition of controls for air emissions has changed the effluent discharged from coal-
and natural gas-fueled generating facilities. Under the originally promulgated guidelines, permitting
authorities were required to include the new limits in each impacted facility's National Pollutant
Discharge Elimination System permit upon renewal with the new limits to be met as soon as possible,
beginning November 1, 2018, and fully implemented by December 31, 2023.

On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with
the EPA. EPA granted the request for reconsideration and extended certain compliance dates for flue
gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020.

On November 22, 2019, EPA proposed updates to the 2015 rule, specifically addressing flue gas
desulfurization 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 flue gas desulfurization 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 flue gas desulfurization wastewater
requirements, and includes additional subcategories to both wastewater categories.

Most of the issues raised by this rule are already being addressed at PacifiCorp facilities through
compliance with the coal combustion residuals rule and are not expected to impose significant
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additional requirements on the facilities. The Dave Johnston plant anticipates achieving compliance
with the rule by issuing a notice of planned participation for subcategorization, or by installation and
operation of a bottom ash recycle system that would enable long-term compliance with the
Reconsideration Rule.
Tax Extender Legislation
On Dec. 27, 2020, President Trump signed into law the Taxpayer Certainty and Disaster Relief
Act of 2020. Among other things, the bill extended and expanded certain alternative energy tax
credits. Notable as relating to the 2021 IRP, the renewable electricity production tax credit (PTC)
was extended by one year for certain qualifying facilities; for wind facilities that begin construction
during 2021, the credit continues to be equal to 60% of the full value of the PTC. The energy tax
credit (ITC) was extended by two years for certain qualifying facilities; the bill extends the 26%
ITC for solar energy property that begins construction during 2021 and 2022, before being phased
down further.

The energy tax credit was expanded to cover offshore wind facilities; generally, any offshore wind
project that on which construction after December 31, 2017, and before January 1, 2026, will
qualify for a 30% ITC. And, finally, the credit for carbon dioxide sequestration was extended to
cover facilities that begin construction by the end of 2025. Additional schedules detailing the
phase-out of the wind PTC and solar ITC are provided as follows:

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Table 3.1 – Tax Extender Legislation and Phaseout of PTC and ITC

These schedules remain then same as referenced in the 2021 IRP.

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.
The first auction of greenhouse gas allowances was held in California in November 2012, and the
second auction in February 2013. PacifiCorp is required to sell, through the auction process, its
directly allocated allowances and purchase the required amount of allowances necessary to meet
its compliance obligations.

In May 2014, CARB approved the first update to the Assembly Bill (AB) 32 Climate Change
scoping plan, which defined California’s climate change priorities for the next five years and set
the groundwork for post-2020 climate goals. In April 2015, Governor Brown issued an executive
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order to establish a mid-term reduction target for California of 40 percent below 1990 levels by
2030. CARB was subsequently directed to update the AB 32 scoping plan to reflect the new interim
2030 target and previously established 2050 target. In July 2017, California Governor Jerry Brown
signed AB 398, extending the state’s California Cap and Trade program from January 1, 2021,
through December 31, 2030. In 2022, CARB is expected to issue a revised scoping plan
establishing emissions reduction targets post-2030. The 2022 scoping plan may also reduce target
prior to 2030.

In 2002, California established a renewable portfolio standard (RPS) requiring investor-owned
utilities to increase procurement from eligible renewable energy resources. California’s RPS
requirements have been accelerated and expanded a number of times since its inception. Most
recently, in September 2018, Governor Jerry Brown signed into law the 100 Percent Clean Energy
Act of 2018, Senate Bill (SB) 100, which requires utilities to procure 60 percent of their electricity
from renewables by 2030 and enabled all the state’s agencies to work toward a longer-term
planning target for 100 percent of California’s electricity to come from renewable and zero-carbon
resources by December 31, 2045.
Oregon
In 2007, Oregon enacted 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—27 percent by 2025, 35 percent by 2030, 45 percent by
2035, and 50 percent by 2040. The bill changes the renewable energy certificate (REC) life to five
years, while allowing RECs generated from the effective date of the bill passage until the end of
2022 from new long-term renewable projects to have unlimited life. The bill also includes
provisions to create a community-solar program in Oregon and encourage greater reliance on
electricity for transportation.

On March 10, 2020, Oregon Governor Kate Brown issued Executive Order 20-04 (EO 20-04),
which directs state agencies to take actions to reduce and regulate greenhouse gas emissions.

EO 20-04 establishes emissions reduction goals for Oregon and directs certain state agencies to
take specific actions to reduce emissions and mitigate the impacts of climate change. EO 20-04
also provides overarching direction to state agencies to exercise their statutory authority to help
achieve Oregon's climate goals.

In 2021, Oregon passed House Bill (HB) 2021, which directs utilities to reduce emissions levels
below 2010-2012 baseline levels by 80% by 2030, 90% by 2035, and 100% by 2040. Utilities will
also convene a Community Benefits and Impacts Advisory Group. PacifiCorp’s 2023 IRP will
include modeling as appropriate to support HB 2021. HB 2021 also increases state goals for small-
scale renewable energy projects, to ten percent of aggregate electrical capacity by 2030. HB 2021
is complementary to – but does not modify – Oregon’s longstanding RPS requirements.
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Washington
In November 2006, Washington voters approved Initiative 937 (I-937), the Washington Energy
Independence Act, which imposes targets for energy conservation and the use of eligible
renewable resources on electric utilities. Under I-937, utilities must supply 15 percent of their
energy from renewable resources by 2020. Utilities must also set and meet energy conservation
targets starting in 2010.

In 2008, the Washington Legislature approved the Climate Change Framework E2SHB 2815,
which establishes the following state greenhouse gas emissions reduction limits: (1) reduce
emissions to 1990 levels by 2020; (2) reduce emissions to 25 percent below 1990 levels by 2035;
and (3) by 2050, reduce emissions to 50 percent below 1990 levels or 70 percent below
Washington’s forecasted emissions in 2050.

In July 2015, Governor Inslee released an executive order that directed the Washington
Department of Ecology to develop new rules to reduce carbon emissions in the state. In December
2017, Washington’s Superior Court concluded that the Department of Ecology did not have the
authority to impose the Clean Air Rule without legislative approval. As a result, the Department
of Ecology has suspended the rule’s compliance requirements.

In 2019, the Washington Legislature approved the Clean Energy Transformation Act (CETA)
which requires utilities to eliminate coal-fired resources from Washington rates by December 31,
2025, be carbon neutral by January 1, 2030, and establishes a target of 100 percent of its electricity
from renewable and non-emitting resources by 2045.

Finally, in 2021, Washington passed the Climate Commitment Act, which establishes a cap-and-
trade program to be implemented by no later than January 1, 2023, through the regulatory
rulemaking process. The Climate Commitment Act does not modify any of PacifiCorp’s
obligations under CETA, and utility allowances within the cap-and-trade program are aligned with
the CETA renewable energy requirements. The legislation allows – but does not require – linkage
with cap-and-trade programs in jurisdictions outside of Washington state. Utilities are provided
allowances at no cost to “mitigate the cost burden” of the program on customers,
Utah
In March 2008, Utah enacted the Energy Resource and Carbon Emission Reduction Initiative,
which includes provisions to require utilities to pursue renewable energy to the extent that it is cost
effective. It sets out a goal for utilities to use eligible renewable resources to account for 20 percent
of their 2025 adjusted retail electric sales.

On March 10, 2016, the Utah legislature passed SB 115–The Sustainable Transportation and
Energy Plan (STEP). The bill supports plans for electric vehicle infrastructure and clean coal
research in Utah and authorizes the development of a renewable energy tariff for new Utah
customer loads. The legislation establishes a five-year pilot program to provide mandated funding
for electric vehicle infrastructure and clean coal research, and discretionary funding for solar
development, utility-scale battery storage, and other innovative technology and air quality
initiatives. The legislation also allows PacifiCorp to recover its variable power supply costs
through an energy balancing account and establishes a regulatory accounting mechanism to
manage risks and provide planning flexibility associated with environmental compliance or other
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economic impairments that may affect PacifiCorp’s coal-fueled resources in the future. The
deferrals of variable power supply costs went into effect in June 2016, and implementation and
approval of the other programs was completed by January 1, 2017.

On March 11, 2020, the Utah Legislature passed HB 396, Electric Vehicle Charging Infrastructure
Amendments, that enables PacifiCorp to create an Electrical Vehicle Infrastructure Program, with
a maximum funding from customers of $50 million for all costs and expenses. The legislation
allows PacifiCorp to own and operate electric vehicle charging stations and to provide investments
in make-ready infrastructure to interested customers.
Wyoming
On March 8, 2019, Wyoming Senate File 0159 (SF 159) was passed into law. SF 159 limits the
recovery costs for the retirement of coal fired electric generation facilities, provides a process for
the sale of an otherwise retiring coal fired electric generation facility, exempts a person purchasing
an otherwise retiring coal fired electric generation facility from regulation as a public utility;
requires purchase of electricity generated from purchased retiring coal fired electric generation
facility (as specified in final bill); and provides an effective date.

Cost recovery associated with electric generation built to replace a retiring coal fired generation
facility shall not be allowed by the Wyoming Public Service Commission unless the Commission
has determined that the public utility made a good faith effort to sell the facility to another person
prior to its retirement and that the public utility did not refuse a reasonable offer to purchase the
facility or the Commission determines that, if a reasonable offer was received, the sale was not
completed for a reason beyond the reasonable control of the public utility.

Under SF 159 electric public utilities, other than cooperative electric utilities, shall be obligated to
purchase electricity generated from a coal fired electric generation facility purchased under
agreement approved by the Commission, provided the otherwise retiring coal fired electric
generation facility offers to sell some or all of the electricity from the facility to an electric public
utility, the electricity is sold at a price that is no greater than the purchasing electric utility’s
avoided cost, the electricity is sold under a power purchase agreement, and the Commission
approves a 100 percent cost recovery in rates for the cost of the power purchase agreement and the
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 requires the Wyoming Public Service
Commission to put in place a standard for each public utility specifying a percentage of
electricity to be generated from coal-fired generation utilizing carbon capture technology by
2030. The requirement would only apply to generation allocated to Wyoming customers. HB 200
will require each public utility to demonstrate in its IRP the steps taken to achieve the electricity
generation standard established by the Commission and will allow rate recovery of costs incurred
by a public utility that utilizes coal-fired generation with carbon capture technology installed.
The Commission finalized administrative rules to implement HB 200, which became effective
January 7, 2022. The administrative rules require public utilities to file an initial application to
establish intermediate standards for compliance by March 31, 2022, and an application to
PACIFICORP – 2021 IRP UPDATE CHAPTER 3 – THE PLANNING ENVIRONMENT
35

establish the final plan for compliance by March 31, 2023. PacifiCorp filed the initial application
with the Commission on March 31, 2022, as required.

During the 2022 legislative session, the Wyoming Legislature passed HB 131, nuclear power plant
and storage amendments, that will help facilitate development of the Natrium nuclear
demonstration project. The bill modifies existing laws to clarify the authority of the United States
Nuclear Regulatory Commission. The bill also requires the operator of the facility, at least 30 days
prior to construction, to submit a report identifying the number of jobs expected to be created by
the project, the amount of local and state taxes estimated to be generated by the project, and the
anticipated benefits and impacts that will accrue to the state and local community from the project.
With respect to SF 159, the bill provides that the requirements of that law shall not apply to a
public utility that replaces a coal-fired generation facility with an advanced nuclear reactor.
Finally, the bill exempts tax payments, but provides that, beginning July 1, 2035, the exemption
only applies if not less than 80 percent of the uranium is sourced in the United States.
Greenhouse Gas Emission Performance Standards
California, Oregon and Washington have greenhouse gas emission performance standards
applicable to all electricity generated in the state or delivered from outside the state that is no
higher than the greenhouse gas emission levels of a state-of-the-art combined cycle natural gas
generation facility. The standards for Oregon and California are currently set at 1,100 lb.
CO2/MWh, which is defined as a metric measure used to compare the emissions from various
greenhouse gases based on their global warming potential. In September 2018, the Washington
Department of Commerce issued a new rule lowering the emissions performance standard to 925
lb. CO2/MWh.
Energy Gateway Transmission Program Planning
As discussed in 2021 IRP, the Energy Gateway transmission project continues to play an important
role in PacifiCorp’s commitment to provide safe, reliable, reasonably priced electricity to meet the
needs of our customers. Energy Gateway’s design and extensive footprint provides needed system
reliability improvements and supports the development of a diverse range of cost-effective
resources required for meeting customers’ energy needs. The IRP has incorporated Energy
Gateway as part of a solution for delivering the least cost resource portfolio for multiple IRP
planning cycles. PacifiCorp continues to develop methods, in parallel with current industry best
practices and regional transmission planning requirements, to better quantify all the benefits of
transmission that are essential to serve customers. For example, Energy Gateway is designed to
relieve operating limitations, increase capacity, and improve operations and reliability in the
existing electric transmission grid. Figure 3.1 shows a high-level geography of the Energy
Gateway transmission project.

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Figure 3.1 – Energy Gateway Map

This map is for general reference only and reflects current plans. It may not reflect the final routes, construction
sequence or exact line configuration.

Energy Gateway Transmission Project Updates
Wallula to McNary (Segment A)
This project was placed in service in January 2019.

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Gateway West (Segments D and E)
Under the National Environmental Policy Act (NEPA), the U.S. Bureau of Land Management
(BLM) has completed the environmental impact statement (EIS) for the Gateway West project.
The BLM released its final EIS on April 26, 2013, followed by the record of decision (ROD) on
November 14, 2013, providing a right-of-way grant for all of Segment D and for all but two
segments of Segment E, followed with a record of decision on these two segments of the line on
April 19, 2018:
• Gateway West (Segment D1): A single-circuit 230-kV line that will run approximately 59
miles between the existing Windstar substation in eastern Wyoming and the Aeolus
substation near Medicine Bow, Wyoming, which includes a loop-in to the existing Shirley
Basin 230-kV substation. The Aeolus – Shirley Basin 230-kV line section was energized
in November 2020. This project was included in the 2021 IRP for acknowledgement with
an in-service date of 2024.

• Gateway West (Segment D2): This single-circuit 500-kV segment was placed in service
November 2020.

• Gateway West (Segment D3): A single-circuit 500-kV line running approximately 200
miles between the new Anticline substation which was placed in-service in November 2020
with the energization of Gateway West Segment D.2 and the Populus substation in
southeast Idaho.

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.

Gateway South (Segment F)
The 2021 PacifiCorp IRP preferred portfolio includes the Aeolus-to-Mona (Clover substation)
transmission segment (Energy Gateway South or Segment F).

To facilitate the delivery of new renewable energy resources to PacifiCorp customers across the
West, the preferred portfolio includes significant transmission investment. Specifically, the 2021
IRP preferred portfolio includes the Energy Gateway South transmission line - a new 416-mile,
high-voltage 500-kilovolt transmission line and associated infrastructure running from the new
Aeolus substation near Medicine Bow, Wyoming, to the Clover substation near Mona, Utah. The
2021 preferred portfolio also includes the Energy Gateway West Subsegment D.1 project - a new
59 mile high-voltage 230-kilovolt transmission line from the Shirley Basin substation in
southeastern Wyoming to the Windstar substation near Glenrock, Wyoming. Both transmission
lines come online by the end of 2024.

Timing of construction is driven by the phase-out schedule of federal production tax credits
(PTCs), particularly the 2024 in-service requirements for 60 percent PTC eligibility, and potential
risk associated with the termination of the BLM permit for non-use. In addition to supporting
renewable resource additions in PacifiCorp’s generation portfolio, qualifying them for PTCs, the
new transmission segment will increase transfer capability out of eastern Wyoming.
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Boardman to Hemingway (Segment H)
The Boardman to Hemingway project was included in the 2021 IRP request for acknowledgement
and represents a significant improvement in the connection between PacifiCorp’s east and west
control areas and will help deliver more diverse resources to serve its customers in Oregon,
Washington, and California. Idaho Power leads the permitting efforts on this project and
PacifiCorp continues to support the permitting efforts under the conditions of the Boardman to
Hemingway Transmission Project Joint Permit Funding Agreement. The Bureau of Land
Management’s Record of Decision was issued in November of 2017, followed by the U.S. Forest
Service ROD issued on November 9, 2018. The Oregon Energy Facilities Siting Council’s final
order on the Site Certificate is currently under process. In January 2020, the three parties signatory
to the permitting agreement entered a non-binding term sheet that addresses the terms required to
move the project to the next step of construction.

In-Service Dates
Table 3.2 summarizes the in-service dates for segments of the Energy Gateway transmission
project.

PACIFICORP – 2021 IRP UPDATE CHAPTER 3 – THE PLANNING ENVIRONMENT
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Table 3.2 - Energy Gateway Segment In-Service Dates
Segment & Name Description
Approximate
Mileage Status and Scheduled In-Service
(A)
Wallula-McNary 230 kV, single circuit 30 mi • Status: completed
• Placed in-service: January 2019
(B)
Populus-Terminal 345 kV, double circuit 135 mi • Status: completed
• Placed in-service: November 2010
(C)
Mona-Oquirrh
500 kV single circuit
345 kV double circuit 100 mi • Status: completed
• Placed in-service: May 2013
Oquirrh-Terminal 345 kV double circuit 14 mi • Status: rights-of-way acquisition underway
• Scheduled in-service: 2026
(D1)
Windstar-Aeolus
New 230 kV single circuit
Re-built 230 kV single
circuit
59 mi • Status: permitting underway
• Scheduled in-service: 2024
(D2)
Aeolus-
Bridger/Anticline
500 kV single circuit 140 mi • Status: completed
• Placed in-service: November 2020
(D3)
Bridger/Anticline-
Populus
500 kV single circuit 200 mi • Status: permitting underway
• Scheduled in-service: 2027 earliest
(E)
Populus-Hemingway 500 kV single circuit 500 mi • Status: permitting underway
• Scheduled in service: 2030 earliest
(F)
Aeolus-Mona 500 kV single circuit 416 mi • Status: permitting underway
• Scheduled in-service: 2024
(G)
Sigurd-Red Butte 345 kV single circuit 170 mi • Status: completed
• Placed in-service: May 2015
(H)
Boardman-
Hemingway
500 kV single circuit 290 mi
• Status: pursuing joint-development and/or firm
capacity opportunities with project sponsors
• Scheduled in-service: 2026

Regional Markets
Increased renewable generation has contributed to the need for balancing sub-hourly demand and
supply across a broader and more diverse market. For balancing purposes, PacifiCorp combined
its resources with those of the CAISO through the creation of the EIM. The EIM became
operational November 1, 2014, and as of March 2022 has 17 utilities participating. Tucson Electric
Power and Bonneville Power Administration plan to join in 2022, while Avangrid, El Paso Electric
and WAPA Desert Southwest plan to join in 2023.4 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 participant entities, PacifiCorp is also participating in the CAISO
stakeholder process to establish an Expanded Day-Ahead Market (EDAM).

4 https://www.westerneim.com/Pages/About/default.aspx
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In December 2021, it was announced that the Western Resource Adequacy Program (WRAP),
administered by the Western Power Pool (WPP), formerly known as the Northwest Power Pool,
had entered the first stage of implementation. The WRAP consists of 26 participants, including
PacifiCorp, who are working on the remaining program design questions and outstanding issues.
Additionally, the WPP has partnered with the Southwest Power Pool (SPP) to provide program
operation services, including facilitating the collection of participants data to perform modeling for the
upcoming seasons.5 This program includes two components, a forward showing (FS) planning
mechanism and an operational program (Ops Program) to help participants that are experiencing
extreme events meet customer demand. The program is intended to be a starting point and does
not solve every issue facing the region, but is an incremental step toward increased regional
coordination, which could better position the region to continue to tackle these big issues. The
WRAP will create a capacity RA program with a demonstration of deliverability. The region
may also benefit from other forms of coordination, and while the structure and process
associated with the program may serve as foundational building blocks to additional regional
coordination, the WPP and the WRAP participants are only working to implement the capacity
RA program at this time. The WRAP does not replace or supplant the resource planning
processes used by states or provinces or the regulatory requirements of the Federal Energy
Regulatory Commission (FERC), North America Electric Reliability Corporation (NERC) or
Western Electricity Coordinating Council (WECC). The program is designed to be supplemental
and complementary to those processes and requirements. Full implementation is expected to
occur in 2024.

5 https://www.westernpowerpool.org/news/wrap-announces-full-participation-of-phase-3a
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
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CHAPTER 4 – LOAD-AND-RESOURCE BALANCE
UPDATE
Introduction
This chapter presents an update to PacifiCorp’s load-and-resource balance. Updates to
PacifiCorp’s long-term load forecasts (both energy and coincident peak load) for each state and
the system as a whole are summarized in the Appendix. Updates to PacifiCorp’s load forecast,
resources, and capacity position are presented and summarized in this chapter.
System Coincident Peak Load Forecast
The 2021 IRP Update relies on PacifiCorp’s May 2021 load forecast. Figure 4.1 compares
PacifiCorp’s most recent load forecast to the forecast used for the 2021 IRP. Figure 4.2 compares
PacifiCorp’s most recent coincident system peak load forecast to the forecast used for the 2021
IRP. Considering that PacifiCorp analyzes incremental energy efficiency and direct-load control
programs as demand-side resource options in its IRP, both figures exclude incremental energy
efficiency savings and direct-load control capacity included in the updated resource portfolio. The
compounded average annual growth rate (CAGR) for system load is 1.46 percent over the period
2022 through 2031. The CAGR for system coincident peak is 1.04 percent over the period 2022
through 2031.

Figure 4.1 - Forecasted Annual Load (GWh)

PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

42

Figure 4.2 – Forecasted Annual Coincident Peak Load (MW)

Wind and Solar Qualifying Facility Resource Updates
Table 4.1 summarizes updates to the capacity from solar and geothermal power-purchase
agreements (PPAs) with qualifying facilities (QFs) that have occurred since the September 1, 2021
IRP filing.

Table 4.1 – New Power Purchase Agreements

Updated Capacity Load-and-Resource Balance
Load-and-Resource Balance Components
Capacity and energy balances make use of the same load-and-resource components in their
calculations. The main component categories consist of the following: resources, obligation,
reserves, system position, and available front-office transactions (FOTs).

The resource categories include resources by type—thermal, hydroelectric, renewable, QFs,
purchases, and sales. Categories in the obligation section include load, private generation, existing
demand response (includes interruptible contracts), and new energy efficiency from the updated
Power Purchase Agreements Resource
Type
PPA or
QF State Capacity
(MW)
COD
Year
Amor IX, LLC Soda Lake Geothermal QF Utah 20 2021
Castle Solar (Intermountain Health Care)Solar PPA Utah 20 2021
Solarize Rogue Solar QF Oregon 0.1296 2021
Wallowa County (Community Solar Project)Solar QF Oregon 0.36 2021
Sunnyside Solar Solar QF Washington 4.99 2023
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
43

resource portfolio. Both resources and obligations can be represented as either a positive or
negative value, which is consistent with how these elements are represented in portfolio modeling.

A description of each of the resource categories is provided below.

Existing Resources
Capacity contribution is a measure of the ability for a resource to reliably meet demand. There are
many possible ways to attribute capacity to specific resources and the portfolio modeling in the
2021 IRP Update doesn’t rely on a specific capacity contribution for each resource during portfolio
development, in part because the reliability benefits of the next resource of a given type may not
be the same as the reliability benefits from resources of that type already included in a portfolio.
For the purpose of calculating capacity contribution, resources which are dispatchable for a limited
duration (measured in hours) are distinguished from resources which are dispatchable for long
durations (i.e., thermal) or whose output must be used as it is delivered, such as wind, solar and
other non-dispatchable generators.
Thermal
This category includes all thermal plants that are wholly owned or partially owned by PacifiCorp.
The capacity balance counts these plants at their expected availability (after derating for forced
outages and maintenance), as discussed below. The energy balance also counts them at expected
availability but includes all hours in the year. This includes the existing fleet of coal-fueled units,
and seven natural-gas-fueled plants. Presently, these thermal resources account for roughly two
thirds of the firm capacity available in the PacifiCorp system.
Resources without duration limits
For the purpose of reporting the capacity contribution resources without duration limits, including
thermal, wind, solar, and other small generators, PacifiCorp first calculated the availability of each
resource type during the top five percent of net load hours in each season (calculated as
PacifiCorp’s load less the wind and solar generation in its portfolio).1 For the purpose of reporting
load in the load and resource balance, the single highest load hour is used, and a planning reserve
margin of 13% is added. Resources whose is output higher in the top five percent load hours than
in the top give percent net load hours are allocated additional capacity value for their role in
meeting peak requirements. It should be noted that while allocation of capacity among resources
as described in this section is helpful for presenting a load and resource balance, the allocation to
specific resources has no bearing on the reliability or economics of the preferred portfolio, which
reflects the coordinated dispatch of all available resources in every hour of the year. The
economics of resource additions are more closely aligned with marginal or “last-in” capacity
contribution estimates, which are generally lower for resources whose output is positively
correlated with other resources already present in the portfolio. For estimates of marginal capacity
contribution values, please refer to PacifiCorp’s 2021 IRP, specifically Volume II, Appendix K
(Capacity Contribution).

1 The Western Resource Adequacy Program (WRAP) has proposed a capacity contribution methodology that is based
in part on the top five percent of net load hours. The WRAP proposal includes an effective load carrying capability
(ELCC) analysis for a number of resource types. ELCC is very computationally intensive. For details, please refer to:
https://www.westernpowerpool.org/private-media/documents/2021-12-21_RAPC_Minutes.pdf
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

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Resources with duration limits
Certain resource types have duration limits, such that while they could be called upon in any given
hour, they cannot be called upon continuously for more than specified duration. Such resources
include energy storage, such as batteries or pumped hydro, as well as demand response programs
and contracts, which generally have limits on consecutive hours, hours per day, and/or hours per
year. As a result, while these resources are available in every hour, they are limited in how often
they can be called upon for energy. However, reliable system operation also requires resources
that can be deployed at short notice to address unexpected events that occur relatively infrequently,
such as a generator outage, increase in load, or decrease in wind and solar output. These operating
reserve requirements are part of the load and resource balance, and because they do not require
frequent energy dispatch, duration-limited resources are assumed to be able to provide operating
reserves continuously. Once operating reserve needs are fulfilled in a given hour, energy limited
resources would need to deploy energy to make additional contributions to serving load. This
incremental energy is assumed to be deployed in the hours with the highest shortfalls, but is capped
for each day at the lesser of the total duration of energy-limited resources (in MWh) and available
excess generation capacity in hours where resources exceed the capacity requirement. This
represents the need to charge batteries, for example, which represent the vast majority of the
energy-limited resources through the study horizon. After summing the operating reserve and
energy contributions of duration-limited resources, their capacity contribution as a class is
calculated based on the net output in the top five percent net load hours, as described above. This
total contribution is then allocated back to individual resources based on their duration capability,
with shorter duration resources receiving a lower contribution.
Sales
Contracts for the sale of firm capacity and energy are treated the same as all other resources, except
that they have a negative capacity value. The energy balance counts them by expected model
dispatch.

Obligation
The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted
retail load, private generation, new energy efficiency from the preferred portfolio, existing demand
response (including interruptible contracts). The following are descriptions of each of these
components:
Load and Private Generation
The largest component of the obligation is retail load. In the 2021 IRP Update, the hourly retail
load at a location is first reduced by hourly private generation at the same location. The system
coincident peak is determined by summing the net loads for all locations (topology bubbles with
loads) and then finding the highest hourly system load by year and season. Loads reported by east
and west BAAs thus reflect loads at the time of PacifiCorp’s coincident system summer and winter
peaks. The energy balance counts the average load on a monthly basis. For simplicity, load net of
private generation is referred to as load in the following sections.
Energy Efficiency (Class 2 DSM)
An adjustment is made to load to remove the projected embedded energy efficiency as a reduction
to load. Due to timing issues with the vintage of the load forecast, there was a level of 2020 energy
efficiency that was not incorporated in the forecast for the 2021 IRP. The 2020 energy efficiency
forecast of 73 MW was accounted for by adding an existing energy efficiency resource in the load-
and-resource balance; this adjustment was not required for the 2021 IRP Update because the 2020
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
45

projected embedded energy efficiency is included in the load forecast. The energy efficiency line
includes the selected energy efficiency from the 2021 IRP Update preferred portfolio.
Demand Response (Class 1 DSM)
Existing demand response program capacity is categorized as a reduction to peak load. Also
included in the demand response category are existing interruptible contracts. PacifiCorp has had
interruptible contracts for approximately 177 MW of load interruption capability 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.
Planning Reserve Margin
Planning reserve margin (PRM) represents an incremental capacity requirement, applied as an
increase to the obligation to ensure that there will be sufficient capacity available on the system to
manage uncertain events (i.e., weather, outages) and known requirements (i.e., operating reserves).

System Position
The system position is the resource surplus or deficit after subtracting obligation plus required
reserves from total resources. While similar, the position calculation is slightly different for the
capacity and energy views of the load and resource balance. Thus, the position calculation for each
of the views will be presented in their respective sections.
Capacity Balance Determination and Results
Methodology
The capacity balance is developed by first determining the system coincident peak load for each
of the first ten years of the planning horizon. Then the annual firm-capacity availability of the
existing resources is determined for each of these annual system summer and winter peak periods,
as applicable, and summed as follows:

Existing Resources = Coal + Gas + Hydro + Renewables + Contracts – Firm Sales

The peak load, private generation, existing demand response, and new energy efficiency from the
preferred portfolio are netted together for each of the annual system summer and winter peaks, as
applicable, to compute the annual peak obligation:

Obligation = Load – Private Generation – Demand Response – New Energy Efficiency

The amount of reserves to be added to the obligation is then calculated. This is accomplished by
the net system obligation calculated above multiplied by the 13 percent PRM adopted for the 2021
IRP Update. The formula for this calculation is:

Planning Reserves = Obligation x PRM

Finally, the annual system position is derived by adding the computed reserves to the obligation,
and then subtracting this amount from existing resources, as shown in the following formula:

System Position = (Existing Resources) – (Obligation + Planning Reserves)
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

46

Capacity Balance Results
Table 4.2 and Table 4.3 show the annual capacity balances and component line items for the
summer peak and winter peak, respectively, using a target PRM of 13 percent to calculate the
planning reserve amount. 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.

PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
47

Table 4.2 – Summer Peak - System Capacity Load and Resource Balance without Resource
Additions, 2021 IRP Update (2022-2031) (Megawatts)2

2 The DSM line includes selected Class 2 DSM from the 2021 IRP Update resource portfolio.
East
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Coal 3,536 3,474 3,505 3,513 3,076 3,067 2,343 2,245 2,199 2,198
Gas 1,942 1,964 1,922 1,947 1,968 1,933 1,950 1,942 1,753 1,748
Hydroelectric 108 108 88 88 88 88 88 87 87 87
Solar 377 521 197 424 341 320 352 316 291 161
Wind 337 405 262 452 445 424 422 491 490 395
Geothermal 49 50 51 50 50 52 51 50 51 50
Contracts 185 182 122 35 31 30 31 24 22 17
Sales and Ancillary Services (267)(267)(243)(243)(239)(236)(235)(234)(233)(233)
East Existing Resources 6,268 6,438 5,905 6,265 5,760 5,678 5,003 4,922 4,660 4,423
Load 7,274 7,421 7,543 7,685 7,654 7,732 7,843 7,944 8,052 8,162
Private Generation (57)(66)(69)(71)(75)(81)(90)(103)(120)(144)
Existing - Demand Response (594)(585)(594)(593)(520)(496)(460)(255)(220)(196)
New Energy Efficiency (134)(210)(242)(379)(500)(810)(801)(1,051)(1,026)(1,252)
East Total obligation 6,489 6,561 6,638 6,642 6,559 6,345 6,493 6,535 6,686 6,570
Planning Reserve Margin (13%)844 853 863 863 853 825 844 850 869 854
East Obligation + Reserves 7,332 7,413 7,501 7,505 7,412 7,170 7,337 7,385 7,555 7,424
East Position (1,065)(976)(1,596)(1,240)(1,653)(1,492)(2,334)(2,463)(2,895)(3,001)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0 0
West
Coal 1,500 1,495 1,487 1,488 1,354 1,352 1,348 1,370 1,356 1,356
Gas 663 673 660 664 663 664 664 664 675 665
Hydroelectric 955 796 790 799 795 798 798 794 792 797
Solar 7 27 10 20 16 15 16 14 13 6
Wind 89 83 50 87 82 89 77 84 91 85
Geothermal 0 0 0 0 0 0 0 0 0 0
Contracts 171 168 131 146 132 97 102 72 63 47
Sales and Ancillary Services (209)(207)(182)(182)(179)(177)(177)(168)(168)(169)
West Existing Resources 3,177 3,034 2,945 3,022 2,863 2,838 2,828 2,831 2,822 2,787
Load 3,372 3,402 3,434 3,471 3,501 3,534 3,569 3,604 3,640 3,679
Private Generation (28)(40)(45)(49)(54)(60)(67)(75)(85)(106)
Existing - Demand Response 0 0 0 0 0 0 0 0 0 0
New Energy Efficiency (73)(120)(147)(192)(242)(157)(354)(264)(442)(321)
West Total obligation 3,271 3,242 3,243 3,229 3,205 3,318 3,148 3,264 3,113 3,251
Planning Reserve Margin (13%)425 421 422 420 417 431 409 424 405 423
West Obligation + Reserves 3,696 3,664 3,664 3,649 3,622 3,749 3,557 3,688 3,518 3,674
West Position (520)(629)(719)(627)(758)(911)(729)(857)(695)(887)
Available Front Office Transactions 500 500 500 500 500 500 500 500 500 500
System
Total Resources 9,445 9,472 8,850 9,287 8,623 8,516 7,831 7,753 7,482 7,210
Obligation 9,760 9,803 9,880 9,871 9,764 9,663 9,641 9,799 9,799 9,821
Planning Reserves (13%)1,269 1,274 1,284 1,283 1,269 1,256 1,253 1,274 1,274 1,277
Obligation + Reserves 11,029 11,077 11,165 11,155 11,034 10,919 10,894 11,073 11,073 11,098
System Position (1,584)(1,605)(2,315)(1,867)(2,411)(2,403)(3,063)(3,320)(3,591)(3,888)
Available Front Office Transactions 500 500 500 500 500 500 500 500 500 500
Uncommitted FOTs to meet remaining Need 1,584 1,605 2,315 1,867 500 500 500 500 500 500
Net Surplus/(Deficit)0 0 0 0 (1,911)(1,903)(2,563)(2,820)(3,091)(3,388)
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

48

Table 4.2 (cont.) – Summer Peak - System Capacity Load and Resource Balance without
Resource Additions, 2021IRP Update (2032-2040) (Megawatts)3

3 The DSM line includes selected Class 2 DSM from the 2021 IRP Update resource portfolio.
East
2032 2033 2034 2035 2036 2037 2038 2039 2040
Coal 2,212 2,219 2,207 2,219 2,218 1,359 1,362 1,357 1,100
Gas 1,743 1,412 1,401 1,397 1,398 1,403 1,403 1,399 1,410
Hydroelectric 86 87 87 86 87 86 86 87 87
Solar 30 136 124 132 125 137 144 142 83
Wind 252 355 359 353 333 475 502 480 457
Geothermal 51 50 51 51 52 50 20 20 20
Contracts 10 15 14 12 9 8 0 0 0
Sales and Ancillary Services (226)(230)(229)(228)(228)(233)(233)(234)(227)
East Existing Resources 4,159 4,043 4,013 4,022 3,993 3,287 3,285 3,251 2,931
Load 8,266 8,370 8,473 8,444 8,585 8,679 8,793 8,655 8,759
Private Generation (173)(203)(236)(150)(173)(196)(221)(116)(128)
Existing - Demand Response (176)(163)(161)(161)(160)(148)(144)(148)(142)
New Energy Efficiency (1,489)(1,442)(1,522)(1,590)(1,607)(1,702)(1,753)(1,702)(1,844)
East Total obligation 6,428 6,563 6,555 6,543 6,644 6,633 6,674 6,689 6,644
Planning Reserve Margin (13%)836 853 852 851 864 862 868 870 864
East Obligation + Reserves 7,264 7,416 7,407 7,394 7,508 7,495 7,542 7,559 7,508
East Position (3,105)(3,372)(3,394)(3,372)(3,515)(4,208)(4,257)(4,308)(4,577)
Available Front Office Transactions 0 0 0 0 0 0 0 0 0
West
Coal 1,356 1,358 1,355 1,354 1,353 1,351 0 0 0
Gas 667 665 665 663 677 449 448 446 446
Hydroelectric 793 794 796 792 793 795 795 798 798
Solar 1 5 4 5 5 9 10 10 7
Wind 56 88 77 73 83 97 114 117 84
Geothermal 0 0 0 0 0 0 0 0 0
Contracts 24 35 31 30 32 23 19 10 10
Sales and Ancillary Services (162)(169)(167)(160)(155)(161)(157)(156)(144)
West Existing Resources 2,735 2,776 2,760 2,757 2,787 2,563 1,229 1,224 1,200
Load 3,711 3,747 3,785 3,775 3,809 3,854 3,892 3,861 3,896
Private Generation (147)(193)(247)(217)(254)(296)(341)(190)(221)
Existing - Demand Response 0 0 0 0 0 0 0 0 0
New Energy Efficiency (432)(382)(412)(450)(561)(327)(344)(455)(685)
West Total obligation 3,133 3,172 3,126 3,108 2,994 3,231 3,207 3,216 2,990
Planning Reserve Margin (13%)407 412 406 404 389 420 417 418 389
East Obligation + Reserves (24)30 (5)(46)(172)93 73 (37)(296)
East Position 2,760 2,746 2,766 2,803 2,959 2,470 1,156 1,262 1,496
Available Front Office Transactions 500 500 500 500 500 500 500 500 500
System
Total Resources 6,894 6,819 6,773 6,779 6,780 5,850 4,514 4,475 4,131
Obligation 9,561 9,735 9,681 9,651 9,638 9,863 9,882 9,905 9,634
Planning Reserves (13%)1,243 1,265 1,259 1,255 1,253 1,282 1,285 1,288 1,252
Obligation + Reserves 10,804 11,000 10,940 10,906 10,891 11,146 11,166 11,192 10,886
System Position (3,910)(4,181)(4,166)(4,127)(4,111)(5,295)(6,652)(6,717)(6,755)
Available Front Office Transactions 500 500 500 500 500 500 500 500 500
Uncommitted FOTs to meet remaining Need 500 500 500 500 500 500 500 500 500
Net Surplus/(Deficit)(3,410)(3,681)(3,666)(3,627)(3,611)(4,795)(6,152)(6,217)(6,255)
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
49

Table 4.3 – Winter Peak – System Capacity Load and Resource Balance without Resource
Additions, 2021 IRP Update (2022-2031) (Megawatts) 4

4 The DSM line includes selected Class 2 DSM from the 2021 IRP Update resource portfolio.
East
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Coal 3,443 3,491 3,470 3,477 2,931 2,941 2,249 2,224 2,148 2,090
Gas 1,938 2,045 2,043 1,995 1,913 1,969 2,042 2,012 1,817 1,700
Hydroelectric 80 80 70 70 68 67 70 69 69 67
Solar 48 72 40 22 14 16 16 24 39 11
Wind 268 383 250 278 280 263 256 355 418 306
Geothermal 52 52 52 51 51 46 52 52 52 50
Contracts 164 137 66 16 15 15 15 9 9 8
Sales and Ancillary Services (212)(215)(189)(192)(190)(189)(191)(193)(194)(194)
East Existing Resources 5,781 6,045 5,801 5,716 5,081 5,127 4,509 4,552 4,360 4,038
Load 5,691 5,868 5,936 6,050 5,977 6,033 6,138 6,220 6,297 6,374
Private Generation (1)(2)(2)(3)(4)(5)(6)(7)(8)(9)
Existing - Demand Response (322)(309)(335)(408)(330)(324)(336)(229)(204)(180)
New Energy Efficiency (108)(148)(198)(221)(275)(725)(400)(842)(880)(520)
East Total obligation 5,260 5,410 5,401 5,418 5,368 4,980 5,396 5,142 5,205 5,665
Planning Reserve Margin (13%)684 703 702 704 698 647 701 668 677 736
East Obligation + Reserves 5,944 6,114 6,103 6,122 6,066 5,627 6,097 5,810 5,882 6,401
East Position (163)(69)(302)(406)(984)(500)(1,588)(1,258)(1,522)(2,363)
Available Front Office Transactions 300 300 300 300 300 300 300 300 300 300
West
Coal 1,488 1,488 1,319 1,468 1,321 1,314 1,338 1,335 1,360 1,313
Gas 718 718 711 713 697 693 717 715 630 695
Hydroelectric 1,038 858 865 861 847 843 869 866 869 843
Solar 0 1 1 1 0 0 0 1 1 0
Wind 39 52 33 50 39 33 34 44 52 50
Geothermal 0 0 0 0 0 0 0 0 0 0
Contracts 78 73 70 68 58 31 33 21 17 15
Sales and Ancillary Services (192)(174)(149)(146)(145)(142)(142)(147)(147)(146)
West Existing Resources 3,168 3,016 2,850 3,014 2,818 2,772 2,849 2,834 2,782 2,771
Load 3,330 3,373 3,408 3,446 3,487 3,534 3,580 3,628 3,673 3,710
Private Generation (0)(1)(1)(1)(1)(2)(2)(3)(3)(4)
Existing - Demand Response 0 0 0 0 0 0 0 0 0 0
New Energy Efficiency (76)(110)(165)(160)(191)150 (271)172 114 (339)
West Total obligation 3,253 3,262 3,243 3,285 3,295 3,682 3,308 3,798 3,784 3,368
Planning Reserve Margin (13%)423 424 422 427 428 479 430 494 492 438
West Obligation + Reserves 3,676 3,686 3,664 3,712 3,723 4,161 3,738 4,291 4,276 3,806
West Position (508)(670)(815)(698)(905)(1,389)(889)(1,458)(1,494)(1,035)
Available Front Office Transactions 700 700 700 700 700 700 700 700 700 700
System
Total Resources 8,950 9,061 8,651 8,730 7,899 7,900 7,358 7,386 7,142 6,809
Obligation 8,513 8,672 8,644 8,703 8,663 8,662 8,703 8,939 8,989 9,033
Planning Reserves (13%)1,107 1,127 1,124 1,131 1,126 1,126 1,131 1,162 1,169 1,174
Obligation + Reserves 9,620 9,800 9,767 9,834 9,789 9,788 9,835 10,101 10,157 10,207
System Position (670)(739)(1,117)(1,104)(1,890)(1,889)(2,477)(2,716)(3,016)(3,398)
Available Front Office Transactions 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Uncommitted FOTs to meet remaining Need 670 739 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Net Surplus/(Deficit)0 0 (117)(104)(890)(889)(1,477)(1,716)(2,016)(2,398)
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

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Table 4.3 (cont.) – Winter Peak – System Capacity Load and Resource Balance without
Resource Additions, 2021IRP Update (2032-2040) (Megawatts)5

5 The DSM line includes selected Class 2 DSM from the 2021 IRP Update resource portfolio.
East
2032 2033 2034 2035 2036 2037 2038 2039 2040
Coal 2,051 2,203 2,178 2,212 2,188 1,353 1,332 1,338 1,178
Gas 1,736 1,444 1,473 1,485 1,353 1,482 1,479 1,487 1,466
Hydroelectric 66 69 69 69 69 70 69 69 69
Solar 7 6 9 23 33 31 37 36 24
Wind 220 271 274 389 454 578 701 744 561
Geothermal 49 52 49 52 52 52 20 20 20
Contracts 7 7 7 6 6 3 0 0 7
Sales and Ancillary Services (194)(196)(198)(203)(205)(202)(203)(205)(208)
East Existing Resources 3,942 3,857 3,861 4,034 3,949 3,367 3,436 3,490 3,116
Load 6,459 6,542 6,645 6,724 6,801 6,890 6,992 7,083 7,190
Private Generation (10)(12)(13)(14)(16)(18)(19)(21)(23)
Existing - Demand Response (166)(155)(155)(155)(162)(141)(137)(139)(135)
New Energy Efficiency (905)(920)(1,185)(1,051)(1,057)(343)(1,143)(443)(1,458)
East Total obligation 5,378 5,456 5,291 5,504 5,566 6,389 5,691 6,481 5,575
Planning Reserve Margin (13%)699 709 688 715 724 831 740 842 725
East Obligation + Reserves 6,077 6,165 5,979 6,219 6,289 7,219 6,431 7,323 6,299
East Position (2,135)(2,308)(2,118)(2,185)(2,340)(3,852)(2,996)(3,833)(3,183)
Available Front Office Transactions 300 300 300 300 300 300 300 300 300
West
Coal 1,285 1,323 1,361 1,362 1,360 1,360 0 0 27
Gas 680 710 718 718 683 490 489 490 495
Hydroelectric 828 865 874 875 874 877 878 880 879
Solar 0 0 0 0 0 1 1 1 0
Wind 31 41 46 52 60 79 83 82 68
Geothermal 0 0 0 0 0 0 0 0 0
Contracts 14 13 13 14 13 13 12 11 14
Sales and Ancillary Services (144)(141)(144)(145)(146)(143)(142)(142)(148)
West Existing Resources 2,695 2,812 2,867 2,877 2,846 2,675 1,322 1,321 1,336
Load 3,756 3,805 3,854 3,902 3,946 3,994 4,048 4,102 4,156
Private Generation (4)(5)(6)(7)(8)(9)(11)(12)(13)
Existing - Demand Response 0 0 0 0 0 0 0 0 0
New Energy Efficiency (80)(134)73 89 40 (934)(237)(1,013)(3)
West Total obligation 3,672 3,666 3,921 3,985 3,978 3,051 3,801 3,076 4,139
Planning Reserve Margin (13%)477 477 510 518 517 397 494 400 538
East Obligation + Reserves 398 343 582 607 558 (537)257 (613)535
East Position 2,298 2,470 2,285 2,270 2,289 3,212 1,065 1,935 801
Available Front Office Transactions 700 700 700 700 700 700 700 700 700
System
Total Resources 6,637 6,669 6,728 6,911 6,796 6,042 4,757 4,811 4,452
Obligation 9,050 9,121 9,212 9,488 9,544 9,440 9,492 9,557 9,714
Planning Reserves (13%)1,176 1,186 1,198 1,233 1,241 1,227 1,234 1,242 1,263
Obligation + Reserves 10,226 10,307 10,409 10,722 10,784 10,667 10,726 10,799 10,976
System Position (3,589)(3,638)(3,681)(3,810)(3,989)(4,625)(5,968)(5,988)(6,524)
Available Front Office Transactions 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Uncommitted FOTs to meet remaining Need 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000
Net Surplus/(Deficit)(2,589)(2,638)(2,681)(2,810)(2,989)(3,625)(4,968)(4,988)(5,524)
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
51

Figure 4.3 and Figure 4.4 are graphic representations of the above tables for the 2021 IRP Update
annual capacity position for the summer system, winter system respectively. Also shown in the
system capacity position graphs are the capacity contribution from uncommitted FOTs, which as
discussed above, are provided for informational purposes.

Figure 4.3 – Summer System Capacity Position Trend

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Me
g
a
w
a
t
t
s
West Existing Resources East Existing Resources
Uncommitted FOTs to meet remaining Need Obligation + Reserves
Obligation
East Existing Resources
West Existing Resources
13% Reserves
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

52

Figure 4.4 – Winter System Capacity Position Trend

Energy Balance Determination
Methodology
The energy balance shows the monthly surplus or (deficit) of energy. Please refer to the section on
load and resource balance components for details on how energy for each component is counted.

Existing Resources = Thermal + Hydro + Renewable + Firm Purchases + QF – Sales

The average obligation is computed using the following formula:

Obligation = Load + Firm Sales

The energy position by month is then computed as follows:

Energy Position = Existing Resources – Obligation – Operating Reserve Requirements

Operating Reserve Requirements include spinning and non-spinning reserves, but not regulation
reserves, which are expected to be close to energy neutral over time. As duration-limited resources
such as batteries become a larger portion of the Company’s portfolio, less of the potential output
of thermal resources is likely to be needed to meet Operating Reserve requirements. In addition,
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Me
g
a
w
a
t
t
s
West Existing Resources East Existing Resources
Uncommitted FOTs to meet remaining Need Obligation + Reserves
Obligation
East Existing Resources
West Existing Resources
13% Reserves
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE
53

energy storage resources represent a net load, due to their roundtrip efficiency. For the 2021 IRP
Update, storage resources are not included in the energy balance.
Energy Balance Results
The capacity position shows how existing resources and loads, accounting for coal unit retirements
and incremental energy efficiency savings from the preferred portfolio, balance during the
coincident peak summer and winter. Outside of these peak periods, PacifiCorp economically
dispatches its resources to meet changing load conditions taking into consideration prevailing
market conditions. In those periods when variable costs of the system resources are less than the
prevailing market price for power, PacifiCorp can dispatch resources that in aggregate exceed
then-current load obligations facilitating off system sales that reduce customer costs. Conversely,
at times when system resource costs fall below prevailing market prices, system balancing market
purchases can be used to meet then-current system load obligations to reduce customer costs. The
economic dispatch of system resources is critical to how PacifiCorp manages net power costs.

Figure 4.5 provides a snapshot of how existing system resources could be used to meet forecasted
load across on-peak and off-peak periods given the assumptions about resource availability and
wholesale power and natural gas prices. At times, resources are economically dispatched above
load levels facilitating net system balancing sales. At other times, economic conditions result in
net system balancing purchases, which occur more often during on-peak periods. Figure 4.5 also
shows how much energy is available from existing resources at any given point in time. Those
periods where all available resource energy falls below forecasted loads are highlighted in red and
indicate short energy positions without the addition of incremental resources to the portfolio.

Figure 4.5 – System Average Monthly Energy Positions

0
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4,000
6,000
8,000
10,000
12,000
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e
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e

E
n
e
r
g
y

A
v
a
i
l
a
b
l
e

(
M
W
)
Monthly Energy Balance
Energy at or Below Load Net Balancing Purchase Net Balancing Sale
Energy Shortfall Energy Available Obligation
PACIFICORP – 2021 IRP UPDATE CHAPTER 4 – LOAD-AND-RESOURCE BALANCE UPDATE

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PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

55
CHAPTER 5 – MODELING AND ASSUMPTIONS
UPDATE
General Assumptions

Consistent with the 2021 IRP, the study period for the 2021 IRP Update is 2021-2040, with a focus
on the 2022-2027 planning horizon.

PacifiCorp has updated certain general assumptions in the 2021 IRP Update from the 2021 IRP as
discussed below.
Inflation Rates
The 2021 IRP Update model simulations and cost data reflect PacifiCorp’s corporate inflation rate
schedule unless otherwise noted. A single annual escalation rate value of 2.155 percent is assumed,
consistent with the 2021 IRP. The annual escalation rate reflects the average of annual inflation
rate projections for the period 2021 through 2040, using PacifiCorp’s September 2020 inflation
curve. PacifiCorp’s inflation curve is a straight average of forecasts for Gross Domestic Product
inflator and Consumer Price Index.
Discount Factor
The discount rate used in present-value calculations is based on PacifiCorp’s after-tax weighted
average cost of capital (WACC). The value used for the 2021 IRP Update is 6.88 percent,
consistent with the 2021 IRP. The use of the after-tax WACC complies with the Public Utility
Commission of Oregon’s IRP guideline 1a, which requires that the after-tax WACC be used to
discount all future resource costs.1 Present-value revenue requirement values reported in the 2021
IRP Update are reported in 2021 dollars.
Front Office Transactions (FOTs)
FOT modeling assumptions in the 2021 IRP Update are consistent with the FOT modeling
assumptions from the 2021 IRP. Table 5.1 reports the available FOT modeling assumptions for
reference; identifying the market hub, product type, annual capacity limit, and availability
associated with the product. PacifiCorp develops its FOT planning limits based upon its active
participation in wholesale power markets, its view of physical delivery constraints, market
liquidity and depth, and with consideration of regional resource supply.

1 Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, January 8, 2007.
PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

56
Table 5.1 - Maximum Available Front Office Transaction Quantity by Market Hub
Market Hub/Proxy FOT Product Type
Available over Study Period
Megawatt Limit and Availability
(MW)
Summer
(July)
Winter
(December)
Mid-Columbia (Mid-C) 350 350 Flat Annual or Heavy Load Hour
Heavy Load Hour 150 0
California Oregon Border (COB)
Flat Annual or Heavy Load Hour 0 250
Nevada Oregon Border (NOB) 0 100 Heavy Load Hour
Mona 0 300 Heavy Load Hour
Stochastic Parameters
Stochastic parameters assumed in the 2021 IRP Update are consistent with those applied in the
2021 IRP. PacifiCorp provided a detailed description of its stochastic parameters and their
development in Volume II, Appendix H of the 2021 IRP.
Flexible Reserve Study
PacifiCorp applied its Flexible Reserve Study methodology from the 2021 IRP in its 2021 IRP
Update. PacifiCorp provided a detailed description of its Flexible Reserve Study in Volume II,
Appendix F of the 2021 IRP.
Natural Gas and Power Market Price Updates
Portfolio modeling for the 2021 IRP Update was prepared using three market price forecasts that
have not changed from the 2021 IRP, in part due to the short period of time that has transpired
since the September 1, 2021, filing. PacifiCorp is also transitioning to a new third-party vendor for
its price curves and a full set of updated prices are not yet available.

Figure 5.1 summarizes the three wholesale electricity price forecasts and three natural gas price
forecasts used in the base and scenario cases for the 2021 IRP Update. As shown, low and medium
power and gas prices are higher in the near term. All three power price scenarios trend higher
beginning in 2024, but generally escalate at different increasing rates.

PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

57
Figure 5.1 – Nominal Wholesale Electricity and Natural Gas Price Scenarios

PacifiCorp’s March 31, 2021, official forward price curve (OFPC) is used to represent medium
natural gas price assumptions with no CO2 prices for the “MN” price-policy scenario. OFPCs are
produced for both natural gas and power prices by point of delivery. For both gas and electricity,
starting with the prompt month, the front 36 months of the OFPC reflects market forwards at the
close of a given trading day.2 As such, these 36 months are market forwards as of March 2021.
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 and electricity OFPCs reflect expert
third-party price forecasts. PacifiCorp updates its natural gas price forecasts each quarter for the
OFPC and, as a corollary, the electricity OFPC is also updated.

Supply and demand for electricity and natural gas are related, and changes in some assumptions
that directly impact one can result in prices changes that indirectly impact the other. Other
assumptions may impact both markets directly. For example, greenhouse gas prices can impact
demand for natural gas for electricity generation, but they can also impact demand for natural gas
for other purposes. The combined impact of the change in demand will in turn change natural gas
prices, which can in turn further impact demand in the electric sector. By using a single vendor
for both electric and gas price forecasting, more of the interaction between these markets as a result
of other assumptions can be captured in the price forecast. PacifiCorp previously prepared the
fundamentals portion of the electricity forecast in house and could not capture these interactions,
which are increasing in importance with the rising penetration of renewable resources and evolving
policies that impact CO2-emitting generation resources.

To improve its forecasts within this changing landscape, PacifiCorp is transitioning to third-party
forecasts of both gas and electricity prices. PacifiCorp executed a two-year contract in February
2022 that will provide quarterly OFPC updates for both gas and electricity, starting with the March
2022 OFPC, as well as the price-policy sensitivities used in IRP modeling going forward.

2 The March 2021 OFPC prompt month is May 2021; April 2021 would be traded as “balance of month” when the
OFPC is released.
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M
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Natural Gas Prices
Henry Hub
Medium Low High
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M
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Wholesale Electricity Prices
Average of Palo Verde and Mid-C (Flat)
Mgas_MCO2 Hgas_HCO2 Lgas_0CO2
PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

58
Carbon Dioxide Emission Policy
Consistent with the 2021 IRP, PacifiCorp used three different CO2 price scenarios in the 2021 IRP
Update—zero, medium, high. The medium and high scenario are derived from expert third-party
multi-client “off-the-shelf” subscription services. Both scenarios apply a CO2 price as a tax
beginning 2025.

A fourth CO2 price scenario, social cost of greenhouse gas (SC-GHG), was used in the 2021 IRP
but has not been incorporated into the 2021 IRP Update. This is primarily because the 2021 IRP
Update is not an update to CETA or the CEIP, and updates such as the CETA Progress Report are
addressed through other specified requirements. For informational purposes, the SC-GHG price
curve is nonetheless discussed here for comparison to the medium and high price curves. In
PacifiCorp’s 2021 IRP and future IRPs, the SC-GHG price curve will be incorporated in
compliance with RCW 19.280.030. 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 in a full IRP also include
the SC-GHG once the portfolios are determined, presenting the risk that this operational
assumption will not be aligned with actual market forces (i.e., market transactions at the Mid-
Columbia market do not reflect the social cost of greenhouse gases and PacifiCorp does not
directly incur emission costs at the price assumed for the social cost of greenhouse gases).

For the purposes of the 2021 IRP Update, the zero and high CO2 price assumptions serve as
bookends for future market environment analysis. As described further in Chapter 6, CETA-driven
resource assumptions that consider the SC-GHG CO2 price are incorporated into the 2021 IRP
Update preferred portfolio so that updated CETA interim targets could be evaluated.

PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

59
Figure 5.2 – Medium, High and Social Cost of Greenhouse Gas CO2 Prices

Supply-Side Resources
Proxy resource costs and operating characteristics are generally unchanged from assumptions used
in the 2021 IRP. The supply-side table in the 2021 IRP showed proxy costs for combined solar
and storage resources based on storage capacity equal to 50% of solar nameplate, with four-hour
duration. As part of the Reliability Assessment in the 2021 IRP, the storage capacity was set at
100% of solar nameplate, with four-hour duration. As part of the development of the 2021 IRP
preferred portfolio, costs and operating characteristics for a hybrid wind-solar-storage resource
were developed. Since these resource configurations were not included in the supply-side table for
the 2021 IRP, they have been provided in the tables below.

All costs remain in real levelized 2020 dollars. Cost (de)escalation curves are applied in the
portfolio modeling process to the solar, wind, and/or storage components of a resource. The cost
(de)escalation curves are unchanged from the 2021 IRP.

$0$10$20$30$40$50$60$70$80$90$100$110$120$130$140$150$160
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PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

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PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

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Table 5.2 - 2021 IRP Update Supply Side Resources
Information Presented is Illustrative

Table 5.3 – 2021 IRP Update Supply Side Resources
Information Presented is Illustrative

Elevation
(AFSL)
Net
Capacity
(MW)
Commercial
Operation
Year
Design
Life (yrs)
Base Capital
($/KW)
Demolition
Cost ($/kW)
Var O&M
($/MWh)
Fixed
O&M
($/KW-yr)
Average Full Load
Heat Rate (HHV
Btu/KWh)/
Efficiency EFOR (%)POR (%)
Water
Consumed
(Gal/MWh)
SO2
(lbs/MMBtu)
NOx
(lbs/MMBtu)
Hg
(lbs/TBTu)
CO2
(lbs/MMBtu)
Idah Falls, ID, 200 MW, Solar, CF: 26.1% + BESS: 100% pwr, 4 hours 4,700 200 2023 25 $ 3,020 $ 475 $ - $ 41.80 85%(a)(a)n/a n/a n/a n/a n/a
Lakeview, OR, 200 MW, Solar, CF: 27.6% + BESS: 100% pwr, 4 hours 4,800 200 2023 25 $ 2,977 $ 475 $ - $ 41.80 85%(a)(a)n/a n/a n/a n/a n/a
Milford, UT, 200 MW, Solar, CF: 30.2% + BESS: 100% pwr, 4 hours 5,000 200 2023 25 $ 2,907 $ 475 $ - $ 43.30 85%(a)(a)n/a n/a n/a n/a n/a
Rock Springs, WY, 100 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours 6,400 100 2023 25 $ 3,201 $ 475 $ - $ 45.20 85%(a)(a)n/a n/a n/a n/a n/a
Rock Springs, WY, 200 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours 6,400 200 2023 25 $ 2,960 $ 475 $ - $ 43.30 85%(a)(a)n/a n/a n/a n/a n/a
Yakima, WA, 100 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours 1,000 100 2023 25 $ 3,323 $ 475 $ - $ 45.20 85%(a)(a)n/a n/a n/a n/a n/a
Yakima, WA, 200 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours 1,000 200 2023 25 $ 3,077 $ 475 $ - $ 43.30 85%(a)(a)n/a n/a n/a n/a n/a
Idah Falls, ID, 200 MW, Solar & Wind, CF: 26.1% + BESS: 100% pwr, 4 hours + 200 MW Wind 4,700 200 2023 25 $ 3,395 $ 488 $ - $ 82.95 85%(a)(a)n/a n/a n/a n/a n/a
Lakeview, OR, 200 MW, Solar & Wind,CF: 27.6% + BESS: 100% pwr, 4 hours + 200 MW Wind 4,800 200 2023 25 $ 3,424 $ 488 $ - $ 82.95 85%(a)(a)n/a n/a n/a n/a n/a
Milford, UT, 200 MW, Solar & Wind,CF: 30.2% + BESS: 100% pwr, 4 hours + 200 MW Wind 5,000 200 2023 25 $ 3,364 $ 488 $ - $ 81.45 85%(a)(a)n/a n/a n/a n/a n/a
Rock Springs, WY, 200 MW, Solar & Wind,CF: 27.9% + BESS: 100% pwr, 4 hours + 200 MW Wind 6,400 200 2023 25 $ 3,364 $ 488 $ - $ 81.45 85%(a)(a)n/a n/a n/a n/a n/a
Yakima, WA, 200 MW, Solar & Wind, CF: 24.2% + BESS: 100% pwr, 4 hours + 200 MW Wind 1,000 200 2023 25 $ 3,424 $ 488 $ - $ 81.45 85%(a)(a)n/a n/a n/a n/a n/a
Resource Characteristics Costs Operating Characteristics EnvironmentalSupply Side Resource Options
Mid-Calendar Year 2020 Dollars ($)
Resource Description
Supply Side Resource Options
Mid-Calendar Year 2020 Dollars ($)
Resource Description Total Capital
Cost
Demolition
Cost Payment Factor Annual Payment
($/kW-Yr) O&M Capitalized
Premium
O&M
Capitalized
Gas
Transportation Total
Idah Falls, ID, 200 MW, Solar, CF: 26.1% + BESS: 100% pwr, 4 hours Yes 4,700 $3,020 $475 6.839%$239.06 $41.80 1.379%$0.58 $0.00 $42.38 $281.44
Lakeview, OR, 200 MW, Solar, CF: 27.6% + BESS: 100% pwr, 4 hours Yes 4,800 $2,977 $475 6.839%$236.10 $41.80 1.379%$0.58 $0.00 $42.38 $278.48
Milford, UT, 200 MW, Solar, CF: 30.2% + BESS: 100% pwr, 4 hours Yes 5,000 $2,907 $475 6.839%$231.30 $43.30 1.379%$0.60 $0.00 $43.90 $275.20
Rock Springs, WY, 200 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours Yes 6,400 $2,960 $475 6.839%$234.95 $43.30 1.379%$0.60 $0.00 $43.90 $278.85
Yakima, WA, 200 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours Yes 1,000 $3,077 $475 6.839%$242.90 $43.30 1.379%$0.60 $0.00 $43.90 $286.79
Idah Falls, ID, 200 MW, Solar, CF: 26.1% + BESS: 100% pwr, 4 hours Yes 4,700 $3,020 $475 6.839%$239.06 $41.80 1.379%$0.58 $0.00 $42.38 $281.44
Lakeview, OR, 200 MW, Solar, CF: 27.6% + BESS: 100% pwr, 4 hours Yes 4,800 $2,977 $475 6.839%$236.10 $41.80 1.379%$0.58 $0.00 $42.38 $278.48
Milford, UT, 200 MW, Solar, CF: 30.2% + BESS: 100% pwr, 4 hours Yes 5,000 $2,907 $475 6.839%$231.30 $43.30 1.379%$0.60 $0.00 $43.90 $275.20
Rock Springs, WY, 200 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours Yes 6,400 $2,960 $475 6.839%$234.95 $43.30 1.379%$0.60 $0.00 $43.90 $278.85
Yakima, WA, 200 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours Yes 1,000 $3,077 $475 6.839%$242.90 $43.30 1.379%$0.60 $0.00 $43.90 $286.79
Idah Falls, ID, 200 MW, Solar & Wind, CF: 26.1% + BESS: 100% pwr, 4 hours + 200 MW Wind No 4,700 $3,395 $488 6.839%$265.55 $82.95 1.379%$1.14 $0.00 $84.09 $349.64
Lakeview, OR, 200 MW, Solar & Wind,CF: 27.6% + BESS: 100% pwr, 4 hours + 200 MW Wind No 4,800 $3,424 $488 6.839%$267.48 $82.95 1.379%$1.14 $0.00 $84.09 $351.58
Milford, UT, 200 MW, Solar & Wind,CF: 30.2% + BESS: 100% pwr, 4 hours + 200 MW Wind No 5,000 $3,364 $488 6.839%$263.42 $81.45 1.379%$1.12 $0.00 $82.57 $345.99
Rock Springs, WY, 200 MW, Solar & Wind,CF: 27.9% + BESS: 100% pwr, 4 hours + 200 MW Wind No 6,400 $3,364 $488 6.839%$263.38 $81.45 1.379%$1.12 $0.00 $82.57 $345.95
Yakima, WA, 200 MW, Solar & Wind, CF: 24.2% + BESS: 100% pwr, 4 hours + 200 MW Wind No 1,000 $3,424 $488 6.839%$267.51 $81.45 1.379%$1.12 $0.00 $82.57 $350.08
Modeled
IRP Elevation (AFSL)
Fixed Cost
Fixed O&M $/kW-Yr
Total Fixed
($/kW-Yr)
Capital Cost $/kW
PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

62
Table 5.4 – 2021 IRP Update Supply Side Resources

Information Presented is Illustrative
Credits
Capacity Factor Total Fixed
($/MWh)
Storage
Efficiency $/MMBtu $/MWh O&M Capitalized
Premium O&M Capitalized Integration Cost Total Resource Cost
PTC Tax Credits / ITC
(Solar Only) / 45Q Tax
Credits (CCUS Only)
Idah Falls, ID, 200 MW, Solar, CF: 26.1% + BESS: 100% pwr, 4 hours 4,700 26%$123.09 85%-$ -$ -$ 0.00%-$ 0.70$ $123.80 (23.18)$ $100.62
Lakeview, OR, 200 MW, Solar, CF: 27.6% + BESS: 100% pwr, 4 hours 4,800 28%$115.18 85%-$ -$ -$ 0.00%-$ 0.70$ $115.88 (21.61)$ $94.28
Milford, UT, 200 MW, Solar, CF: 30.2% + BESS: 100% pwr, 4 hours 5,000 30%$104.02 85%-$ -$ -$ 0.00%-$ 0.70$ $104.73 (19.28)$ $85.45
Rock Springs, WY, 200 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours 6,400 28%$114.09 85%-$ -$ -$ 0.00%-$ 0.70$ $114.80 (21.25)$ $93.54
Yakima, WA, 200 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours 1,000 24%$135.29 85%-$ -$ -$ 0.00%-$ 0.70$ $135.99 (25.46)$ $110.52
Idah Falls, ID, 200 MW, Solar, CF: 26.1% + BESS: 100% pwr, 4 hours 4,700 26%$123.09 85%-$ -$ -$ 0.00%-$ 0.70$ $123.80 (1.10)$ $122.70
Lakeview, OR, 200 MW, Solar, CF: 27.6% + BESS: 100% pwr, 4 hours 4,800 28%$115.18 85%-$ -$ -$ 0.00%-$ 0.70$ $115.88 (1.03)$ $114.86
Milford, UT, 200 MW, Solar, CF: 30.2% + BESS: 100% pwr, 4 hours 5,000 30%$104.02 85%-$ -$ -$ 0.00%-$ 0.70$ $104.73 (0.91)$ $103.81
Rock Springs, WY, 200 MW, Solar, CF: 27.9% + BESS: 100% pwr, 4 hours 6,400 28%$114.09 85%-$ -$ -$ 0.00%-$ 0.70$ $114.80 (1.01)$ $113.79
Yakima, WA, 200 MW, Solar, CF: 24.2% + BESS: 100% pwr, 4 hours 1,000 24%$135.29 85%-$ -$ -$ 0.00%-$ 0.70$ $135.99 (1.21)$ $134.78
Idah Falls, ID, 200 MW, Solar & Wind, CF: 26.1% + BESS: 100% pwr, 4 hours + 200 MW Wind 4,700 26%$152.92 85%-$ -$ -$ 0.00%-$ 0.70$ $153.63 -$ $153.63
Lakeview, OR, 200 MW, Solar & Wind,CF: 27.6% + BESS: 100% pwr, 4 hours + 200 MW Wind 4,800 28%$145.41 85%-$ -$ -$ 0.00%-$ 0.70$ $146.12 -$ $146.12
Milford, UT, 200 MW, Solar & Wind,CF: 30.2% + BESS: 100% pwr, 4 hours + 200 MW Wind 5,000 30%$130.78 85%-$ -$ -$ 0.00%-$ 0.70$ $131.49 -$ $131.49
Rock Springs, WY, 200 MW, Solar & Wind,CF: 27.9% + BESS: 100% pwr, 4 hours + 200 MW 6,400 28%$141.55 85%-$ -$ -$ 0.00%-$ 0.70$ $142.25 -$ $142.25
Yakima, WA, 200 MW, Solar & Wind, CF: 24.2% + BESS: 100% pwr, 4 hours + 200 MW Wind 1,000 24%$165.14 85%-$ -$ -$ 0.00%-$ 0.70$ $165.84 -$ $165.84
Supply Side Resource Options
Mid-Calendar Year 2020 Dollars ($)
Resource Description
Elevation
(AFSL)
Convert to $/MWh
Total Resource Cost -
with PTC / ITC / 45Q
Credits
Variable Costs ($/MWh)
Levelized Fuel
PACIFICORP – 2021 IRP UPDATE CHAPTER 5 – MODELING AND ASSUMPTIONS UPDATE

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Modeling Enhancements and Resource Updates
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 the IRP Update preferred portfolio. Upon additional
review of demand response availability, demand response targets have been scaled back to
obtainable levels, decreasing potential selections in this update. Also in the 2021 IRP Update,
energy efficiency shapes are now aligned to load, better representing the relative effectiveness of
bundles to meet system need.
2020 All-source Request for Proposals Resources (2020AS RFP)
Since September 1, 2021, two 2020AS RFP resources withdrew from further contract
negotiations and have been removed from assumed development. These solar resources were
planned to contribute 153 MW of nameplate capacity and 58 MW of storage capacity in the
2024-2025 timeframe. At this time no replacement has been identified for these solar projects.
Other Contracts
Five contracts have been signed since September 2021, comprising 45 MW of nameplate solar
and geothermal capacity, partially offsetting losses due to changes in the 2020AS RFP. As an
original purchaser of the output of the Priest Rapids and Wanapum hydro projects, PacifiCorp
has an annual option to purchase approximately 100 MW of the output from these plants at
market-based rates. For this IRP Update, it has been assumed that PacifiCorp elects to purchase
this hydro output in each year of the study horizon.

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CHAPTER 6 – PORTFOLIO DEVELOPMENT
Introduction

PacifiCorp used Plexos’ three optimization models to develop an updated preferred portfolio based
on inputs and assumptions that have changed since the 2021 Integrated Resource Plan (IRP) was
filed September 1, 2021. This updated resource portfolio is consistent with PacifiCorp’s most
recent load-and-resource balance as described in Chapter 4. This chapter presents the 2021 IRP
Update preferred portfolio and a comparison of changes relative to the 2021 IRP preferred
portfolio. This chapter also includes three key variants studied in the 2021 IRP regarding
significant transmission projects and related resources, and one regional haze sensitivity evaluating
compliance strategy for Hunter and Huntington coal.

2021 IRP Update Preferred Portfolio
Key Updates

As discussed in Chapter 5 – Modeling and Assumptions Updates, key updates driving preferred
portfolio outcomes include higher load (approaching the 2021 IRP high-load sensitivity), DSM
alignment with achievable objectives and improved alignment to load, and resource changes due
to 2020AS RFP activity and newly signed contracts.

Also of note is the March 11, 2022 release of the Environmental Protection Agency’s pre-publication
version of its "Ozone Transport Rule" (also called Good Neighbor Rule or Cross-State Air Pollution
Rule). The rule, discussed in Chapter 3 – Planning Environment, could not be modeled in the 2021
IRP Update at this early juncture, but is expected to be considered in the 2023 IRP development cycle.
Portfolio Outcomes

The 2021 IRP Update focuses on updates following PacifiCorp’s filed 2021 IRP. These include
updates to load forecast, changes in existing resources and PacifiCorp’s contracts with other
entities.

Figure 6.1 summarizes the annual nameplate capacity in the 2021 IRP Update relative to the 2021
IRP preferred portfolio for the 20-year period 2021 through 2040. Consistent with the change in
PacifiCorp’s load-and-resource balance, the increase in loads accelerates transmission projects and
related resources into earlier timeframes and re-balances the resource mix as a result.

PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Figure 6.1 – Cumulative Increase/(Decrease) in 2021 IRP Update and
2021 IRP Preferred Portfolio

As in the 2021 IRP, the 2021 IRP Update preferred portfolio does not include any new natural gas
proxy resources through the 20-year planning horizon. Table 6.5 (summer) and (winter)
summarize the 2021 IRP Update load and resource balance, inclusive of incremental resources,
for 2021-2040.

Present Value Revenue Requirement (PVRR)
In Table 6.1, the 2021 IRP Update reports a PVRR differential (PVRR(d)) increase in system cost
of $946m compared to the 2021 IRP preferred portfolio. Increased load is the primary driver for
differences between the two studies, and therefore the High Load sensitivity (S01) analyzed in the
2021 IRP is also compared for reference. The 2021 IRP Update portfolio’s increase in cost falls
intuitively between the cost of the 2021 IRP preferred portfolio and the High Load sensitivity. The
increased load trends notably higher but does not exceed the high load forecast, as seen in Figure
6.3, below. Emissions and energy not served are also marginally higher, but the 2021 IRP Update
portfolio avoids the extremes anticipated in the S01 High Load sensitivity.

Table 6.1 – Cost and Risk Portfolio Summary

Figure 6.2 reports the relative annual PVRR of three portfolios, indicating the magnitude of the
load change in the 2021 IRP Update compared to the 2021 IRP and also to the S01 High Load
sensitivity. The results show that the annual PVRR of the updated portfolio is higher than in the
-3000
-2500
-2000
-1500
-1000
-500
0
500
1000
1500
2000
In
s
t
a
l
l
e
d

M
W
Coal Gas Contracts QF
Hydro Nuclear Hydro Storage Battery
Solar Solar+Storage Wind Wind+Storage
Geothermal Energy Efficiency Demand Response Non-Emitting Peaker
Converted Gas
21 IRP Update Preferred Portfolio Update (MM-CETA)26,866 27,289 122 419 $2,587 3.9 0.005647%
21 IRP Preferred Portfolio (P02-MM-CETA)26,740 27,167 -420 $2,594 3.9 0.005647%
21 IRP High Load (S01)27,606 28,436 1,269 409 $2,446 8.9 0.012619%
2021 to 2040
Vintage Study Name
ST PVRR
($million)
ST PVRR
plus 5% of
95th
Stochastic
($million)
Risk
Adjusted
PVRR(d)
Compared to
2021
Preferred
Portfolio
($million)
CO2
emissions
(Mtons)
CO2
emissions
cost
($million)
Avg Annual
Energy Not
Served plus
Reserve
Deficiency
(GWh)
Energy Not
Served as a
Percentage of
Load (%)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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2021 IRP, generally lower than in the High Load sensitivity, but rises above the High Load
sensitivity in some years (2029-2032). The trend comports with expected changes in PVRR under
higher load conditions and intuitively tracks with the load trajectory over the course of the 20-year
study period.

Figure 6.2 – Annual Present Value Revenue Requirement Comparison

Load Increase
The 2021 IRP Update load forecast is significantly higher than the forecast at the time of the 2021
IRP, and is discussed in more detail in Chapter 4 – Load and Resource Balance. Figure 6.3 shows
the load comparison among the 2021 IRP, 2021 IRP Update and the S01 High Load sensitivity
from the 2021 IRP in support of the PVRR comparison discussed above.

Figure 6.3 – Load Forecast Comparison

1,000
1,500
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3,000
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6,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
21 IRP CETA 21 IRP High Load 21 IRP Update CETA
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Forecasted Annual System Load
(GWh)
2021 IRP Update 2021 IRP 2021 IRP High
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Forecasted Annual System Coincident Peak
(MW)
2021 IRP Update 2021 IRP 2021 IRP High
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Transmission Acceleration
Load increase drives new and accelerated transmission in the updated preferred portfolio. While
more expensive, accelerated transmission is necessary to meet the higher load. By the end of the
study period, accumulated efficiencies including load-aligned DSM and improved resource
locations allows the model to avoid a major transmission upgrade in year 2040, and to avoid
approximately 400 MW of accompanying additional resources, net of the demand response
decrease discussed in Chapter 5 – Modeling Updates.

Table 6.2 reports changes in transmission selections relative the 2021 IRP. Four transmission paths
are accelerated by a total of 12 years in combination and two new paths are selected, adding 30
MW of interconnection capability to the system. One transmission upgrade, Portland North coast
to Willamette Valley, is delayed in the back 10 years of the model horizon. Finally, one
transmission path, Portland North Coast to Southern Oregon, is removed, partly offset by the
accelerations, particularly of the Central Oregon to Willamette Valley transmission line, as well
as the additional transmission selected.

Table 6.2 – Transmission Upgrade Changes in the 2021 IRP Update Preferred Portfolio
Compared to the 2021 IRP Preferred Portfolio1
1 – Negative values in the “Change” column indicates the number of years of acceleration compared to the 2021 IRP Preferred
Portfolio.

Table 6.3 reports all of the transmission projects selected for the 2021 IRP Update.

Upgrade Export Capacity 2021 Update Year 2020 IRP Year Change
CON Central OR > TxCON 2027 100 2030 2037 -7
CON Yakima > TxCON 2027a 180 2029 2030 -1
CON Yakima > TxCON 2027b 100 2029 -New
INC Central OR > Willamette Valley 2037 1500 2037 2040 -3
INC Portland North Coast > Southern Oregon 2037 1500 -2040 Removed
INC Portland North Coast > Willamette Valley 2032 450 2038 2032 6
INC Utah South > Utah North 2032 800 2032 2033 -1
INC Walla Walla - WA > Yakima 2030 200 2030 -New
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Table 6.3 – Transmission Projects Included in the 2021 IRP Update Preferred Portfolio1, 2
1 - TTC = 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 - Energy Gateway South is modeled in the 2021 IRP as a contingent option with bids in the 2020 All Source RFP. Other
transmission options prior to 2026 are not modeled as transmission requirements and costs are accounted for in the 2020 All Source
RFP cluster study for all other resource bids.
* Reclaimed transmission is committed with resources with COD later than the date of retirement.

New Solar Resources
The 2021 IRP Update preferred portfolio includes 1,709 MW of new solar by the end of 2024 and
2,309 MW by the end of 2026, with additions of 5,297 MW through 2040. Accounting for a 153
MW reduction in resources associated with the 2020 AS RFP, the 2021 IRP Update includes 833
MW more new solar capacity by the end of 2031 compared to the 2021 IRP preferred portfolio.
After 2031, driven by more efficient higher cost transmission and energy efficiency gains, solar
additions are ultimately reduced 730 MW by 2040.
Year Resource(s)From To Description
2025 1,641 MW RFP Wind (2025)Aeolus WY Clover Enables 1,930 MW of interconnection with 1700
MW of TTC: Energy Gateway South
2026 415 MW Wind (2026)
200 MW Standalone Battery (2026)
Enables 615 MW of interconnection: Albany OR area
reinforcement
130 MW Wind (2026)
450 MW Wind (2032)
2026 600 MW Solar+Storage (2026)Borah-Populous Hemingway Enables 600 MW of interconnection with 600 MW
of TTC: B2H Boardman-Hemingway
2028 83 MW Solar+Storage (2028)
377 MW Solar+Storage (2030)
Enables 460 MW of interconnection: Medford area
reinforcement
2029 160 MW Solar+Wind+Storage (2030)
120 MW Solar+Storage (2030)
Enables 280 MW of interconnection: Yakima local
area reinforcement
2030 100 MW Wind (2030)Walla Walla Yakima Enables 100 MW of interconnection
2030 100 MW Solar+Storage (2030)Enables 100 MW of interconnection
2031 626 MW Solar+Storage (2031)
412 MW Non-Emitting Peaker (2033)
Enables 1040 MW of interconnection: Northern UT
345 kV reinforcement
2032 1100 MW Solar+Storage (2032)Southern UT Northern UT
Enables 1500 MW of interconnection with 800 MW
TTC: Spanish Fork - Mercer 345 kV; New Emery –
Clover 345 kV
Southwest Wyoming
Transmission Area
Willamette Valley
Central OR Transmission Area
2028*500 MW Adv Nuclear (2028)Reclaimed transmission upon retirement of Naughton
1 & 2
2029*500 MW Battery (2029)
330 MW Wind (2028 & 2029)
Eastern Wyoming Reclaimed transmission upon retirement of Dave
Johnston PlantTransmission Area
2038 412 MW Non-Emitting Peaker (2038)
1000 MW Adv Nuclear (2038)
Bridger WY
Within Willamette Valley OR Transmission Area
Willamette Valley
2026 Portland North Coast
Enables 450 MW of interconnection with 450 MW
TTC; Portland Coast area reinforcement and
Willamette Valley
Yakima WA Transmission Area
Northern UT Transmission Area
2037 155 MW Wind (2037)
500 MW Pumped Storage (2040)
Within Southern OR Transmission Area
Central OR Enables 980 MW of interconnection with 1500 MW
of TTC
Reclaimed transmission upon retirement of Jim
Bridger Plant Transmission Area
2037 702 MW Solar+Storage (2037)
206 MW Non-Emitting Peaker (2037)
Southern Utah Reclaimed transmission upon retirement of
Huntington 1 & 2Transmission Area
2040 268 MW Wind (2040)
Eastern Wyoming
Reclaimed transmission upon retirement of Wyodak
Transmission Area
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Figure 6.4 – 2021 IRP Update Preferred Portfolio New Solar Capacity*
* 2021 IRP Update solar capacity shown in the figure includes solar resources coming via the 2020 All-Source Request
for Proposals by the end of 2024. Resources are shown in the first full year of operation (the year after the year-online
dates). The reported capacity for the 2020 All-Source Request for Proposals solar resources reflects their expected
maximum output after degradation in their first full year of operation.

New Wind Resources
As shown in Figure 6.5, by the end of 2024, PacifiCorp’s 2021 IRP Update preferred portfolio
includes 1,815 MW of new wind generation resulting from the 2020 All-Source RFP and the
acquisition and repowering of Rock River I (49 MW) and Foote Creek II-IV (43 MW). Through
the end of 2026, the 2021 IRP Update preferred portfolio includes an additional 2,363 MW of new
wind and more than 4,000 MW of new wind by 2040. Relative to the 2021 IRP, 2021 IRP Update
wind additions are mostly reduced or flat through 2037, and ultimately increase by 348 MW of
new wind by the end of 2040.

Figure 6.5 – 2021 IRP Update Preferred Portfolio New Wind Capacity*
*Note: Wind additions shown are incremental to Energy Vision 2020 and other projects that have come online over
the past few years. Resources are shown in the first full year of operation (the year after year-end online dates).

New Storage Resources
New storage resources in the 2021 IRP Update preferred portfolio are summarized in Figure 6.6.
The updated portfolio includes nearly 639 MW of battery storage by the end of 2024 – 200 MW
of which is a standalone battery and the remaining portion paired with solar resources resulting
from the 2020 All-Source RFP. Through 2040, the 2021 IRP includes 4,146 MW of storage co-
located with solar resources, 900 MW of standalone battery, and 500 MW of pumped hydro.
0
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2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
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PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Figure 6.6 – 2021 IRP Update Preferred Portfolio New Storage Capacity*
*Note: Resources are shown in the first full year of operation (the year after the year-end online dates).

Other Non-Emitting Resources
The 2021 IRP was the first to include new advanced nuclear and non-emitting peaking resources
as part of its least-cost, least-risk preferred portfolio. The 2021 IRP Update continues to select
these resources. As shown in Figure 6.7, the 500 MW advanced nuclear NatriumTM demonstration
project is projected to come online by summer 2028. Through 2040, the 2021 IRP Update preferred
portfolio includes 1,500 MW of advanced nuclear resources and 1,237 MW of non-emitting
peaking resources to support meeting requirements. Compared to the 2021 IRP, non-emitting
peaker additions increase by 11 MW due to capacity sizing differences of the selected locations.

Figure 6.7 – 2021 IRP Update Other Non-Emitting Resources Capacity
*Note: Resources are shown in the first full year of operation (the year after the year-end online dates).

Demand-Side Management
DSM resources continue to play a key role in PacifiCorp’s resource mix. The chart to the left in
Figure 6.8 compares total energy efficiency capacity savings in the 2021 IRP Update preferred
portfolio relative to the 2021 IRP preferred portfolio and includes 4,685 MW by the end of the
planning period. This increase is attributed to the reductions in demand response, combined with
the alignment of energy efficiency to load, both described in Chapter 5 – Modeling Updates. For
the 2021 IRP Update, selections of demand response have been scaled back to realistic targets,
which is responsible for decreases shown on the right-hand side of Figure 6.8. Demand response
selections in the 2021 IRP Update total nearly 1,000 MW over the 20-year horizon. By the end of
2040 and relative to the 2021 IRP preferred portfolio, energy efficiency selection increases by
nearly 400 MW, whereas demand response selections are reduced by more than 1,400 MW.

0
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PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Figure 6.8 – 2021 IRP Update Preferred Portfolio Energy Efficiency (Class 2 DSM) and
Direct Load Control Capacity (Class 1 DSM)

Market Activity
Figure 6.9 compares market purchases and sales among the 2021 IRP preferred portfolio, the 2021
IRP S01 High Load sensitivity and the 2021 IRP Update. While the 2021 IRP Update averages
approximately 500 GWh of additional sales annually compared to both the 2021 IRP preferred
portfolio and the 2021 IRP High Load scenario, offsetting purchases are higher in some years,
particularly 2032 to 2037. On average, 2021 IRP Update purchases increase by an average of 200
MW annually on a purely volumetric basis. Given near-term concerns over resource adequacy,
generally lower market purchases in 2021 IRP Update portfolio in the first 5 years are viewed
favorably.

Figure 6.9 – 2021 IRP Update Market Activity Comparison to 2021 IRP Studies

Coal and Gas Retirements/Gas Conversions
The 2021 IRP Update did not trigger any changes to the retirement or conversion assumptions
selected in the 2021 IRP. Driven in part by ongoing cost pressures on existing coal-fired facilities
and dropping costs for new resource alternatives, of the 22 coal units currently serving PacifiCorp
customers, the updated preferred portfolio continues to include retirement of 14 of the units by
2030 and 19 of the units by the end of the planning period in 2040. As shown in , coal unit
retirements/gas peaker conversions in the 2021 IRP Update preferred portfolio will reduce coal-
fueled generation capacity by 1,300 MW by the end of 2025, over 2,200 MW by 2030, and over
4,000 MW by 2040.

0
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Purch-21 IRP CETA Purch-21 IRP High Load
Purch-21 IRP Update CETA
(10,000)
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Sales-21 IRP CETA Sales-21 IRP High Load
Sales-21 IRP Update CETA
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Figure 6.10 – 2021 IRP Update Preferred Portfolio Coal Retirements/Gas Conversions*
* Note: Coal retirements are assumed to occur by the end of the year before the year shown in the graph. The graph
shows the year in which the capacity will not be available for meeting summer peak load. All figures represent
PacifiCorp’s ownership share of jointly owned facilities.

(4,500)
(4,000)
(3,500)
(3,000)
(2,500)
(2,000)
(1,500)
(1,000)
(500)
0
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PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Table 6.4 – Comparison of 2021 IRP Update with 2021 IRP Preferred Portfolio (Megawatts)

2021 IRP Update
Capacity (MW)10- year Total
Resource 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2021-2040
Expansion Options
Gas - CCCT - - - - - - - - - - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - - - - - - - - - - -
NonEmitting Peaking - - - - - - - - - - 412 - - - - - 412 412 - - 1,237
DSM - Energy Efficiency 146 124 131 132 199 237 270 304 323 347 348 339 322 296 262 230 201 176 155 143 4,685
DSM - Demand Response - 117 148 74 61 35 37 62 58 58 54 28 24 22 47 24 72 20 17 20 978
Renewable - Wind 49 - - 194 1,641 547 - 255 202 308 - - - - - - 156 450 - 268 4,069
Renewable - Wind+Storage - - - - - - - - 160 - - - - - - - - - - - 160
Renewable - Utility Solar - - - - - - - - - - - - - - - - - - - - -
Renewable - Utility Solar + Storage - - - 345 805 600 - 83 160 477 626 1,100 - - - - 702 - - - 4,898
Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable - Battery (Wind+Storage)- - - - - - - - - - - - - - - - - - - - -
Renewable - Battery (Solar+Storage)- - - 88 352 600 - 42 160 477 626 1,100 - - - - 702 - - - 4,146
Battery - Stand Alone - - - 200 - 200 - - 500 - - - - - - - - - - - 900
Storage - CAES - - - - - - - - - - - - - - - - - - - - -
Storage - Pumped Hydro - - - - - - - - - - - - - - - - - - - 500 500
Nuclear - - - - - - - 345 - - - - - - - - - 690 - - 1,035
Nuclear + Storage - - - - - - - 155 - - - - - - - - - 310 - - 465
Front Office Transactions - Summer *125 59 108 132 171 113 129 141 188 172 163 164 251 253 301 251 255 309 348 351 199
Front Office Transactions - Winter *164 60 121 143 133 1 1 1 1 - - - - 89 103 138 366 607 670 714 166
Existing Unit Changes
Thermal Plant End-of-life Retirements - - - - - (230) - (788) (123) - - - - - - - (909) (699) - (268) (3,018)
Coal Early Retirement - - - - - (357) - - - - - - - - - - - - - - (357)
Coal Plant Gas Conversion - - - 713 - - - - - - - - - - - - - (713) - - -
Coal Plant ceases running as Coal - - - (713) - - - - - - - - - - - - - - - - Coal Plant ceases running as Coal(713)
Gas Plant End-of-life Retirements - - - - - - - - - (247) - - (356) - - - (237) - - - (840)
Total 484 360 509 1,306 3,361 1,746 437 600 1,630 1,592 2,228 2,730 240 661 713 644 1,720 1,561 1,191 1,728
* FOT in resource total are 20-year averages
2021 IRP Update less 2021 IRP Preferred Portfolio
Capacity (MW)10- year Total
Resource 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2021-2040
Expansion Options
Gas - CCCT - - - - - - - - - - - - - - - - - - - - -
Gas- Peaking - - - - - - - - - - - - - - - - - - - - -
NonEmitting Peaking - - - - - - - - - - 412 - (402) - - - 412 (206) - (206) 11
DSM - Energy Efficiency (11) (14) (13) (33) 14 26 32 41 44 43 47 46 50 47 41 36 12 6 (5) (13) 395
DSM - Demand Response - (7) (94) (110) (18) (29) (32) (18) (19) (19) (29) (22) (189) (48) (113) (101) (111) (139) (90) (281) (1,471)
Renewable - Wind - - (151) 151 - (198) - 255 202 (182) - (450) - - - - 156 450 - 208 441
Renewable - Wind+Storage - - - - - - - - 160 (160) - - - - - - - - - - -
Renewable - Utility Solar - - - (95) - - - - - - - - - - - - - - - - (95)
Renewable - Utility Solar + Storage - - - (407) 349 - - - 160 (81) (194) 1,100 (1,100) - - - (307) - - (156) (635)
Renewable - Geothermal - - - - - - - - - - - - - - - - - - - - -
Renewable - Battery (Wind+Storage)- - - - - - - - - - - - - - - - - - - - -
Renewable - Battery (Solar+Storage)- - - (152) 94 - - - 160 (81) (194) 1,100 (1,100) - - - (307) - - (156) (635)
Battery - Stand Alone - - - - - 200 - - (49) (1) - - - - - - (650) - - - (500)
Storage - CAES - - - - - - - - - - - - - - - - - - - - -
Storage - Pumped Hydro - - - - - - - - - - - - - - - - - - - - -
Nuclear - - - - - - - - - - - - - - - - - - - - -
Nuclear + Storage - - - - - - - - - - - - - - - - - - - - -
Front Office Transactions - Summer *(90) (180) (119) (71) (138) (94) (117) (114) (145) (193) (210) (209) (122) (247) (72) (192) (179) (191) (152) (149) (149)
Front Office Transactions - Winter *(6) (113) (78) (38) (56) (22) (40) (29) (29) (30) (22) (86) (165) (114) (102) (165) (64) 82 118 38 (46)
Existing Unit Changes
Thermal Plant End-of-life Retirements - - - - - - - - - - - - - - - - - - - - -
Coal Early Retirement - - - - - - - - - - - - - - - - - - - - -
Coal Plant Gas Conversion - - - - - - - - - - - - - - - - - - - - -
Coal Plant ceases running as Coal - - - - - - - - - - - - - - - - - - - - -
Gas Plant End-of-life Retirements - - - - - - - - - - - - - - - - - - - - -
Total (107) (314) (456) (754) 244 (116) (158) 135 483 (703) (190) 1,479 (3,028) (361) (246) (423) (1,037) 1 (129) (714)
* FOT in resource total are 20-year averages
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Table 6.5 – 2021 IRP Update Summer Capacity Load and Resource Balance (Megawatts)

East
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Coal 3,536 3,474 3,505 3,513 3,076 3,067 2,343 2,245 2,199 2,198
Gas 1,942 1,964 1,922 1,947 1,968 1,933 1,950 1,942 1,753 1,748
Hydroelectric 108 108 88 88 88 88 88 87 87 87
Solar 377 521 197 424 341 320 352 316 291 161
Wind 337 405 262 452 445 424 422 491 490 395
Geothermal 49 50 51 50 50 52 51 50 51 50
Contracts 185 182 122 35 31 30 31 24 22 17
Sales and Ancillary Services (267)(267)(243)(243)(239)(236)(235)(234)(233)(233)
East Existing Resources 6,268 6,438 5,905 6,265 5,760 5,678 5,003 4,922 4,660 4,423
Front Office Transactions 300 300 300 124 0 0 0 0 0 0
NonEmitting Peaker 0 0 0 0 0 0 0 0 0 367
Wind 0 0 14 300 293 291 352 397 449 392
Solar 0 0 30 169 143 133 165 148 129 117
Storage 1 1 284 583 553 535 669 923 817 1,125
Nuclear 0 0 0 0 0 0 324 322 334 318
East Planned Resources 301 301 628 1,177 990 959 1,510 1,790 1,729 2,319
East Total Resources 6,569 6,739 6,533 7,442 6,749 6,637 6,513 6,712 6,388 6,742
Load 7,274 7,421 7,543 7,685 7,654 7,732 7,843 7,944 8,052 8,162
Private Generation (57)(66)(69)(71)(75)(81)(90)(103)(120)(144)
Existing - Demand Response (594)(585)(594)(593)(520)(496)(460)(255)(220)(196)
New Demand Response (74)(146)(169)(192)(182)(187)(202)(158)(141)(130)
New Energy Efficiency (134)(210)(242)(379)(500)(810)(801)(1,051)(1,026)(1,252)
East Total obligation 6,415 6,414 6,468 6,450 6,377 6,158 6,291 6,378 6,545 6,440
East Reserve Margin 2%5%1%15%6%8%4%5%-2%5%
West
Coal 1,500 1,495 1,487 1,488 1,354 1,352 1,348 1,370 1,356 1,356
Gas 663 673 660 664 663 664 664 664 675 665
Hydroelectric 955 796 790 799 795 798 798 794 792 797
Solar 7 27 10 20 16 15 16 14 13 6
Wind 89 83 50 87 82 89 77 84 91 85
Geothermal 0 0 0 0 0 0 0 0 0 0
Contracts 171 168 131 146 132 97 102 72 63 47
Sales and Ancillary Services (209)(207)(182)(182)(179)(177)(177)(168)(168)(169)
West Existing Resources 3,177 3,034 2,945 3,022 2,863 2,838 2,828 2,831 2,822 2,787
Front Office Transactions 1,245 1,128 1,445 290 0 0 0 0 0 0
NonEmitting Peaker 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 141 153 162 223 273 239
Solar 0 0 0 59 157 154 190 196 274 151
Storage 0 0 0 53 844 844 886 868 1,092 971
Nuclear 0 0 0 0 0 0 0 0 0 0
West Planned Resources 1,245 1,128 1,445 402 1,142 1,151 1,238 1,286 1,640 1,361
West Total Resources 4,421 4,162 4,390 3,424 4,006 3,989 4,066 4,118 4,462 4,148
Load 3,372 3,402 3,434 3,471 3,501 3,534 3,569 3,604 3,640 3,679
Private Generation (28)(40)(45)(49)(54)(60)(67)(75)(85)(106)
Existing - Demand Response 0 0 0 0 0 0 0 0 0 0
New Demand Response (42)(107)(149)(174)(164)(170)(174)(119)(110)(103)
New Energy Efficiency (73)(120)(147)(192)(242)(157)(354)(264)(442)(321)
West Total obligation 3,229 3,136 3,094 3,055 3,041 3,147 2,975 3,145 3,003 3,148
West Reserve Margin 37%33%42%12%32%27%37%31%49%32%
System
Total Resources 10,990 10,900 10,924 10,866 10,755 10,626 10,578 10,830 10,850 10,890
Obligation 9,644 9,550 9,562 9,505 9,418 9,305 9,265 9,523 9,548 9,588
Capacity Reserve Margin (13%)1,254 1,242 1,243 1,236 1,224 1,210 1,204 1,238 1,241 1,246
Obligation + Reserves 10,898 10,792 10,805 10,741 10,643 10,515 10,470 10,761 10,789 10,834
System Position 92 109 119 125 113 111 109 69 61 56
Reserve Margin 14%14%14%14%14%14%14%14%14%14%
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Table 6.5 (Cont.) – 2021 IRP Update Summer Capacity Load and Resource Balance
(Megawatts)

East
2032 2033 2034 2035 2036 2037 2038 2039 2040
Thermal 2,212 2,219 2,207 2,219 2,218 1,359 1,362 1,357 1,100
Hydroelectric 1,743 1,412 1,401 1,397 1,398 1,403 1,403 1,399 1,410
Hydroelectric 86 87 87 86 87 86 86 87 87
Solar 30 136 124 132 125 137 144 142 83
Wind 252 355 359 353 333 475 502 480 457
Geothermal 51 50 51 51 52 50 20 20 20
Contracts 10 15 14 12 9 8 0 0 0
Sales and Ancillary Services (226)(230)(229)(228)(228)(233)(233)(234)(227)
East Existing Resources 4,159 4,043 4,013 4,022 3,993 3,287 3,285 3,251 2,931
Front Office Transactions 0 0 0 0 0 0 0 0 0
NonEmitting Peaker 398 380 386 385 398 581 580 585 576
Wind 253 394 413 400 372 490 483 526 568
Solar 40 200 187 191 172 474 520 525 324
Storage 1,642 1,521 1,497 1,497 1,496 1,720 1,675 1,626 1,558
Nuclear 322 314 326 322 335 319 932 925 939
East Planned Resources 2,655 2,809 2,809 2,795 2,773 3,584 4,190 4,187 3,965
East Total Resources 6,813 6,853 6,822 6,817 6,766 6,871 7,475 7,438 6,896
Load 8,266 8,370 8,473 8,444 8,585 8,679 8,793 8,655 8,759
Private Generation (173)(203)(236)(150)(173)(196)(221)(116)(128)
Existing - Demand Response (176)(163)(161)(161)(160)(148)(144)(148)(142)
New Demand Response (119)(113)(113)(120)(122)(123)(121)(126)(122)
New Energy Efficiency (1,489)(1,442)(1,522)(1,590)(1,607)(1,702)(1,753)(1,702)(1,844)
East Total obligation 6,309 6,450 6,442 6,423 6,522 6,510 6,553 6,563 6,522
East Reserve Margin 8%6%6%6%4%6%14%13%6%
West
Coal 1,356 1,358 1,355 1,354 1,353 1,351 0 0 0
Gas 667 665 665 663 677 449 448 446 446
Hydroelectric 793 794 796 792 793 795 795 798 798
Solar 1 5 4 5 5 9 10 10 7
Wind 56 88 77 73 83 97 114 117 84
Geothermal 0 0 0 0 0 0 0 0 0
Contracts 24 35 31 30 32 23 19 10 10
Sales and Ancillary Services (162)(169)(167)(160)(155)(161)(157)(156)(144)
West Existing Resources 2,735 2,776 2,760 2,757 2,787 2,563 1,229 1,224 1,200
Front Office Transactions 0 0 0 0 0 0 0 0 0
NonEmitting Peaker 0 0 0 0 0 196 566 575 586
Wind 157 246 256 220 220 343 522 543 470
Solar 35 137 126 127 130 249 272 278 183
Storage 873 809 796 796 796 735 915 940 1,364
Nuclear 0 0 0 0 0 0 0 0 0
West Planned Resources 1,065 1,192 1,177 1,143 1,145 1,522 2,276 2,337 2,603
West Total Resources 3,801 3,968 3,938 3,900 3,932 4,086 3,505 3,561 3,803
Load 3,711 3,747 3,785 3,775 3,809 3,854 3,892 3,861 3,896
Private Generation (147)(193)(247)(217)(254)(296)(341)(190)(221)
Existing - Demand Response 0 0 0 0 0 0 0 0 0
New Demand Response (94)(88)(88)(90)(91)(85)(84)(87)(84)
New Energy Efficiency (432)(382)(412)(450)(561)(327)(344)(455)(685)
West Total obligation 3,040 3,084 3,038 3,018 2,902 3,145 3,124 3,129 2,906
West Reserve Margin 25%29%30%29%35%30%12%14%31%
System
Total Resources 10,614 10,820 10,760 10,716 10,699 10,957 10,980 10,999 10,698
Obligation 9,348 9,534 9,481 9,441 9,425 9,655 9,677 9,692 9,428
Capacity Reserve Margin (13%)1,215 1,239 1,232 1,227 1,225 1,255 1,258 1,260 1,226
Obligation + Reserves 10,563 10,773 10,713 10,668 10,650 10,911 10,935 10,952 10,653
System Position 51 47 47 48 49 46 45 47 45
Reserve Margin 14%13%13%14%14%13%13%13%13%
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Table 6.6 – 2021 IRP Update Winter Capacity Load and Resource Balance (Megawatts)

East
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Coal 3,443 3,491 3,470 3,477 2,931 2,941 2,249 2,224 2,148 2,090
Gas 1,938 2,045 2,043 1,995 1,913 1,969 2,042 2,012 1,817 1,700
Hydroelectric 80 80 70 70 68 67 70 69 69 67
Solar 48 72 40 22 14 16 16 24 39 11
Wind 268 383 250 278 280 263 256 355 418 306
Geothermal 52 52 52 51 51 46 52 52 52 50
Contracts 164 137 66 16 15 15 15 9 9 8
Sales and Ancillary Services (212)(215)(189)(192)(190)(189)(191)(193)(194)(194)
East Existing Resources 5,781 6,045 5,801 5,716 5,081 5,127 4,509 4,552 4,360 4,038
Front Office Transactions 181 167 187 0 0 0 0 0 0 0
NonEmitting Peaker 0 0 0 0 0 0 0 0 11 375
Wind 0 0 20 293 255 247 309 424 539 460
Solar 0 0 7 14 10 11 8 14 24 13
Storage 1 1 250 491 456 453 614 847 758 1,037
Nuclear 0 0 0 0 0 3 308 309 308 297
East Planned Resources 182 168 464 797 722 715 1,240 1,594 1,640 2,182
East Total Resources 5,963 6,213 6,265 6,514 5,803 5,842 5,749 6,146 6,000 6,220
Load 5,691 5,868 5,936 6,050 5,977 6,033 6,138 6,220 6,297 6,374
Private Generation (1)(2)(2)(3)(4)(5)(6)(7)(8)(9)
Existing - Demand Response (322)(309)(335)(408)(330)(324)(336)(229)(204)(180)
New Demand Response (73)(138)(150)(166)(163)(167)(182)(142)(131)(120)
New Energy Efficiency (108)(148)(198)(221)(275)(725)(400)(842)(880)(520)
East Total obligation 5,186 5,273 5,251 5,252 5,205 4,813 5,213 5,000 5,074 5,545
East Reserve Margin 15%18%19%24%11%21%10%23%18%12%
West
Coal 1,488 1,488 1,319 1,468 1,321 1,314 1,338 1,335 1,360 1,313
Gas 718 718 711 713 697 693 717 715 630 695
Hydroelectric 1,038 858 865 861 847 843 869 866 869 843
Solar 0 1 1 1 0 0 0 1 1 0
Wind 39 52 33 50 39 33 34 44 52 50
Geothermal 0 0 0 0 0 0 0 0 0 0
Contracts 78 73 70 68 58 31 33 21 17 15
Sales and Ancillary Services (192)(174)(149)(146)(145)(142)(142)(147)(147)(146)
West Existing Resources 3,168 3,016 2,850 3,014 2,818 2,772 2,849 2,834 2,782 2,771
Front Office Transactions 422 390 437 0 0 0 0 0 0 0
NonEmitting Peaker 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 2 67 63 60 109 135 123
Solar 0 0 0 3 7 7 8 11 21 8
Storage 0 0 0 53 844 844 886 782 1,013 894
Nuclear 0 0 0 0 0 0 0 0 0 0
West Planned Resources 422 390 437 58 918 915 954 902 1,169 1,025
West Total Resources 3,590 3,407 3,287 3,072 3,737 3,687 3,803 3,736 3,951 3,796
Load 3,330 3,373 3,408 3,446 3,487 3,534 3,580 3,628 3,673 3,710
Private Generation (0)(1)(1)(1)(1)(2)(2)(3)(3)(4)
Existing - Demand Response 0 0 0 0 0 0 0 0 0 0
New Demand Response (35)(82)(108)(136)(129)(134)(144)(107)(102)(95)
New Energy Efficiency (76)(110)(165)(160)(191)150 (271)172 114 (339)
West Total obligation 3,218 3,179 3,135 3,148 3,166 3,548 3,164 3,690 3,682 3,273
West Reserve Margin 12%7%5%-2%18%4%20%1%7%16%
System
Total Resources 9,553 9,620 9,553 9,585 9,540 9,529 9,552 9,882 9,951 10,016
Obligation 8,405 8,452 8,385 8,401 8,371 8,361 8,377 8,690 8,756 8,818
Capacity Reserve Margin (13%)1,093 1,099 1,090 1,092 1,088 1,087 1,089 1,130 1,138 1,146
Obligation + Reserves 9,497 9,551 9,475 9,493 9,459 9,448 9,466 9,820 9,894 9,965
System Position 56 69 77 92 81 81 86 62 57 51
Reserve Margin 14%14%14%14%14%14%14%14%14%14%
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Table 6.6 (Cont.) - 2021 IRP Update Winter Capacity Load and Resource Balance
(Megawatts)

East
2032 2033 2034 2035 2036 2037 2038 2039 2040
Coal 2,051 2,203 2,178 2,212 2,188 1,353 1,332 1,338 1,178
Gas 1,736 1,444 1,473 1,485 1,353 1,482 1,479 1,487 1,466
Hydroelectric 66 69 69 69 69 70 69 69 69
Solar 7 6 9 23 33 31 37 36 24
Wind 220 271 274 389 454 578 701 744 561
Geothermal 49 52 49 52 52 52 20 20 20
Contracts 7 7 7 6 6 3 0 0 7
Sales and Ancillary Services (194)(196)(198)(203)(205)(202)(203)(205)(208)
East Existing Resources 3,942 3,857 3,861 4,034 3,949 3,367 3,436 3,490 3,116
Front Office Transactions 0 0 0 0 0 0 0 0 126
NonEmitting Peaker 360 382 387 385 386 577 579 581 569
Wind 300 424 460 535 581 676 790 852 792
Solar 11 13 16 39 59 100 112 114 84
Storage 1,549 1,449 1,445 1,447 1,509 1,634 1,596 1,523 1,478
Nuclear 278 312 314 310 305 342 945 955 906
East Planned Resources 2,498 2,581 2,622 2,715 2,841 3,328 4,022 4,024 3,955
East Total Resources 6,440 6,437 6,483 6,749 6,790 6,695 7,457 7,514 7,071
Load 6,459 6,542 6,645 6,724 6,801 6,890 6,992 7,083 7,190
Private Generation (10)(12)(13)(14)(16)(18)(19)(21)(23)
Existing - Demand Response (166)(155)(155)(155)(162)(141)(137)(139)(135)
New Demand Response (113)(107)(109)(116)(123)(117)(115)(118)(116)
New Energy Efficiency (905)(920)(1,185)(1,051)(1,057)(343)(1,143)(443)(1,458)
East Total obligation 5,265 5,348 5,183 5,387 5,443 6,272 5,576 6,363 5,459
East Reserve Margin 22%20%25%25%25%7%34%18%30%
West
Coal 1,285 1,323 1,361 1,362 1,360 1,360 0 0 27
Gas 680 710 718 718 683 490 489 490 495
Hydroelectric 828 865 874 875 874 877 878 880 879
Solar 0 0 0 0 0 1 1 1 0
Wind 31 41 46 52 60 79 83 82 68
Geothermal 0 0 0 0 0 0 0 0 0
Contracts 14 13 13 14 13 13 12 11 14
Sales and Ancillary Services (144)(141)(144)(145)(146)(143)(142)(142)(148)
West Existing Resources 2,695 2,812 2,867 2,877 2,846 2,675 1,322 1,321 1,336
Front Office Transactions 0 0 0 0 0 0 0 0 293
NonEmitting Peaker 0 0 0 0 7 212 577 579 540
Wind 84 111 112 131 127 189 290 294 242
Solar 4 5 5 13 18 24 30 37 22
Storage 823 770 768 769 803 698 872 881 1,294
Nuclear 0 0 0 0 0 0 0 0 0
West Planned Resources 911 886 886 913 954 1,123 1,769 1,791 2,392
West Total Resources 3,606 3,699 3,753 3,790 3,801 3,798 3,091 3,112 3,727
Load 3,756 3,805 3,854 3,902 3,946 3,994 4,048 4,102 4,156
Private Generation (4)(5)(6)(7)(8)(9)(11)(12)(13)
Existing - Demand Response 0 0 0 0 0 0 0 0 0
New Demand Response (88)(84)(85)(87)(92)(81)(80)(81)(80)
New Energy Efficiency (80)(134)73 89 40 (934)(237)(1,013)(3)
West Total obligation 3,584 3,582 3,836 3,898 3,886 2,970 3,721 2,995 4,059
West Reserve Margin 1%3%-2%-3%-2%28%-17%4%-8%
System
Total Resources 10,047 10,136 10,236 10,539 10,591 10,493 10,548 10,625 10,798
Obligation 8,848 8,930 9,018 9,285 9,329 9,243 9,297 9,358 9,518
Capacity Reserve Margin (13%)1,150 1,161 1,172 1,207 1,213 1,202 1,209 1,217 1,237
Obligation + Reserves 9,999 10,091 10,191 10,492 10,542 10,444 10,505 10,574 10,755
System Position 48 45 45 47 49 49 43 51 43
Reserve Margin 14%14%14%14%14%14%13%14%13%
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Carbon Dioxide Emissions

While the 2021 IRP Update preferred portfolio reflects PacifiCorp’s on-going efforts to provide
cost-effective clean-energy solutions for our customers, increased load has driven thermal dispatch
and therefore emissions higher based on currently modeled resource options and assumptions.
Portfolio emissions and costs due to the higher load forecast present a less extreme version of the
S01 High Load sensitivity from the 2021 IRP.

PacifiCorp’s emissions have been declining and are expected to continue to decline related to
several factors including PacifiCorp’s participation in the EIM, which reduces customer costs and
maximizes use of clean energy; PacifiCorp’s on-going transition to clean-energy resources
including new renewable resources, new advanced nuclear resources, new non-emitting resources,
storage, and associated transmission; and Regional Haze compliance. Input updates and additional
transmission and resource options in the 2023 IRP are expected to allow economic emissions
reductions not available to the 2021 IRP Update and in the absence of a full IRP cycle.

The chart on the left in Figure 6.11 compares projected annual CO2 emissions between the 2021
IRP update and 2021 IRP preferred portfolios. In this graph, emissions are not assigned to market
purchases or sales.

The chart on the right in Figure 6.11 includes historical data, assigns emissions at a rate of 0.4708
tons CO2 equivalent per MWh to market purchases (with no credit to market sales), includes
emissions associated with specified purchases, and extrapolates projections out through 2050. This
graph demonstrates that relative to a 2005 baseline, 2021 IRP Update preferred portfolio system
CO2 equivalent emissions are down 49 percent in 2025, 69 percent in 2030, 78 percent in 2035,
88 percent in 2040, 94 percent in 2045, and 100 percent in 2050.

Figure 6.11 – 2021 IRP Preferred Portfolio CO2 Emissions and PacifiCorp CO2 Equivalent
Emissions Trajectory*

*Note: PacifiCorp CO2 equivalent emissions trajectory reflects actual emissions through 2020 from owned facilities,
specified sources and unspecified sources. From 2021 through the end of the twenty-year planning period in 2040,
emissions reflect those from the 2021 IRP Update preferred portfolio with emissions from specified sources reported
in CO2 equivalent. Market purchases are assigned a default emission factor (0.4708 short tons CO2e/MWh) –
emissions from sales are not removed. Beyond 2040, emissions reflect the rolling average emissions of each resource
from the 2021 IRP update preferred portfolio through the life of the resource. The emissions trajectory does not
incorporate clean energy targets set forth in Oregon House Bill 2021 or any other state-specific emissions trajectories.
PacifiCorp expects these targets, and an Oregon-specific emissions trajectory, to be incorporated following the 2023
integrated resource plan when PacifiCorp is required under the bill to file a Clean Energy Plan.

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o
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o
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O
2e)
PacifiCorp CO2 Equivalent Emissions Trajectory
PacifiCorp Emissions (Million ST CO2e)PacifiCorp 2005 Base (Million ST CO2e)
% Reduction from 2005 Base
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Monthly CO2 emissions are available for the preferred portfolio as shown in Figure 6.12 below.

Figure 6.12 – 2021 IRP Update Monthly CO2

Renewable Portfolio Standards

Figure 6.13 shows PacifiCorp’s renewable portfolio standard (RPS) compliance forecast for
California, Oregon, and Washington after accounting for new renewable resources in the preferred
portfolio. While these resources are included in the preferred portfolio as cost-effective system
resources and are not included to specifically meet RPS targets, they nonetheless contribute to
meeting RPS targets in PacifiCorp’s western states.
Oregon RPS compliance is achieved through 2040 with the addition of new renewable resources
and transmission in the 2021 IRP Update preferred portfolio. Consistent with the 2021 IRP, in the
2021 IRP Update, Washington RPS compliance is achieved with the benefit of increased system
renewable resources as well as additional resources procured that meet the state’s Clean Energy
Transformation Act. Under PacifiCorp’s 2020 Protocol, and the Washington Interjurisdictional
Allocation Methodology, Washington’s RPS position is improved by receiving a system share of
renewable resources across the PacifiCorp’s system.
The California RPS compliance position will be met with owned and contracted renewable
resources, as well as REC purchases throughout the study period. The ramping RPS requirement
results in an increased need for unbundled REC purchases to meet the annual and compliance
period targets in 2021-2040. New renewable resources and transmission in the 2021 IRP update
preferred portfolio mitigate that shortfall, but the company has made a 120,000 REC purchase
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towards compliance period 4, years 2021-2024, and will continue to evaluate the need for
unbundled RECs and issue RFPs to meet its state RPS compliance requirements as needed.
While not shown in Figure 6.13, PacifiCorp meets the Utah 2025 state target to supply 20 percent
of adjusted retail sales with eligible renewable resources with existing owned and contracted
resources and new renewable resources and transmission in the 2021 IRP Update preferred
portfolio.

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Figure 6.13 – Annual State RPS Compliance Forecast

0
20,000
40,000
60,000
80,000
100,000
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160,000
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s

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Unbundled Bank Surrendered Bundled Bank Surrendered
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Shortfall Requirement
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Washington Clean Energy Transformation Act

Washington’s Clean Energy Transformation Act (CETA) legislation establishes specific targets
for utilities serving customers in Washington including:

• By 2025, utilities remove coal-fueled generation from Washington’s allocation of
electricity;1
• By 2030, Washington retail sales are carbon-neutral;
• By 2045, Washington’s retail sales are 100 percent renewable and non-carbon-emitting.

In the 2021 IRP, resources required to achieve compliance and meet targets in 2030 and 2045 were
identified. These resource additions are not re-evaluated in the 2021 IRP Update, which is not a
Clean Energy Implementation Plan Update (CEIP) and is not a Washington requirement. Instead,
the same CETA resource considerations made in the 2021 IRP are included in the 2021 IRP
Update, with adjustments made only to the extent necessary to align with changes in the updated
portfolio. The two changes layered into the 2021 IRP Update portfolio are 1) the inclusion of
incremental demand-side management resources specific to Washington identified from the P02-
SCGHG portfolio in the 2021 IRP, and 2) in 2029, the creation of a hybrid Washington-situs
assigned 160 MW Yakima resource that includes wind collocated with the solar and storage
resource. This Washington-situs assigned resource maximizes usage of transmission
interconnection availability at this location, and as a result is added in 2029 rather than 2030, to
align with the one-year acceleration of Yakima transmission included as part of the least-cost least-
risk selection of transmission upgrades.

As previously noted, in the 2021 IRP Update preferred portfolio, increased system load drives the
acceleration of 300 MW of new transmission interconnection into the front 10 years, as well as
increased energy efficiency and other portfolio shifts when compared to the 2021 IRP preferred
portfolio. The added renewables and system dispatch in the ST model, partly offset by the loss of
two 2020AS RFP resources, contributes to reducing the cost of the previously identified CETA
portfolio additions relative to the updated base portfolio. Although higher load increases PVRR
across all cases, relative to the base case, CETA portfolio costs are reduced from $164 million to
$122 million on a risk adjusted PVRR(d) basis. Bearing in mind that PVRR(d) is not the measure
of CETA incremental costs, the CETA portfolio in the 2021 RP Update is $42 million less costly
than in the 2021 IRP on a risk-adjusted PVRR(d) basis.

Table 6.7 summarizes the PVRR(d) of the 2021 IRP Update preferred portfolio, including CETA
resource, relative to the Base portfolio under a range of different price-policy scenarios.

1 RCW 19.405.030(1)(a)
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Table 6.7 – PVRR(d) of the 2021 IRP Update Portfolio Relative to the Base Portfolio Under
Varying Price-Policy Scenarios

While a full assessment of incremental costs as calculated in the Washington Clean Energy
Implementation Plan is not contemplated here, this comparison is informative as PacifiCorp’s
CETA Progress Report is developed to be filed January 1, 2023, ahead of the March 31, 2023,
filing of the 2023 IRP.

Figure 6.14 reports updated CETA interim targets assuming the same compliance resources
assumed in both the 2021 IRP and the CEIP, prior to alternative compliance via unbundled REC
purchases. In the 2021 IRP Update, PacifiCorp achieves 100 percent compliance with the 2030
and 2045 CETA standard with lower reliance on alternative compliance through the purchase of
unbundled RECs. While CO2 emissions are higher by roughly 3 percent over the planning period,
Washington has no coal generation in its energy portfolio from 2025 forward, and therefore the
projection to meeting CETA requirements is largely unaffected.

ST PVRR
($million)
ST PVRR plus
5% of 95th
Stochastic
($million)
Energy Not
Served as a
Percentage of
Load (%)
CO2 emissions
(Mtons)
Base MM $26,740 $27,167 0.0056%420
Base LN $23,367 $23,732 0.0059%460
Base HH $29,946 $30,311 0.0056%386
2021 IRP Update CETA MM $26,866 $27,289 0.0056%419
2021 IRP Update CETA LN $23,533 $23,899 0.0059%460
2021 IRP Update CETA HH $30,045 $30,410 0.0056%385
Change from P02-MM-MM $126 $122 0.0000%(1)
Change from P02-MM-LN $167 $167 0.0000%(0)
Change from P02-MM-HH $99 $99 0.0000%(1)
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Figure 6.14 - 2021 IRP Update Interim Targets

Oregon Clean Energy Plan

The 2021 IRP Update preferred portfolio of resources, similar to the 2021 IRP preferred portfolio,
anticipates the high-level environmental objectives of Oregon’s Clean Energy Plan (CEP), which
was passed by the Oregon legislature in 2021 in House Bill 2021, through the procurement of
renewable and non-emitting resources. CEP provisions are not modeled in the 2021 IRP Update;
however, PacifiCorp is actively engaged with the Public Utility Commission of Oregon’s
rulemaking efforts in this regard and is in the process of developing its public engagement and
planning. The CEP will be further considered and discussed in the 2023 IRP development cycle.

Additional information regarding the CEP is included in Chapter 3 – Planning Environment.

Projected Energy Mix

Figure 6.15 how PacifiCorp’s system energy 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 preferred portfolio outcomes in the long-term (LT) model.
Renewable capacity and generation reflect categorization by technology type and not disposition
of renewable energy attributes for regulatory compliance requirements.2 On an energy basis, coal

2The projected PacifiCorp 2021 IRP preferred portfolio “energy mix” is based on energy production and not
resource capability, capacity or delivered energy. All or some of the renewable energy attributes associated with
wind, biomass, geothermal and qualifying hydro facilities in PacifiCorp’s energy mix may be: (a) used in future

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generation drops to 25 percent by 2028, falls to 10 percent by 2032, and declines to only 2 percent
by the end of the planning period. Reduced energy from coal is offset primarily by increased
energy from renewable and storage resources, nuclear resources, DSM resources, and to a smaller
extent later in the plan, non-emitting peaker resources.

Figure 6.15 – Projected Energy Mix with 2021 IRP Update Preferred Portfolio Resources

Additional Studies

In addition to the 2021 IRP Update preferred portfolio, PacifiCorp developed key variants of the
updated preferred portfolio, focusing on three variant studies from the 2021 IRP which address
large transmission projects and significant volumes of associated resources. The economics of
these studies further supports their value in the 2021 IRP Update preferred portfolio as the least-
cost, least-risk portfolio. In addition, PacifiCorp examined one regional haze sensitivity.

The variant portfolios are summarized in the Table 6.8. Each variant portfolio is aligned with a
P02-MM variant portfolio from the 2021 IRP, updated here to assess the impacts of assumption
updates since the filing of the 2021 IRP.

years to comply with renewable portfolio standards or other regulatory requirements; (b) sold to third parties in the
form of renewable energy credits or other environmental commodities; or (c) excluded from energy purchased.
PacifiCorp’s 2021 IRP preferred portfolio energy mix includes owned resources and purchases from third parties.
50%46%43%43%
31%27%26%21%18%17%14%10%10%8%8%8%8%3%3%2%
13%15%18%14%
15%13%14%
14%13%13%13%13%12%13%13%13%12%
11%11%10%
5%7%5%5%
5%
4%4%
4%4%4%4%4%4%4%4%3%3%
3%3%3%
4.0%3.9%3.8%3.6%3.4%3.4%3.3%3.3%3.3%3.2%8.2%8.2%7.6%
1.1%
1.9%1.8%1.6%3.1%2.9%3.2%4.0%4.1%4.6%4.8%4.8%5.0%4.9%4.9%5.7%
24%24%25%28%
40%45%44%45%46%48%50%54%54%53%53%52%53%53%53%52%
2%3%4%4%5%6%6%7%7%7%8%8%9%9%9%10%10%10%
1.9%1.9%1.8%1.8%1.5%1.3%1.4%1.4%1.5%1.4%1.5%1.4%1.4%1.4%1.4%1.4%1.3%1.3%1.3%1.3%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Coal Gas Existing Purchases Hydroelectric
Nuclear Storage Renewable Energy Efficiency
Demand Response Non-Emitting Peaker Front Office Transactions
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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Table 6.8 – Base Case Variant Portfolios1, 2
1 – The Base case in the 2021 IRP Update is equivalent the P02-MM case from the 2021 IRP in that it is the least-cost least-risk
portfolio for the entire system prior to small additions made for Washington CETA compliance.
2- In the 2021 IRP, the No B2H case equivalent was referred to as P02b – No B2H; the No GWS case equivalent was referred to
as P02c – No GWS; the No RFP case equivalent was referred to as P02c – No RFP

Table 6.9 provides a cost and risk summary of the variant portfolios compared to the Base case,
which is the least-cost least-risk portfolio before the addition of CETA-compliant Washington
demand response and the Yakima 160 MW hybrid renewable resource.

Table 6.9 – Cost and Risk Summary of Variant Portfolios

Boardman-to-Hemingway Variant (No B2H)
The B2H transmission line provides more flexibility and increased load-serving capability on the
500-kV transmission system into the central Oregon load pocket. In the case where the Boardman
to Hemingway (B2H) transmission line and associated renewable resources is excluded from
consideration, the portfolio responds by replacing 200 MW of wind in the Willamette Valley area
with 200 MW of standalone storage in 2026. The 2026 removal of wind in favor of storage is
accompanied by a 41 aMW increase in front office transactions. In 2030, 207 MW of Solar plus
Storage is removed relative to the Base portfolio, offset by an additional 87 aMW increase in front
office transactions.

Figure 6.16 shows the cumulative (at left) and incremental (at right) portfolio changes when the
B2H transmission line is eliminated from the Base portfolio. A positive value indicates an increase
Case Description
No B2H Excludes Boardman-to-Hemingway transmission segment
No GWS Excludes the Energy Gateway South transmission segment
No RFP Excludes 2020 All-Source Request for Proposals Final Shortlist and the
Energy Gateway South transmission segment
21 IRP Update Base 26,740 27,167 -420 $2,594 3.9 0.005647%
21 IRP Update No B2H 27,154 27,607 439 423 $2,625 3.9 0.005648%
21 IRP Update No GWS 27,010 27,562 395 451 $3,000 4.3 0.006117%
21 IRP Update No RFP 28,415 29,084 1,916 499 $3,404 35.6 0.051194%
2021 to 2040
Vintage Study Name
ST PVRR
($million)
ST PVRR
plus 5% of
95th
Stochastic
($million)
Risk
Adjusted
PVRR(d)
($million)
CO2
emissions
(Mtons)
CO2
emissions
cost
($million)
Avg Annual
Energy Not
Served plus
Reserve
Deficiency
(GWh)
Energy Not
Served as a
Percentage of
Load (%)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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in resources and a negative value indicates a decrease in resources when the transmission line is
eliminated.

Figure 6.16 – Increase/(Decrease) in Proxy Resources when the B2H Transmission Line is
Eliminated from the Base portfolio

Through 2040, the risk-adjusted PVRR(d) of the portfolio without the B2H transmission line is
$439 million higher cost than the Base portfolio. This substantial outcome is comparable to the
$453 million higher cost PVRR(d) seen in the 2021 IRP. Relative to the Base case, the No B2H
case is also slightly less reliable as measured by the energy not served as a percentage of load and
reports 2.7 million tons of higher CO2 emissions. This analysis assumes that 725 MW of incremental
4-hour battery resources and other transmission upgrades would also be needed in southern Oregon if
the B2H transmission line is not built. Transmission cost savings reflect the fact that these
investments would be avoided if B2H is built.

Figure 6.17 - Increase/(Decrease) in System Costs when the B2H Transmission Line is
Eliminated from the Base Portfolio

Table 6.10 summarizes the PVRR(d) of the No B2H portfolio relative to the Base portfolio under
a range of different price-policy scenarios. Eliminating the B2H transmission line increases the ST
PVRR and the risk-adjusted PVRR for all price-policy scenarios, Removal of B2H also results in
higher emissions. Note, that both portfolios, as measured by ENS results, are very reliable among
all price-policy scenarios. While the cost increase from B2H in the LN price-policy scenario is low
relative to other price-policy scenarios, it is more likely than not that there will be some form of
policy that will impute a cost on greenhouse gas emissions. It is also unlikely that gas prices will
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Coal Gas Contracts
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Geothermal Energy Efficiency Demand Response
Non-Emitting Peaker Converted Gas
($100)
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Coal & Gas Fixed Coal & Gas Variable
Proxy Resource Costs Emissions
Net Market Transactions Transmission
$414
$0
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$100
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$200
$250
$300
$350
$400
$450
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Net Difference In Total System Cost
Net Cost/(Benefit)Cumulative PVRR(d)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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remain low for decades to come. In aggregate, these results support the inclusion of the B2H
transmission line in the 2021 IRP Update preferred portfolio.

Table 6.10 – PVRR(d) of the No B2H Portfolio Relative to the Base Portfolio Under Varying
Price-Policy Scenarios

Energy Gateway South and Sub-Segment D.1 Variant (No GWS)
The No GWS portfolio is a variant of the Base portfolio that eliminates the Energy Gateway South
and D.1 transmission lines. Because wind bids selected to the 2020AS RFP final shortlist that are
located in eastern Wyoming cannot interconnect without these two transmission lines,3 these
resources are also eliminated from the No GWS portfolio. When GWS and D.1 transmission
upgrades are excluded from consideration in the modeling, resource shifts are more significant than
in the Boardman to Hemingway exclusion, as Energy Gateway South supports 1,641 MW of
renewable resources which are no longer eligible to come online in 2025. An additional 289 MW
of Wyoming East wind relying on GWS interconnection will no longer be built in years 2029 and
2030. To meet reliability, the model replaces 100 MW of Willamette Valley wind with 100 MW
of standalone battery in 2026. Additionally, 500 MW of wind and standalone battery is removed
from the Dave Johnson brownfield site to allow for the inclusion of a 500 MW advanced nuclear
project in 2030.

Figure 6.18 shows the cumulative (at left) and incremental (at right) portfolio changes when the
GWS and D.1 transmission line are eliminated from the Base portfolio. A positive value indicates
an increase in resources and a negative value indicates a decrease in resources when the
transmission lines are eliminated.

3 Examination of this variant focuses on the estimated impacts to resource procurement, market purchases, and
system costs, but ignores the elimination of GWS and D.1 transmission lines would interfere with PacifiCorp
transmission’s ability to provide nearly 2,500 MW of requests for transmission and interconnection service governed
by multiple FERC-jurisdictional executed contracts.
 PVRR ($m)
ST PVRR +
5% of 95th
Stochastic ($m)
ENS
Average %
of Load
CO2 Emissions
2021-2040
(Million Tons)
Base MM $26,740 $27,167 0.0056%420
Base LN $23,367 $23,732 0.0059%460
Base HH $29,946 $30,311 0.0056%386
No B2H MM $27,154 $27,607 0.0056%423
No B2H LN $23,514 $23,797 0.0059%462
No B2H HH $30,394 $31,007 0.0056%392
Change from Base MM $414 $439 0.0000%3
Change from Base LN $148 $65 0.0000%2
Change from Base HH $448 $696 0.0000%6
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Figure 6.18 – Increase/(Decrease) in Proxy Resources when the GWS and D.1 Transmission
Lines are Eliminated from the Base portfolio

The removal of GWS and associated RFP wind resources results in a cost increase to the system
of $395 million on a risk-adjusted PVRR(d) basis. This is $135 million more in relative costs than
measured in the 2021 IRP variant P02c. The relative increase in the value of GWS compared to
the 2021 IRP is primarily driven by higher load, increasing the value of the renewables enabled by
GWS transmission. Cost increases without GWS stem from higher thermal generation and
emission costs, and market purchases, which are more expensive than transmission plus low cost
renewables. Market purchases increase by 134 aMW. Without GWS and D.1, emissions from
PacifiCorp’s fossil-fueled resources increase by 7 percent, and energy not served increase by more
than 8 percent. These factors further substantiate the benefits of GWS and D.1, which lower
portfolio emissions and provide system reliability.

Figure 6.19 – Increase/(Decrease) in System Costs when the GWS and D.1 Transmission
Lines are Eliminated from the Base Portfolio

Table 6.11 summarizes the PVRR(d) of the No GWS portfolio relative to the Base portfolio under
a range of different price-policy scenarios. System costs increase when GWS and D.1 are removed
from the portfolio in MM, and HH price-policy scenarios. Conversely, costs decrease in the LN
price-policy scenario. Without GWS and D.1, emissions from PacifiCorp’s fossil-fueled resources
increase considerably—ranging from 6.9% in the MM price-policy scenario to 9.7% in the HH
price-policy scenario. As discussed earlier, it is more likely than not that there will be some form
of policy action taken to impute a cost or penalty on greenhouse gas emissions. It is also unlikely
gas prices will be suppressed for many decades to come, as assumed in the LN price-policy
-4000
-2000
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2000
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Cumulative Changes
Coal Gas Contracts
QF Hydro Nuclear
Hydro Storage Battery SolarSolar+Storage Wind Wind+StorageGeothermalEnergy Efficiency Demand ResponseNon-Emitting Peaker Converted Gas
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Coal Gas ContractsQFHydroNuclearHydro Storage Battery SolarSolar+Storage Wind Wind+StorageGeothermalEnergy Efficiency Demand ResponseNon-Emitting Peaker Converted Gas
($400)
($300)
($200)
($100)
$0
$100
$200
$300
$400
$500
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Coal & Gas Fixed Coal & Gas Variable
Proxy Resource Costs Emissions
Net Market Transactions Transmission
$271
($50)
$0
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$250
$300
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Net Difference In Total System Cost
Net Cost/(Benefit)Cumulative PVRR(d)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

93

scenario. Further, cost-and-risk results indicate that there is a tremendous opportunity cost of not
building these transmission lines should policies develop that impose costs on greenhouse gas
emissions. This is seen with the disproportionate increase in costs under MM and HH price-policy
scenarios relative to the size of cost reductions in the unlikely LN price-policy scenario.
Considering the removal of GWS and D.1 increases system costs in the MM and HH price-policy
scenarios, increases emissions and associated costs and risks, and significantly increases market-
reliance risk, this analysis supports including GWS, D.1, and the associated 2020AS RFP wind
resources in the 2021 IRP Update preferred portfolio.

Table 6.11 – PVRR(d) of the No GWS Portfolio Relative to the Base Portfolio Under
Varying Price-Policy Scenarios

2020AS RFP Variant (No RFP)
The No RFP portfolio is a variant of the Base portfolio that eliminates all 2020AS RFP resources,
including the GWS and D.1 transmission lines. Compared to either the No B2H or No GWS
variants, resource changes are more drastic with the removal of all RFP-related transmission and
resources, where more than 3,400 MW of RFP renewable resources are excluded. As a result, 100
MW of Willamette Valley wind is replaced by 100 MW of standalone battery in 2026. At Dave
Johnson, 500 MW of advanced Nuclear in 2030 replaces 100 MW of wind and 400 MW of
standalone battery. In Utah, 207 MW of Solar plus Storage is replaced with 207 MW of non-
emitting peaker.

Figure 6.20 shows the cumulative (at left) and incremental (at right) portfolio changes when the
2020AS RFP resources are eliminated from the Base portfolio. A positive value indicates an
increase in resources and a negative value indicates a decrease in resources when the 2020AS RFP
resources and the GWS and D.1 transmission lines are eliminated.

ST PVRR
($million)
ST PVRR plus
5% of 95th
Stochastic
($million)
Energy Not
Served as a
Percentage of
Load (%)
CO2 emissions
(Mtons)
Base MM $26,740 $27,167 0.0056%420
Base LN $23,367 $23,732 0.0059%460
Base HH $29,946 $30,311 0.0056%386
No GWS MM $27,010 $27,562 0.0061%451
No GWS LN $22,814 $23,162 0.0063%498
No GWS HH $30,945 $31,687 0.0060%427
Change from Base MM $271 $395 0.0005%31
Change from Base LN ($553)($570)0.0003%38
Change from Base HH $999 $1,375 0.0004%41
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94

Figure 6.20 – Increase/(Decrease) in Proxy Resources when 2020AS RFP Resources are
Eliminated from the Base portfolio

The removal of all RFP renewables increases costs to the system by $1.9 billion on a risk-adjusted
PVRR(d) basis. This is $651 million more in relative costs than measured in the 2021 IRP variant
P02d. The relative increase in the value of the RFP resources including GWS and D.1 is primarily
driven by higher load, which increases the value of the additional renewables. This cost increase
is primarily comprised of higher thermal generation and emission costs and heavy market reliance.
Market purchases increase by 282 aMW. Without RFP bids and the GWS and D.1 projects,
emissions from PacifiCorp’s fossil-fueled resources increase by nearly 19 percent, and energy not
served increases by more than eight-fold.

Figure 6.21 – Increase/(Decrease) in System Costs when RFP Projects and GWS and D.1
Transmission Lines are Eliminated from the Base Portfolio

Table 6.12 summarizes the PVRR(d) of the No RFP portfolio relative to the Base portfolio under
a range of different price-policy scenarios. System costs increase significantly when 2020AS RFP
resources are removed from the portfolio in all three price-policy scenarios. Without the RFP
resources, emissions from PacifiCorp’s fossil-fueled resources increase considerably—ranging
from 15.8% in the MM price-policy scenario to 17.4% in the HH price-policy scenario. As
discussed earlier, it is more likely than not that there will be policy actions taken to impute a cost
or penalty on greenhouse gas emissions. It is also unlikely that gas prices will be suppressed for
many decades to come, as assumed in the LN price-policy scenario. Further, cost-and-risk results
indicate that there is a tremendous opportunity cost of not pursuing the RFP resources along with
the associated investments in the GWS and D.1 transmission lines should policies develop that
-5000
0
5000
In
s
t
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e
d

M
W
Cumulative Changes
Coal Gas Contracts
QF Hydro NuclearHydro Storage Battery Solar
Solar+Storage Wind Wind+Storage
Geothermal Energy Efficiency Demand ResponseNon-Emitting Peaker Converted Gas
-4000
-2000
0
2000
Ca
p
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c
i
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y

B
u
i
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t

M
W
Incremental Portfolio Changes
Coal Gas Contracts
QF Hydro Nuclear
Hydro Storage Battery SolarSolar+Storage Wind Wind+Storage
Geothermal Energy Efficiency Demand Response
Non-Emitting Peaker Converted Gas
($600)($500)($400)($300)($200)($100)$0$100$200$300$400$500$600$700$800$900$1,000
20
2
1
20
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20
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5
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6
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7
20
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8
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20
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20
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4
20
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6
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3
7
20
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8
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4
0
$ m
i
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Annual Change in Cost by Line Item
Coal & Gas Fixed Coal & Gas Variable
Proxy Resource Costs Emissions
Net Market Transactions Transmission
$1,676
($200)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
20
2
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20
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2
20
2
3
20
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4
20
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6
20
3
7
20
3
8
20
3
9
20
4
0
Net Difference In Total System Cost
Net Cost/(Benefit)Cumulative PVRR(d)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

95

impose costs on greenhouse gas emissions. This is seen with the disproportionate increase in costs
under MM and HH price-policy scenarios relative to the size of cost increase in the unlikely LN
price-policy scenario. Further, each of cases that remove 2020AS RFP resources show a more
notable decline in reliability, as measured by the ENS metric. Considering the removal of 2020AS
RFP bids and the associated investment in the GWS and D.1 transmission lines increases system
costs among all price-policy scenarios, significantly increases emissions and associated costs, and
significantly increases market-reliance risk, this analysis supports including 2020AS RFP
resources in the 2021 IRP Update preferred portfolio.

Table 6.12 – PVRR(d) of the No RFP Portfolio Relative to the Base Portfolio Under Varying
Price-Policy Scenarios

Regional Haze Hunter-Huntington Sensitivity

Table 6.13 reports the cost and risk outcome of the regional haze sensitivity. Additional discussion
of Regional Haze under the EPA’s rule finalized in 1999 is presented in Chapter 3 – The Planning
Environment. The study is designed to look at reducing nitrogen oxide starting in 2022 under the
State of Utah’s proposed state implementation plan for the second planning period for the Hunter
and Huntington coal plants. Decreasing nitrogen oxide emission limits are implemented using a
“reasonable progress emission limits” (RPEL) approach that will require changes to how these
coal plants operate but avoids installation of costly emission control equipment.

Table 6.13 – Cost and Risk Summary of Regional Haze Hunter-Huntington Sensitivity

ST PVRR
($million)
ST PVRR plus
5% of 95th
Stochastic
($million)
Energy Not
Served as a
Percentage of
Load (%)
CO2 emissions
(Mtons)
Base MM $26,740 $27,167 0.0056%420
Base LN $23,367 $23,732 0.0059%460
Base HH $29,946 $30,311 0.0056%386
No RFP MM $28,415 $29,084 0.0512%499
No RFP LN $23,530 $23,958 0.0589%535
No RFP HH $33,056 $33,946 0.0542%467
Change from Base MM $1,676 $1,916 0.0455%79
Change from Base LN $164 $226 0.0529%75
Change from Base HH $3,110 $3,634 0.0486%81
21 IRP Update Base 26,740 27,167 -420 $2,594 3.9 0.005647%
21 IRP Update Regional Haze Hunter-Huntington 26,756 27,184 16 418 $2,597 3.9 0.005663%
2021 to 2040
Vintage Study Name
ST PVRR
($million)
ST PVRR
plus 5% of
95th
Stochastic
($million)
Risk
Adjusted
PVRR(d)
($million)
CO2
emissions
(Mtons)
CO2
emissions
cost
($million)
Avg Annual
Energy Not
Served plus
Reserve
Deficiency
(GWh)
Energy Not
Served as a
Percentage of
Load (%)
PACIFICORP – 2021 IRP UPDATE CHAPTER 6 – PORTFOLIO DEVELOPMENT

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PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

97

CHAPTER 7 – ACTION PLAN STATUS UPDATE
This chapter provides an update to the action items listed in the Action Plan of PacifiCorp’s 2021 IRP. The status for all action items is
provided in Table 7.1 below.

Table 7.1 – 2021 IRP Action Plan Status Update
Action
Item 1. Existing Resource Actions Status
1a
Colstrip Units 3 and 4:
• PacifiCorp will continue to work closely with co-
owners to seek the most cost-effective path forward
toward the 2021 IRP preferred portfolio target exit
date of December 31, 2025.
• The Company continues to work with co-owners to
develop the most cost-effective path toward an exit
from the project.
1b
Craig Unit 1:
• PacifiCorp will continue to work closely with co-
owners to seek the most cost-effective path forward
toward the 2021 IRP preferred portfolio target exit date
of December 31, 2025.
• The Company continues to work with co-owners to
develop the most cost-effective path toward an exit
from the project.

1b

Naughton Units 1 and 2:
• PacifiCorp will initiate the process of retiring
Naughton Units 1-2 by the end of December 2025,
including completion of all required regulatory
notices and filings.
• By the end of Q2 2023, PacifiCorp will confirm
transmission system reliability assessment and year-
end 2025 retirement economics in 2023 IRP filing.
• By the end of Q4 2023, PacifiCorp will initiate the
process with the Wyoming Public Service
Commission for approval of a reverse request for
• PacifiCorp is on track to complete required regulatory
notices and filings to process the retirements of
Naughton units 1 and 2.
• PacifiCorp’s Integrate Resource Planning group has
initiated gathering updated assumptions and
stakeholder feedback for the 2023 IRP.
• PacifiCorp is on track to initiate the approval process
of a reverse request for proposals for a potential sale
of Naughton Units 1 and 2.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

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(1b)
proposals for a potential sale of Naughton Units 1 and
2.
• By the end of Q4 2023, PacifiCorp will administer
termination, amendment, or close-out of existing
permits, contracts, and other agreements.
• PacifiCorp is on track to close-out existing
environmental permits and coal agreements for
Naughton Units 1 and 2.
1c
Jim Bridger Units 1 and 2 Gas Conversion:
• PacifiCorp will initiate the process of ending coal-
fueled operations and seeking permitting for a
natural-gas conversion by 2024, including completion
of all required regulatory notices and filings.
• By the end of Q2 2022, PacifiCorp will finalize an
employee transition plan.
• By the end of Q2 2022, PacifiCorp will develop a
community action plan in coordination with
community leaders.
• By the end of Q4 2023, PacifiCorp will administer
termination, amendment, or close-out of existing
permits, contracts, and other agreements.
• By the end of Q4, 2023, PacifiCorp will remove units
1 and 2 from Washington’s allocation of electricity.
• PacifiCorp plans to submit a permit application to the
Wyoming Department of Environmental Quality in
Q2 2022 for the conversion of JB Units 1 &2 to
natural gas by 2024 and is on track to complete
required regulatory notices and filings.
• An Impacted Employee Transition Plan was created
and finalized in 2020 and will be updated as needed.
• In 2020, PacifiCorp assigned a Certified Economic
Developer (CEcD) to work with impacted
communities, state and federal agencies and state
associations to identify economic diversification
funding and resources. In May 2021, the Company
provided an update to the WPSC and will provide
another in April 2022.
• PacifiCorp is on track to remove units 1 and 2 from
Washington’s allocation of electricity.

1d

Carbon Capture, Utilization, and
Sequestration/Wyoming House Bill 200 Compliance:
• PacifiCorp issued a carbon capture, utilization, and
sequestration (CCUS) request for expression of
interest (REOI) on June 29, 2021. PacifiCorp will
complete the 2021 CCUS REOI process and utilize
any new relevant information. Additional model
sensitivities will be run accordingly.
• PacifiCorp issued a carbon capture, utilization, and
sequestration (CCUS) request for expression of
interest (REOI) on June 29, 2021. PacifiCorp
completed the 2021 CCUS REOI process and a third
party evaluated the responses.
• PacifiCorp will issue two CCUS Requests for
Proposals (RFP) in 2022.
• A completed CCUS Front End Engineering &
Design Study (FEED Study) based on a new CCUS
technology was submitted to PacifiCorp in July 2021
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99

(1d)
• PacifiCorp will issue a CCUS Request for Proposals
(RFP) in 2022. The 2021 CCUS REOI responses will
inform the scope of the CCUS RFP.
• A completed CCUS Front End Engineering & Design
Study (FEED Study) based on a new CCUS
technology was submitted to PacifiCorp in July 2021
for Dave Johnston Unit 2. Third-party review of the
FEED Study will be completed by Q1 2022, and
model sensitivities will subsequently be run as
needed, with FEED Study assumptions and inputs as
appropriate.
• Subject to finalization of rules by the Wyoming
Public Service Commission (WPSC) to implement
House Bill 200 (HB 200), the Wyoming Low Carbon
Energy Standard (anticipated by Q4 2021), by March
31, 2022, PacifiCorp will file with the WPSC an
initial CCUS application to establish intermediate
CCUS standards and requirements.
• Subject to finalization of rules by the WPSC to
implement HB 200, the Wyoming Low Carbon Energy
Standard (anticipated by Q4 2021), PacifiCorp will
submit for WPSC approval a final plan with its
proposed energy portfolio standard for dispatchable
and reliable low-carbon electricity, its plan for
achieving the standard, and a target date of no later
than July 1, 2030.
for Dave Johnston Unit 2. Third-party review of the
FEED Study was completed in February 2022.
Model sensitivities will be run in the 2023 IRP with
the FEED Study assumptions and inputs as
appropriate.
• PacifiCorp filed with the Wyoming Public Service
Commission (WPSC), an initial application to
establish intermediate CCUS standards and
requirements on March 31, 2022, as required under
Wyoming House Bill 200.
• PacifiCorp will submit a final plan with its proposed
energy portfolio standard for dispatchable and
reliable low-carbon electricity by March 31, 2023.
The final plan will be submitted for WPSC approval
and will detail the Company’s plan for achieving the
standard, by July 1, 2030.

1e

Regional Haze Compliance:
• Following the resolution of first planning period
regional haze compliance disputes, and the submission
of second planning period regional haze state
implementation plans, PacifiCorp will evaluate and
model any emission control retrofits, emission
• PacifiCorp is working with parties to resolve regional
haze first planning period disputes, and has engaged
with states and commented on proposed second
planning period implementation plans. No second
planning periods requirements have been finalized to
date.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

100

(1e)
limitations, or utilization reductions that are required
for coal units.
• PacifiCorp will continue to engage with the
Environmental Protection Agency, 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.
• PacifiCorp is on track in engaging with the
Environmental Protection Agency, state agencies, and
stakeholders relating to second planning period
regional haze compliance.

Action
Item 2. New Resource Actions Status
2a
Customer Preference Request for Proposals:
• Consistent with Utah Community Renewable Energy
Act, PacifiCorp continues to work with eligible
communities to develop program to achieve goal of
being net 100 percent renewable by 2030; PacifiCorp
anticipates filing an application for approval of the
program with the Utah Public Service Commission in
2022, which may necessitate issuance of a request for
proposals to procure resources within the action plan
window.
• The Company and the eligible communities are
meeting monthly to discuss program design. Subject
to finalization of the program details, PacifiCorp
anticipates filing an application for approval of the
program with the Utah Public Service Commission in
2022.

2b

• Acquisition and Repowering of Foote Creek II-IV and
Rock River I:
• In Q3 2021, PacifiCorp will pursue necessary
regulatory approvals to authorize the acquisition and
repowering of Foote Creek II-IV in order to issue
repowering contracts in Q1 2022 in support of a late
2023 in-service date.
• In Q1 2022, PacifiCorp will pursue necessary
regulatory approvals to authorize the acquisition and
repowering of Rock River I following the expiration of
• PacifiCorp is pursuing necessary regulatory approvals
to authorize the acquisition and repowering of Foote
Creek II-IV in order to commence construction in late
Q2 2022 in support of a late 2023 in-service date.
PacifiCorp filed a certificate of public convenience
and necessity (CPCN) application with the WPSC for
Foote Creek II-IV in October 2021. A decision from
the WPSC is expected sometime in Q2 2022.
• In Q1 2022, PacifiCorp initiated necessary regulatory
approvals to authorize the acquisition and repowering
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101

(2b)
the existing power purchase agreement in order to
issue repowering contracts in Q3 2022 to support a late
2024 in-service date.
of Rock River I in order to issue repowering contracts
in Q3 2022 to support a late 2024 in-service date.
PacifiCorp filed a CPCN application with the WPSC
for Rock River I in March 2022 and requested a
decision in Q3 2022.
2c
NatriumTM Demonstration Project:
• PacifiCorp will continue to monitor
key TerraPower milestones for development and will
make regulatory filings, as applicable.
• By the end of 2022, PacifiCorp will finalize
commercial agreements for the NatriumTM project.

• Q1 2022, PacifiCorp will develop a community action
plan in coordination with community leaders.
• By 2025, PacifiCorp will begin training operators.

• PacifiCorp will continue to monitor key TerraPower
milestones for development and will make regulatory
filings, as applicable, including, but not limited to, a
request for the Oregon Public Utility Commission to
explicitly acknowledge an alternative acquisition
method consistent with OAR 860-089-0100(3)(c), and
a request for a waiver of a solicitation for a significant
energy resource decision consistent with Utah statute
54-17-501.

• The Company continues to monitor TerraPower’s
development of the NatriumTM project. The Company
and TerraPower are discussing potential commercial
agreement structures. The agreement is expected to
contain numerous conditions precedent, including the
Company obtaining required regulatory approvals
and/or waivers, project offramps and performance
related metrics which must be met for the PacifiCorp
to move forward with acquisition of the NatriumTM
project to provide protections to customers.
• PacifiCorp will supplement TerraPower in
stakeholder outreach and coordination with
community leaders in PacifiCorp’s service territory.
• PacifiCorp is evaluating training schedules, positions,
and requirements for the NatriumTM project.
• See response to 2c bullet 1. No regulatory filings are
required at this time.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

102

2d
2022 All-Source Request for Proposals:
• PacifiCorp will issue an all-source Request for
Proposals (RFP) to procure resources that can achieve
commercial operations by the end of December 2026.
• In September 2021, PacifiCorp will notify the Public
Utility Commission of Oregon, the Public Service
Commission of Utah, and the Washington Utilities and
Transportation Commission, of PacifiCorp’s need for
an independent evaluator.
• In October 2021, PacifiCorp will file a draft all-source
RFP with applicable state utility commissions.
• In January 2022, PacifiCorp expects to receive
approval of the all-source RFP from applicable state
utility commissions and issue the RFP to the market.
• In Q2 2022, PacifiCorp will identify an initial shortlist
in advance of annual Cluster Request Window.
• In Q1 2023, PacifiCorp will identify a final shortlist
from the all-source RFP, and file for approval of the
final shortlist in Oregon, file, certificate of public
convenience and necessity (CPCN) applications, as
applicable.
• By Q2 2023 PacifiCorp will execute definitive
agreements with winning bids from the all-source
RFP.
• By Q4 2025-2026, winning bids from the all-source
RFP are expected to achieve commercial operation.
Resources must have commercial operation date of
December 31, 2026, or earlier.
• PacifiCorp will issue an all-source Request for
Proposals (RFP) to procure resources that can achieve
commercial operations by the end of December 2027.
• In Q4 2021, PacifiCorp notified the Public Utility
Commission of Oregon, the Public Service
Commission of Utah, and the Washington Utilities
and Transportation Commission, of PacifiCorp’s need
for an independent evaluator.
• In December 2021 and January 2022, PacifiCorp filed
a draft all-source RFP with applicable state utility
commissions.
• In March 2022, PacifiCorp received approval from the
Washington Utilities and Transportation Commission
and in April, PacifiCorp expects to receive approval
of the all-source RFP from the Public Utility
Commission of Oregon, the Public Service
Commission of Utah and issue the RFP to the market.
• In Q2 2023, PacifiCorp will identify a final shortlist
from the all-source RFP, and in Q3 2023 file for
approval of the final shortlist in Oregon, file,
certificate of public convenience and necessity
(CPCN) applications, as applicable.
• By Q1 2024 PacifiCorp will execute definitive
agreements with winning bids from the all-source
RFP.
• By Q4 2027, winning bids from the all-source RFP are
expected to achieve commercial operation. Resources
must have commercial operation date of December
31, 2027, or earlier.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

103

2e
2020 All-Source Request for Proposals:
• PacifiCorp filed for approval of the final shortlist in
Oregon in June 2021.
• In September 2021, PacifiCorp will file CPCN
applications in Wyoming, as applicable, for final
shortlist.
• In Q4 2021, PacifiCorp will make a filing in Utah for
significant energy resources on final shortlist.
• In September 2021, PacifiCorp filed CPCN
applications for the Gateway South Transmission
project in Wyoming, as applicable, in support of the
2020AS RFP final shortlist.
• In January 2022, Rocky Mountain Power (RMP) filed
an Application for Waiver to the Utah Public Service
Commission (PUC) to waive the requirement that
RMP obtain certain significant energy resource
decisions representing five bids in the 2020AS
RFP. On February 2022, the waiver, subject to
certain conditions, was granted by the Utah PUC (see
Docket No. 22-035-03 for further details).
Action
Item 3. Transmission Action Items Status
3a
Energy Gateway South Segment F (Aeolus-Clover 500
kV transmission line):
• By Q2 2022, obtain Utah and Wyoming Certificates
of Public Convenance and Necessity.
• By the end of Q1 2022, Bureau of Land Management
notice to proceed to construct Energy Gateway South.
• In Q3 2024, construction of Energy Gateway South is
expected to be completed and placed in service.
• Regulatory approval processes for certificates of
public convenience and necessity in Utah and
Wyoming are on track. In Utah an unopposed
stipulation for the CPCN was filed February 22,
2022 and a commission order is pending. In
Wyoming, hearings were completed March 2, 2022
and briefs due April 1, 2022; a decision is expected
in early Q2 2022. Wyoming approval will be
conditioned on obtaining all right-of-way, which is
on track to be completed by the end of Q2 2022.

PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

104

3b
Energy Gateway West, Segment D.1 (Windstar-Shirley
Basin 230 kV transmission line):
• By Q2 2022, obtain conditional Wyoming Certificate
of Public Convenance and Necessity
• By Q3 2022 complete ROW easement acquisition and
option full Wyoming CPCN
• In Q3 2024, construction of Energy Gateway West
segment D.1 to be completed and placed in service.
• The Wyoming approval process for the certificate of
public convenience and necessity is on track;
hearings were completed March 2, 2022 and briefs
due April 1, 2022, with a decision expected in early
Q2 2022. Approval will be conditioned on obtaining
all right-of-way, which is on track to be completed
by Q3 2022.

3c
Boardman-to-Hemingway (500 kV transmission line):
• Continue to support the project under the conditions
of the Boardman-to-Hemingway Transmission
Project (B2H) Joint Permit Funding Agreement.
• Continue to participate in the development and
negotiations of the construction agreement.
• Continue to participate in “pre-construction”
activities in support of the 2026 in-service date.
• Continue negotiations for plan of service post B2H
for parties to the permitting agreement.
• PacifiCorp has continued to participate in the support,
negotiations, planning and permitting of the
Boardman-to-Hemingway 500 kV transmission line,
which remains targeted for a 2026 in-service date.
3d
Initiate Local Reinforcement Projects as identified with
the addition of new resources per the preferred portfolio,
and follow-on requests for proposal successful bids
• Reinforcements have been identified. A final
assessment of upgrades is pending signed agreements.
3e
Continue permitting support for Gateway West segments
D.3 and E.
• PacifiCorp continues permitting efforts on both
segments D.3 and E, maintaining the record of
decision on each segment.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

105

Action
Item 4. Demand-Side Management (DSM) Actions Status

4a

Energy Efficiency Targets:
• PacifiCorp will acquire cost-effective Class 2 DSM
(energy efficiency) resources targeting annual system
energy and capacity selections from the preferred
portfolio as summarized below. PacifiCorp’s state-
specific processes for planning for DSM acquisitions
is provided in Appendix D in Volume II of the 2021
IRP.
• PacifiCorp will pursue cost-effective energy
efficiency resources as summarized in the table
below:

• PacifiCorp will pursue cost-effective Class 1 (demand
response) resources targeting annual system capacity1
selections from the preferred portfolio2 as
summarized in the table below:

1 Capacity impacts for demand response include both summer
and winter impacts within a year.
2A portion of cost-effective demand response resources
identified in the 2021 preferred portfolio are expected to be
• PacifiCorp achieved the Action Plan target of 510
GWh in 2021 and the Company is on track to achieve
its 2022 Class 2 DSM target.

• PacifiCorp is actively working to pursue demand
response resources in multiple states. The Company is
currently expanding its existing programs and
contracting for new demand response resources
identified in the 2021 demand response RFP. In the
event additional demand response resource need is
identified, PacifiCorp may issue a voluntary targeted
RFP outlining the specific remaining incremental
resource needs, including type, location and timing.

PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

106

(4a)
acquired through a previously issued demand response RFP
soliciting resources identified in the 2019 IRP. PacifiCorp will
pursue all cost-effective demand response resources identified as
incremental to resources subsequently procured under the
previously issued RFP in compliance with state level
procurement requirements.
Action
Item 5. Market Purchases Status
5a
Market Purchases:
• Acquire short-term firm market purchases for on-
peak delivery from 2021-2023 consistent with the
Risk Management Policy and Energy Supply
Management Front Office Procedures and Practices.
These short-term firm market 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.
• Since the publication of the 2021 IRP action plan,
PacifiCorp has continued to engage in financially
beneficial transactions to support customers’ interests.
Such transactions include seeking competitive pricing
to acquire short-term firm purchases, execute balance
of month, day-ahead and hour-ahead transactions
through exchanges, and engage in prompt-month,
balance-of-month, day-ahead and hour-ahead non-
brokered bi-lateral transactions.
PACIFICORP – 2021 IRP UPDATE CHAPTER 7 – ACTION PLAN STATUS UPDATE

107

Action
Item 6. Renewable Energy Credit (REC) Actions Status
6a
Renewable Portfolio Standards (RPS):
• PacifiCorp will pursue unbundled REC RFPs and
purchases to meet its state RPS compliance
requirements.
• As needed, issue RFPs seeking then current-year or
forward-year vintage unbundled RECs that will
qualify in meeting California RPS targets through
2024.
• Since October 1, 2021, PacifiCorp has purchased
unbundled RECs to meet its California RPS targets
through 2024. PacifiCorp will continue to evaluate the
need for unbundled RECs and issue RFPs to meet its
state RPS compliance requirements as needed.

6b
Renewable Energy Credit Sales:
• Maximize the sale of RECs that are not required to
meet state RPS compliance obligations.
• On October 27, 2021, PacifiCorp issued a reverse
RFPs to sell RECs and completed several bilateral
transactions. PacifiCorp will continue to issue reverse
RFPs to maximize the sale of RECs that are not
required to meet state RPS compliance obligations
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PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

109

APPENDIX A – ADDITIONAL LOAD FORECAST
DETAILS
The load forecast presented in Chapter 4 represents the data used for capacity expansion modeling
and excludes load reductions from incremental energy efficiency resources (Class 2 DSM). The
load forecast used in the 2021 IRP Update was produced in May 2021. The average annual energy
growth rate for the 10-year period (2022 through 2031) is 1.46 percent. Relative to the load forecast
prepared for the 2021 IRP, PacifiCorp’s 2031 forecasted energy requirement decreased in all
jurisdictions other than Oregon and Utah, while PacifiCorp system energy requirement increased
approximately 2.3 percent. Table A.1 and Table A.2 illustrate the annual load and coincident peak
load forecast when not reducing load projections to account for new energy efficiency measures
(Class 2 DSM).1

Table A.1 – Forecasted Annual Load Growth, 2022 through 2031 (Megawatt-hours), at
Generation, pre-DSM

1 Class 2 DSM load reductions are included as resources in the System Optimizer model.
Year Total OR WA CA UT WY ID
2022 61,564,330 15,225,790 4,605,340 870,230 27,635,390 9,281,340 3,946,240
2023 63,153,010 15,542,160 4,643,520 871,480 28,603,020 9,538,990 3,953,840
2024 64,661,770 16,080,310 4,681,580 874,560 29,438,980 9,627,450 3,958,890
2025 65,743,100 16,349,100 4,691,870 873,570 29,989,480 9,867,530 3,971,550
2026 65,308,270 16,677,410 4,720,470 876,030 29,123,740 9,920,230 3,990,390
2027 66,210,480 17,013,040 4,755,770 879,110 29,600,710 9,953,650 4,008,200
2028 67,345,980 17,408,920 4,810,220 884,040 30,182,810 10,027,440 4,032,550
2029 68,250,270 17,742,390 4,843,960 884,190 30,679,530 10,052,470 4,047,730
2030 69,298,260 18,122,940 4,890,370 886,080 31,248,620 10,091,160 4,059,090
2031 70,122,890 18,357,130 4,938,900 887,880 31,741,320 10,128,710 4,068,950
2022-31 1.46%2.10%0.78%0.22%1.55%0.98%0.34%
Compound Annual Growth Rate
PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS
110

Table A.2 - Forecasted Annual Coincident Peak Load (Megawatts) at Generation, pre-
DSM

Table A.3 and Table A.4 show the forecast changes relative to the 2021 IRP load forecast for loads
and coincident system peak, respectively.

Table A.3 – Annual Load Growth Change: 2021 IRP Update Forecast less 2021 IRP
Forecast (Megawatt-hours) at Generation, pre-DSM

Year Total OR WA CA UT WY ID
2022 10,561 2,429 775 140 5,201 1,231 786
2023 10,717 2,442 779 142 5,320 1,250 785
2024 10,864 2,468 782 140 5,423 1,265 786
2025 11,035 2,494 787 141 5,524 1,293 796
2026 11,027 2,516 790 141 5,481 1,298 801
2027 11,126 2,538 795 142 5,545 1,302 805
2028 11,255 2,560 799 143 5,636 1,309 808
2029 11,370 2,582 805 142 5,717 1,312 812
2030 11,487 2,603 810 142 5,800 1,317 815
2031 11,590 2,613 818 142 5,875 1,321 821
2022-31 1.04%0.81%0.60%0.10%1.36%0.79%0.49%
Compound Annual Growth Rate
Year Total OR WA CA UT WY ID
2022 (196,580) (180,480) 14,320 (9,030) 191,300 (186,600) (26,090)
2023 (89,980) (216,520) (12,510) (11,020) 392,640 (217,480) (25,090)
2024 210,460 (25,810) (29,060) (13,610) 646,800 (335,810) (32,050)
2025 580,840 109,590 (38,370) (15,320) 648,450 (89,470) (34,040)
2026 781,240 258,590 (40,420) (15,100) 770,820 (159,280) (33,370)
2027 1,032,080 403,790 (40,420) (13,300) 899,780 (186,400) (31,370)
2028 1,262,560 552,280 (40,180) (12,240) 989,950 (200,380) (26,870)
2029 1,481,610 705,290 (35,940) (11,180) 1,069,680 (225,750) (20,490)
2030 1,575,050 854,900 (32,730) (12,530) 1,092,870 (302,510) (24,950)
2031 1,594,240 877,130 (19,280) (11,680) 1,107,530 (336,960) (22,500)
PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

111

Table A.4 – Annual Coincident Peak Growth Change: 2021 IRP Update Forecast less 2017
IRP Forecast (Megawatts) at Generation, pre-DSM

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 2021 IRP Update preferred portfolio. The average annual retail sales growth rate
for the 10-year period (2022 through 2031) is 0.58 percent.

Table A.5 – System Annual Retail Sales Forecast 2022 through 2031 (Megawatt-hours),
post-DSM

Year Total OR WA CA UT WY ID
2022 26 (13) (4) (0) 42 (17) 18
2023 26 (20) (10) (0) 65 (29) 20
2024 56 (13) (14) (1) 97 (35) 21
2025 93 (6) (17) (1) 105 (9) 21
2026 160 3 (20) (1) 173 (16) 22
2027 186 11 (22) (1) 194 (19) 23
2028 212 20 (24) (0) 211 (20) 25
2029 237 30 (26) (0) 227 (23) 28
2030 248 41 (27) (0) 237 (31) 29
2031 252 42 (28) (0) 244 (35) 29
Year Residential Commercial Industrial Irrigation Lighting Total
2022 16,883,025 19,430,835 18,304,202 1,483,507 107,925 56,209,495
2023 16,880,836 20,126,970 18,576,997 1,482,501 102,792 57,170,096
2024 17,023,491 20,766,719 18,657,118 1,482,555 99,255 58,029,138
2025 17,101,849 21,036,255 18,773,837 1,482,228 96,195 58,490,363
2026 17,296,271 21,299,464 17,330,721 1,481,509 94,166 57,502,131
2027 17,526,492 21,499,322 17,278,284 1,479,999 92,587 57,876,684
2028 17,861,288 21,747,665 17,257,346 1,478,048 91,497 58,435,844
2029 18,081,010 21,871,791 17,160,525 1,475,700 89,955 58,678,981
2030 18,305,130 22,031,321 17,120,319 1,473,386 88,706 59,018,862
2031 18,546,830 22,014,167 17,088,099 1,470,631 87,515 59,207,242
2022-31 1.05%1.40%-0.76%-0.10%-2.30%0.58%
System Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS
112

Table A.6– Forecasted Retail Sales Growth in Oregon, post-DSM

Table A.7 – Forecasted Retail Sales Growth in Washington, post-DSM

Year Residential Commercial Industrial Irrigation Lighting Total
2022 5,787,079 5,887,735 1,480,507 333,775 36,859 13,525,955
2023 5,762,694 6,066,118 1,437,047 333,504 35,996 13,635,359
2024 5,785,881 6,372,669 1,408,680 333,517 35,350 13,936,096
2025 5,796,057 6,501,134 1,401,833 333,409 34,630 14,067,063
2026 5,838,292 6,640,891 1,397,397 333,326 34,138 14,244,045
2027 5,887,806 6,778,086 1,393,803 333,013 33,759 14,426,467
2028 5,972,311 6,925,882 1,392,590 332,569 33,571 14,656,922
2029 6,036,711 7,051,309 1,389,902 332,002 33,263 14,843,186
2030 6,121,032 7,189,924 1,388,345 331,520 33,109 15,063,930
2031 6,203,383 7,201,637 1,389,462 331,062 32,998 15,158,541
2022-31 0.77%2.26%-0.70%-0.09%-1.22%1.27%
Oregon Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
Year Residential Commercial Industrial Irrigation Lighting Total
2022 1,529,078 1,563,728 854,633 160,251 3,514 4,111,204
2023 1,510,337 1,581,369 842,930 159,721 3,283 4,097,639
2024 1,504,658 1,586,702 831,049 159,603 3,220 4,085,232
2025 1,491,410 1,582,136 817,469 159,602 3,188 4,053,805
2026 1,484,929 1,577,641 809,322 159,577 3,181 4,034,651
2027 1,480,508 1,571,996 803,278 159,531 3,179 4,018,493
2028 1,483,834 1,569,934 799,933 159,466 3,189 4,016,356
2029 1,479,846 1,560,954 793,073 159,322 3,179 3,996,373
2030 1,479,029 1,559,549 789,220 159,096 3,179 3,990,074
2031 1,480,155 1,559,370 787,489 158,885 3,179 3,989,077
2022-31 -0.36%-0.03%-0.91%-0.10%-1.11%-0.33%
Washington Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS

113

Table A.8 – Forecasted Retail Sales Growth in California, post-DSM

Table A.9 – Forecasted Retail Sales Growth in Utah, post-DSM

Year Residential Commercial Industrial Irrigation Lighting Total
2022 382,297 235,420 53,687 91,103 1,421 763,928
2023 381,755 235,971 52,872 90,973 1,323 762,893
2024 383,221 236,685 51,010 90,920 1,246 763,081
2025 382,098 235,693 49,105 90,846 1,178 758,920
2026 382,238 235,144 47,575 90,647 1,128 756,731
2027 382,478 234,065 46,454 90,367 1,091 754,454
2028 384,043 233,155 45,038 90,051 1,066 753,353
2029 383,329 230,679 43,237 89,700 1,043 747,988
2030 383,712 228,952 41,414 89,361 1,029 744,469
2031 384,512 227,073 39,790 88,986 1,018 741,380
2022-31 0.06%-0.40%-3.27%-0.26%-3.63%-0.33%
California Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
Year Residential Commercial Industrial Irrigation Lighting Total
2022 7,486,721 9,885,130 7,826,692 232,649 51,617 25,482,810
2023 7,563,353 10,386,939 7,921,202 232,571 47,781 26,151,846
2024 7,698,651 10,706,741 8,005,055 232,586 45,136 26,688,169
2025 7,807,461 10,869,905 7,962,311 232,495 43,154 26,915,326
2026 7,977,241 11,013,101 6,544,182 232,429 41,986 25,808,940
2027 8,170,602 11,104,346 6,536,315 232,339 41,275 26,084,877
2028 8,414,703 11,226,321 6,529,252 232,207 40,969 26,443,452
2029 8,584,013 11,261,726 6,485,280 231,928 40,603 26,603,549
2030 8,749,010 11,302,572 6,480,594 231,603 40,457 26,804,237
2031 8,933,960 11,288,665 6,468,866 231,292 40,373 26,963,156
2022-31 1.98%1.49%-2.09%-0.06%-2.69%0.63%
Utah Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
PACIFICORP – 2021 IRP UPDATE APPENDIX A – ADDITIONAL LOAD FORECAST DETAILS
114

Table A.10 – Forecasted Retail Sales Growth in Idaho, post-DSM

Table A.11 – Forecasted Retail Sales Growth in Wyoming, post-DSM

Year Residential Commercial Industrial Irrigation Lighting Total
2022 731,411 536,502 1,740,182 638,729 2,607 3,649,432
2023 720,703 536,531 1,746,769 638,753 2,574 3,645,330
2024 723,863 540,050 1,732,842 638,946 2,547 3,638,247
2025 720,853 540,125 1,732,104 638,909 2,504 3,634,496
2026 723,428 539,778 1,730,168 638,580 2,469 3,634,423
2027 726,455 537,494 1,726,496 637,829 2,434 3,630,709
2028 733,689 536,026 1,722,956 636,869 2,407 3,631,947
2029 736,108 531,204 1,717,517 635,903 2,367 3,623,099
2030 731,214 528,740 1,713,034 634,996 2,335 3,610,320
2031 724,653 527,341 1,709,501 633,630 2,304 3,597,428
2022-31 -0.10%-0.19%-0.20%-0.09%-1.36%-0.16%
Idaho Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate
Year Residential Commercial Industrial Irrigation Lighting Total
2022 966,439 1,322,319 6,348,502 26,999 11,907 8,676,165
2023 941,994 1,320,042 6,576,179 26,979 11,836 8,877,030
2024 927,218 1,323,873 6,628,483 26,983 11,757 8,918,313
2025 903,969 1,307,262 6,811,014 26,967 11,542 9,060,753
2026 890,143 1,292,909 6,802,077 26,950 11,263 9,023,341
2027 878,643 1,273,335 6,771,939 26,920 10,848 8,961,685
2028 872,709 1,256,347 6,767,577 26,885 10,295 8,933,814
2029 861,004 1,235,919 6,731,517 26,845 9,501 8,864,786
2030 841,131 1,221,583 6,707,712 26,809 8,598 8,805,833
2031 820,168 1,210,082 6,692,991 26,776 7,643 8,757,660
2022-31 -1.81%-0.98%0.59%-0.09%-4.81%0.10%
Wyoming Retail Sales – Megawatt-hours (MWh)
Compound Annual Growth Rate