20211230IRP Appendix C.pdf

INTEGRATED RESOURCE PLAN
A VIEW FROM ABOVE
2021IRP
DECEMBER • 2021
APPENDIX C: TECHNICAL REPORT
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s filings with the
Securities and Exchange Commission.
Table of Contents
2021 Integrated Resource Plan—Appendix C Page i
TABLE OF CONTENTS
Table of Contents ........................................................................................................................... i
Introduction .................................................................................................................................. 1
IRP Advisory Council ...................................................................................................................... 2
Customer Representatives ...................................................................................................... 2
Public-Interest Representatives .............................................................................................. 2
Regulatory Commission Representatives ................................................................................ 3
IRPAC Meeting Schedule and Agenda ..................................................................................... 3
Sales and Load Forecast Data ........................................................................................................ 5
50th Percentile Annual Forecast Growth Rates ........................................................................ 5
Expected-Case Load Forecast .................................................................................................. 6
Annual Summary ................................................................................................................... 16
Load and Resource Balance Data ................................................................................................ 18
Demand-Side Resource Data ....................................................................................................... 38
DSM Financial Assumptions .................................................................................................. 38
Avoided Cost Averages ($/MWh except where noted) ......................................................... 38
DSM alternate cost summer pricing periods (June 1–August 31) .................................... 39
DSM alternate cost non-summer pricing periods (September 1–May 31) ...................... 40
Bundle Amounts .................................................................................................................... 41
Bundle Costs.......................................................................................................................... 41
Supply-Side Resource Data ......................................................................................................... 42
Key Financial and Forecast Assumptions ............................................................................... 42
Cost Inputs and Operating Assumptions (Costs in 2021$) ..................................................... 43
Supply-Side Resource Escalation Factors1 (2022–2030) ........................................................ 44
Supply-Side Resource Escalation Factors1 (2031–2040) ........................................................ 45
Levelized Cost of Energy (costs in 2021$, $/MWh) at stated capacity factors ....................... 46
Levelized Capacity (fixed) Cost per kW/Month (costs in 2021$) ........................................... 47
Renewable Energy Certificate Forecast ................................................................................. 48
Existing Resource Data ................................................................................................................ 49
Qualifying Facility Data (PURPA) ........................................................................................... 49
Table of Contents
Page ii 2021 Integrated Resource Plan—Appendix C
Cogeneration & Small Power Production Projects Status as of December 31,
2020 ................................................................................................................................ 49
Power Purchase Agreement Data ......................................................................................... 51
Hydro Flow Modeling ............................................................................................................ 52
Hydro Models .................................................................................................................. 52
Hydro Model Inputs ........................................................................................................ 52
Hydro Model Results ....................................................................................................... 53
2021 Hydro Model Parameters (acre-feet/year) ............................................................. 55
Hydro Modeling Results (aMW) ............................................................................................ 56
Long-Term Capacity Expansion Results (MW) ............................................................................. 66
Preferred Portfolio—Base with B2H ...................................................................................... 66
Base with B2H—High Gas High Carbon Test (MW) ............................................................... 67
Base with B2H—PAC Bridger Alignment (MW) ..................................................................... 68
Base without B2H (MW) ........................................................................................................ 69
Base without B2H, without Gateway West (MW) ................................................................. 70
Base without B2H—PAC Bridger Alignment (MW) ................................................................ 71
Rapid Electrification (MW) .................................................................................................... 72
Climate Change (MW) ........................................................................................................... 73
100% Clean by 2035 (MW) .................................................................................................... 74
100% Clean by 2045 (MW) .................................................................................................... 75
SWIP North (MW) ................................................................................................................. 76
CSPP Wind Renewal Low (MW) ............................................................................................. 77
CSPP Wind Renewal High (MW) ............................................................................................ 78
Validation Test: Natural Gas in 2028 Rather Than Solar and Storage (MW) .......................... 79
Validation Test: Bridger Exit Units 1 and 2 at the End of 2023 (MW) .................................... 80
Validation Test: Bridger Exit Unit 2 at the End of 2026 (MW) ............................................... 81
Validation Test: Bridger Exit Units 3 and 4 in 2028 and 2030 (MW) ...................................... 82
Validation Test: Valmy Unit 2 Exit in 2023 (MW) .................................................................. 83
Validation Test: Valmy Unit 2 Exit in 2024 (MW) .................................................................. 84
Validation Test: Biomass (MW) ............................................................................................. 85
Validation Test: Geothermal (MW) ....................................................................................... 86
Table of Contents
2021 Integrated Resource Plan—Appendix C Page iii
Validation Test: Demand Response (MW) ............................................................................. 87
Validation Test: Energy Efficiency (MW) ............................................................................... 88
Portfolio Emissions Forecast ....................................................................................................... 89
CO2 Tons ................................................................................................................................ 89
NOx Tons ............................................................................................................................... 89
SO2 Tons ................................................................................................................................ 90
Preferred Portfolio (Base with B2H) Emissions ..................................................................... 91
Stochastic Risk Analysis ............................................................................................................... 92
Natural Gas Sampling (Nominal $/MMBTU) .......................................................................... 92
Customer Load Sampling (Annual MWh) .............................................................................. 93
Portfolio Stochastic Analysis, Total Portfolio Cost ................................................................. 95
NPV Years 2021–2040 ($ x 1,000) .................................................................................... 95
Loss of Load Expectation ............................................................................................................. 96
Methodology Components ................................................................................................... 96
Modeling Idaho Power’s System ........................................................................................... 97
ELCC Results .......................................................................................................................... 98
LOLE of Portfolios .................................................................................................................. 99
Portfolio Reliability Results............................................................................................ 100
Compliance with State of Oregon IRP Guidelines ...................................................................... 101
Guideline 1: Substantive Requirements .............................................................................. 101
Guideline 2: Procedural Requirements ............................................................................... 103
Guideline 3: Plan Filing, Review, and Updates .................................................................... 104
Guideline 4: Plan Components ............................................................................................ 105
Guideline 5: Transmission ................................................................................................... 108
Guideline 6: Conservation ................................................................................................... 108
Guideline 7: Demand Response .......................................................................................... 109
Guideline 8: Environmental Costs ....................................................................................... 109
Guideline 9: Direct Access Loads ......................................................................................... 111
Guideline 10: Multi-state Utilities ....................................................................................... 111
Guideline 11: Reliability ...................................................................................................... 111
Guideline 12: Distributed Generation ................................................................................. 112
Table of Contents
Page iv 2021 Integrated Resource Plan—Appendix C
Guideline 13: Resource Acquisition ..................................................................................... 112
Compliance with EV Guidelines ................................................................................................. 113
Guideline 1: Forecast the Demand for Flexible Capacity ..................................................... 113
Guideline 2: Forecast the Supply for Flexible Capacity ........................................................ 113
Guideline 3: Evaluate Flexible Resources on a Consistent and Comparable Basis ............... 113
State of Oregon Action Items Regarding Idaho Power’s 2019 IRP ............................................ 114
Action Item 1: Jim Bridger Units 1 and 2 ............................................................................. 114
Action Item 2: Solar Hosting Capacity ................................................................................. 114
Action Item 3: B2H .............................................................................................................. 114
Action Item 4: B2H .............................................................................................................. 115
Action Item 5: VER variability and system reliability ........................................................... 115
Action Item 6: Boardman .................................................................................................... 115
Action Item 7: Jim Bridger Units 1 and 2 ............................................................................. 115
Action Item 8: VER Integration ............................................................................................ 116
Action Item 9: North Valmy Unit 2 ...................................................................................... 116
Action Item 10: Jim Bridger Units 1 and 2 ........................................................................... 116
Action Item 11: Jim Bridger Units 1 or 2 .............................................................................. 116
Action Item 12: Jackpot Solar .............................................................................................. 117
Action Item 13: North Valmy Unit 2 .................................................................................... 117
Action Item 14: Jim Bridger Units 1 or 2 .............................................................................. 117

Introduction
2021 Integrated Resource Plan—Appendix C Page 1
INTRODUCTION

Appendix C–Technical Appendix contains supporting data and explanatory materials used to
develop Idaho Power’s 2021 Integrated Resource Plan (IRP).
The main document, the 2021 IRP Report, contains a full narrative of Idaho Power’s resource
planning process. Additional information regarding the 2021 IRP sales and load forecast is
contained in Appendix A–Sales and Load Forecast, details on Idaho Power’s demand-side
management efforts are explained in Appendix B–Demand-Side Management 2020 Annual
Report, and supplemental information on Boardman to Hemingway (B2H) transmission is
provided in Appendix D–B2H Supplement, anticipated to be filed in first quarter 2022.
For information or questions concerning the resource plan or the resource planning process,
contact Idaho Power:
Jared Hansen, Resource Planning
Idaho Power
1221 West Idaho Street
Boise, Idaho 83702
208-388-2706
[e-mail]

IRP Advisory Council
Page 2 2021 Integrated Resource Plan—Appendix C
IRP ADVISORY COUNCIL
Idaho Power has involved representatives of the public in the IRP planning process since the
early 1990s. This public forum is known as the IRP Advisory Council (IRPAC). The IRPAC
generally meets monthly during the development of the IRP, and the meetings are open to the
public. Members of the council include regulatory, political, environmental, and customer
representatives, as well as representatives of other public-interest groups.
Idaho Power hosted nine IRPAC meetings for the 2021 IRP, with an additional three workshops
that focused on various topics, such as a review of the AURORA modeling software. Idaho
Power values these opportunities to convene, and the IRPAC members and the public have
made significant contributions to this plan.
Idaho Power the IRP is better because of public involvement and is grateful to the individuals
and groups that participated in the process.
Customer Representatives
Adler Industrial Mike Adler
Agricultural Representative Sid Erwin
Boise State University Barry Burbank
Idaho National Laboratory Kurt Myers
Micron Jim Swier
Rule Steel Greg Burkhardt
St. Luke’s Medical Stephanie Wicks
Public-Interest Representatives
Boise State University Energy Policy Institute Kathleen Araujo
City of Boise Steve Burgos
City of Nampa Mayor Debbie Kling
Idaho Conservation League Ben Otto
Idaho Legislature Rep. Laurie Lickley
Idaho Office of Energy and Mineral Resources John Chatburn
Idaho Sierra Club Mike Heckler
Idaho Water Resource Board Roger Chase
Northwest Power and Conservation Council Ben Kujala
Oil and Gas Industry Advisor David Hawk
Oregon State University, Malheur Experiment Station Professor Emeritus Clint Shock
IRP Advisory Council
2021 Integrated Resource Plan—Appendix C Page 3
Snake River Alliance Chad Worth
Sun Valley Institute for Resilience Herbert Romero
Regulatory Commission Representatives
Idaho Public Utilities Commission Mike Louis
Public Utility Commission of Oregon Nadine Hanhan
IRPAC Meeting Schedule and Agenda
Meeting Dates Agenda Items
2021 Tuesday, January 12 Energy Efficiency Subcommittee Meeting
Historical Modeling of Energy Efficiency in the IRP
Energy Efficiency Potential Study—Introduction & Overview
Energy Efficiency & Load Forecast Discussion
2021 Tuesday, February 9 Introduction from President & CEO Lisa Grow
Idaho Power Clean Energy Goal
2019 IRP in Review
2021 IRP Schedule, Process Overview, & Process Road Map
2021 IRP Carbon Outlook
Valmy Unit 2 Study Outline
2021 Tuesday, February 23 Load Forecasting Workshop
2021 Thursday, March 11 Industry Topics
CSPP Forecast & Assumptions
Natural Gas Price Forecast
Load Forecast
2021 Thursday, April 8 Operations Hydrology: RMJOC-II Part 2 Climate Change Update
Operations Hydrology: Streamflow & Hydrogeneration Development
Coal Unit Overview & Inputs
Energy Efficiency Potential Study & Bundling Analysis
Effective Load Carrying Capability: Solar, Wind & Storage
Demand Response
Valmy Unit 2 Study Update
2021 Thursday, April 22 AURORA Workshop
2021 Thursday, May 13 Northwest Resource Adequacy
Resource Adequacy at Idaho Power
Regional Transmission Overview
Transmission Projects Update
Future Supply-Side Resource Options
2021 Thursday, June 10 Industry Topics
Transmission & Distribution Planning Topics
Resource Sufficiency (IPC Flexibility & Reserve Requirements)
2020 Variable Energy Resource Integration Study
Modeling Regulation Reserve Requirements
IRP Modeling Scenarios
Natural Gas Price Forecast Follow-Up
IRP Advisory Council
Page 4 2021 Integrated Resource Plan—Appendix C
Meeting Dates Agenda Items
2021 Tuesday, July 13 Power System Recent Events: 2021 Pacific Northwest Heatwave
Meeting a New Peak Demand
IRP Scenarios & Sensitivities Follow-Up
Electrification Scenario Analysis
Loss of Load Analysis & ELCC Update
2021 Tuesday, August 10 Analysis Workshop
IRP Portfolio & Sensitivity Development Methodology
Carbon Adder Forecasts
Transmission Benefits
Stochastic Risk Analysis
Ideation Sessions Report-Out
Demand Response Update
2021 Thursday, October 21 Analysis Check-in
Preliminary Results
Bridger Natural Gas Conversion
2021 Thursday, November 18 Aurora Results Update
Preliminary Preferred Portfolio
Validation & Verification
LOLE Analysis
Quantitative Risk Assessment
IRP Action Plan

Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 5
SALES AND LOAD FORECAST DATA
50th Percentile Annual Forecast Growth Rates
2021–2026 2021–2031 2021–2040
Sales
Residential Sales 0.92% 0.69% 0.77%
Commercial Sales 1.18% 0.91% 0.92%
Irrigation Sales 0.43% 0.45% 0.58%
Industrial Sales 2.82% 1.86% 1.59%
Additional Firm Sales 18.07% 12.37% 6.34%
System Sales 2.68% 2.08% 1.47%
Total Sales 2.68% 2.08% 1.47%
Loads
Residential Load 0.90% 0.68% 0.76%
Commercial Load 1.16% 0.91% 0.91%
Irrigation Load 0.43% 0.45% 0.56%
Industrial Load 2.79% 1.85% 1.57%
Additional Firm Sales 18.07% 12.37% 6.34%
System Load Losses 1.75% 1.36% 1.11%
System Load 2.59% 2.02% 1.43%
Total Load 2.59% 2.02% 1.43%
Peaks
System Peak 2.07% 1.69% 1.36%
Total Peak 2.07% 1.69% 1.36%
Winter Peak 2.34% 1.61% 1.23%
Summer Peak 2.07% 1.69% 1.36%
Customers
Residential Customers 2.56% 2.26% 1.90%
Commercial Customers 2.18% 2.05% 1.84%
Irrigation Customers 1.13% 1.11% 1.07%
Industrial Customers 0.39% 0.51% 0.54%
Sales and Load Forecast Data
Page 6 2021 Integrated Resource Plan—Appendix C
Expected-Case Load Forecast
2021 Monthly Summary1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 830 727 605 521 468 579 724 670 523 530 680 875
Commercial 493 474 442 428 428 464 529 526 478 458 470 502
Irrigation 4 4 11 150 335 557 658 574 315 61 7 4
Industrial 283 290 286 280 284 305 303 309 300 304 302 297
Additional Firm 107 111 110 106 98 101 101 110 112 109 111 115
Loss 146 135 120 124 137 173 203 190 146 121 131 152
System Load 1,863 1,741 1,574 1,609 1,750 2,180 2,518 2,380 1,874 1,583 1,702 1,946
Light Load 1,736 1,613 1,455 1,466 1,586 1,952 2,267 2,103 1,701 1,435 1,575 1,812
Heavy Load 1,972 1,837 1,659 1,713 1,891 2,346 2,716 2,598 2,012 1,699 1,804 2,052
Total Load 1,863 1,741 1,574 1,609 1,750 2,180 2,518 2,380 1,874 1,583 1,702 1,946
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,462 2,130 1,930 2,012 2,557 3,624 3,745 3,499 3,027 2,244 2,351 2,584
Total Peak Load 2,462 2,130 1,930 2,012 2,557 3,624 3,745 3,499 3,027 2,244 2,351 2,584

2022 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 848 746 620 532 475 585 725 673 525 532 685 884
Commercial 510 496 452 430 446 470 527 524 479 462 477 508
Irrigation 3 3 9 116 307 587 677 580 319 62 7 4
Industrial 298 294 295 287 292 305 306 310 302 304 303 308
Additional Firm 115 117 113 107 112 107 117 118 121 118 123 127
Loss 151 139 123 122 137 177 205 191 147 122 133 155
System Load 1,926 1,794 1,611 1,595 1,770 2,231 2,557 2,396 1,893 1,600 1,727 1,987
Light Load 1,794 1,662 1,490 1,453 1,604 1,998 2,303 2,118 1,719 1,450 1,598 1,850
Heavy Load 2,038 1,893 1,698 1,698 1,912 2,401 2,777 2,598 2,033 1,717 1,831 2,095
Total Load 1,926 1,794 1,611 1,595 1,770 2,231 2,557 2,396 1,893 1,600 1,727 1,987
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,529 2,296 2,086 2,121 2,680 3,654 3,801 3,523 3,054 2,261 2,377 2,609
Total Peak Load 2,529 2,296 2,086 2,121 2,680 3,654 3,801 3,523 3,054 2,261 2,377 2,609
1.The sales and load forecast considers and reflects the impact of existing energy efficiency programs on average load and peak demand. The new energy efficiency programs, proposed as part of the
2019 IRP, are accounted for in the load and resource balance. The peak load forecast does not include the impact of existing or new demand response programs, which are both accounted for in
Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 7

2023 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 859 755 625 537 480 592 735 682 530 536 690 893
Commercial 516 501 457 435 450 475 533 531 484 466 481 515
Irrigation 3 3 9 117 310 592 683 586 322 62 7 4
Industrial 309 305 307 299 305 319 320 322 314 316 315 319
Additional Firm 133 137 131 126 122 113 123 123 120 122 128 134
Loss 154 142 126 125 140 180 209 194 149 123 134 157
System Load 1,976 1,845 1,656 1,639 1,807 2,271 2,603 2,437 1,919 1,626 1,755 2,023
Light Load 1,841 1,709 1,531 1,493 1,638 2,034 2,344 2,154 1,742 1,474 1,624 1,884
Heavy Load 2,092 1,946 1,745 1,755 1,940 2,444 2,826 2,642 2,060 1,746 1,860 2,143
Total Load 1,976 1,845 1,656 1,639 1,807 2,271 2,603 2,437 1,919 1,626 1,755 2,023
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,570 2,338 2,119 2,160 2,730 3,804 3,866 3,625 3,104 2,292 2,403 2,679
Total Peak Load 2,570 2,338 2,119 2,160 2,730 3,804 3,866 3,625 3,104 2,292 2,403 2,679

2024 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 871 738 631 542 485 600 746 690 534 539 694 900
Commercial 526 492 464 443 458 482 543 540 492 473 488 520
Irrigation 3 3 9 117 311 595 687 590 324 63 8 4
Industrial 320 305 316 308 314 329 329 332 324 326 324 325
Additional Firm 144 145 144 140 136 128 142 144 144 152 163 176
Loss 157 140 128 127 142 183 212 197 152 126 137 160
System Load 2,022 1,824 1,693 1,676 1,846 2,317 2,660 2,494 1,970 1,678 1,814 2,085
Light Load 1,884 1,689 1,566 1,528 1,673 2,075 2,395 2,204 1,789 1,522 1,679 1,941
Heavy Load 2,131 1,923 1,793 1,785 1,982 2,510 2,869 2,704 2,129 1,792 1,923 2,208
Total Load 2,022 1,824 1,693 1,676 1,846 2,317 2,660 2,494 1,970 1,678 1,814 2,085
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,635 2,382 2,166 2,192 2,796 3,844 3,939 3,718 3,178 2,350 2,472 2,731
Total Peak Load 2,635 2,382 2,166 2,192 2,796 3,844 3,939 3,718 3,178 2,350 2,472 2,731

Sales and Load Forecast Data
Page 8 2021 Integrated Resource Plan—Appendix C

2025 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 878 770 634 543 487 604 752 696 536 539 695 905
Commercial 531 514 467 446 461 486 548 545 495 476 490 523
Irrigation 4 3 9 118 312 597 690 593 325 63 8 4
Industrial 325 322 322 314 319 342 343 345 337 338 337 337
Additional Firm 180 186 187 184 184 179 195 200 201 206 211 222
Loss 160 147 130 129 144 187 216 201 155 129 140 163
System Load 2,078 1,942 1,750 1,735 1,906 2,395 2,745 2,579 2,049 1,751 1,882 2,155
Light Load 1,936 1,799 1,618 1,581 1,728 2,145 2,471 2,280 1,861 1,587 1,741 2,006
Heavy Load 2,189 2,050 1,853 1,847 2,047 2,595 2,960 2,816 2,200 1,869 2,005 2,272
Total Load 2,078 1,942 1,750 1,735 1,906 2,395 2,745 2,579 2,049 1,751 1,882 2,155
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,695 2,466 2,224 2,251 2,869 3,951 4,045 3,814 3,280 2,430 2,562 2,803
Total Peak Load 2,695 2,466 2,224 2,251 2,869 3,951 4,045 3,814 3,280 2,430 2,562 2,803

2026 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 887 776 637 545 489 608 758 701 538 539 697 911
Commercial 537 519 471 450 465 490 554 551 499 479 493 525
Irrigation 4 3 9 118 313 600 694 596 327 64 8 4
Industrial 337 335 333 326 330 346 347 349 341 342 341 339
Additional Firm 236 245 238 233 234 231 247 250 250 252 268 279
Loss 164 151 133 132 147 190 220 205 158 131 143 166
System Load 2,163 2,029 1,822 1,805 1,978 2,465 2,819 2,651 2,113 1,807 1,949 2,224
Light Load 2,015 1,879 1,686 1,645 1,793 2,208 2,538 2,343 1,918 1,638 1,804 2,071
Heavy Load 2,279 2,141 1,930 1,922 2,138 2,653 3,041 2,894 2,269 1,929 2,077 2,346
Total Load 2,163 2,029 1,822 1,805 1,978 2,465 2,819 2,651 2,113 1,807 1,949 2,224
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,784 2,555 2,298 2,324 2,928 4,036 4,149 3,903 3,360 2,520 2,615 2,901
Total Peak Load 2,784 2,555 2,298 2,324 2,928 4,036 4,149 3,903 3,360 2,520 2,615 2,901

Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 9

2027 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 895 782 639 547 491 612 765 706 540 539 698 917
Commercial 539 520 472 451 465 491 556 553 499 479 493 527
Irrigation 4 3 9 118 314 603 698 600 329 64 8 4
Industrial 339 338 336 329 333 349 350 352 344 345 344 342
Additional Firm 295 303 298 294 292 287 299 304 303 311 325 341
Loss 167 154 136 135 150 192 223 208 160 133 145 169
System Load 2,238 2,101 1,891 1,874 2,045 2,534 2,890 2,722 2,176 1,871 2,013 2,301
Light Load 2,086 1,946 1,749 1,708 1,854 2,270 2,602 2,406 1,976 1,697 1,863 2,142
Heavy Load 2,369 2,217 1,993 1,996 2,210 2,727 3,117 2,972 2,337 2,009 2,134 2,426
Total Load 2,238 2,101 1,891 1,874 2,045 2,534 2,890 2,722 2,176 1,871 2,013 2,301
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,870 2,614 2,378 2,401 3,028 4,140 4,238 4,031 3,437 2,572 2,689 2,965
Total Peak Load 2,870 2,614 2,378 2,401 3,028 4,140 4,238 4,031 3,437 2,572 2,689 2,965

2028 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 904 762 642 549 493 616 772 712 542 539 700 923
Commercial 544 506 475 455 468 495 561 558 503 482 495 530
Irrigation 4 3 9 118 315 605 701 603 331 64 8 4
Industrial 343 329 339 331 336 352 352 355 347 348 347 345
Additional Firm 349 351 349 341 335 327 335 334 331 337 347 358
Loss 170 152 139 137 152 195 226 210 162 135 146 171
System Load 2,313 2,103 1,953 1,932 2,099 2,589 2,947 2,772 2,216 1,905 2,043 2,332
Light Load 2,156 1,948 1,807 1,760 1,903 2,319 2,653 2,450 2,012 1,727 1,891 2,171
Heavy Load 2,449 2,218 2,059 2,069 2,254 2,787 3,200 3,005 2,379 2,046 2,166 2,471
Total Load 2,313 2,103 1,953 1,932 2,099 2,589 2,947 2,772 2,216 1,905 2,043 2,332
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,955 2,686 2,447 2,462 3,066 4,226 4,318 4,084 3,488 2,612 2,722 2,999
Total Peak Load 2,955 2,686 2,447 2,462 3,066 4,226 4,318 4,084 3,488 2,612 2,722 2,999

Sales and Load Forecast Data
Page 10 2021 Integrated Resource Plan—Appendix C

2029 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 913 795 645 550 494 620 778 717 543 539 701 928
Commercial 549 529 479 459 472 498 566 563 506 485 498 535
Irrigation 4 3 9 118 315 608 705 607 333 65 8 4
Industrial 345 343 342 334 339 355 356 358 350 351 350 349
Additional Firm 357 364 352 341 336 327 335 335 331 338 348 359
Loss 172 159 139 138 153 196 227 212 163 135 147 172
System Load 2,341 2,193 1,966 1,941 2,109 2,604 2,967 2,790 2,227 1,912 2,052 2,347
Light Load 2,181 2,032 1,819 1,769 1,912 2,332 2,671 2,466 2,022 1,734 1,898 2,185
Heavy Load 2,466 2,314 2,073 2,079 2,264 2,802 3,221 3,025 2,406 2,041 2,175 2,486
Total Load 2,341 2,193 1,966 1,941 2,109 2,604 2,967 2,790 2,227 1,912 2,052 2,347
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 2,987 2,708 2,462 2,470 3,078 4,273 4,355 4,130 3,508 2,620 2,730 3,016
Total Peak Load 2,987 2,708 2,462 2,470 3,078 4,273 4,355 4,130 3,508 2,620 2,730 3,016

2030 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 920 800 646 551 495 622 782 720 543 537 701 933
Commercial 556 535 483 464 476 503 573 569 511 489 502 538
Irrigation 4 3 9 118 316 610 708 610 335 65 8 4
Industrial 349 347 346 338 343 359 359 361 354 355 354 352
Additional Firm 360 366 354 343 337 329 337 336 333 340 350 361
Loss 174 160 140 139 154 197 229 213 164 136 148 173
System Load 2,362 2,211 1,978 1,952 2,120 2,620 2,988 2,811 2,239 1,921 2,062 2,361
Light Load 2,201 2,048 1,830 1,779 1,922 2,346 2,690 2,484 2,033 1,742 1,908 2,198
Heavy Load 2,489 2,333 2,095 2,079 2,277 2,838 3,223 3,047 2,420 2,051 2,185 2,502
Total Load 2,362 2,211 1,978 1,952 2,120 2,620 2,988 2,811 2,239 1,921 2,062 2,361
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,008 2,724 2,471 2,478 3,092 4,309 4,394 4,172 3,529 2,630 2,741 3,028
Total Peak Load 3,008 2,724 2,471 2,478 3,092 4,309 4,394 4,172 3,529 2,630 2,741 3,028

Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 11

2031 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 928 806 647 551 495 624 786 724 544 535 701 938
Commercial 560 538 485 467 478 506 577 573 513 491 503 542
Irrigation 4 3 9 118 317 612 712 614 337 65 8 4
Industrial 352 350 349 341 346 362 363 365 357 358 357 356
Additional Firm 360 366 354 343 337 329 337 336 333 340 350 362
Loss 175 161 141 139 154 198 230 215 165 136 148 174
System Load 2,379 2,224 1,986 1,958 2,127 2,631 3,004 2,826 2,248 1,925 2,067 2,376
Light Load 2,217 2,060 1,837 1,785 1,928 2,356 2,705 2,497 2,041 1,745 1,912 2,212
Heavy Load 2,496 2,347 2,103 2,085 2,271 2,850 3,221 3,085 2,399 2,055 2,190 2,494
Total Load 2,379 2,224 1,986 1,958 2,127 2,631 3,004 2,826 2,248 1,925 2,067 2,376
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,031 2,739 2,482 2,483 3,101 4,359 4,429 4,217 3,544 2,635 2,746 3,047
Total Peak Load 3,031 2,739 2,482 2,483 3,101 4,359 4,429 4,217 3,544 2,635 2,746 3,047

2032 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 936 782 648 550 494 625 789 726 543 533 700 942
Commercial 567 525 491 472 483 511 584 580 518 496 508 545
Irrigation 4 3 9 119 318 616 716 618 340 66 8 4
Industrial 357 342 353 345 350 366 367 369 361 362 361 360
Additional Firm 360 360 355 343 337 329 337 337 333 340 350 362
Loss 177 157 142 140 155 199 232 216 165 137 148 175
System Load 2,400 2,170 1,997 1,969 2,138 2,646 3,026 2,846 2,260 1,933 2,075 2,388
Light Load 2,237 2,010 1,847 1,794 1,938 2,370 2,724 2,515 2,052 1,752 1,920 2,223
Heavy Load 2,518 2,300 2,104 2,096 2,296 2,848 3,244 3,107 2,412 2,075 2,189 2,507
Total Load 2,400 2,170 1,997 1,969 2,138 2,646 3,026 2,846 2,260 1,933 2,075 2,388
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,052 2,753 2,491 2,490 3,115 4,396 4,468 4,259 3,566 2,644 2,755 3,057
Total Peak Load 3,052 2,753 2,491 2,490 3,115 4,396 4,468 4,259 3,566 2,644 2,755 3,057

Sales and Load Forecast Data
Page 12 2021 Integrated Resource Plan—Appendix C

2033 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 943 815 648 549 493 625 792 728 542 530 698 946
Commercial 572 547 493 475 486 514 588 584 520 498 509 549
Irrigation 4 3 9 119 320 620 722 622 342 66 8 4
Industrial 360 358 356 348 353 370 371 373 365 366 365 364
Additional Firm 360 367 355 343 337 329 337 337 333 340 350 362
Loss 178 163 142 140 155 200 233 217 166 137 149 176
System Load 2,416 2,253 2,003 1,975 2,146 2,659 3,043 2,861 2,268 1,936 2,080 2,401
Light Load 2,252 2,087 1,853 1,800 1,945 2,381 2,740 2,529 2,059 1,755 1,924 2,236
Heavy Load 2,546 2,377 2,111 2,103 2,304 2,861 3,282 3,101 2,420 2,079 2,193 2,521
Total Load 2,416 2,253 2,003 1,975 2,146 2,659 3,043 2,861 2,268 1,936 2,080 2,401
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,073 2,767 2,500 2,495 3,124 4,443 4,503 4,303 3,580 2,648 2,759 3,074
Total Peak Load 3,073 2,767 2,500 2,495 3,124 4,443 4,503 4,303 3,580 2,648 2,759 3,074

2034 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 951 820 650 550 495 631 801 736 546 533 703 954
Commercial 578 553 497 480 490 519 595 590 525 501 513 552
Irrigation 4 3 9 120 323 625 727 627 345 67 8 4
Industrial 364 362 361 353 358 374 375 377 369 370 369 368
Additional Firm 360 367 355 343 337 329 337 337 333 340 350 362
Loss 180 165 143 141 157 202 236 219 167 138 150 178
System Load 2,437 2,270 2,015 1,987 2,159 2,679 3,070 2,887 2,285 1,948 2,093 2,418
Light Load 2,271 2,103 1,863 1,811 1,957 2,400 2,764 2,551 2,074 1,766 1,936 2,251
Heavy Load 2,568 2,395 2,123 2,128 2,305 2,884 3,312 3,130 2,439 2,092 2,207 2,549
Total Load 2,437 2,270 2,015 1,987 2,159 2,679 3,070 2,887 2,285 1,948 2,093 2,418
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,093 2,782 2,509 2,503 3,142 4,486 4,547 4,351 3,610 2,662 2,773 3,088
Total Peak Load 3,093 2,782 2,509 2,503 3,142 4,486 4,547 4,351 3,610 2,662 2,773 3,088

Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 13

2035 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 961 829 655 555 501 639 813 747 551 535 706 962
Commercial 582 556 500 483 492 522 599 595 527 503 514 555
Irrigation 4 3 9 121 325 629 732 632 347 67 8 4
Industrial 368 366 365 357 362 379 379 382 373 374 374 373
Additional Firm 362 368 356 344 338 330 338 338 334 341 352 363
Loss 181 166 144 142 158 204 238 221 169 138 150 179
System Load 2,459 2,289 2,029 2,002 2,176 2,702 3,100 2,913 2,301 1,960 2,105 2,437
Light Load 2,292 2,121 1,877 1,824 1,972 2,420 2,791 2,575 2,089 1,777 1,947 2,269
Heavy Load 2,580 2,416 2,139 2,144 2,323 2,908 3,343 3,158 2,471 2,092 2,220 2,570
Total Load 2,459 2,289 2,029 2,002 2,176 2,702 3,100 2,913 2,301 1,960 2,105 2,437
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,116 2,799 2,521 2,515 3,162 4,531 4,592 4,401 3,639 2,675 2,785 3,104
Total Peak Load 3,116 2,799 2,521 2,515 3,162 4,531 4,592 4,401 3,639 2,675 2,785 3,104

2036 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 973 809 661 560 506 648 826 757 557 538 710 971
Commercial 588 542 504 487 496 526 605 600 531 507 518 560
Irrigation 4 3 9 122 327 634 737 636 350 68 8 4
Industrial 374 358 369 361 366 383 384 387 378 379 378 378
Additional Firm 362 362 356 344 338 330 338 338 334 341 352 363
Loss 183 162 145 144 159 206 241 224 170 139 151 181
System Load 2,483 2,236 2,045 2,018 2,193 2,727 3,131 2,942 2,319 1,972 2,117 2,458
Light Load 2,314 2,072 1,892 1,839 1,988 2,442 2,819 2,600 2,106 1,788 1,959 2,288
Heavy Load 2,605 2,358 2,166 2,149 2,341 2,955 3,357 3,212 2,476 2,105 2,244 2,580
Total Load 2,483 2,236 2,045 2,018 2,193 2,727 3,131 2,942 2,319 1,972 2,117 2,458
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,143 2,821 2,536 2,526 3,185 4,585 4,639 4,455 3,672 2,690 2,798 3,125
Total Peak Load 3,143 2,821 2,536 2,526 3,185 4,585 4,639 4,455 3,672 2,690 2,798 3,125

Sales and Load Forecast Data
Page 14 2021 Integrated Resource Plan—Appendix C

2037 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 985 848 668 566 513 658 840 769 563 542 715 980
Commercial 596 568 509 493 501 531 613 608 536 511 522 566
Irrigation 4 3 9 123 329 638 743 641 352 68 8 4
Industrial 379 376 375 366 372 389 390 392 383 385 384 384
Additional Firm 361 368 355 344 338 330 338 337 333 341 351 363
Loss 185 169 146 145 161 208 243 226 172 140 153 182
System Load 2,509 2,333 2,063 2,037 2,213 2,754 3,166 2,974 2,340 1,987 2,132 2,480
Light Load 2,338 2,161 1,908 1,856 2,006 2,467 2,851 2,628 2,125 1,802 1,973 2,308
Heavy Load 2,633 2,462 2,185 2,169 2,376 2,964 3,394 3,246 2,498 2,121 2,260 2,603
Total Load 2,509 2,333 2,063 2,037 2,213 2,754 3,166 2,974 2,340 1,987 2,132 2,480
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,172 2,841 2,553 2,539 3,210 4,643 4,689 4,514 3,709 2,707 2,813 3,148
Total Peak Load 3,172 2,841 2,553 2,539 3,210 4,643 4,689 4,514 3,709 2,707 2,813 3,148

2038 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 996 858 674 572 519 668 854 781 569 545 719 989
Commercial 605 575 515 499 507 538 621 616 543 517 527 572
Irrigation 4 4 10 123 332 643 748 646 355 69 8 4
Industrial 385 382 381 372 377 395 396 398 390 391 390 389
Additional Firm 361 368 356 344 338 330 338 337 334 341 351 363
Loss 188 171 148 147 162 210 246 229 173 142 154 184
System Load 2,538 2,358 2,083 2,057 2,235 2,784 3,204 3,007 2,363 2,004 2,150 2,501
Light Load 2,365 2,185 1,927 1,875 2,026 2,494 2,884 2,658 2,145 1,817 1,989 2,328
Heavy Load 2,675 2,489 2,196 2,191 2,400 2,996 3,434 3,283 2,522 2,152 2,267 2,625
Total Load 2,538 2,358 2,083 2,057 2,235 2,784 3,204 3,007 2,363 2,004 2,150 2,501
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,202 2,865 2,570 2,554 3,238 4,698 4,741 4,573 3,750 2,726 2,830 3,168
Total Peak Load 3,202 2,865 2,570 2,554 3,238 4,698 4,741 4,573 3,750 2,726 2,830 3,168

Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 15

2039 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 1,008 868 681 578 525 678 868 792 575 549 724 998
Commercial 612 581 520 505 512 543 629 623 548 521 531 577
Irrigation 4 4 10 124 334 648 754 651 358 69 8 4
Industrial 389 387 385 377 382 400 401 403 394 396 395 395
Additional Firm 360 367 355 343 337 329 337 337 333 340 350 362
Loss 190 173 149 148 164 212 249 232 175 143 155 186
System Load 2,564 2,380 2,100 2,075 2,254 2,811 3,238 3,038 2,383 2,017 2,163 2,522
Light Load 2,389 2,205 1,942 1,891 2,044 2,517 2,915 2,685 2,163 1,829 2,002 2,348
Heavy Load 2,701 2,511 2,213 2,209 2,421 3,025 3,493 3,294 2,543 2,166 2,282 2,647
Total Load 2,564 2,380 2,100 2,075 2,254 2,811 3,238 3,038 2,383 2,017 2,163 2,522
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,230 2,886 2,585 2,566 3,263 4,754 4,790 4,630 3,786 2,742 2,844 3,190
Total Peak Load 3,230 2,886 2,585 2,566 3,263 4,754 4,790 4,630 3,786 2,742 2,844 3,190

2040 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 50th Percentile
Residential 1,020 848 687 584 531 688 882 804 581 552 728 1,007
Commercial 620 568 526 511 517 550 637 632 553 527 536 583
Irrigation 4 3 10 125 337 653 760 656 361 70 8 4
Industrial 396 379 391 382 388 406 407 410 400 402 401 401
Additional Firm 360 360 355 343 337 329 337 337 333 340 350 362
Loss 192 169 151 149 166 215 252 234 177 144 156 187
System Load 2,593 2,329 2,120 2,095 2,276 2,841 3,276 3,073 2,405 2,034 2,180 2,544
Light Load 2,416 2,157 1,961 1,909 2,063 2,544 2,949 2,715 2,184 1,844 2,017 2,369
Heavy Load 2,732 2,456 2,234 2,244 2,430 3,057 3,533 3,331 2,582 2,171 2,299 2,683
Total Load 2,593 2,329 2,120 2,095 2,276 2,841 3,276 3,073 2,405 2,034 2,180 2,544
Peak Load (MW) 90th Percentile
System Peak Load (1 hour) 3,262 2,910 2,603 2,580 3,291 4,814 4,842 4,692 3,826 2,761 2,860 3,214
Total Peak Load 3,262 2,910 2,603 2,580 3,291 4,814 4,842 4,692 3,826 2,761 2,860 3,214

Sales and Load Forecast Data
Page 16 2021 Integrated Resource Plan—Appendix C
Annual Summary
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Billed Sales (MWh) 50th Percentile
Residential 5,635,713 5,710,186 5,772,357 5,834,308 5,864,905 5,898,453 5,931,181 5,967,746 5,999,109 6,018,724
Commercial 4,154,365 4,217,870 4,263,448 4,334,031 4,365,752 4,404,485 4,412,187 4,445,191 4,478,255 4,524,186
Irrigation 1,970,226 1,965,458 1,983,439 1,994,283 2,002,695 2,012,609 2,022,833 2,032,511 2,041,379 2,050,717
Industrial 2,580,373 2,623,201 2,730,455 2,816,579 2,897,217 2,965,928 2,992,099 3,017,063 3,044,712 3,074,987
Additional Firm 942,656 1,018,694 1,104,071 1,288,348 1,705,710 2,163,300 2,667,909 2,996,219 3,009,581 3,025,290
System Load 15,283,333 15,535,409 15,853,770 16,267,549 16,836,279 17,444,775 18,026,210 18,458,730 18,573,037 18,693,904
Total Load 15,283,333 15,535,409 15,853,770 16,267,549 16,836,279 17,444,775 18,026,210 18,458,730 18,573,037 18,693,904
Generation Month Sales (MWh) 50th Percentile
Residential 5,643,792 5,715,460 5,777,754 5,837,430 5,868,421 5,902,080 5,935,286 5,971,643 6,002,306 6,022,165
Commercial 4,157,604 4,220,547 4,267,693 4,335,826 4,367,986 4,404,768 4,414,055 4,447,059 4,480,927 4,525,422
Irrigation 1,969,952 1,965,473 1,983,447 1,994,290 2,002,703 2,012,617 2,022,841 2,032,518 2,041,387 2,050,724
Industrial 2,586,804 2,631,598 2,738,356 2,820,809 2,906,038 2,968,139 2,994,178 3,019,425 3,047,267 3,077,338
Additional Firm 942,656 1,018,694 1,104,071 1,288,348 1,705,710 2,163,300 2,667,909 2,996,219 3,009,581 3,025,290
System Sales 15,300,808 15,551,772 15,871,321 16,276,703 16,850,858 17,450,904 18,034,270 18,466,864 18,581,468 18,700,939
Total Sales 15,300,808 15,551,772 15,871,321 16,276,703 16,850,858 17,450,904 18,034,270 18,466,864 18,581,468 18,700,939
Loss 1,299,774 1,317,582 1,339,261 1,364,116 1,390,580 1,417,751 1,441,898 1,462,314 1,471,333 1,480,536
Required Generation 16,600,582 16,869,354 17,210,583 17,640,819 18,241,438 18,868,655 19,476,169 19,929,178 20,052,801 20,181,475
Average Load (aMW) 50th Percentile
Residential 644 652 660 665 670 674 678 680 685 687
Commercial 475 482 487 494 499 503 504 506 512 517
Irrigation 225 224 226 227 229 230 231 231 233 234
Industrial 295 300 313 321 332 339 342 344 348 351
Additional Firm 108 116 126 147 195 247 305 341 344 345
Loss 148 150 153 155 159 162 165 166 168 169
System Load 1,895 1,926 1,965 2,008 2,082 2,154 2,223 2,269 2,289 2,304
Light Load 1,727 1,755 1,790 1,830 1,898 1,963 2,026 2,068 2,086 2,100
Heavy Load 2,027 2,060 2,102 2,148 2,227 2,304 2,378 2,427 2,448 2,463
Total Load 1,895 1,926 1,965 2,008 2,082 2,154 2,223 2,269 2,289 2,304
Peak Load (MW) 90th Percentile
System Peak (1 hour) 3,745 3,801 3,866 3,939 4,045 4,149 4,238 4,318 4,355 4,394
Total Peak Load 3,745 3,801 3,866 3,939 4,045 4,149 4,238 4,318 4,355 4,394
Sales and Load Forecast Data
2021 Integrated Resource Plan—Appendix C Page 17

2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Billed Sales (MWh) 50th Percentile
Residential 6,038,740 6,053,331 6,061,524 6,104,752 6,167,697 6,234,707 6,307,610 6,379,036 6,451,389 6,524,479
Commercial 4,547,247 4,597,454 4,623,819 4,666,477 4,691,896 4,730,777 4,781,058 4,840,659 4,891,067 4,946,878
Irrigation 2,059,844 2,072,374 2,087,185 2,102,102 2,117,049 2,132,249 2,148,024 2,163,705 2,180,446 2,197,856
Industrial 3,102,840 3,139,967 3,172,009 3,209,971 3,246,433 3,287,987 3,335,272 3,388,295 3,429,735 3,483,237
Additional Firm 3,026,907 3,032,142 3,027,782 3,028,582 3,039,830 3,043,140 3,034,836 3,036,125 3,028,047 3,032,367
System Load 18,775,578 18,895,269 18,972,319 19,111,884 19,262,906 19,428,860 19,606,800 19,807,820 19,980,685 20,184,816
Total Load 18,775,578 18,895,269 18,972,319 19,111,884 19,262,906 19,428,860 19,606,800 19,807,820 19,980,685 20,184,816
Generation Month Sales (MWh) 50th Percentile
Residential 6,038,740 6,053,331 6,061,524 6,104,752 6,167,697 6,234,707 6,307,610 6,379,036 6,451,389 6,524,479
Commercial 4,547,247 4,597,454 4,623,819 4,666,477 4,691,896 4,730,777 4,781,058 4,840,659 4,891,067 4,946,878
Irrigation 2,059,844 2,072,374 2,087,185 2,102,102 2,117,049 2,132,249 2,148,024 2,163,705 2,180,446 2,197,856
Industrial 3,102,840 3,139,967 3,172,009 3,209,971 3,246,433 3,287,987 3,335,272 3,388,295 3,429,735 3,483,237
Additional Firm 3,026,907 3,032,142 3,027,782 3,028,582 3,039,830 3,043,140 3,034,836 3,036,125 3,028,047 3,032,367
System Sales 18,775,578 18,895,269 18,972,319 19,111,884 19,262,906 19,428,860 19,606,800 19,807,820 19,980,685 20,184,816
Total Sales 18,775,578 18,895,269 18,972,319 19,111,884 19,262,906 19,428,860 19,606,800 19,807,820 19,980,685 20,184,816
Loss 1,487,351 1,496,764 1,503,299 1,515,098 1,527,602 1,541,794 1,557,512 1,574,430 1,589,893 1,607,050
Required Generation 20,272,221 20,399,203 20,484,525 20,635,958 20,801,018 20,982,844 21,177,403 21,393,841 21,583,530 21,804,967
Average Load (aMW) 50th Percentile
Residential 690 689 692 697 705 710 721 729 737 743
Commercial 519 524 528 533 536 539 546 553 559 564
Irrigation 235 236 238 240 242 243 245 247 249 250
Industrial 355 358 362 367 371 375 381 387 392 397
Additional Firm 346 345 346 346 347 346 346 347 346 345
Loss 170 170 172 173 174 176 178 180 181 183
System Load 2,314 2,322 2,338 2,356 2,375 2,389 2,418 2,442 2,464 2,482
Light Load 2,109 2,117 2,131 2,147 2,164 2,177 2,203 2,226 2,246 2,262
Heavy Load 2,468 2,477 2,494 2,513 2,532 2,548 2,578 2,605 2,628 2,648
Total Load 2,314 2,322 2,338 2,356 2,375 2,389 2,418 2,442 2,464 2,482
Peak Load (MW) 90th Percentile
System Peak (1 hour) 4,429 4,468 4,503 4,547 4,592 4,639 4,689 4,741 4,790 4,842
Total Peak Load 4,429 4,468 4,503 4,547 4,592 4,639 4,689 4,741 4,790 4,842
Load and Resource Balance Data
Page 18 2021 Integrated Resource Plan—Appendix C
LOAD AND RESOURCE BALANCE DATA
1/2021 2/2021 3/2021 4/2021 5/2021 6/2021 7/2021 8/2021 9/2021 10/2021 11/2021 12/2021
Peak-Hour (50th+15.5%) w/EE (2,693) (2,339) (2,172) (2,064) (2,757) (3,938) (4,161) (3,899) (3,259) (2,453) (2,525) (2,733)
Existing Demand Response Capacity – – – – – 66 66 58 – – – –
Peak-Hour (50th+15.5%) w/DR and EE (2,693) (2,339) (2,172) (2,064) (2,757) (3,873) (4,096) (3,840) (3,259) (2,453) (2,525) (2,733)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy 121 121 121 121 121 121 121 121 121 121 121 121
Total Coal 784 784 784 784 784 784 784 784 784 784 784 784
Langley Gulch 288 282 279 279 276 270 270 270 273 276 282 288
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 717 708 689 680 672 640 636 637 671 691 706 725
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 356 366 285 431 458 434 295 254 244 218 200 378
Total Hydroelectric (50%) 1,368 1,378 1,346 1,492 1,615 1,591 1,355 1,266 1,159 1,086 875 1,342
Solar CSPP (PURPA) – – 99 99 99 197 197 197 99 99 99 –
Wind CSPP Capacity 94 94 94 94 94 93 93 93 94 94 94 94
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 125 133 239 276 314 424 420 412 296 260 227 126
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – – – – – – – – – – –
Clatskanie Exchange – – – – – 14 11 2 – – – –
Total PPAs 50 50 48 46 38 52 42 38 41 46 51 52
Available Transmission w/3rd Party Secured 50 50 50 50 150 200 200 200 200 200 150 150
Emergency Transmission (CBM)330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,424 3,434 3,486 3,657 3,904 4,021 3,767 3,667 3,481 3,397 3,123 3,510
731 1,095 1,314 1,594 1,147 148 (329) (173) 222 944 598 776
2021 IRP Resources
New Transmission—B2H – – – – – – – – – – – –
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – – – – – – – –
New Resource—Battery: 4 hour – – – – – – – – – – – –
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Storage) – – – – – – – – – – – –
New Resource—Solar – – – – – – – – – – – –
New Resource—WY Wind – – – – – – – – – – – –
New Resource—ID Wind – – – – – – – – – – – –
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits – – – – – – – – – – – –
New Resource Subtotal 0 0 0 0 0 0 0 0 0 0 0 0
731 1,095 1,314 1,594 1,147 148 (329) (173) 222 944 598 776
46.8% 69.6% 85.4% 104.7% 63.6% 19.9% 6.4% 10.4% 23.4% 59.9% 42.9% 48.3%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 19
1/2022 2/2022 3/2022 4/2022 5/2022 6/2022 7/2022 8/2022 9/2022 10/2022 11/2022 12/2022
Peak-Hour (50th+15.5%) w/EE (2,771) (2,531) (2,352) (2,188) (2,899) (3,973) (4,226) (3,927) (3,291) (2,473) (2,555) (2,762)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (2,771) (2,531) (2,352) (2,188) (2,899) (3,798) (4,050) (3,800) (3,188) (2,473) (2,555) (2,762)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy 121 121 121 121 121 121 121 121 121 121 121 121
Total Coal 784 784 784 784 784 784 784 784 784 784 784 784
Langley Gulch 288 282 279 279 276 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 717 708 689 680 672 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 356 366 286 431 461 437 295 254 244 218 200 379
Total Hydroelectric (50%) 1,368 1,378 1,346 1,492 1,618 1,594 1,355 1,266 1,159 1,086 875 1,343
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 94 94 94 94 94 93 93 93 94 94 94 94
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 125 133 240 276 316 425 422 414 297 261 228 126
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – – – – – – – – – – –
Clatskanie Exchange – – – – – 14 11 2 – – – –
Total PPAs 50 50 48 46 38 52 42 38 41 46 51 52
Available Transmission w/3rd Party Secured 150 150 150 150 250 300 300 300 300 300 250 209
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,524 3,534 3,588 3,758 4,008 4,161 3,904 3,804 3,618 3,533 3,259 3,605
753 1,003 1,236 1,570 1,109 364 (146) 4 430 1,060 705 843
2021 IRP Resources
New Transmission—B2H – – – – – – – – – – – –
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – – – – – – – –
New Resource—Battery: 4 hour – – – – – – – – – – – –
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Storage) – – – – – – – – – – – –
New Resource—Solar – – – – – – – – – – – –
New Resource—WY Wind – – – – – – – – – – – –
New Resource—ID Wind – – – – – – – – – – – –
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits – – – – – – – – – – – –
New Resource Subtotal 0 0 0 0 0 0 0 0 0 0 0 0
753 1,003 1,236 1,570 1,109 364 (146) 4 430 1,060 705 843
46.9% 61.3% 76.2% 98.4% 59.7% 26.1% 11.5% 15.6% 30.6% 65.0% 47.4% 50.8%

Load and Resource Balance Data
Page 20 2021 Integrated Resource Plan—Appendix C
1/2023 2/2023 3/2023 4/2023 5/2023 6/2023 7/2023 8/2023 9/2023 10/2023 11/2023 12/2023
Peak-Hour (50th+15.5%) w/EE (2,818) (2,579) (2,390) (2,234) (2,956) (4,146) (4,301) (4,045) (3,348) (2,509) (2,585) (2,843)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (2,818) (2,579) (2,390) (2,234) (2,956) (3,971) (4,126) (3,917) (3,245) (2,509) (2,585) (2,843)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy 121 121 121 121 121 121 121 121 121 121 121 121
Total Coal 784 784 784 784 784 784 784 784 784 784 784 784
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 356 366 287 431 464 443 295 254 244 218 200 381
Total Hydroelectric (50%) 1,368 1,378 1,347 1,492 1,621 1,599 1,355 1,266 1,159 1,086 875 1,345
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 94 94 94 94 94 93 93 93 94 94 94 94
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 125 133 240 276 316 425 422 414 297 261 228 126
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – 14 11 2 – – – –
Total PPAs 50 50 68 66 58 92 82 78 61 66 71 52
Available Transmission w/3rd Party Secured 239 295 330 330 271 380 380 380 380 380 275 206
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,648 3,714 3,825 3,994 4,088 4,287 4,025 3,925 3,718 3,634 3,305 3,605
Mon 830 1,135 1,435 1,760 1,132 316 (101) 8 473 1,125 720 762
2021 IRP Resources
New Transmission—B2H – – – – – – – – – – – –
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 7 7 5 4 – – –
New Resource—Battery: 4 hour 50 50 50 101 101 101 101 101 50 50 50 50
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Storage) – – – – – – – – – – – –
New Resource—Solar – – – – – – – – – – – –
New Resource—WY Wind – – – – – – – – – – – –
New Resource—ID Wind – – – – – – – – – – – –
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits – – – – – – – – – – – –
New Resource Subtotal 50 50 50 50 101 108 108 106 105 50 50 50
881 1,185 1,485 1,810 1,232 424 7 114 578 1,175 770 812
51.6% 68.6% 87.2% 109.1% 63.6% 27.3% 15.7% 18.7% 35.4% 69.6% 49.9% 48.5%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 21
1/2024 2/2024 3/2024 4/2024 5/2024 6/2024 7/2024 8/2024 9/2024 10/2024 11/2024 12/2024
Peak-Hour (50th+15.5%) w/EE (2,893) (2,630) (2,444) (2,271) (3,033) (4,192) (4,385) (4,152) (3,433) (2,576) (2,664) (2,902)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (2,893) (2,630) (2,444) (2,271) (3,033) (4,017) (4,210) (4,025) (3,330) (2,576) (2,664) (2,902)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy 121 121 121 121 121 121 121 121 121 121 121 121
Total Coal 784 784 784 784 784 784 784 784 784 784 784 784
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 357 366 289 432 466 446 295 253 244 218 200 383
Total Hydroelectric (50%) 1,369 1,379 1,349 1,492 1,623 1,603 1,355 1,266 1,159 1,085 875 1,347
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 94 94 94 94 94 93 93 93 94 94 94 94
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 125 133 240 276 316 425 422 414 297 261 228 126
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – 14 11 2 – – – –
Total PPAs 50 50 68 66 58 92 82 78 61 66 71 52
Available Transmission w/3rd Party Secured 237 294 330 330 269 380 379 380 380 380 273 205
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,647 3,714 3,826 3,994 4,088 4,290 4,023 3,925 3,718 3,633 3,303 3,604
Mo 754 1,083 1,382 1,723 1,056 274 (186) (100) 388 1,058 639 702
2021 IRP Resources
New Transmission—B2H – – – – – – – – – – – –
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 7 7 5 4 – – –
New Resource—Battery: 4 hour 53 53 53 53 105 105 105 105 105 53 53 53
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Storage) – – – – – – – – – – – –
New Resource—Solar – – – – – – – – – 10 10 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – 334 334 334 334 334 334 334
Early Bridger Coal Exits (334) (334) (334) (334) (334) (334) (334) (334) (334) (334) (334) (334)
New Resource Subtotal (204) (204) (204) (204) (151) 190 190 188 187 141 141 131
550 879 1,178 1,520 904 464 4 88 575 1,198 779 833
37.5% 54.1% 71.2% 92.8% 49.9% 28.3% 15.6% 18.0% 34.8% 69.2% 49.3% 48.6%

Load and Resource Balance Data
Page 22 2021 Integrated Resource Plan—Appendix C
1/2025 2/2025 3/2025 4/2025 5/2025 6/2025 7/2025 8/2025 9/2025 10/2025 11/2025 12/2025
Peak-Hour (50th+15.5%) w/EE (2,962) (2,727) (2,512) (2,339) (3,118) (4,316) (4,508) (4,263) (3,551) (2,669) (2,768) (2,986)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (2,962) (2,727) (2,512) (2,339) (3,118) (4,140) (4,332) (4,135) (3,448) (2,669) (2,768) (2,986)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy 121 121 121 121 121 121 121 121 121 121 121 121
Total Coal 784 784 784 784 784 784 784 784 784 784 784 784
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 356 366 288 431 466 445 295 253 243 218 200 382
Total Hydroelectric (50%) 1,369 1,378 1,349 1,492 1,623 1,602 1,355 1,266 1,159 1,085 875 1,346
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 94 94 94 94 94 93 93 93 94 93 93 93
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 125 133 240 276 316 425 422 414 297 259 227 125
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – 14 11 2 – – – –
Total PPAs 50 50 68 66 58 92 82 78 61 66 71 52
Available Transmission w/3rd Party Secured 235 290 330 330 268 380 377 380 380 379 271 203
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,645 3,710 3,826 3,994 4,086 4,289 4,021 3,925 3,718 3,631 3,300 3,601
683 983 1,314 1,654 968 149 (311) (211) 269 962 531 614
2021 IRP Resources
New Transmission—B2H – – – – – – – – – – – –
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 55 55 55 55 109 109 109 109 109 55 55 55
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 5 5 5 10 10 10 5 5 5 –
New Resource—Solar + Storage 1:1 (Storage) 43 43 43 43 87 87 87 87 87 43 43 43
New Resource—Solar – – 10 10 10 20 20 20 10 10 10 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (334) (334) (334) (334) (334) (334) (334) (334) (334) (334) (334) (334)
New Resource Subtotal 176 176 191 191 290 319 319 315 298 191 191 176
859 1,160 1,505 1,846 1,258 468 8 105 567 1,154 723 791
49.0% 64.6% 84.7% 106.6% 62.1% 28.0% 15.7% 18.3% 34.0% 65.4% 45.7% 46.1%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 23
1/2026 2/2026 3/2026 4/2026 5/2026 6/2026 7/2026 8/2026 9/2026 10/2026 11/2026 12/2026
Peak-Hour (50th+15.5%) w/EE (3,065) (2,829) (2,598) (2,423) (3,186) (4,415) (4,620) (4,358) (3,636) (2,765) (2,822) (3,092)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,065) (2,829) (2,598) (2,423) (3,186) (4,239) (4,445) (4,231) (3,533) (2,765) (2,822) (3,092)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 356 365 288 431 465 445 294 253 243 218 200 380
Total Hydroelectric (50%) 1,368 1,378 1,348 1,491 1,622 1,601 1,355 1,265 1,159 1,085 875 1,344
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 93 93 92 92 92 91 91 91 92 92 92 92
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 124 132 238 274 313 423 420 412 295 258 226 124
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 50 50 68 66 58 78 71 76 61 66 71 52
Available Transmission w/3rd Party Secured 233 289 330 330 266 380 375 380 380 277 170 102
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,520 3,585 3,702 3,870 3,961 4,152 3,885 3,799 3,594 3,407 3,076 3,375
455 756 1,105 1,447 775 (88) (560) (432) 61 642 253 283
2021 IRP Resources
New Transmission—B2H – – – – – 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 55 55 55 55 109 109 109 109 109 55 55 55
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 5 5 5 10 10 10 5 5 5 –
New Resource—Solar + Storage 1:1 (Storage) 43 43 43 43 87 87 87 87 87 43 43 43
New Resource—Solar – – 21 21 21 42 42 42 21 21 27 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497)
New Resource Subtotal 13 13 39 39 138 678 678 674 646 439 445 413
468 769 1,144 1,486 912 591 118 242 707 1,081 699 696
33.1% 46.9% 66.4% 86.4% 48.6% 30.9% 18.5% 21.9% 37.9% 60.7% 44.1% 41.5%

Load and Resource Balance Data
Page 24 2021 Integrated Resource Plan—Appendix C
1/2027 2/2027 3/2027 4/2027 5/2027 6/2027 7/2027 8/2027 9/2027 10/2027 11/2027 12/2027
Peak-Hour (50th+15.5%) w/EE (3,157) (2,890) (2,682) (2,505) (3,294) (4,527) (4,724) (4,506) (3,725) (2,825) (2,907) (3,166)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,157) (2,890) (2,682) (2,505) (3,294) (4,351) (4,548) (4,379) (3,622) (2,825) (2,907) (3,166)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 355 364 287 431 465 443 294 253 243 218 200 377
Total Hydroelectric (50%) 1,367 1,376 1,347 1,491 1,621 1,600 1,355 1,265 1,159 1,085 874 1,341
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 92 92 92 92 92 91 91 91 92 92 92 92
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 123 131 238 274 313 423 420 412 295 258 226 124
Elkhorn 15 15 15 15 15 15 15 15 15 15 15 15
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 50 50 68 66 58 78 71 76 61 66 71 52
Available Transmission w/3rd Party Secured 132 187 250 258 165 380 374 380 380 276 169 101
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,416 3,481 3,621 3,798 3,858 4,150 3,883 3,799 3,594 3,406 3,074 3,371
259 591 939 1,293 565 (201) (665) (580) (28) 581 167 205
2021 IRP Resources
New Transmission—B2H 400 400 400 699 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 57 57 57 57 114 114 114 114 114 57 57 57
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 5 5 5 10 10 10 5 5 5 –
New Resource—Solar + Storage 1:1 (Storage) 43 43 43 43 87 87 87 87 87 43 43 43
New Resource—Solar – – 27 27 27 68 68 68 34 34 34 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497)
New Resource Subtotal 415 415 447 746 848 708 708 704 663 454 454 415
675 1,006 1,386 2,039 1,413 507 44 124 635 1,035 622 621
40.2% 55.7% 75.2% 109.5% 65.0% 28.4% 16.6% 18.7% 35.2% 57.8% 40.2% 38.1%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 25
1/2028 2/2028 3/2028 4/2028 5/2028 6/2028 7/2028 8/2028 9/2028 10/2028 11/2028 12/2028
Peak-Hour (50th+15.5%) w/EE (3,254) (2,974) (2,761) (2,576) (3,337) (4,626) (4,816) (4,568) (3,784) (2,871) (2,946) (3,205)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,254) (2,974) (2,761) (2,576) (3,337) (4,451) (4,640) (4,440) (3,681) (2,871) (2,946) (3,205)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 353 362 285 430 463 442 294 253 243 217 199 374
Total Hydroelectric (50%) 1,366 1,374 1,345 1,490 1,620 1,598 1,354 1,265 1,159 1,085 874 1,338
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 92 92 92 92 92 91 91 91 92 92 92 92
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 123 131 238 274 313 423 420 412 295 258 226 124
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 43 63 56 61 46 51 56 37
Available Transmission w/3rd Party Secured 131 188 249 258 164 380 373 380 380 276 168 100
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,399 3,465 3,603 3,782 3,841 4,134 3,867 3,784 3,579 3,390 3,059 3,353
145 491 842 1,206 504 (317) (773) (657) (102) 519 113 148
2021 IRP Resources
New Transmission—B2H 400 400 400 695 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 81 81 81 81 162 162 162 162 162 81 81 81
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 5 5 5 10 10 10 5 5 5 –
New Resource—Solar + Storage 1:1 (Storage) 43 43 43 43 87 87 87 87 87 43 43 43
New Resource—Solar – – 34 34 34 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497) (497)
New Resource Subtotal 439 439 478 774 903 768 768 764 717 485 485 439
584 930 1,320 1,980 1,406 451 (4) 108 615 1,004 597 587
36.2% 51.6% 70.7% 104.3% 64.2% 26.8% 15.4% 18.2% 34.3% 55.9% 38.9% 36.7%

Load and Resource Balance Data
Page 26 2021 Integrated Resource Plan—Appendix C
1/2029 2/2029 3/2029 4/2029 5/2029 6/2029 7/2029 8/2029 9/2029 10/2029 11/2029 12/2029
Peak-Hour (50th+15.5%) w/EE (3,292) (3,000) (2,779) (2,584) (3,352) (4,681) (4,859) (4,621) (3,807) (2,881) (2,956) (3,225)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,292) (3,000) (2,779) (2,584) (3,352) (4,505) (4,684) (4,493) (3,704) (2,881) (2,956) (3,225)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 352 361 283 429 459 441 294 253 243 217 199 371
Total Hydroelectric (50%) 1,365 1,373 1,344 1,490 1,616 1,598 1,354 1,265 1,158 1,085 874 1,335
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 87 87 87 86 86 85 85 85 86 86 86 86
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 118 127 233 268 308 418 414 406 289 252 220 118
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 43 63 56 61 46 51 56 37
Available Transmission w/3rd Party Secured 130 185 249 257 163 380 372 380 380 275 167 99
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,393 3,456 3,597 3,774 3,830 4,127 3,861 3,778 3,572 3,383 3,052 3,343
101 457 818 1,190 479 (378) (823) (716) (131) 503 96 118
2021 IRP Resources
New Transmission—B2H 400 400 400 692 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 149 149 149 149 298 298 298 298 298 149 149 149
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 10 10 10 20 20 20 10 10 10 –
New Resource—Solar + Storage 1:1 (Storage) 87 87 87 87 174 174 174 174 174 87 87 87
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 385 385 435 727 971 835 835 831 779 435 435 385
486 842 1,253 1,917 1,449 457 12 116 648 938 531 503
32.6% 47.9% 67.6% 101.2% 65.5% 26.8% 15.8% 18.4% 35.2% 53.1% 36.3% 33.5%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 27
1/2030 2/2030 3/2030 4/2030 5/2030 6/2030 7/2030 8/2030 9/2030 10/2030 11/2030 12/2030
Peak-Hour (50th+15.5%) w/EE (3,316) (3,018) (2,790) (2,594) (3,368) (4,722) (4,904) (4,669) (3,832) (2,892) (2,968) (3,238)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,316) (3,018) (2,790) (2,594) (3,368) (4,546) (4,729) (4,541) (3,729) (2,892) (2,968) (3,238)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 351 359 282 429 458 438 294 252 242 217 199 368
Total Hydroelectric (50%) 1,364 1,371 1,342 1,489 1,615 1,594 1,354 1,265 1,158 1,085 874 1,332
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 86 86 86 86 86 81 81 81 82 82 82 82
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 117 125 232 268 308 414 410 402 285 248 216 114
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 43 63 56 61 46 51 56 37
Available Transmission w/3rd Party Secured 130 185 248 256 162 380 371 380 380 274 166 99
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,390 3,453 3,593 3,773 3,829 4,120 3,856 3,774 3,568 3,379 3,046 3,335
73 435 803 1,180 461 (427) (873) (768) (160) 486 79 97
2021 IRP Resources
New Transmission—B2H 400 400 400 688 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 173 173 173 173 346 346 346 346 346 173 173 173
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 10 10 10 20 20 20 10 10 10 –
New Resource—Solar + Storage 1:1 (Storage) 87 87 87 87 174 174 174 174 174 87 87 87
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 409 409 459 748 1,019 883 883 879 827 459 459 409
482 844 1,262 1,927 1,480 457 10 111 667 945 538 506
32.3% 47.8% 67.8% 101.3% 66.3% 26.7% 15.7% 18.3% 35.6% 53.2% 36.4% 33.5%

Load and Resource Balance Data
Page 28 2021 Integrated Resource Plan—Appendix C
1/2031 2/2031 3/2031 4/2031 5/2031 6/2031 7/2031 8/2031 9/2031 10/2031 11/2031 12/2031
Peak-Hour (50th+15.5%) w/EE (3,342) (3,035) (2,803) (2,599) (3,377) (4,780) (4,944) (4,721) (3,849) (2,898) (2,974) (3,260)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,342) (3,035) (2,803) (2,599) (3,377) (4,604) (4,769) (4,594) (3,746) (2,898) (2,974) (3,260)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 349 360 281 428 457 436 294 252 242 217 199 364
Total Hydroelectric (50%) 1,362 1,372 1,342 1,489 1,614 1,592 1,354 1,265 1,158 1,084 873 1,328
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 75 63 63 63 61 60 60 60 61 61 58 58
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 105 103 210 246 283 393 389 381 264 228 193 90
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 43 63 56 61 46 51 56 37
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,376 3,430 3,569 3,750 3,802 4,097 3,833 3,753 3,547 3,357 3,022 3,307
34 395 767 1,150 425 (507) (935) (841) (198) 459 48 47
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 197 197 197 197 394 394 394 394 394 197 197 197
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 10 10 10 20 20 20 10 10 10 –
New Resource—Solar + Storage 1:1 (Storage) 87 87 87 87 174 174 174 174 174 87 87 87
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 433 433 483 768 1,067 932 932 928 875 483 483 433
467 828 1,250 1,918 1,492 425 (4) 87 677 942 531 480
31.6% 47.0% 67.0% 100.7% 66.5% 25.8% 15.4% 17.6% 35.8% 53.1% 36.1% 32.5%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 29
1/2032 2/2032 3/2032 4/2032 5/2032 6/2032 7/2032 8/2032 9/2032 10/2032 11/2032 12/2032
Peak-Hour (50th+15.5%) w/EE (3,367) (3,051) (2,812) (2,608) (3,394) (4,823) (4,989) (4,770) (3,874) (2,908) (2,984) (3,272)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,367) (3,051) (2,812) (2,608) (3,394) (4,647) (4,813) (4,642) (3,771) (2,908) (2,984) (3,272)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 348 358 280 427 456 434 293 252 242 217 198 360
Total Hydroelectric (50%) 1,360 1,370 1,341 1,488 1,613 1,590 1,354 1,264 1,158 1,084 873 1,324
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 58 58 58 58 58 57 57 57 58 58 58 58
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 89 98 204 241 280 390 387 378 261 225 192 90
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 7 8 8 8 9 9 10 10
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 43 63 56 61 46 51 56 37
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,358 3,423 3,563 3,743 3,798 4,092 3,830 3,750 3,544 3,354 3,021 3,303
Monthly (9) 372 751 1,135 405 (555) (983) (893) (227) 446 38 31
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 221 221 221 221 442 442 442 442 442 221 221 221
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 10 10 10 20 20 20 10 10 10 –
New Resource—Solar + Storage 1:1 (Storage) 87 87 87 87 174 174 174 174 174 87 87 87
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 457 457 507 792 1,115 980 980 976 923 507 507 457
448 829 1,258 1,928 1,520 425 (3) 83 697 953 545 488
30.9% 46.9% 67.2% 100.9% 67.2% 25.7% 15.4% 17.5% 36.3% 53.4% 36.6% 32.7%

Load and Resource Balance Data
Page 30 2021 Integrated Resource Plan—Appendix C
1/2033 2/2033 3/2033 4/2033 5/2033 6/2033 7/2033 8/2033 9/2033 10/2033 11/2033 12/2033
Peak-Hour (50th+15.5%) w/EE (3,391) (3,067) (2,823) (2,613) (3,405) (4,877) (5,029) (4,820) (3,890) (2,912) (2,989) (3,291)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,391) (3,067) (2,823) (2,613) (3,405) (4,702) (4,854) (4,693) (3,787) (2,912) (2,989) (3,291)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 347 357 279 427 456 432 293 252 242 216 198 356
Total Hydroelectric (50%) 1,359 1,369 1,339 1,487 1,612 1,589 1,354 1,264 1,158 1,084 873 1,320
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 38 38 38 38 38 38 38 38 38 38 38 38
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 69 78 184 221 260 370 367 359 241 205 172 70
Elkhorn – – – – – – – – – – – –
Raft River Geothermal 10 10 9 10 – – – – – – – –
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 35 35 53 51 36 55 48 53 37 42 46 27
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,337 3,402 3,541 3,723 3,771 4,063 3,803 3,722 3,515 3,324 2,991 3,269
(53) 335 719 1,110 366 (639) (1,051) (971) (272) 412 2 (22)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 265 265 265 265 529 529 529 529 529 265 265 265
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 10 10 10 20 20 20 10 10 10 –
New Resource—Solar + Storage 1:1 (Storage) 87 87 87 87 174 174 174 174 174 87 87 87
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 501 501 551 836 1,203 1,067 1,067 1,063 1,011 551 551 501
447 836 1,270 1,946 1,568 428 16 92 739 963 553 479
30.7% 47.0% 67.4% 101.5% 68.7% 25.6% 15.9% 17.7% 37.4% 53.7% 36.9% 32.3%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 31
1/2034 2/2034 3/2034 4/2034 5/2034 6/2034 7/2034 8/2034 9/2034 10/2034 11/2034 12/2034
Peak-Hour (50th+15.5%) w/EE (3,414) (3,084) (2,833) (2,623) (3,425) (4,926) (5,080) (4,876) (3,925) (2,929) (3,004) (3,308)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,414) (3,084) (2,833) (2,623) (3,425) (4,751) (4,905) (4,749) (3,823) (2,929) (3,004) (3,308)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 346 357 277 426 455 431 293 252 242 216 198 352
Total Hydroelectric (50%) 1,358 1,369 1,337 1,486 1,612 1,587 1,353 1,264 1,157 1,084 873 1,316
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 38 38 38 38 38 38 38 38 38 38 38 38
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 69 78 184 221 260 370 367 359 241 205 172 70
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 25 25 44 41 36 55 48 53 37 42 46 27
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,326 3,391 3,530 3,712 3,770 4,062 3,802 3,721 3,515 3,324 2,991 3,264
(88) 307 697 1,089 345 (689) (1,102) (1,027) (308) 395 (14) (43)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 287 287 287 287 573 573 573 573 573 287 287 287
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 15 15 15 31 31 31 15 15 15 –
New Resource—Solar + Storage 1:1 (Storage) 130 130 130 130 260 260 260 260 260 130 130 130
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) 334 334 334 334 334 334 334 334 334 334 334 334
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 566 566 621 906 1,338 1,208 1,208 1,204 1,147 621 621 566
478 873 1,319 1,995 1,683 519 106 177 839 1,017 608 523
31.7% 48.2% 69.3% 103.4% 72.2% 27.7% 17.9% 19.7% 40.2% 55.6% 38.9% 33.8%

Load and Resource Balance Data
Page 32 2021 Integrated Resource Plan—Appendix C
1/2035 2/2035 3/2035 4/2035 5/2035 6/2035 7/2035 8/2035 9/2035 10/2035 11/2035 12/2035
Peak-Hour (50th+15.5%) w/EE (3,441) (3,105) (2,848) (2,636) (3,449) (4,979) (5,133) (4,933) (3,959) (2,944) (3,018) (3,326)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,441) (3,105) (2,848) (2,636) (3,449) (4,804) (4,957) (4,806) (3,856) (2,944) (3,018) (3,326)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 345 354 275 425 454 431 293 251 242 216 196 348
Total Hydroelectric (50%) 1,357 1,367 1,335 1,485 1,611 1,588 1,353 1,263 1,157 1,083 871 1,312
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 38 38 38 38 38 38 38 38 38 38 38 38
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 69 78 184 221 260 370 367 359 241 205 172 70
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 25 25 44 41 36 55 48 53 37 42 46 27
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,325 3,389 3,529 3,711 3,769 4,062 3,802 3,721 3,515 3,324 2,989 3,260
(116) 284 681 1,075 320 (742) (1,155) (1,085) (341) 379 (29) (66)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 376 376 376 376 753 753 753 753 753 376 376 376
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour – – – – – – – – – – – –
New Resource—Solar + Storage 1:1 (Solar) – – 20 20 20 41 41 41 20 20 20 –
New Resource—Solar + Storage 1:1 (Storage) 174 174 174 174 347 347 347 347 347 174 174 174
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 365 365 425 710 1,275 1,150 1,150 1,146 1,084 425 425 365
249 649 1,106 1,785 1,595 408 (5) 61 742 805 396 299
23.8% 39.7% 60.4% 93.7% 68.9% 25.0% 15.4% 16.9% 37.2% 47.1% 30.7% 25.9%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 33
1/2036 2/2036 3/2036 4/2036 5/2036 6/2036 7/2036 8/2036 9/2036 10/2036 11/2036 12/2036
Peak-Hour (50th+15.5%) w/EE (3,472) (3,129) (2,865) (2,649) (3,474) (5,041) (5,187) (4,996) (3,996) (2,961) (3,033) (3,350)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,472) (3,129) (2,865) (2,649) (3,474) (4,866) (5,011) (4,869) (3,893) (2,961) (3,033) (3,350)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 344 352 274 424 453 429 292 251 241 216 197 342
Total Hydroelectric (50%) 1,356 1,364 1,334 1,485 1,610 1,586 1,353 1,263 1,157 1,083 871 1,306
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 38 38 38 38 38 38 38 38 38 38 38 38
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 69 78 184 221 260 370 367 359 241 205 172 70
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 27
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 25 25 44 41 36 55 48 53 37 42 46 27
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,324 3,387 3,528 3,710 3,768 4,060 3,802 3,721 3,514 3,324 2,989 3,255
(148) 257 663 1,061 293 (805) (1,210) (1,148) (379) 363 (44) (95)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 378 378 378 378 757 757 757 757 757 378 378 378
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour 49 49 49 49 49 49 49 49 49 49 49 49
New Resource—Solar + Storage 1:1 (Solar) – – 20 20 20 41 41 41 20 20 20 –
New Resource—Solar + Storage 1:1 (Storage) 174 174 174 174 347 347 347 347 347 174 174 174
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 415 415 476 761 1,328 1,203 1,203 1,199 1,136 476 476 415
Monthly 268 673 1,139 1,822 1,621 398 (7) 51 757 839 432 321
24.4% 40.3% 61.4% 94.9% 69.4% 24.6% 15.3% 16.7% 37.4% 48.2% 32.0% 26.6%

Load and Resource Balance Data
Page 34 2021 Integrated Resource Plan—Appendix C
1/2037 2/2037 3/2037 4/2037 5/2037 6/2037 7/2037 8/2037 9/2037 10/2037 11/2037 12/2037
Peak-Hour (50th+15.5%) w/EE (3,506) (3,153) (2,884) (2,664) (3,504) (5,108) (5,244) (5,065) (4,040) (2,981) (3,051) (3,377)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,506) (3,153) (2,884) (2,664) (3,504) (4,933) (5,069) (4,937) (3,937) (2,981) (3,051) (3,377)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 343 350 272 423 452 426 292 251 241 216 196 338
Total Hydroelectric (50%) 1,355 1,363 1,332 1,483 1,609 1,583 1,353 1,263 1,157 1,083 871 1,302
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 29 29 29 24 24 23 23 23 24 24 24 24
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 60 69 175 206 245 356 352 344 226 190 158 55
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal 25 25 24 21 16 15 8 13 17 22 26 –
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 25 25 44 41 36 55 48 53 37 42 46 0
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,314 3,376 3,517 3,694 3,752 4,043 3,787 3,706 3,500 3,309 2,974 3,209
(192) 223 633 1,030 248 (890) (1,282) (1,231) (437) 328 (76) (168)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 14 14 10 8 – – –
New Resource—Battery: 4 hour 424 424 424 424 849 849 849 849 849 424 424 424
New Resource—Battery: 4 hour - Removals – – – – – – – – – – – –
New Resource—Battery: 8 hour 49 49 49 49 49 49 49 49 49 49 49 49
New Resource—Solar + Storage 1:1 (Solar) – – 20 20 20 41 41 41 20 20 20 –
New Resource—Solar + Storage 1:1 (Storage) 174 174 174 174 347 347 347 347 347 174 174 174
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 461 461 522 807 1,420 1,295 1,295 1,291 1,228 522 522 461
270 684 1,155 1,837 1,668 404 13 60 791 850 446 293
24.4% 40.6% 61.8% 95.1% 70.5% 24.6% 15.8% 16.9% 38.1% 48.4% 32.4% 25.5%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 35
1/2038 2/2038 3/2038 4/2038 5/2038 6/2038 7/2038 8/2038 9/2038 10/2038 11/2038 12/2038
Peak-Hour (50th+15.5%) w/EE (3,541) (3,180) (2,903) (2,681) (3,536) (5,171) (5,304) (5,132) (4,087) (3,003) (3,071) (3,400)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,541) (3,180) (2,903) (2,681) (3,536) (4,996) (5,129) (5,005) (3,984) (3,003) (3,071) (3,400)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 342 351 271 422 451 425 292 251 241 215 197 333
Total Hydroelectric (50%) 1,354 1,363 1,331 1,483 1,607 1,582 1,352 1,263 1,157 1,083 872 1,297
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 24 24 24 24 24 23 23 23 24 24 24 24
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 54 63 170 206 245 356 352 344 226 190 158 55
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal – – – – – – – – – – – –
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 0 0 20 20 20 40 40 40 20 20 20 0
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,282 3,346 3,486 3,673 3,735 4,026 3,780 3,693 3,482 3,287 2,949 3,204
(258) 166 583 991 199 (970) (1,349) (1,312) (501) 283 (122) (196)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE – – – – – – – – – – – –
New Resource—DR – – – – – 22 22 16 13 – – –
New Resource—Battery: 4 hour 427 427 427 427 853 853 853 853 853 427 427 427
New Resource—Battery: 4 hour - Removals (50) (50) (50) (50) (101) (101) (101) (101) (101) (50) (50) (50)
New Resource—Battery: 8 hour 97 97 97 97 97 97 97 97 97 97 97 97
New Resource—Solar + Storage 1:1 (Solar) – – 26 26 26 51 51 51 26 26 26 –
New Resource—Solar + Storage 1:1 (Storage) 217 217 217 217 434 434 434 434 434 217 217 217
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 505 505 571 856 1,464 1,351 1,351 1,345 1,277 571 571 505
247 671 1,153 1,847 1,663 382 2 34 775 854 449 309
Planning 23.6% 39.9% 61.4% 95.1% 69.8% 24.0% 15.5% 16.3% 37.4% 48.3% 32.4% 26.0%

Load and Resource Balance Data
Page 36 2021 Integrated Resource Plan—Appendix C
1/2039 2/2039 3/2039 4/2039 5/2039 6/2039 7/2039 8/2039 9/2039 10/2039 11/2039 12/2039
Peak-Hour (50th+15.5%) w/EE (3,573) (3,204) (2,921) (2,695) (3,565) (5,237) (5,361) (5,198) (4,128) (3,021) (3,086) (3,426)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,573) (3,204) (2,921) (2,695) (3,565) (5,061) (5,185) (5,071) (4,025) (3,021) (3,086) (3,426)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 342 351 271 422 451 425 292 251 241 215 197 333
Total Hydroelectric (50%) 1,354 1,363 1,331 1,483 1,607 1,582 1,352 1,263 1,157 1,083 872 1,297
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 24 24 24 24 24 23 23 23 24 24 24 24
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 54 63 170 206 245 356 352 344 226 190 158 55
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal – – – – – – – – – – – –
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 0 0 20 20 20 40 40 40 20 20 20 0
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,282 3,346 3,486 3,673 3,735 4,026 3,780 3,693 3,482 3,287 2,949 3,204
(290) 142 565 977 170 (1,035) (1,406) (1,378) (543) 266 (138) (222)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE 2 2 2 2 2 2 2 2 2 2 2 2
New Resource—DR – – – – – 29 29 21 17 – – –
New Resource—Battery: 4 hour 451 451 451 451 901 901 901 901 901 451 451 451
New Resource—Battery: 4 hour - Removals (53) (53) (53) (53) (105) (105) (105) (105) (105) (53) (53) (53)
New Resource—Battery: 8 hour 97 97 97 97 97 97 97 97 97 97 97 97
New Resource—Solar + Storage 1:1 (Solar) – – 26 26 26 51 51 51 26 26 26 –
New Resource—Solar + Storage 1:1 (Storage) 217 217 217 217 434 434 434 434 434 217 217 217
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 529 529 595 880 1,510 1,404 1,404 1,396 1,327 595 595 529
239 671 1,160 1,857 1,680 370 (2) 18 784 860 457 307
23.2% 39.7% 61.4% 95.1% 69.9% 23.7% 15.5% 15.9% 37.4% 48.4% 32.6% 25.8%

Load and Resource Balance Data
2021 Integrated Resource Plan—Appendix C Page 37
1/2040 2/2040 3/2040 4/2040 5/2040 6/2040 7/2040 8/2040 9/2040 10/2040 11/2040 12/2040
Peak-Hour (50th+15.5%) w/EE (3,610) (3,232) (2,942) (2,712) (3,597) (5,306) (5,421) (5,269) (4,175) (3,043) (3,106) (3,453)
Existing Demand Response Capacity – – – – – 176 176 127 103 – – –
Peak-Hour (50th+15.5%) w/DR and EE (3,610) (3,232) (2,942) (2,712) (3,597) (5,130) (5,246) (5,142) (4,072) (3,043) (3,106) (3,453)
Existing Resources
Bridger 663 663 663 663 663 663 663 663 663 663 663 663
Valmy – – – – – – – – – – – –
Total Coal 663 663 663 663 663 663 663 663 663 663 663 663
Langley Gulch 323 318 315 315 312 306 306 306 309 312 318 323
Total Gas Peakers 429 426 410 400 396 370 365 367 397 415 424 437
Total Gas 752 743 725 715 708 675 671 672 706 727 741 761
Hydro (50%) HCC 1,012 1,012 1,060 1,060 1,157 1,157 1,060 1,012 916 868 675 964
Hydro (50%)—Other 342 351 271 422 451 425 292 251 241 215 197 333
Total Hydroelectric (50%) 1,354 1,363 1,331 1,483 1,607 1,582 1,352 1,263 1,157 1,083 872 1,297
Solar CSPP (PURPA) – – 99 99 99 199 199 199 99 99 99 –
Wind CSPP Capacity 24 24 24 24 24 23 23 23 24 24 24 24
Other CSPP 31 39 47 83 122 134 130 122 104 67 35 32
Total CSPP 54 63 170 206 245 356 352 344 226 190 158 55
Elkhorn – – – – – – – – – – – –
Raft River Geothermal – – – – – – – – – – – –
Neal Hot Springs Geothermal – – – – – – – – – – – –
Jackpot Solar – – 20 20 20 40 40 40 20 20 20 –
Clatskanie Exchange – – – – – – – – – – – –
Total PPAs 0 0 20 20 20 40 40 40 20 20 20 0
Available Transmission w/3rd Party Secured 129 184 247 256 161 380 370 380 380 274 165 98
Emergency Transmission (CBM) 330 330 330 330 330 330 330 330 330 330 330 330
Existing Resource Subtotal 3,282 3,346 3,486 3,673 3,735 4,026 3,780 3,693 3,482 3,287 2,949 3,204
(328) 114 545 961 138 (1,104) (1,466) (1,449) (590) 244 (157) (249)
2021 IRP Resources
New Transmission—B2H 400 400 400 685 700 500 500 500 500 400 400 400
New Resource—EE 5 5 5 5 5 5 5 5 5 5 5 5
New Resource—DR – – – – – 36 36 26 21 – – –
New Resource—Battery: 4 hour 475 475 475 475 949 949 949 949 949 475 475 475
New Resource—Battery: 4 hour - Removals (55) (55) (55) (55) (109) (109) (109) (109) (109) (55) (55) (55)
New Resource—Battery: 8 hour 97 97 97 97 97 97 97 97 97 97 97 97
New Resource—Solar + Storage 1:1 (Solar) – – 26 26 26 51 51 51 26 26 26 –
New Resource—Solar + Storage 1:1 (Storage) 217 217 217 217 434 434 434 434 434 217 217 217
New Resource—Solar – – 40 40 40 80 80 80 40 40 40 –
New Resource—WY Wind 45 45 45 45 45 45 45 45 45 45 45 45
New Resource—ID Wind 33 33 33 33 33 33 33 33 33 33 33 33
New Resource—Gas Conversion (exit 2034) – – – – – – – – – – – –
Early Bridger Coal Exits (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663) (663)
New Resource Subtotal 554 554 620 905 1,557 1,458 1,458 1,449 1,378 620 620 554
227 669 1,164 1,866 1,695 355 (8) (0) 789 864 463 305
22.8% 39.4% 61.2% 95.0% 69.9% 23.2% 15.3% 15.5% 37.3% 48.3% 32.7% 25.7%

Demand-Side Resource Data
Page 38 2021 Integrated Resource Plan—Appendix C
DEMAND-SIDE RESOURCE DATA
DSM Financial Assumptions
Avoided Levelized Capacity Costs
Simple Cycle Combustion Turbine (SCCT) $131.60/kW-year*
Financial Assumptions
Discount rate (weighted average cost of capital) 7.12%
Financial escalation factor 2.30%
Transmission Losses
Non-summer secondary losses 9.60%
Summer peak loss 9.70%
*The selection of an SCCT matches the company's filings for approval to modify its demand response programs (IPUC Case No. IPC-E-21-32 and
OPUC Tariff Advice No. 21-12). An SCCT is also the resource selected to fulfill unmet LOLE reliability requirements in the 2021 IRP.
Avoided Cost Averages ($/MWh except where noted)
Year
Summer
On-Peak
Summer
Mid-Peak
Summer
Off-Peak
Non-Summer
Mid-Peak
Non-Summer
Off-Peak
Annual T&D
On-Peak EE Deferral
Value ($/kW-year)
2021 $32.43 $26.86 $23.33 $26.96 $23.92 $6.33
2022 $32.83 $26.70 $23.62 $26.41 $23.64 $6.42
2023 $47.75 $40.76 $35.04 $36.78 $33.10 $6.42
2024 $49.14 $41.34 $36.00 $36.46 $33.57 $6.77
2025 $49.63 $41.03 $36.28 $34.61 $32.32 $6.35
2026 $50.40 $40.01 $34.38 $35.11 $32.97 $6.39
2027 $50.75 $35.14 $31.16 $30.71 $31.06 $6.35
2028 $54.17 $36.81 $32.71 $31.79 $33.55 $6.53
2029 $53.51 $36.42 $33.44 $33.05 $35.85 $6.64
2030 $51.51 $30.48 $30.30 $30.44 $36.23 $6.44
2031 $54.93 $31.80 $32.57 $31.69 $37.22 $6.35
2032 $55.88 $32.56 $33.72 $33.05 $39.16 $6.33
2033 $55.06 $29.37 $33.17 $31.75 $40.52 $6.52
2034 $57.35 $31.20 $34.77 $32.64 $41.68 $6.29
2035 $57.24 $31.79 $35.03 $34.11 $43.54 $3.89
2036 $58.88 $32.54 $36.79 $36.38 $44.18 $2.53
2037 $56.64 $29.74 $35.62 $30.80 $39.90 $2.54
2038 $58.93 $32.09 $38.00 $32.12 $42.51 $1.53
2039 $61.82 $34.40 $40.23 $32.53 $42.10 $1.65
2040 $62.84 $35.36 $41.54 $32.02 $42.16 $1.72
*Energy efficiency will also receive a capacity value in all Summer On-Peak hours when the company is capacity deficient,
and the measure contributes energy savings during those hours.

Demand-Side Resource Data
2021 Integrated Resource Plan—Appendix C Page 39
DSM alternate cost summer pricing periods (June 1–August 31)
Hour End Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
1 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
2 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
3 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
4 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
5 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
6 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
7 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
8 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
9 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
10 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
11 SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
12 SMP SMP SMP SMP SMP SMP SMP SOFP
13 SMP SMP SMP SMP SMP SMP SMP SOFP
14 SMP SMP SMP SMP SMP SMP SMP SOFP
15 SMP SMP SMP SMP SMP SMP SMP SOFP
16 SMP SONP SONP SONP SONP SONP SMP SOFP
17 SMP SONP SONP SONP SONP SONP SMP SOFP
18 SMP SONP SONP SONP SONP SONP SMP SOFP
19 SMP SONP SONP SONP SONP SONP SMP SOFP
20 SMP SONP SONP SONP SONP SONP SMP SOFP
21 SMP SONP SONP SONP SONP SONP SMP SOFP
22 SMP SONP SONP SONP SONP SONP SMP SOFP
23 SMP SONP SONP SONP SONP SONP SMP SOFP
24 SMP SMP SMP SMP SMP SMP SMP SOFP
SOFP—Summer Off-Peak
SMP—Summer Mid-Peak
SONP—Summer On-Peak

Demand-Side Resource Data
Page 40 2021 Integrated Resource Plan—Appendix C
DSM alternate cost non-summer pricing periods (September 1–May 31)
Hour End Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
1 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
2 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
3 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
4 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
5 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
6 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
7 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
8 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
9 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
10 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
11 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
12 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
13 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
14 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
15 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
16 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
17 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
18 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
19 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
20 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
21 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
22 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
23 NSOFP NSMP NSMP NSMP NSMP NSMP NSMP NSOFP
24 NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP NSOFP
NSOFP—Non-Summer Off-Peak
NSMP—Non-Summer Mid-Peak

Demand-Side Resource Data
2021 Integrated Resource Plan—Appendix C Page 41
Bundle Amounts
Incremental Achievable Potential (aMW)
Bundle 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Summer Low 3 3 3 3 4 4 4 5 4 4
Summer High 5 8 12 16 20 23 24 26 27 28
Winter Low 6 8 11 15 18 21 21 21 21 19
Winter High 3 3 4 4 5 6 6 7 7 7
Total 17 21 30 38 47 53 56 58 59 59

Bundle 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Summer Low 4 4 4 4 3 3 3 3 3 3
Summer High 28 28 28 28 27 25 22 22 20 18
Winter Low 17 14 11 10 8 8 6 6 6 6
Winter High 8 7 7 7 7 6 6 6 6 5
Total 57 54 50 48 45 42 37 37 35 32

Bundle Costs
Savings Weighted Levelized Cost of Energy ($/MWh) Real Dollars
Bundle 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Summer Low $80 $90 $97 $99 $101 $104 $107 $108 $109 $108
Summer High $1,699 $1,305 $1,040 $861 $789 $721 $654 $606 $570 $544
Winter Low $70 $70 $69 $69 $69 $69 $68 $67 $66 $66
Winter High $249 $331 $349 $359 $368 $368 $360 $352 $346 $320
Total $552 $523 $465 $416 $386 $359 $330 $308 $297 $287

Bundle 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
Summer Low $107 $105 $105 $104 $104 $104 $105 $105 $105 $105
Summer High $527 $515 $506 $497 $494 $476 $461 $458 $460 $463
Winter Low $66 $66 $65 $65 $65 $64 $60 $60 $59 $60
Winter High $321 $324 $328 $321 $313 $302 $290 $305 $293 $285
Total $291 $299 $306 $308 $309 $298 $288 $294 $284 $276

Supply-Side Resource Data
Page 42 2021 Integrated Resource Plan—Appendix C
SUPPLY-SIDE RESOURCE DATA
Key Financial and Forecast Assumptions
Financing Cap Structure and Cost
Composition
Debt 50.10%
Preferred 0.00%
Common 49.90%
Total 100.00%
Cost
Debt 5.73%
Preferred 0.00%
Common 10.00%
Average Weighted Cost 7.86%

Financial Assumptions and Factors
Plant operating (book) life Expected Life of the Asset
Discount rate (weighted average cost of capital1) 7.12%
Composite tax rate 25.74%
Deferred rate 21.30%
General O&M escalation rate 2.30%
Annual property tax rate (% of investment) 0.47%
B2H annual property tax rate (% of investment) 0.64%
Property tax escalation rate 3.00%
B2H property tax escalation rate 0.68%
Annual insurance premiums (% of investment) 0.049%
B2H annual insurance premiums (% of investment) 0.004%
Insurance escalation rate 3.00%
B2H insurance escalation rate 3.00%
AFUDC rate (annual) 7.45%
1 Incorporates tax effects.

Supply-Side Resource Data
2021 Integrated Resource Plan—Appendix C Page 43
Cost Inputs and Operating Assumptions (Costs in 2021$)

1 /I

2

3
-Side Resources (MW) ($/kW) ($/kW) ($/kW) ($/kW-mth) ($/MWh) (Btu/kWh) (years)
Aeroderivative (45 MW) 45 $1,500 $166 $1,666 $1.42 $4.92 8,533 40
Biomass (35 MW)35 $4,176 $128 $4,304 $3.54 $4.71 0 30
Boardman to Hemingway (500 MW Summer/200 MW Winter) $0 $647 $647 $0.03 $0.00 0 55
CCCT (1x1) F Class (300 MW) 300 $1,656 $25 $1,681 $1.49 $1.11 6,708 30
Danskin 1 Retrofit (90 MW) 90 $2,350 $41 $2,391 $1.49 $1.11 6,909 30
Geothermal (30 MW) 30 $4,500 $149 $4,649 $11.99 $0.00 0 30
Reciprocating Gas Engine (55.5 MW) 56 $1,560 $67 $1,627 $3.07 $5.95 8,300 40
SCCT—Frame F Class (170 MW) 170 $900 $22 $922 $1.02 $4.82 9,720 35
Small Modular Nuclear (77 MW) 77 $4,250 $144 $4,394 $10.62 $2.48 11,500 60
Solar PV—Utility Scale 1-Axis Tracking (100 MW) 100 $1,000 $50 $1050 $0.81 $0.00 0 30
Solar PV—Utility Scale 1-Axis Tracking (100 MW) w/ 4-hr Battery (100 MW) 100 $2,150 $50 $2,200 $3.30 $0.00 0 303
Storage—4-Hour Li Battery (50 MW) 50 $1,150 $77 $1,227 $2.49 $0.00 0 15
Storage—4-Hour Li Battery for Grid Benefits (5 MW) 5 $863 $77 $940 $2.49 $0.00 0 15
Storage—8-Hour Li Battery (50 MW) 50 $2,100 $77 $2,177 $2.49 $0.00 0 15
Storage—Compressed Air Energy Storage (150 MW) 150 $2,200 $77 $2,277 $1.08 $6.65 0 50
Storage—Pumped-Hydro (250 MW) 250 $2,100 $227 $2,327 $0.38 $0.00 0 75
SWIP North (100 MW Summer/200 MW Winter) $0 $798 $798 $0.04 $0.00 0 55
Wind ID (100 MW) 100 $1,300 $50 $1,350 $2.11 $0.00 0 25
Wind WY (100 MW)100 $1,300 $50 $1,350 $2.11 $0.00 0 25
2 Fixed O&M excludes property taxes and insurance (separately calculated within the levelized resource cost analysis)
3

Supply-Side Resource Data
Page 44 2021 Integrated Resource Plan—Appendix C
Supply-Side Resource Escalation Factors1 (2022–2030)
Aeroderivative (45 MW) 1.81% 1.12% 0.46% 1.06% 1.55% 1.48% 1.76% 1.93% 1.79%
Biomass (35 MW)2.17% 2.17% 2.17% 1.93% 2.12% 2.06% 2.10% 2.08% 1.98%
CCCT (1x1) F Class (300 MW) 1.21% 1.20% 0.89% 1.28% 1.69% 1.63% 1.85% 1.97% 1.83%
Danskin 1 Retrofit (90 MW) 1.21% 1.20% 0.89% 1.28% 1.69% 1.63% 1.85% 1.97% 1.83%
Geothermal (30 MW) 0.14% 0.09% 0.04% -0.01% -0.06% -0.12% -0.17% -0.24% -0.29%
Reciprocating Gas Engine (55.5 MW) 1.81% 1.12% 0.46% 1.06% 1.55% 1.48% 1.76% 1.93% 1.79%
SCCT—Frame F Class (170 MW) 1.81% 1.12% 0.46% 1.06% 1.55% 1.48% 1.76% 1.93% 1.79%
Small Modular Nuclear (77 MW) -2.15% -2.15% -2.15% -2.15% -2.15% -2.15% -2.15% -2.15% -2.15%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) -1.76% -1.93% -2.11% -2.31% -2.53% -2.77% -3.04% -3.33% -3.66%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) w/ 4-hr Battery (100 MW) -3.60% -4.01% -4.47% -5.02% -2.90% -3.18% -3.49% -3.84% -4.23%
Storage—4-Hour Li Battery (50 MW) -5.45% -6.08% -6.83% -7.72% -3.26% -3.58% -3.94% -4.35% -4.81%
Storage—4-Hour Li Battery for Grid Benefits (5 MW) -5.45% -6.08% -6.83% -7.72% -3.26% -3.58% -3.94% -4.35% -4.81%
Storage—8-Hour Li Battery (50 MW) -5.45% -6.08% -6.83% -7.72% -3.26% -3.58% -3.94% -4.35% -4.81%
Storage—Compressed Air Energy Storage (150 MW) 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30%
Storage—Pumped-Hydro (250 MW) 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30%
Wind ID (100 MW) 0.22% 0.14% 0.06% -0.03% -0.12% -0.21% -0.32% -0.43% -0.54%
Wind WY (100 MW)0.38% 0.27% 0.15% 0.02% -0.11% -0.25% -0.40% -0.56% -0.73%
1 Factors include the 2021 IRP general O&M escalation rate assumption of 2.3%.

Supply-Side Resource Data
2021 Integrated Resource Plan—Appendix C Page 45
Supply-Side Resource Escalation Factors1 (2031–2040)
Aeroderivative (45 MW) 1.86% 1.83% 1.76% 1.91% 2.02% 1.91% 2.06% 2.02% 1.94% 1.92%
Biomass (35 MW)2.01% 1.98% 1.96% 2.06% 2.03% 1.90% 2.04% 2.00% 1.93% 1.91%
CCCT (1x1) F Class (300 MW) 1.89% 1.86% 1.80% 1.94% 2.01% 1.90% 2.05% 2.01% 1.93% 1.91%
Danskin 1 Retrofit (90 MW) 1.89% 1.86% 1.80% 1.94% 2.01% 1.90% 2.05% 2.01% 1.93% 1.91%
Geothermal (30 MW) 1.79% 1.79% 1.79% 1.79% 1.79% 1.79% 1.79% 1.79% 1.79% 1.79%
Reciprocating Gas Engine (55.5 MW) 1.86% 1.83% 1.76% 1.91% 2.02% 1.91% 2.06% 2.02% 1.94% 1.92%
SCCT—Frame F Class (170 MW) 1.86% 1.83% 1.76% 1.91% 2.02% 1.91% 2.06% 2.02% 1.94% 1.92%
Small Modular Nuclear (77 MW) 1.62% 1.58% 1.56% 1.67% 1.63% 1.49% 1.63% 1.59% 1.50% 1.48%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) 1.39% 1.38% 1.37% 1.37% 1.36% 1.35% 1.34% 1.33% 1.32% 1.31%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) w/ 4-hr Battery (100 MW) 0.84% 0.82% 0.80% 0.77% 0.74% 0.72% 0.69% 0.66% 0.62% 0.59%
Storage—4-Hour Li Battery (50 MW) 0.30% 0.26% 0.22% 0.17% 0.13% 0.08% 0.03% -0.02% -0.07% -0.13%
Storage—4-Hour Li Battery for Grid Benefits (5 MW) 0.30% 0.26% 0.22% 0.17% 0.13% 0.08% 0.03% -0.02% -0.07% -0.13%
Storage—8-Hour Li Battery (50 MW) 0.30% 0.26% 0.22% 0.17% 0.13% 0.08% 0.03% -0.02% -0.07% -0.13%
Storage—Compressed Air Energy Storage (150 MW) 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30%
Storage—Pumped-Hydro (250 MW) 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30% 2.30%
Wind ID (100 MW) 1.26% 1.25% 1.24% 1.22% 1.21% 1.19% 1.18% 1.16% 1.15% 1.13%
Wind WY (100 MW)1.51% 1.50% 1.49% 1.48% 1.47% 1.45% 1.44% 1.43% 1.41% 1.40%
1

Supply-Side Resource Data
Page 46 2021 Integrated Resource Plan—Appendix C
Levelized Cost of Energy (costs in 2021$, $/MWh) at stated capacity factors
Supply-Side Resources
Cost of
Capital1
Non-Fuel
O&M2 Fuel3
Total Cost per
MWh4,5
Capacity
Factor6
Aeroderivative (45 MW) $145 $42 $36 $223 12%
Biomass (35 MW) $91 $23 $0 $114 61%
Boardman to Hemingway (500 MW Summer/200 MW Winter) $19 $4 $0 $23 33%
CCCT (1x1) F Class (300 MW) $38 $9 $26 $73 55%
Danskin 1 Retrofit (90 MW) $52 $10 $27 $89 55%
Geothermal (30 MW) $59 $28 $0 $87 95%
Reciprocating Gas Engine (55.5 MW) $147 $69 $35 $251 12%
SCCT—Frame F Class (170 MW) $91 $29 $40 $160 12%
Small Modular Nuclear (77 MW) $62 $32 $9 $103 93%
Solar PV—Utility Scale 1-Axis Tracking (100 MW), 26% ITC $27 $8 $0 $35 29%
Solar PV—Utility Scale 1-Axis Tracking (100 MW), 10% ITC $33 $8 $0 $41 29%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) + 4-hr Battery (100 MW), 26% ITC $65 $23 $0 $88 30%
Solar PV—Utility Scale 1-Axis Tracking (100 MW) + 4-hr Battery (100 MW), 10% ITC $80 $23 $0 $103 30%
Storage—4-Hour Li Battery (50 MW) $100 $30 $0 $130 17%
Storage—4-Hour Li Battery for Locational Grid Benefits (5 MW) $77 $28 $0 $105 17%
Storage—8-Hour Li Battery (50 MW) $90 $17 $0 $107 33%
Storage—Compressed Air Energy Storage (150 MW) $73 $23 $0 $96 33%
Storage—Pumped-Hydro (250 MW) $82 $10 $0 $92 33%
SWIP North (100 MW Summer/200 MW Winter) $18 $2 $0 $20 33%
Wind ID (100 MW), PTC $29 $14 $0 $43 35%
Wind ID (100 MW) $42 $14 $0 $56 35%
Wind WY (100 MW), PTC $21 $10 $0 $31 48%
Wind WY (100 MW) $31 $10 $0 $41 48%
1 Cost of Capital includes tax credit benefits (ITC/PTC).
2 Non-Fuel O&M includes fixed and variable costs and property taxes.
3 Fuel costs are not included for biomass resource.
4 Storage resources will have a cost or benefit associated with the price difference between the energy price to charge the storage and the energy price during the time of discharge (less losses). Arbitrage is not included in the LCOE calculation in the table. As noted in IRP, levelized cost for storage resources is driven by fixed costs.
5 Transmission resource costs do not include potential benefits of additional short-term and non-firm third-party wheeling usage. The LCOE does not include a price for market purchases, therefore, the LCOE in this table can be viewed as a cost above the market purchase price for the energy assuming the associated capacity factor.
6 Capacity factor for 4-hour storage resources assume one discharge cycle per day; 8-hour storage resources and above assume eight hours of discharge per day.
Supply-Side Resource Data
2021 Integrated Resource Plan—Appendix C Page 47
Levelized Capacity (fixed) Cost per kW/Month (costs in 2021$)
Supply-Side Resources Cost of Capital1 Non-Fuel O&M2 Total Cost per kW
Aeroderivative (45 MW)$13 $3 $16
Biomass (35 MW) $40 $8 $48
Boardman to Hemingway (500 MW Summer/200 MW Winter) $5 $1 $6
CCCT (1x1) F Class (300 MW) $15 $3 $18
Danskin 1 Retrofit (90 MW) $21 $3 $24
Geothermal (30 MW) $41 $19 $60
Reciprocating Gas Engine (55.5 MW) $13 $5 $18
SCCT—Frame F Class (170 MW) $8 $2 $10
Small Modular Nuclear (77 MW) $40 $19 $59
Solar PV—Utility Scale 1-Axis Tracking (100 MW), 26% ITC $5 $2 $7
Solar PV—Utility Scale 1-Axis Tracking (100 MW), 10% ITC $7 $2 $9
Solar PV—Utility Scale 1-Axis Tracking (100 MW) + 4-hr Battery (100 MW), 26% ITC $14 $5 $19
Solar PV—Utility Scale 1-Axis Tracking (100 MW) + 4-hr Battery (100 MW), 10% ITC $18 $5 $23
Storage—4-Hour Li Battery (50 MW) $12 $4 $16
Storage—4-Hour Li Battery for Locational Grid Benefits (5 MW) $9 $4 $13
Storage—8-Hour Li Battery (50 MW) $22 $4 $26
Storage—Compressed Air Energy Storage (150 MW) $18 $3 $21
Storage—Pumped-Hydro (250 MW) $20 $2 $22
SWIP North (100 MW Summer/200 MW Winter) $4 $1 $5
Wind ID (100 MW), PTC $8 $4 $12
Wind ID (100 MW) $10 $4 $14
Wind WY (100 MW), PTC $7 $4 $11
Wind WY (100 MW) $10 $4 $14
1 Cost of Capital includes tax credit benefits (ITC/PTC).
2 Non-Fuel O&M includes fixed and variable costs, property taxes.

Supply-Side Resource Data
Page 48 2021 Integrated Resource Plan—Appendix C
Renewable Energy Certificate Forecast

Year Nominal ($/MWh)
2021 7.94
2022 7.82
2023 7.70
2024 7.54
2025 7.37
2026 7.42
2027 7.58
2028 7.58
2029 7.64
2030 7.82
2031 7.85
2032 7.96
2033 8.14
2034 8.20
2035 8.21
2036 8.45
2037 8.46
2038 8.57
2039 8.76
2040 8.87
Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 49
EXISTING RESOURCE DATA
Qualifying Facility Data (PURPA)
Cogeneration & Small Power Production Projects
Status as of December 31, 2020
Hydro Projects
Contract Contract
Project MW On-line Date End Date Project MW -line Date End Date
Arena Drop 0.45 Sep-2010 Sep-2030 Littlewood/Arkoosh 0.87 Aug-1986 Aug-2021
Baker City Hydro 0.24 Sep-2015 Sep-2030 Low Line Canal 8.20 May-2020 May-2040
Barber Dam 3.70 Apr-1989 Apr-2024 Low Line Midway Hydro 2.50 Aug-2007 Aug-2027
Birch Creek 0.07 Nov-1984 Nov-2039 Lowline #2 2.79 Apr-1988 Apr-2023
Black Canyon #3 0.13 Apr-2019 Apr-2039 Magic Reservoir 9.07 Jun-1989 Jun-2024
Black Canyon Bliss Hydro 0.03 Nov-2014 Oct-2035 Malad River 1.17 May-2019 May-2039
Blind Canyon 1.63 Dec-2014 Dec-2034 Marco Ranches 1.20 Aug-2020 Aug-2040
Box Canyon 0.30 Feb-2019 Feb-2039 MC6 Hydro 2.10 Apr-2021 Estimated
Briggs Creek 0.60 Oct-2020 Oct-2040 Mile 28 1.50 Jun-1994 Jun-2029
Bypass 9.96 Jun-1988 Jun-2023 Mitchell Butte 2.09 May-1989 Dec-2033
Canyon Springs 0.11 Jan-2019 Jan-2039 Mora Drop Small Hydro 1.85 Sep-2006 Sep-2026
Cedar Draw 1.55 Jun-1984 Jun-2039 Mud Creek/S&S 0.52 Feb-2017 Feb-2037
Clear Springs Trout 0.56 Nov-2018 Nov-2038 Mud Creek/White 0.21 Jan-1986 Jan-2021
Coleman Hydro 0.80 Jun-2021 Estimated North Gooding Main 1.30 Oct-2016 Oct-2036
Crystal Springs 2.44 Apr-1986 Apr-2021 Owyhee Dam CSPP 5.00 Aug-1985 May-2033
Curry Cattle Company 0.25 Jun-2018 Jun-2033 Pigeon Cove 1.75 Oct-1984 Nov-2039
Dietrich Drop 4.50 Aug-1988 Aug-2023 Pristine Springs #1 0.13 May-2020 May-2040
Eightmile Hydro Project 0.36 Oct-2014 Oct-2034 Pristine Springs #3 0.20 May-2020 May-2040
Elk Creek 2.00 May-1986 May-2021 Reynolds Irrigation 0.26 May-1986 May-2021
Fall River 9.10 Aug-1993 Aug-2028 Rock Creek #1 2.17 Jan-2018 Jan-2038
Fargo Drop Hydroelectric 1.27 Apr-2013 Apr-2033 Rock Creek #2 1.90 Apr-1989 Apr-2024
Faulkner Ranch 0.87 Aug-1987 Aug-2022 Sagebrush 0.58 Jun-2021 Jun-2040
Fisheries Dev. 0.26 Jul-1990 Jul-2040 Sahko Hydro 0.50 Feb-2011 Feb-2021
Geo-Bon #2 0.93 Nov-1986 Nov-2021 Schaffner 0.53 Aug-1986 Aug-2021
Hailey CSPP 0.04 Jun-2020 Jun-2025 Shingle Creek 0.22 Aug-2017 Aug-2022
Hazelton A 8.10 Mar-2011 Mar-2026 Shoshone #2 0.58 May-1996 May-2031
Hazelton B 7.60 May-1993 May-2028 Shoshone CSPP 0.36 Feb-2017 Feb-2037
Head of U Canal Project 1.28 May-2015 Jun-2035 Snake River Pottery 0.09 Nov-1984 Dec-2027
Horseshoe Bend Hydro 9.50 Sep-1995 Sep-2030 Snedigar 0.50 Jan-2020 Jan-2040
Jim Knight 0.48 Jun-2021 Estimated Tiber Dam 7.50 Jun-2004 Jun-2024
Koyle Small Hydro 1.25 Apr-2019 Apr-2039 Trout-Co 0.24 Dec-1986 Dec-2021
Lateral # 10 2.06 May-2020 May-2040 Tunnel #1 7.00 Jun-1993 Feb-2035
Lemoyne 0.08 Jun-2020 Jun-2030 White Water Ranch 0.16 Aug2020 Aug-2040
Little Wood River Ranch II 1.25 Jun-2015 Oct-2035 Wilson Lake Hydro 8.40 May-1993 May-2028
Little Wood River Res 2.85 Mar-2020 Mar-2040
Total Hydro Nameplate Rating 150.94 MW

Existing Resource Data
Page 50 2021 Integrated Resource Plan—Appendix C
Cogeneration/Thermal Projects
Contract
Project MW On-line Date End Date
Pico Energy, LLC 2.13 Aug-2020 Aug-2030
Simplot Pocatello Cogen 15.90 Mar-2019 Mar-2022
TASCO—Nampa Natural Gas 2 Sep-2003 Sept-2040
TASCO—Twin Falls Natural Gas 3 Aug-2001 Jan-2040
Total Thermal Nameplate Rating 23.03 MW

Biomass Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
Bannock County Landfill 3.20 May-2014 May-2034 Pocatello Waste 0.46 Dec-1985 Dec-2020
Fighting Creek Landfill 3.06 Apr-2014 Apr-2029 SISW LFGE 5.00 Sept-2018 Sept-2038
Hidden Hollow Landfill Gas 3.20 Jan-2007 Jan-2027 Tamarack CSPP 6.25 Jun-2018 Jun-2038
Total Biomass Nameplate Rating 21.17 MW

Solar Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
American Falls Solar II, LLC 20.00 Mar-2017 Mar-2037 Mt. Home Solar 1, LLC 20.00 Mar-2017 Mar-2037
American Falls Solar, LLC 20.00 Mar-2017 Mar-2037 Murphy Flat Power, LLC 20.00 Mar-2017 Mar-2037
Baker Solar Center 15.00 Feb-2020 Feb-2040 Ontario Solar Center 3.00 Mar-2020 Mar-2040
Brush Solar 2.75 Oct-2019 Dec-2039 Open Range Solar Center, LLC 10.00 Mar-2017 Mar-2037
Durkee Solar 3.00 Mar-2022 Estimated Orchard Ranch Solar, LLC 20.00 Oct-2016 Oct-2036
Grand View PV Solar Two 80.00 Dec-2016 Dec-2036 Railroad Solar Center, LLC 4.50 Dec-2016 Dec-2036
Grove Solar Center, LLC 6.00 Oct-2016 Oct-2036 Simcoe Solar, LLC 20.00 Mar-2017 Mar-2037
Hyline Solar Center, LLC 9.00 Nov-2016 Nov-2036 Thunderegg Solar Center, LLC 10.00 Nov-2016 Nov-2036
ID Solar 1 40.00 Aug-2016 Jan-2036 Vale Air Solar Center, LLC 10.00 Nov-2016 Nov-2036
Morgan Solar 3.00 Apr-2020 Apr-2040 Vale 1 Solar 3.00 Jul-2020 Jul-2040
Total Solar Nameplate Rating 319.25 MW

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 51
Wind Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
Bennett Creek Wind Farm 21.00 Dec-2008 Dec-2028 Mainline Windfarm 23.00 Dec-2012 Dec-2032
Benson Creek Windfarm 10.00 Mar-2017 Mar-2037 Milner Dam Wind 19.92 Feb-2011 Feb-2031
Burley Butte Wind Park 21.30 Feb-2011 Feb-2031 Oregon Trail Wind Park 13.50 Jan-2011 Jan-2031
Camp Reed Wind Park 22.50 Dec-2010 Dec-2030 Payne's Ferry Wind Park 21.00 Dec-2010 Dec-2030
Cassia Wind Farm LLC 10.50 Mar-2009 Mar-2029 Pilgrim Stage Station Wind Park 10.50 Jan-2011 Jan-2031
Cold Springs Windfarm 23.00 Dec-2012 Dec-2032 Prospector Windfarm 10.00 Mar-2017 Mar-2037
Desert Meadow Windfarm 23.00 Dec-2012 Dec-2032 Rockland Wind Farm 80.00 Dec-2011 Dec-2036
Durbin Creek Windfarm 10.00 Mar-2017 Mar-2037 Ryegrass Windfarm 23.00 Dec-2012 Dec-2032
Fossil Gulch Wind 10.50 Sep-2005 Sep-2025 Salmon Falls Wind 22.00 Apr-2011 Apr-2031
Golden Valley Wind Park 12.00 Feb-2011 Feb-2031 Sawtooth Wind Project 22.00 Nov-2011 Nov-2031
Hammett Hill Windfarm 23.00 Dec-2012 Dec-2032 Thousand Springs Wind Park 12.00 Jan-2011 Jan-2031
High Mesa Wind Project 40.00 Dec-2012 Dec-2032 Tuana Gulch Wind Park 10.50 Jan-2011 Jan-2031
Horseshoe Bend Wind 9.00 Feb-2006 Feb-2026 Tuana Springs Expansion 35.70 May-2010 May-2030
Hot Springs Wind Farm 21.00 Dec-2008 Dec-2028 Two Ponds Windfarm 23.00 Dec-2012 Dec-2032
Jett Creek Windfarm 10.00 Mar-2017 Mar-2037 Willow Spring Windfarm 10.00 Mar-2017 Mar-2037
Lime Wind Energy 3.00 Dec-2011 Dec-2031 Yahoo Creek Wind Park 21.00 Dec-2010 Dec-2030
Total Wind Nameplate Rating 626.92 MW
Total Nameplate Rating 1,141.31 MW
The above is a summary of the Nameplate rating for the CSPP projects under contract with Idaho Power as of December 31, 2020. In the case of CSPP projects, Nameplate rating of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects will deliver to Idaho Power. Historical generation information, resource specific industry standard capacity factors, and other known and measurable operating characteristics are accounted for in determining a reasonable
estimate of the energy these projects will produce.

Power Purchase Agreement Data
Project MW On-Line Date Contract End Date
Wind Projects
Elkhorn Wind Project 101 Dec-2007 Dec-2027
Total Wind Nameplate Rating 101
Geothermal Projects
Raft River Unit 1 13 Apr-2008 Apr-2033
Neal Hot Springs 22 Nov-2012 Nov-2037
Total Geothermal Nameplate Rating 35
Solar Projects
Jackpot Solar Facility 120 Dec-2022 Dec-2042
Total Solar Nameplate Rating 120
Total Nameplate Rating 256
The above is a summary of the Nameplate rating for the CSPP projects under contract with Idaho Power as of December 31, 2020. In the case of
CSPP projects, Nameplate rating of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects will
deliver to Idaho Power. Historical generation information, resource specific industry standard capacity factors, and other known and
measurable operating characteristics are accounted for in determining a reasonable estimate of the energy these projects will produce.
Existing Resource Data
Page 52 2021 Integrated Resource Plan—Appendix C
Hydro Flow Modeling
Hydro Models
Idaho Power uses two modeling methods (planning models) for the development of future
hydro flow scenarios for the IRP. The first method accounts for surface water regulation in the
system, this consists of two models built in the CADSWES RiverWare modeling framework. The
first of these models covers the spatial extent of the Snake River basin from the headwaters to
Brownlee inflow. The second model takes the results of the first and regulates the flows
through the Hells Canyon Complex (HCC). The second modeling method uses the Enhanced
Snake Plain Aquifer Model (ESPAM) to model aquifer management practices implemented on
the Eastern Snake Plain Aquifer (ESPA). The planning models have been updated to include
hydrologic conditions for water years 1951 through 2018. ESPAM was updated with the release
of ESPAM 2.1 in late 2012.
Hydro Model Inputs
The inputs for the 2021 IRP were derived, in part, from management practices outlined in an
agreement between the Surface Water Coalition (SWC) and Idaho Groundwater Appropriators
(IGWA). The agreement set out specific targets for several management practices that include
aquifer recharge, system conversions, and a total reduction in ground water diversions of
240,000 acre-feet. The modeling also included inputs from other entities diverting ground
water on the ESPA who have separate mitigation agreements with the SWC. Model inputs also
included a long-term analysis of trends in reach gains to the Snake River from Palisades Dam to
King Hill. Weather modification activities conducted by Idaho Power and other participating
entities were included in the modeling effort. The modeling also included aquifer recharge
efforts by the Idaho Water Resource Board who is targeting an average annual natural flow
recharge of 250,000 acre-ft per year.
Recharge capacity modeled for the 2021 IRP included diversions with the capability of diverting
all available water at the Snake River below Milner Dam during the winter months under typical
release conditions. These diversions can have a significant impact to flows downstream of
Milner Dam. Total recharge diversions, including private and state sponsored programs, are
modeled at approximately 407,000 acre-ft per year of the IRP. In IRP year 2025, approximately
195,000 acre-feet (acre-ft) of recharge diversions occur above American Falls Reservoir and
212,000 acre-ft is diverted at Milner Dam. The 2021 IRP included approximately
55,000 acre-feet of additional annual recharge not included in the 2019 IRP. This increase in
projected recharge activity is based upon recharge activity observed from spring 2016 through
spring 2020. The additional annual recharge volume can be attributed to the development of
private aquifer recharge and state sponsored storage water recharge demonstrating a higher
level of recharge capacity than anticipated in the 2019 IRP.
Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 53
System conversion projects involve the conversion of ground water supplied irrigated land to
surface water supplied irrigated land. The number of acres modeled and potential water
savings was based on data provided by the Idaho Department of Water Resources (IDWR) and
local ground water districts. The current model assumes approximately 57,000 acres of
converted land on the ESPA. Water savings for conversion projects are calculated at a rate of
2.0 acre-ft/converted acre. Diversions for conversion projects are modeled at approximately
114,000 acre-ft and are held essentially constant through all years of the IRP. The model
accounted for approximately 140,000 acre-ft decrease in ground water pumping from the ESPA.
The decrease was spread evenly over ground water irrigated lands subject to the agreement
between the SWC and the IGWA. The SWC agreement requires a total reduction of
240,000 acre-ft per year (acre-ft/year), but the agreement allows for a portion to be offset by
aquifer recharge activities. Based on recent management activity, approximately 100,000 acre-
ft/year reduction is accomplished through other forms of mitigation, such as private aquifer
recharge.
The 2021 IRP modeling also recognized ongoing declines in specific reaches. Future reach
declines were determined using several statistical analyses. Trend data indicate reach gains
from Blackfoot to Neely and from Lower Salmon Falls Dam to King Hill demonstrated a
statistically significant decline from 1990 to 2019. The long-term declines are still present, but
they have improved since the 2019 IRP. Reach gains to the Snake River increased since 2017.
The increases in reach gains may be due to recent high runoff events, good supply of irrigation
water, and aquifer recharge activities. This results in additional water in the Snake River
throughout the planning period. Weather modification was added to the model at various
levels of development. For IRP years 2021 through 2026, weather modification reflects the
current 2020 level of program development in Eastern Idaho and the Wood River, Boise, and
Payette basins. Beyond IRP year 2026, weather modification levels in Eastern Idaho and the
Wood River and Boise basins were increased due to an anticipation of expanding the cloud
seeding program. The level of weather modification was held constant at the current level in
the Payette River Basin throughout the IRP planning period. The modeling also accounts for
changes in reach gains from observed water management activities on the ESPA since 2014.
Reach gain calculations include management activities since 2014. Idaho Power used data from
IDWR and other sources to determine the magnitude of the management activities and the
ESPAM was used to model the projected reach gains. The impact of those management
activities can have impacts on reach gains for up to 30 years.
Hydro Model Results
The modeling methods implemented by Idaho Power allows for the inclusion of all future
management activities, and the resulting reach gains from those management activities into
Idaho Power’s 2021 IRP. Management activities, such as recharge and system conversions, do
Existing Resource Data
Page 54 2021 Integrated Resource Plan—Appendix C
not significantly change the total annual volume of water expected to flow through the HCC,
but instead change the timing and location of reach gains within the system. Other future
management activities, such as weather modification and a decrease in ground water pumping,
directly impact the annual volume of water expected through the HCC as well as the timing and
location of gains within the system.
Overall inflow to Brownlee Reservoir increases from IRP modeled year 2021 through 2026.
Flows peak in 2026 with the 50% exceedance water year annual inflow to Brownlee Reservoir at
just over 12.86 million acre-ft/year. In 2040, those flows declined to approximately
12.59 million acre-ft/year.
The Brownlee inflow volumes for the 2021 IRP are higher than those reported in the 2019 IRP.
There are several factors leading to the increase in modeled flows. The change in reach declines
had a significant impact on inflows to Brownlee Reservoir. For example, in model year 2038 the
increase in Brownlee inflow volume attributable to changes in reach declines between the 2021
and 2019 IRPs is approximately 380,000 acre-feet. Weather modification volume increased by
approximately 10,000 acre-ft/year in the 2021 IRP as compared to the 2019 IRP. The other
notable change is the observed recharge conducted in 2018 through 2020 exceeded recharge
volume assumptions made during the 2019 IRP. Over 1,000,000 acre-ft water were recharged
to the ESPA during 2018 through 2020. While outside the modeling period of 2021 to 2040, the
reach gains resulting from this recharge are modeled and significantly increase reach gains for
the modeling period. The modeled reach gains from this recharge increased reach gains in the
Snake River and inflows to Brownlee Reservoir particularly during the first five years of the
modeling period.

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 55
2021 Hydro Model Parameters (acre-feet/year)
Managed Recharge Reach Declines
Year
Above
American
Falls
Below
American
Falls Total
Weather
Modification
System
Conversions
Ground Water
Pumping Declines
American
Falls
Inflows
Below
Milner
Inflows
2021 194,877 212,336 407,213 1,005,582 114,236 140,047 17,807 19,724
2022 194,877 212,336 407,213 1,005,582 114,236 140,047 29,341 32,500
2023 194,877 212,336 407,213 1,005,582 114,236 140,047 40,876 45,276
2024 194,877 212,336 407,213 1,005,582 114,236 140,047 52,542 58,197
2025 194,877 212,336 407,213 1,005,582 114,236 140,047 63,944 70,827
2026 194,877 212,336 407,213 1,279,757 114,236 140,047 75,478 83,603
2027 194,877 212,336 407,213 1,279,757 114,236 140,047 87,013 96,379
2028 194,877 212,336 407,213 1,279,757 114,236 140,047 98,805 109,441
2029 194,877 212,336 407,213 1,279,757 114,236 140,047 110,081 121,931
2030 194,877 212,336 407,213 1,279,757 114,236 140,047 121,615 134,707
2031 194,877 212,336 407,213 1,279,757 114,236 140,047 133,150 147,483
2032 194,877 212,336 407,213 1,279,757 114,236 140,047 145,069 160,684
2033 194,877 212,336 407,213 1,279,757 114,236 140,047 156,218 173,034
2034 194,877 212,336 407,213 1,279,757 114,236 140,047 167,753 185,810
2035 194,877 212,336 407,213 1,279,757 114,236 140,047 179,287 198,586
2036 194,877 212,336 407,213 1,279,757 114,236 140,047 191,332 211,928
2037 194,877 212,336 407,213 1,279,757 114,236 140,047 202,355 224,138
2038 194,877 212,336 407,213 1,279,757 114,236 140,047 213,890 236,914
2039 194,877 212,336 407,213 1,279,757 114,236 140,047 225,424 249,690
2040 194,877 212,336 407,213 1,279,757 114,236 140,047 237,596 263,171

Existing Resource Data
Page 56 2021 Integrated Resource Plan—Appendix C
Hydro Modeling Results (aMW)

50th Percentile
(planning case) Climate Change Modeling
Year Month HCC* ROR** Total HCC ROR Total
2021 Jan 765 312 1,077 1198 558 1,757
Feb 960 337 1,297 1189 510 1,699
Mar 865 389 1,253 1160 562 1,722
Apr 1073 411 1,484 1198 595 1,794
May 941 365 1,306 1208 596 1,804
June 902 403 1,305 1267 524 1,792
July 621 389 1,011 899 426 1,325
Aug 512 298 810 627 414 1,041
Sept 637 250 887 750 257 1,007
Oct 423 226 650 473 240 713
Nov 340 219 559 331 237 567
Dec 514 219 733 602 358 959
Annual aMW 713 318 1,031 909 440 1,348
2022 Jan 763 311 1,074 1218 544 1,762
Feb 958 337 1,295 1187 502 1,689
Mar 863 388 1,251 1139 580 1,719
Apr 1071 410 1,481 1126 583 1,708
May 940 365 1,305 1094 582 1,676
June 901 403 1,303 1306 582 1,888
July 620 389 1,009 817 395 1,212
Aug 511 297 808 652 436 1,088
Sept 635 250 885 687 260 947
Oct 423 226 649 430 239 670
Nov 340 219 559 330 219 549
Dec 514 218 732 591 362 953
Annual aMW 712 318 1,029 881 440 1,322
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 57

50th Percentile
(planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2023 Jan 762 311 1,072 1154 545 1,699
Feb 957 336 1,293 1126 497 1,623
Mar 863 387 1,249 1113 444 1,557
Apr 1072 409 1,481 1185 462 1,647
May 940 365 1,305 923 517 1,439
June 900 402 1,302 893 422 1,315
July 620 389 1,009 615 405 1,019
Aug 511 297 808 462 281 743
Sept 634 250 884 630 241 871
Oct 422 226 648 397 234 631
Nov 340 219 559 335 221 556
Dec 513 218 732 451 194 645
Annual aMW 711 317 1,028 774 372 1,145
2024 Jan 761 310 1,071 561 282 843
Feb 956 336 1,292 620 284 903
Mar 862 386 1,248 529 281 810
Apr 1071 408 1,480 537 218 755
May 940 364 1,304 546 234 780
June 899 402 1,301 501 338 839
July 619 389 1,008 462 264 726
Aug 510 297 807 399 201 599
Sept 633 249 882 421 201 622
Oct 422 226 647 353 197 550
Nov 340 219 559 340 194 534
Dec 513 218 731 434 187 621
Annual aMW 710 317 1,027 475 240 715
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
Page 58 2021 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2025 Jan 760 309 1,069 564 197 762
Feb 955 334 1,289 594 186 781
Mar 860 385 1,246 619 205 824
Apr 1071 408 1,479 879 202 1,081
May 939 364 1,303 667 291 957
June 899 402 1,300 750 261 1,012
July 619 388 1,007 490 251 741
Aug 510 297 806 421 194 614
Sept 631 249 881 389 198 587
Oct 421 225 647 361 197 558
Nov 340 219 559 346 189 535
Dec 513 218 730 430 185 616
Annual aMW 710 317 1,026 543 213 756
2026 Jan 783 324 1,107 619 220 838
Feb 975 351 1,327 703 222 925
Mar 884 399 1,282 507 189 696
Apr 1089 441 1,530 675 191 866
May 940 379 1,319 950 238 1,188
June 914 412 1,326 816 252 1,068
July 621 396 1,017 533 286 820
Aug 511 302 813 425 217 642
Sept 633 250 882 373 206 579
Oct 422 226 647 362 193 554
Nov 340 219 559 350 185 535
Dec 513 218 732 424 188 612
Annual aMW 719 326 1,045 561 216 777
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 59
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2027 Jan 780 323 1,103 533 185 719
Feb 974 350 1,325 688 205 893
Mar 882 397 1,280 669 194 863
Apr 1089 440 1,529 670 191 861
May 939 378 1,318 719 268 987
June 913 412 1,324 662 244 906
July 620 396 1,016 502 260 763
Aug 510 302 812 437 211 648
Sept 631 250 881 463 202 665
Oct 421 225 647 377 189 566
Nov 340 219 559 332 183 516
Dec 513 218 731 453 185 637
Annual aMW 718 326 1,044 542 210 752
2028 Jan 778 322 1,100 538 246 784
Feb 973 349 1,322 550 226 776
Mar 881 396 1,277 416 213 629
Apr 1089 440 1,529 562 222 784
May 939 376 1,315 903 265 1,167
June 912 411 1,323 655 249 905
July 620 395 1,015 582 371 953
Aug 510 301 810 451 268 719
Sept 630 249 879 462 219 682
Oct 421 225 646 370 201 571
Nov 340 219 559 348 189 537
Dec 513 218 730 645 178 823
Annual aMW 717 325 1,042 540 237 777
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
Page 60 2021 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2029 Jan 775 321 1,095 1119 282 1,400
Feb 972 348 1,320 1142 217 1,359
Mar 880 395 1,275 1148 285 1,433
Apr 1089 439 1,528 1193 537 1,730
May 939 375 1,314 1218 509 1,728
June 912 410 1,322 1101 472 1,573
July 619 395 1,014 631 416 1,047
Aug 509 300 809 492 285 777
Sept 628 249 878 566 237 803
Oct 420 225 645 391 209 601
Nov 340 219 559 338 190 528
Dec 512 218 730 495 197 692
Annual aMW 716 325 1,041 820 320 1,139
2030 Jan 773 319 1,092 605 321 926
Feb 970 347 1,317 724 347 1,071
Mar 879 394 1,273 627 379 1,007
Apr 1089 438 1,527 638 309 947
May 938 376 1,314 675 235 910
June 911 410 1,321 542 347 889
July 618 395 1,013 475 270 745
Aug 508 300 809 405 222 627
Sept 627 249 876 511 215 725
Oct 419 225 644 368 198 566
Nov 340 219 559 336 187 522
Dec 511 217 729 426 187 612
Annual aMW 715 324 1,039 528 268 796
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 61
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2031 Jan 771 318 1,089 541 217 758
Feb 969 345 1,314 641 225 866
Mar 877 393 1,270 665 228 893
Apr 1088 437 1,525 799 332 1,131
May 938 375 1,313 934 243 1,178
June 909 410 1,319 945 258 1,203
July 618 394 1,012 596 324 920
Aug 508 300 808 484 325 809
Sept 625 249 874 482 223 705
Oct 419 225 644 392 203 595
Nov 340 218 558 342 187 528
Dec 511 217 728 421 184 604
Annual aMW 714 323 1,038 603 246 849
2032 Jan 768 317 1,085 602 300 902
Feb 967 344 1,310 690 285 975
Mar 877 392 1,269 767 418 1,185
Apr 1087 436 1,523 1118 551 1,668
May 940 378 1,319 1032 442 1,474
June 908 410 1,318 1118 528 1,646
July 617 394 1,011 627 389 1,016
Aug 507 300 807 514 351 865
Sept 624 248 872 482 234 716
Oct 418 224 643 389 215 604
Nov 340 218 558 346 190 536
Dec 510 217 728 438 188 626
Annual aMW 714 323 1,037 677 341 1,018
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
Page 62 2021 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2033 Jan 765 315 1,080 651 332 983
Feb 965 342 1,307 732 330 1,061
Mar 876 391 1,266 646 321 967
Apr 1086 435 1,521 757 273 1,030
May 940 378 1,318 840 315 1,155
June 907 409 1,316 1129 307 1,435
July 616 394 1,010 515 293 807
Aug 506 299 806 442 240 682
Sept 622 248 870 503 228 730
Oct 418 224 642 394 215 609
Nov 340 218 558 340 196 535
Dec 510 217 727 522 182 704
Annual aMW 713 322 1,035 622 269 892
2034 Jan 762 313 1,075 873 296 1,170
Feb 963 341 1,304 1083 301 1,384
Mar 873 389 1,263 1120 532 1,653
Apr 1086 435 1,521 1113 513 1,626
May 939 377 1,317 1067 499 1,566
June 906 408 1,315 1293 583 1,875
July 615 393 1,009 1092 546 1,638
Aug 506 299 805 691 437 1,127
Sept 621 248 868 649 252 901
Oct 417 224 641 422 222 644
Nov 340 218 558 341 194 535
Dec 509 217 726 634 454 1,088
Annual aMW 712 322 1,033 865 402 1,267
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 63
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2035 Jan 760 312 1,071 1103 536 1,640
Feb 961 339 1,301 1152 476 1,628
Mar 872 388 1,260 1097 486 1,583
Apr 1085 434 1,519 1108 495 1,603
May 939 376 1,315 725 391 1,116
June 905 408 1,313 538 337 875
July 615 393 1,008 617 405 1,022
Aug 505 299 804 457 277 734
Sept 619 247 867 589 229 818
Oct 417 224 640 381 210 591
Nov 340 218 558 329 192 521
Dec 509 216 725 438 199 637
Annual aMW 711 321 1,032 711 353 1,064
2036 Jan 757 310 1,067 505 223 728
Feb 960 338 1,298 641 260 901
Mar 870 386 1,257 460 234 693
Apr 1084 433 1,517 487 190 677
May 939 376 1,314 532 233 766
June 904 407 1,311 532 337 868
July 614 393 1,006 427 271 698
Aug 505 299 803 370 203 573
Sept 618 247 865 436 203 639
Oct 416 223 640 382 193 575
Nov 340 218 558 344 185 529
Dec 508 216 724 411 178 589
Annual aMW 710 320 1,030 461 226 686
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
Page 64 2021 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2037 Jan 755 308 1,063 452 174 626
Feb 958 336 1,294 616 196 812
Mar 868 384 1,252 756 216 972
Apr 1082 432 1,514 781 388 1,169
May 938 376 1,314 695 255 949
June 903 407 1,310 619 237 856
July 613 392 1,005 506 372 878
Aug 504 298 802 442 272 714
Sept 616 247 863 441 218 659
Oct 416 223 639 376 209 585
Nov 340 217 558 339 184 524
Dec 508 216 724 504 191 695
Annual aMW 708 320 1,028 544 243 787
2038 Jan 752 306 1,059 675 344 1,019
Feb 956 334 1,290 945 372 1,318
Mar 866 382 1,248 605 339 944
Apr 1083 431 1,514 545 315 860
May 938 375 1,313 473 262 736
June 902 406 1,308 462 310 772
July 612 391 1,003 487 367 854
Aug 504 298 802 361 245 606
Sept 614 246 861 387 224 611
Oct 415 223 638 362 199 561
Nov 340 217 557 342 186 528
Dec 507 216 723 477 171 648
Annual aMW 707 319 1,026 510 278 788
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2021 Integrated Resource Plan—Appendix C Page 65
50th Percentile (planning case) Climate Change Modeling
Year Month HCC ROR Total HCC ROR Total
2039 Jan 750 305 1,054 579 240 819
Feb 954 333 1,287 741 255 996
Mar 864 381 1,245 777 218 995
Apr 1082 430 1,512 922 210 1,132
May 937 373 1,310 830 243 1,072
June 900 406 1,306 568 247 815
July 612 391 1,002 499 348 847
Aug 503 298 801 395 233 629
Sept 613 246 859 440 211 650
Oct 415 223 637 373 187 560
Nov 340 217 557 343 165 509
Dec 507 215 722 448 173 621
Annual aMW 707 318 1,024 576 228 804
2040 Jan 748 302 1,050 819 318 1,137
Feb 952 331 1,283 1179 463 1,642
Mar 863 379 1,242 1129 580 1,709
Apr 1081 429 1,510 1144 584 1,728
May 937 372 1,309 1181 583 1,765
June 899 405 1,304 1243 506 1,749
July 611 392 1,003 642 359 1,001
Aug 503 297 800 548 363 911
Sept 611 246 857 636 236 872
Oct 414 222 637 410 212 623
Nov 340 217 557 329 207 537
Dec 506 215 722 462 184 646
Annual aMW 706 317 1,023 810 383 1,193
*HCC=Hells Canyon Complex, **ROR=Run of River

Long-Term Capacity Expansion Results
Page 66 2021 Integrated Resource Plan—Appendix C
LONG-TERM CAPACITY EXPANSION RESULTS (MW)
Preferred Portfolio—Base with B2H
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 0 25 0
2025 0 0 300 105 0 20 -308 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 55 0 0 -175 27 0
2029 0 0 100 255 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 100 0 0 0 22 0
2034 -357 0 100 150 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 155 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 3
2040 0 0 0 55 0 20 0 10 9
Subtotal 0 700 1,405 1,685 500 400 -841 428 12
Total 4,289

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 67
Base with B2H—High Gas High Carbon Test (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 0 25 0
2025 0 0 300 105 0 20 -308 27 0
2026 0 0 515 0 500 0 0 28 0
2027 0 0 250 0 0 0 0 27 0
2028 0 400 320 0 GW1 0 -175 27 0
2029 0 100 100 200 0 0 0 26 0
2030 0 100 0 55 GW2 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 100 0 0 0 22 0
2034 -357 0 100 150 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 0 155 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 3
2040 0 0 0 55 0 20 0 10 9
Subtotal 357 1,300 1,805 1,570 500 400 -841 428 12
Total 5,531

Long-Term Capacity Expansion Results
Page 68 2021 Integrated Resource Plan—Appendix C
Base with B2H—PAC Bridger Alignment (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 0 0 20 0 25 0
2025 0 0 300 105 0 0 -134 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 0 0 0 0 27 0
2028 0 0 120 0 0 0 0 27 0
2029 0 0 0 5 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 5 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 105 0 0 0 22 0
2034 -357 0 100 305 0 0 -349 21 0
2035 0 0 200 505 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 100 105 0 0 0 14 0
2038 0 0 0 155 0 0 0 12 0
2039 0 100 0 55 GW1 0 0 11 0
2040 0 100 0 55 0 0 0 10 0
Subtotal 0 900 1,405 1,680 500 340 -841 428 0
Total 4,412

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 69
Base without B2H (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 900 0 0 0 0 0 25 0
2025 0 0 400 205 0 0 -308 27 0
2026 0 0 515 305 GW1 0 0 28 0
2027 0 0 250 105 0 0 -175 27 0
2028 0 200 320 205 GW2 20 0 27 0
2029 0 100 0 50 0 0 0 26 0
2030 0 100 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 105 0 0 0 22 0
2034 -357 0 100 155 0 0 0 21 0
2035 0 0 100 300 0 0 0 20 0
2036 0 0 0 55 0 20 0 16 0
2037 0 0 0 100 0 0 0 14 6
2038 0 0 0 150 0 20 0 12 6
2039 0 0 0 50 0 40 0 11 3
2040 0 0 0 50 0 20 0 10 9
Subtotal 0 1,300 1,805 2,115 0 440 -841 428 23
Total 5,271

Long-Term Capacity Expansion Results
Page 70 2021 Integrated Resource Plan—Appendix C
Base without B2H, without Gateway West (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 130 0 20 -357 24 0
2024 357 400 0 20 0 20 0 25 0
2025 0 0 200 120 0 0 -134 27 0
2026 0 0 215 270 0 0 0 28 0
2027 0 0 250 70 0 20 0 27 0
2028 0 0 120 120 0 0 -175 27 0
2029 0 200 0 220 0 0 0 26 0
2030 0 200 0 20 0 0 0 24 0
2031 0 0 0 70 0 0 0 24 0
2032 0 0 0 60 0 0 -174 23 0
2033 0 0 0 265 0 0 0 22 0
2034 -357 0 0 265 0 0 0 21 0
2035 0 0 0 205 0 20 0 20 8
2036 0 0 0 60 0 0 0 16 11
2037 0 0 0 120 0 0 0 14 6
2038 0 0 0 170 0 0 0 12 6
2039 0 0 0 70 0 20 0 11 6
2040 0 0 0 170 0 20 0 10 3
Subtotal 0 800 905 2,425 0 420 -841 428 40
Total 4,177

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 71
Base without B2H—PAC Bridger Alignment (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 800 0 0 0 0 0 25 0
2025 0 0 400 205 0 0 -134 27 0
2026 0 0 215 155 0 0 0 28 0
2027 0 200 250 55 GW1 0 0 27 0
2028 0 0 120 105 0 0 0 27 0
2029 0 100 0 50 0 0 0 26 0
2030 0 100 100 100 0 0 0 24 0
2031 0 0 0 0 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 100 100 GW2 0 0 22 0
2034 -357 0 100 305 0 0 -349 21 0
2035 0 0 300 505 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 100 100 0 0 0 14 0
2038 0 0 100 150 0 0 0 12 6
2039 0 0 0 55 0 0 0 11 3
2040 0 0 0 55 0 20 0 10 9
Subtotal 0 1,200 1,905 2,165 0 340 -841 428 18
Total 5,215

Long-Term Capacity Expansion Results
Page 72 2021 Integrated Resource Plan—Appendix C
Rapid Electrification (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 14
2024 357 800 0 5 0 0 0 25 0
2025 0 0 300 105 0 0 -308 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 105 0 0 0 27 0
2029 0 100 0 55 0 0 -175 26 0
2030 0 300 0 205 GW1 0 0 24 0
2031 0 0 100 105 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 55 0 0 0 22 0
2034 -357 0 100 105 0 0 0 21 0
2035 0 0 100 405 0 20 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 6
2038 0 0 100 205 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 0
2040 0 200 100 5 GW2 40 0 10 0
Subtotal 0 1,400 1,505 1,745 500 420 -841 428 20
Total 5,178

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 73
Climate Change (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 215 0 20 -357 24 30
2024 357 900 400 5 0 20 0 25 0
2025 0 0 400 105 0 0 -308 27 0
2026 0 0 215 5 500 0 0 28 0
2027 0 0 250 5 GW1 0 0 27 0
2028 0 300 120 5 0 0 -175 27 0
2029 0 0 200 255 GW2 0 0 26 0
2030 0 100 100 5 0 0 0 24 0
2031 0 0 100 105 0 0 0 24 0
2032 0 0 0 5 0 0 0 23 0
2033 0 0 100 150 0 0 0 22 0
2034 -357 0 100 105 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 100 105 0 0 0 14 0
2038 0 0 100 255 0 0 0 12 6
2039 0 0 0 55 0 0 0 11 6
2040 0 0 100 55 0 0 0 10 9
Subtotal 0 1,300 2,505 1,795 500 340 -841 428 50
Total 6,078

Long-Term Capacity Expansion Results
Page 74 2021 Integrated Resource Plan—Appendix C
100% Clean by 2035 (MW)
Year Gas Wind Solar Storage Nuclear Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 0 20 -357 24 0
2024 357 900 0 0 0 0 0 0 25 0
2025 0 0 400 205 0 0 0 -308 27 0
2026 0 0 515 305 0 500 0 0 28 0
2027 0 0 250 105 0 GW1 0 -175 27 0
2028 0 200 320 205 0 0 20 0 27 0
2029 0 100 0 50 0 0 0 0 26 0
2030 -45 100 0 55 0 GW2 0 0 24 0
2031 -45 0 0 55 77 0 0 0 24 0
2032 -164 0 0 55 0 0 0 0 23 0
2033 -171 0 0 105 154 0 0 0 22 0
2034 -693 0 100 155 154 0 0 0 21 0
2035 0 0 100 300 308 0 0 0 20 0
2036 0 0 0 55 0 0 20 0 16 0
2037 0 0 0 100 0 0 0 0 14 6
2038 0 0 0 150 0 0 20 0 12 6
2039 0 0 0 50 0 0 40 0 11 3
2040 0 0 0 50 0 0 20 0 10 9
Subtotal -762 1,300 1,805 2,115 693 500 440 -841 428 23
Total 5,702

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 75
100% Clean by 2045 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 -134 25 0
2025 0 0 900 200 0 0 -174 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 GW1 0 -175 27 0
2028 0 0 220 105 0 0 0 27 0
2029 0 0 0 55 0 0 0 26 0
2030 0 0 100 105 0 0 0 24 0
2031 0 0 0 5 0 0 0 24 0
2032 0 0 0 55 0 20 0 23 0
2033 0 0 0 55 0 20 0 22 0
2034 -357 0 0 155 0 20 0 21 0
2035 0 0 100 305 0 20 0 20 0
2036 0 0 0 55 0 20 0 16 0
2037 0 0 0 105 0 20 0 14 0
2038 0 0 0 155 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 9
2040 0 0 0 55 0 20 0 10 9
Subtotal 0 700 1,905 1,590 500 500 -841 428 18
Total 4,800

Long-Term Capacity Expansion Results
Page 76 2021 Integrated Resource Plan—Appendix C
SWIP North (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 800 0 0 0 0 0 25 0
2025 0 0 200 0 1001 0 -308 27 0
2026 0 0 215 5 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 55 0 0 -175 27 0
2029 0 300 0 205 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 100 100 GW1 0 0 24 0
2032 0 100 0 5 0 0 0 23 0
2033 0 0 100 105 0 0 0 22 0
2034 -357 0 0 150 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 8
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 150 0 20 0 12 6
2039 0 0 0 50 0 20 0 11 0
2040 0 100 0 55 0 0 0 10 0
Subtotal 0 1,300 1,305 1,520 600 360 -841 428 13
Total 4,686
1. SWIP North Capacity

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 77
CSPP Wind Renewal Low (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 0 25 0
2025 0 0 300 100 0 20 -308 27 0
2026 0 0 215 5 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 55 0 0 -175 27 0
2029 0 0 100 250 0 0 0 26 0
2030 0 0 0 50 0 0 0 24 0
2031 0 0 100 105 0 0 0 24 0
2032 0 100 0 5 0 0 0 23 0
2033 0 0 0 105 0 0 0 22 0
2034 -357 0 0 155 0 0 0 21 0
2035 0 0 100 305 0 20 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 155 GW1 0 0 12 9
2039 0 100 0 55 0 0 0 11 0
2040 0 100 0 50 0 0 0 10 6
Subtotal 0 1,000 1,405 1,680 500 360 -841 428 15
Total 4,547

Long-Term Capacity Expansion Results
Page 78 2021 Integrated Resource Plan—Appendix C
CSPP Wind Renewal High (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 0 0 20 0 25 0
2025 0 0 300 105 0 0 -308 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 0 0 0 0 27 0
2028 0 0 120 100 0 0 -175 27 0
2029 0 0 0 200 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 100 0 50 0 0 0 24 0
2032 0 0 0 50 0 0 0 23 0
2033 0 0 0 50 0 0 0 22 0
2034 -357 0 100 150 0 0 0 21 0
2035 0 100 100 300 0 0 0 20 0
2036 0 0 0 55 0 20 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 150 GW1 0 0 12 0
2039 0 0 0 50 0 0 0 11 0
2040 0 200 300 5 0 20 0 10 0
Subtotal 0 1,100 1,605 1,540 500 380 -841 428 0
Total 4,712

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 79
Validation Test: Natural Gas in 2028 Rather Than Solar and Storage (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 0 25 0
2025 0 0 300 105 0 20 -308 27 0
2026 0 0 215 5 500 0 0 28 0
2027 0 0 250 5 0 0 -175 27 0
2028 170 0 120 55 0 0 0 27 0
2029 0 0 0 55 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 105 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 55 0 0 0 22 0
2034 -357 0 0 55 0 0 0 21 0
2035 0 0 100 405 0 20 0 20 0
2036 0 0 0 100 0 0 0 16 0
2037 0 0 0 50 0 0 0 14 3
2038 0 0 100 205 0 0 0 12 6
2039 0 0 0 55 0 0 0 11 0
2040 0 300 0 5 GW1 20 0 10 6
Subtotal 170 1,000 1,205 1,490 500 380 -841 428 15
Total 4,347

Long-Term Capacity Expansion Results
Page 80 2021 Integrated Resource Plan—Appendix C
Validation Test: Bridger Exit Units 1 and 2 at the End of 2023 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 0 400 400 400 0 0 0 25 0
2025 0 0 300 100 0 0 -308 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 55 0 0 -175 27 0
2029 0 0 100 250 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 100 100 0 0 0 23 0
2033 0 100 0 0 0 20 0 22 0
2034 0 0 0 55 0 0 0 21 10
2035 0 100 0 55 GW1 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 100 0 155 0 0 0 12 0
2039 0 0 0 55 0 20 0 11 3
2040 0 100 0 55 0 0 0 10 0
Subtotal 0 800 1,605 1,670 500 360 -841 428 13
Total 4,535

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 81
Validation Test: Bridger Exit Unit 2 at the End of 2026 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -177 24 0
2024 177 800 0 0 0 0 0 25 0
2025 0 0 300 105 0 0 -308 27 0
2026 0 0 215 0 500 0 -180 28 0
2027 0 0 250 150 0 0 0 27 0
2028 0 0 120 105 0 0 -175 27 0
2029 0 0 200 250 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 100 0 55 0 0 0 22 0
2034 -177 100 0 55 GW1 0 0 21 0
2035 0 0 100 255 0 0 0 20 0
2036 0 0 0 105 0 0 0 16 8
2037 0 0 0 0 0 20 0 14 6
2038 0 100 100 155 0 20 0 12 6
2039 0 0 0 55 0 20 0 11 6
2040 0 0 0 55 0 40 0 10 6
Subtotal 0 1,100 1,405 1,625 500 420 -841 428 31
Total 4,669

Long-Term Capacity Expansion Results
Page 82 2021 Integrated Resource Plan—Appendix C
Validation Test: Bridger Exit Units 3 and 4 in 2028 and 2030 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 0 25 0
2025 0 0 300 100 0 20 -134 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 27 0
2028 0 0 120 5 0 0 -174 27 0
2029 0 0 0 105 0 20 0 26 0
2030 0 0 0 55 0 0 -175 24 0
2031 0 0 0 255 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 100 0 0 0 22 0
2034 -357 0 100 200 0 0 0 21 0
2035 0 100 100 250 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 100 100 0 0 0 14 0
2038 0 0 100 155 GW1 20 0 12 6
2039 0 0 0 50 0 20 0 11 0
2040 0 0 0 50 0 20 0 10 9
Subtotal 0 800 1,405 1,660 500 420 -841 428 15
Total 4,387

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 83
Validation Test: Valmy Unit 2 Exit in 2023 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -491 24 0
2024 357 600 100 150 0 0 0 25 0
2025 0 0 300 105 0 0 -174 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 0 0 0 -175 27 0
2028 0 0 220 105 0 0 0 27 0
2029 0 0 0 55 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 100 0 100 0 0 0 24 0
2032 0 100 0 5 0 0 0 23 0
2033 0 0 0 105 0 0 0 22 0
2034 -357 0 0 205 0 0 0 21 0
2035 0 0 100 255 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 155 GW1 0 0 12 0
2039 0 100 0 105 0 0 0 11 0
2040 0 0 0 55 0 20 0 10 0
Subtotal 0 900 1,405 1,730 500 340 -841 428 0
Total 4,462

Long-Term Capacity Expansion Results
Page 84 2021 Integrated Resource Plan—Appendix C
Validation Test: Valmy Unit 2 Exit in 2024 (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 5 0 0 -134 25 0
2025 0 0 400 250 0 0 -174 27 0
2026 0 0 215 0 500 0 0 28 0
2027 0 0 250 5 0 0 -175 27 0
2028 0 0 120 105 0 0 0 27 0
2029 0 0 0 55 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 100 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 105 0 0 0 22 0
2034 -357 0 100 155 0 0 0 21 0
2035 0 0 100 300 0 0 0 20 0
2036 0 0 0 50 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 100 0 155 GW1 0 0 12 0
2039 0 0 0 55 0 20 0 11 0
2040 0 0 100 105 0 0 0 10 0
Subtotal 0 900 1,405 1,730 500 340 -841 428 0
Total 4,462

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 85
Validation Test: Biomass (MW)
Year Gas Wind Solar Storage Biomass Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 0 20 -357 24 0
2024 357 700 0 5 0 0 0 0 25 0
2025 0 0 300 105 0 0 20 -308 27 0
2026 0 0 215 0 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 0 27 0
2028 0 0 120 5 50 0 0 -175 27 0
2029 0 0 100 255 0 0 0 0 26 0
2030 0 0 0 55 0 0 0 0 24 0
2031 0 0 0 55 0 0 0 0 24 0
2032 0 0 0 55 0 0 0 0 23 0
2033 0 0 0 100 0 0 0 0 22 0
2034 -357 0 100 150 0 0 0 0 21 0
2035 0 0 100 305 0 0 0 0 20 0
2036 0 0 0 55 0 0 0 0 16 0
2037 0 0 0 105 0 0 0 0 14 0
2038 0 0 100 155 0 0 20 0 12 0
2039 0 0 0 55 0 0 20 0 11 3
2040 0 0 0 55 0 0 20 0 10 9
Subtotal 0 700 1,405 1,635 50 500 400 -841 428 12
Total 4,289

Long-Term Capacity Expansion Results
Page 86 2021 Integrated Resource Plan—Appendix C
Validation Test: Geothermal (MW)
Year Gas Wind Solar Storage Geothermal Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 0 20 -357 24 0
2024 357 700 0 5 0 0 0 0 25 0
2025 0 0 300 105 0 0 20 -308 27 0
2026 0 0 215 0 0 500 0 0 28 0
2027 0 0 250 5 0 0 0 0 27 0
2028 0 0 120 5 50 0 0 -175 27 0
2029 0 0 100 255 0 0 0 0 26 0
2030 0 0 0 55 0 0 0 0 24 0
2031 0 0 0 55 0 0 0 0 24 0
2032 0 0 0 55 0 0 0 0 23 0
2033 0 0 0 100 0 0 0 0 22 0
2034 -357 0 100 150 0 0 0 0 21 0
2035 0 0 100 305 0 0 0 0 20 0
2036 0 0 0 55 0 0 0 0 16 0
2037 0 0 0 105 0 0 0 0 14 0
2038 0 0 100 155 0 0 20 0 12 0
2039 0 0 0 55 0 0 20 0 11 3
2040 0 0 0 55 0 0 20 0 10 9
Subtotal 0 700 1,405 1,635 50 500 400 -841 428 12
Total 4,289

Long-Term Capacity Expansion Results
2021 Integrated Resource Plan—Appendix C Page 87
Validation Test: Demand Response (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 115 0 20 -357 24 0
2024 357 700 0 0 0 20 0 25 0
2025 0 0 300 100 0 20 -308 27 0
2026 0 0 215 0 500 20 0 28 0
2027 0 0 250 0 0 20 0 27 0
2028 0 0 120 50 0 0 -175 27 0
2029 0 0 100 255 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 100 0 0 0 22 0
2034 -357 0 100 150 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 155 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 3
2040 0 0 0 55 0 20 0 10 9
Subtotal 0 700 1,405 1,665 500 460 -841 428 12
Total 4,329

Long-Term Capacity Expansion Results
Page 88 2021 Integrated Resource Plan—Appendix C
Validation Test: Energy Efficiency (MW)
Year Gas Wind Solar Storage Transmission
Demand
Response Coal Exit
Energy Efficiency
Forecast
Energy Efficiency
Bundles
2021 0 0 0 0 0 0 0 23 0
2022 0 0 0 0 0 300 0 24 0
2023 0 0 120 110 0 20 -357 24 14
2024 357 700 0 0 0 0 0 25 18
2025 0 0 300 100 0 20 -308 27 22
2026 0 0 215 0 500 0 0 28 25
2027 0 0 250 0 0 0 0 27 26
2028 0 0 120 40 0 0 -175 27 0
2029 0 0 100 255 0 0 0 26 0
2030 0 0 0 55 0 0 0 24 0
2031 0 0 0 55 0 0 0 24 0
2032 0 0 0 55 0 0 0 23 0
2033 0 0 0 100 0 0 0 22 0
2034 -357 0 100 150 0 0 0 21 0
2035 0 0 100 305 0 0 0 20 0
2036 0 0 0 55 0 0 0 16 0
2037 0 0 0 105 0 0 0 14 0
2038 0 0 100 155 0 20 0 12 0
2039 0 0 0 55 0 20 0 11 3
2040 0 0 0 55 0 20 0 10 9
Subtotal 0 700 1,405 1,650 500 400 -841 428 117
Total 4,359

Portfolio Emissions Forecast
2021 Integrated Resource Plan—Appendix C Page 89
PORTFOLIO EMISSIONS FORECAST
Total emissions forecasts (CO2, NOx, and SO2) for Idaho Power’s resources are outputs of the
AURORA model and are presented below.
CO2 Tons

NOx Tons

Portfolio Emissions Forecast
Page 90 2021 Integrated Resource Plan—Appendix C

SO2 Tons

Portfolio Emissions Forecast
2021 Integrated Resource Plan—Appendix C Page 91
Preferred Portfolio (Base with B2H) Emissions
Year CO2 (short tons) NOx (short tons) SO2 (short tons)
2021 3,146,734 1,825 1,459
2022 3,464,248 2,175 1,588
2023 3,133,471 1,656 1,119
2024 2,428,049 857 639
2025 2,304,014 801 649
2026 2,014,136 604 348
2027 2,025,337 611 339
2028 2,111,398 652 348
2029 1,748,562 558 9
2030 1,725,706 555 9
2031 1,787,393 590 9
2032 1,831,248 608 10
2033 1,905,600 633 10
2034 1,889,374 631 10
2035 1,783,130 606 9
2036 1,787,069 611 9
2037 1,809,568 617 9
2038 1,839,524 627 9
2039 1,869,889 642 9
2040 1,861,797 642 9

Stochastic Risk Analysis
Page 92 2021 Integrated Resource Plan—Appendix C
STOCHASTIC RISK ANALYSIS
The stochastic analysis assesses the effect on portfolio costs when select variables take on
values different from their planning-case levels. Stochastic variables are selected based on the
degree to which there is uncertainty regarding their forecasts and the degree to which they can
affect the analysis results (i.e., portfolio costs).
The purpose of the analysis is to understand the range of portfolio costs across the full extent
of stochastic shocks (i.e., across the full set of stochastic iterations) and how the ranges for
portfolios differ.
Idaho Power identified the following three variables for the stochastic analysis:
1. Natural gas price—Based on the historical Henry Hub natural gas price data for the 1997
to 2020 period, it was determined that natural gas price variance around the trend
approximates a log-normal distribution with a year-to-year correlation factor of 0.55.
The graph below shows planning case average annual price in the black dashed line and
the remaining-colored lines show the 20 different stochastic iterations for Henry Hub
gas prices.
Natural Gas Sampling (Nominal $/MMBTU)

0.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
He
n
r
y

H
u
b

$
/
M
M
B
t
u
Stochastic Risk Analysis
2021 Integrated Resource Plan—Appendix C Page 93
2. Customer load—Customer load follows a normal distribution and is adjusted around the
planning case load forecast, which is shown as the dashed line in the figure below. To
assess the reasonableness of the stochastic error bounds as they relate to customer
load, the upper and lower bounds were compared to the load forecast 90/10 error
bounds. For both the upper and lower bound, the stochastic values were found to fall
slightly outside of the 90/10 bounds which is to be expected. The stochastic process
produces 20 scenarios which could be expected to test a larger bound of 95/5.
Customer Load Sampling (Annual MWh)

3. Hydroelectric variability—Hydroelectric generation variability was found to approximate
a uniform distribution based on the historical generation from the 1951 to 2017 period.
Although an unexpected result based on the non-uniform distribution of rainfall across
the Snake River Basin, the regulation of streamflow likely explains the difference
between rainfall and generation distributions. In addition to the distribution, the
historical data also shows a correlation between years of 0.55.

16,000,000
17,000,000
18,000,000
19,000,000
20,000,000
21,000,000
22,000,000
23,000,000
24,000,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
MW
h
Stochastic Risk Analysis
Page 94 2021 Integrated Resource Plan—Appendix C
Hydro Generation Sampling (Annual MWh)

The three selected stochastic variables are key drivers of variability in year-to-year
power-supply costs and therefore provide suitable stochastic shocks to allow differentiated
results for analysis.
Due to the significant time required to perform the stochastic risk analysis, Idaho Power was
limited to performing a maximum of 20 risk iterations. Based on the sample size, the choice was
made to use the Latin Hypercube sampling technique over a pure Monte Carlo method.
The Latin Hypercube design samples the distribution range with a relatively smaller sample size,
allowing a reduction in simulation run times. The Latin Hypercube method does this by
sampling at regular intervals across the distribution spectrum. Contrast this to Monte Carlo
methods where samples are taken randomly from the distribution range. The random Monte
Carlo draw requires far more than 20 iterations to ensure a good distribution of draws. Once
the stochastic elements are drawn, Idaho Power then calculated the 20-year NPV portfolio cost
for each of the 20 iterations for all evaluated portfolios. The distribution of 20-year NPV
portfolio costs for the portfolios are shown in the graph below.
5,000,000
6,000,000
7,000,000
8,000,000
9,000,000
10,000,000
11,000,000
12,000,000
13,000,000
14,000,000
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
MW
h
Stochastic Risk Analysis
2021 Integrated Resource Plan—Appendix C Page 95
Portfolio Stochastic Analysis, Total Portfolio Cost
NPV Years 2021–2040 ($ x 1,000)

In the figure above, each line represents the likelihood of occurrence by NPV with the diamonds
showing the planning conditions NPV. Higher values on the line represent a higher probability
of occurrence with values near the horizontal axis representing improbable events. Values that
occur toward the left have lower cost while values toward the right have higher cost. As
indicated by the peak of the graph being furthest left, the results of the stochastic analysis
show that the Preferred Portfolio (Base with B2H) is likely to have the lowest cost given a range
of natural gas prices, load forecasts, and hydroelectric generation levels. Next lowest is the
Base B2H PAC Bridger Alignment portfolio indicated by the middle peak. Nearly tied as the most
expensive options analyzed using stochastic elements are both Base without B2H portfolios
regardless of PAC Bridger alignment.

Loss of Load Expectation
Page 96 2021 Integrated Resource Plan—Appendix C
LOSS OF LOAD EXPECTATION
As utilities continue to add more renewable energy to the electric grid, it is becoming more
critical to analyze the effect variable energy resources have on system reliability. For the 2021
IRP, Idaho Power utilized the risk-based equations and methodologies described in this section
to calculate the contribution to peak of different variable energy resources for the AURORA
model and quantitatively analyze the risk associated with the portfolios. The company chose to
conduct this study because of the recognition that the output of variable energy resources such
as wind and solar change with time (with their hourly output being dependent on a multitude
of factors like weather and environmental conditions) and that it is essential to capture and
value that variability. Another key factor for conducting this study is that the industry is also
attempting to establish a generally accepted method to calculate the contribution to peak of
variable energy resources, so it is essential for Idaho Power to adopt and apply these
best practices.
Methodology Components
The Loss of Load Probability (LOLP) is the likelihood of the system load exceeding the available
generating capacity during a given time period (typically an hour). The LOLP can be calculated
by determining the probability that the available generation at any given hour is able to meet
the net load during that same hour. The LOLP can be defined as: 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿=𝐿𝐿𝑖𝑖(𝐺𝐺𝑖𝑖− 𝐿𝐿𝑖𝑖)
where 𝐿𝐿𝑖𝑖 is the cumulative probability of the available generation required to meet the system
demand at hour 𝑖𝑖, 𝐺𝐺𝑖𝑖 is the available generation required to meet the system demand at hour 𝑖𝑖,
and 𝐿𝐿𝑖𝑖 is the system demand at hour 𝑖𝑖.
The Loss of Load Expectation (LOLE) is the expected number of days per time period for which
the available generation capacity is insufficient to serve the demand at least once per day. The
LOLE can be calculated by adding the maximum LOLP from each day for a time period (typically
over the course of a year). LOLE can be defined as: 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿= �𝑚𝑚𝑚𝑚𝑚𝑚[𝑖𝑖=1𝐻𝐻(𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝑖𝑖)]𝐷𝐷
𝑑𝑑=1
where 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝑖𝑖 is the LOLP at hour 𝑖𝑖.
The Effective Load Carrying Capability (ELCC) is a reliability-based metric used to assess the
contribution to peak of any given generation unit or power plant. ELCC decomposes an
individual generator’s contribution to the overall system reliability and is primarily driven by the
timing of high LOLP hours. These calculated values were assigned to existing and selectable
Loss of Load Expectation
2021 Integrated Resource Plan—Appendix C Page 97
resources when modeling the different portfolios. To calculate the ELCC of a resource, there are
two definitions that should first be stated:
hours a generation unit is forced off-line compared to the number of
hours the unit runs; for example, an EFOR of three percent means a
generator is forced off three percent of its running time.
always available and never forced off-line.
The ELCC of a resource is determined by first calculating the perfect generation required to
achieve an LOLE of 0.05 days per year with all market purchases set equal to zero. Then, the
resource being evaluated is added to the system and the perfect generation required is
calculated once again. The ELCC of a given resource will be equal to the difference in the size of
the perfect generators from the two runs divided by the resource’s nameplate: 𝐿𝐿𝐿𝐿𝐸𝐸𝐸𝐸=𝐿𝐿𝐺𝐺1 −𝐿𝐿𝐺𝐺2𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑁𝑁𝑁𝑁
where 𝐿𝐿𝐺𝐺1 is the perfect generation required to achieve an LOLE of 0.05 days per year without
including the evaluated resource, 𝐿𝐿𝐺𝐺2 is the perfect generation required to achieve an LOLE of
0.05 days per year with the evaluated resource included, and 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑁𝑁𝑁𝑁 is the nameplate of
the evaluated resource.
Modeling Idaho Power’s System
Idaho Power created a tool to implement the LOLE methodology and maximize computational
efficiency for modeling Idaho Power’s existing and potential resource stack. Within this tool,
the company’s resources were split into three primary categories: dispatchable resources,
intermittent resources, and energy limited resources (demand response and storage).
Dispatchable resources were modeled using a monthly outage table that was calculated using
their monthly capacity and EFOR. The outage table is comprised of the following four
components:

Loss of Load Expectation
Page 98 2021 Integrated Resource Plan—Appendix C
Dispatchable resources include the Hells Canyon Complex, natural gas plants, Bridger and
Valmy coal and various transmission assets with access to the market.
Variable resources (such as wind and solar) were modeled by using four years of historical
hourly output data to maintain the relationship between load and renewable generation. Other
resources for which Idaho Power does not have direct control over (in reference to their
dispatch) were also modeled using four years of historical hourly output data. Examples of
these resources include dairy digestors, non-wind and non-solar PURPA projects, run of river
hydroelectric plants and geothermal generation. In the model, these variable resources are
subtracted from the system adjusted load to produce a net load that is then used in the LOLE
calculations.
Because resources such as storage and demand response are dispatched based on the daily
peak load shape, Idaho Power devised a separate way to model energy limited resources. The
tool begins by sorting the days in a year from high to low based on their net load peak. Starting
on the day with the highest net load, a target for each day was set based on the net load peak
and the size of the demand response group or storage selection. After verifying that the
operating parameters of the demand response portfolio or storage resource are met on that
day, the algorithm iterates over each hour of the day and compares the net load with the
target. If the net load is above the target, the function will dispatch the MW assigned for that
hour. The algorithm will then move to the next day and perform all the checks before it iterates
over all the hours again; this is done for every day in each year.
This customization functionality of the LOLE tool allows for a detailed approach to modeling
Idaho Power’s system. As system needs continue to change, new analysis such as this LOLE tool
will be essential in best evaluating the company’s highest risk hours (which is of key importance
since they will no longer necessarily align with the peak load hour).
ELCC Results
The ELCC of future variable energy resources are dependent upon the order of the resources
built before them, making the ELCC calculation of future resources challenging. For the 2021
IRP, Idaho Power adopted the concept of “last-in ELCC” where from the future resources being
modeled, only one resource is added at a time. For example, to calculate the ELCC of future
solar PV, all the existing resources are modeled and only solar is included in the LOLE tool. This
approach will result in an accurate baseline for AURAORA to build the portfolios.
The average ELCC values used in AURORA for future solar PV, wind, demand response, 4-hour
storage, 8-hour storage and solar PV plus storage were fed into the model. The table below
shows the ELCC for existing and future resources that were used in the AURORA model.

Loss of Load Expectation
2021 Integrated Resource Plan—Appendix C Page 99
LOLE of Portfolios
To quantitively analyze portfolio reliability, Idaho Power fed portfolio results into the
company’s LOLE tool, as described in Chapter 10 of the 2021 IRP. Idaho Power utilized a
reliability threshold (LOLE) of 0.1 days per year in the 2019 IRP. For the 2021 IRP, Idaho Power is
adopting a reliability threshold of 0.05 days per year. The 0.05 (1-in-20) reliability threshold was
chosen to 1) account for the extreme weather events that are becoming more frequent in the
Northwest, and 2) factor in water availability uncertainty year to year. A poor water year,
resulting in reduced hydro generation, can look equivalent to a season-long resource outage.
This 0.05 days per year threshold aligns with the reliability threshold used by the Northwest
Power & Conservation Council (NWPCC).

The LOLE tool was used to evaluate various portfolios created by AURORA using the four test
years, producing an average LOLE for each year of the planning horizon for each of the selected
portfolios. A generator with an EFOR of 5% was added to the LOLE tool when the LOLE of a
particular year was above the preestablished threshold.

ELCC of Existing Resources ELCC of Future Resources
Resource Average Resource Average
PURPA Solar 62.3% Solar PV 10.2%
Oregon Solar 62.3% Jackpot Solar 34.0%
PUPRA Wind 15.0% Wind 11.2%
Elkhorn Wind 15.0% 4-Hour Storage 87.5%
Current Demand Response 17.3% 8-Hour Storage 97.0%
Solar PV + 4-Hour Storage 97.0%
Proposed Demand Response 58.5%
Incremental Demand Response 36.0%
Loss of Load Expectation
Page 100 2021 Integrated Resource Plan—Appendix C
The portfolio reliability results table below shows the portfolio LOLE per year and the additional
generation (when needed) that was added to each of the selected portfolios.
Portfolio Reliability Results

Preferred Portfolio
(Base with B2H) Base without B2H
Base B2H PAC
Bridger Alignment
Base without B2H
PAC Bridger
Alignment SWIP-North
Year
LOLE (d/yr)
Additional
Gen. (MW) LOLE (d/yr)
Additional
Gen.
(MW) LOLE (d/yr)
Additional
Gen.
(MW) LOLE (d/yr)
Additional
Gen.
(MW) LOLE (d/yr)
Additional
Gen.
(MW)
2021 0.1050 0 0.1050 0 0.1050 0 0.1050 0 0.1050 0
2022 0.0594 0 0.0594 0 0.0594 0 0.0594 0 0.0594 0
2023 0.0259 0 0.0259 0 0.0259 0 0.0259 0 0.0259 0
2024 0.0161 0 0.0147 0 0.0149 0 0.0157 0 0.0157 0
2025 0.0072 0 0.0032 0 0.0074 0 0.0034 0 0.0067 0
2026 0.0016 0 0.0075 0 0.0003 0 0.0071 0 0.0013 0
2027 0.0024 0 0.0087 0 0.0006 0 0.0079 0 0.0024 0
2028 0.0025 0 0.0164 0 0.0009 0 0.0066 0 0.0024 0
2029 0.0035 0 0.0188 0 0.0014 0 0.0076 0 0.0034 0
2030 0.0039 0 0.0199 0 0.0014 0 0.0055 0 0.0038 0
2031 0.0056 0 0.0282 0 0.0025 0 0.0103 0 0.0033 0
2032 0.0064 0 0.0324 0 0.0027 0 0.0120 0 0.0046 0
2033 0.0073 0 0.0389 0 0.0026 0 0.0123 0 0.0043 0
2034 0.0049 0 0.0280 0 0.0007 0 0.0042 0 0.0032 0
2035 0.0354 0 0.0494 185 0.0276 0 0.0493 200 0.0190 0
2036 0.0392 0 0.0491 20 0.0361 0 0.0442 45 0.0220 0
2037 0.0495 7 0.0477 40 0.0402 0 0.0506 15 0.0293 0
2038 0.0445 3 0.0386 0 0.0473 0 0.0509 20 0.0293 0
2039 0.0487 15 0.0499 5 0.0492 16 0.0498 20 0.0315 0
2040 0.0496 16 0.0498 10 0.0480 24 0.0511 5 0.0400 0
Total 41 260 40 305 0
Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 101
COMPLIANCE WITH STATE OF OREGON IRP GUIDELINES
Guideline 1: Substantive Requirements
a. All resources must be evaluated on a consistent and comparable basis.
• All known resources for meeting the utility's load should be considered, including
supply-side options which focus on the generation, purchase and transmission of
power or gas purchases, transportation, and storage and demand side options which
focus on conservation and demand response.
• Utilities should compare different resource fuel types, technologies, lead times, in-
service dates, durations and locations in portfolio risk modeling.
• Consistent assumptions and methods should be used for evaluation of all resources.
• The after-tax marginal weighted-average cost of capital (WACC) should be used to
discount all future resource costs.
Idaho Power response:
Idaho Power considered a range of resource types including renewables (e.g., wind and storage), demand-side management,
transmission, market purchases, thermal resources, and energy storage. Each of these resources was included as options in
the AURORA capacity expansion modeling.
Supply-side and purchased resources for meeting the utility’s load are discussed in Chapter 4. Idaho Power Today; demand-
side options are discussed in Chapter 6. Demand-Side Resources; and transmission resources are discussed in Chapter 7.
Transmission Planning.
New resource options including fuel types, technologies, lead times, in-service dates, durations, and locations are described
in Chapter 5. Future Supply-side Generation and Storage Resources, Chapter 6. Demand-Side resources, Chapter 7.
Transmission Planning, and Chapter 8. Planning Period Forecasts.
The consistent modeling method for evaluating new resource options is described in Chapter 8. Planning Period Forecasts
and Chapter 10. Modeling Analysis and Results.
The WACC rate used to discount all future resource costs is discussed in the Technical Appendix Supply Side Resource Data –
Key Financial and Forecast Assumptions.

b. Risk and uncertainty must be considered.
• At a minimum, utilities should address the following sources of risk and uncertainty:
1. Electric utilities: load requirements, hydroelectric generation, plant forced
outages, fuel prices, electricity prices, and costs to comply with any regulation of
greenhouse gas emissions.
2. Natural gas utilities: demand (peak, swing, and baseload), commodity supply and
price, transportation availability and price, and costs to comply with any
regulation of greenhouse gas emissions.
• Utilities should identify in their plans any additional sources of risk and uncertainty.
Compliance with State of Oregon IRP Guidelines
Page 102 2021 Integrated Resource Plan—Appendix C
Idaho Power response:
Electric utility risk and uncertainty factors (load, natural gas, and hydroelectric generation) for resource portfolios are
considered in Chapter 10. Modeling Analysis and Results. Plant forced outages are modeled in AURORA on a unit basis and
are discussed in Chapter 9 Portfolios. Risk and uncertainty associated with high natural gas and high carbon cost are
discussed in Chapter 9 Portfolios.
Additional sources of risk and uncertainty including regional resource adequacy and qualitative risks are discussed in Chapter 10. Modeling Analysis and Results.

c. The primary goal must be the selection of a portfolio of resources with the best
combination of expected costs and associated risks and uncertainties for the utility and
its customers.
• The planning horizon for analyzing resource choices should be at least 20 years and
account for end effects. Utilities should consider all costs with a reasonable
likelihood of being included in rates over the long term, which extends beyond the
planning horizon and the life of the resource.
• Utilities should use present value of revenue requirement (PVRR) as the key cost
metric. The plan should include analysis of current and estimated future costs for all
long-lived resources such as power plants, gas storage facilities, and pipelines, as
well as all short-lived resources such as gas supply and short-term power purchases.
• To address risk, the plan should include, at a minimum:
a. Two measures of PVRR risk: one that measures the variability of costs and one
that measures the severity of bad outcomes.
b. Discussion of the proposed use and impact on costs and risks of physical and
financial hedging.
• The utility should explain in its plan how its resource choices appropriately balance
cost and risk.
Idaho Power response:
The IRP methodology and the planning horizon of 20 years are discussed in Chapter 1. Background.
Modeling analysis of current and estimated future costs for all long-lived resources such as power plants, gas storage
facilities, and pipelines, as well as all short-lived resources such as gas supply and short-term power purchases is discussed in
Chapter 10. Modeling Analysis and Results.
The discussion of cost variability and extreme outcomes, including bad outcomes is discussed in Chapter 10. Modeling
Analysis and Results.
Idaho Power’s Risk Management Policy regarding physical and financial hedging is discussed in Chapter 1. Background. Idaho
Power’s Energy Risk Management Program is designed to systematically identify, quantify, and manage the exposure of the
company and its customers to the uncertainties related to the energy markets in which the Company is an active participant.
The company’s Risk Management Standards limit term purchases to the prompt 18 months of the forward curve.
Idaho Power’s plan and how the resource choices appropriately balance cost and risk is presented in Chapter 11. Preferred
Portfolio and Action Plan.

Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 103
d. The plan must be consistent with the long-run public interest as expressed in Oregon
and federal energy policies.
Idaho Power response:
Long-run public interest issues are discussed in Chapter 2. Political, Regulatory, and Operational Issues and Chapter 3.
Climate Change. The company also evaluated four future scenarios, including rapid electrification, climate change, 100%
clean by 2035, and 100% clean by 2045. These are discussed in Chapter 9. Portfolios.

Guideline 2: Procedural Requirements
a. The public, which includes other utilities, should be allowed significant involvement in
the preparation of the IRP. Involvement includes opportunities to contribute
information and ideas, as well as to receive information. Parties must have an
opportunity to make relevant inquiries of the utility formulating the plan. Disputes
about whether information requests are relevant or unreasonably burdensome, or
whether a utility is being properly responsive, may be submitted to the Commission for
resolution.
Idaho Power response:
The IRPAC meetings are open to the public. A roster of the IRPAC members along with meeting schedules and agendas is
provided in the Technical Appendix, IRP Advisory Council.

b. While confidential information must be protected, the utility should make public, in its
plan, any non-confidential information that is relevant to its resource evaluation and
action plan. Confidential information may be protected through use of a protective
order, through aggregation or shielding of data, or through any other mechanism
approved by the Commission.
Idaho Power response:
Idaho Power makes public extensive information relevant to its resource evaluation and action plan. This information is
discussed in IRPAC meetings and found throughout the 2021 IRP, the 2021 Load and Sales Forecast and in the 2021 Technical
Appendix.

c. The utility must provide a draft IRP for public review and comment prior to filing a final
plan with the Commission.
Compliance with State of Oregon IRP Guidelines
Page 104 2021 Integrated Resource Plan—Appendix C
Idaho Power response:
Idaho Power posted online a draft 2021 IRP for public review on December 20, 2021. The company requested comments to
be provided no later than December 27, 2021.
Guideline 3: Plan Filing, Review, and Updates
a. A utility must file an IRP within two years of its previous IRP acknowledgment order. If
the utility does not intend to take any significant resource action for at least two years
after its next IRP is due, the utility may request an extension of its filing date from the
Commission.
Idaho Power response:
The OPUC acknowledged Idaho Power’s 2019 IRP on June 4, 2021 in Order 21-184. The company received an extension on its

b. The utility must present the results of its filed plan to the Commission at a public
meeting prior to the deadline for written public comment.
Idaho Power response:
Idaho Power will schedule a public meeting at the OPUC following the December 30, 2021 filing of the 2021 IRP.

c. Commission staff and parties should complete their comments and recommendations
within six months of IRP filing.
Idaho Power response:
This will be conducted following the filing of this IRP.

d. The Commission will consider comments and recommendations on a utility’s plan at a
public meeting before issuing an order on acknowledgment. The Commission may
provide the utility an opportunity to revise the plan before issuing an acknowledgment
order.
Idaho Power response:
This will be conducted following the filing of this IRP.

e. The Commission may provide direction to a utility regarding any additional analyses or
actions that the utility should undertake in its next IRP.
Idaho Power response:
No response needed.

Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 105
f. Each utility must submit an annual update on its most recently acknowledged plan. The
update is due on or before the acknowledgment order anniversary date. Once a utility
anticipates a significant deviation from its acknowledged IRP, it must file an update with
the Commission, unless the utility is within six months of filing its next IRP. The utility
must summarize the update at a Commission public meeting. The utility may request
acknowledgment of changes in proposed actions identified in an update.
Idaho Power response:
Idaho Power requested and received a waiver of the 2019 IRP update in Order No. 21-184. This activity for the 2021 IRP will

g. Unless the utility requests acknowledgement of changes in proposed actions, the annual
update is an informational filing that:
• Describes what actions the utility has taken to implement the plan;
• Provides an assessment of what has changed since the acknowledgment order that
affects the action plan, including changes in such factors as load, expiration of
resource contracts, supply-side and demand-side resource acquisitions, resource
costs, and transmission availability; and
• Justifies any deviations from the acknowledged action plan.
Idaho Power response:
Not applicable to this filling; this activity will be conducted at a later time.
Guideline 4: Plan Components
At a minimum, the plan must include the following elements:
a. An explanation of how the utility met each of the substantive and procedural
requirements;
Idaho Power response:
The information in this section is intended to show how the company complied with this guideline.

b. Analysis of high and low load growth scenarios in addition to stochastic load risk analysis
with an explanation of major assumptions;
Idaho Power response:
High-growth scenarios are tested using the Rapid Electrification case as discussed in Chapter 9. Portfolios. Stochastic analysis was performed on load (which creates high and low load conditions) and the details of that analysis are contained in the Technical Appendix.

Compliance with State of Oregon IRP Guidelines
Page 106 2021 Integrated Resource Plan—Appendix C
c. For electric utilities, a determination of the levels of peaking capacity and energy
capability expected for each year of the plan, given existing resources; identification of
capacity and energy needed to bridge the gap between expected loads and resources;
modeling of all existing transmission rights, as well as future transmission additions
associated with the resource portfolios tested;
Idaho Power response:
Peaking capacity and energy capability for each year of the plan for existing resources is discussed in Chapter 8. Planning
Period Forecasts. Detailed forecasts are provided in the Technical Appendix, Load and Resource Balance, Sales and Load
Forecast Data and Existing Resource Data. Identification of capacity and energy needed to bridge the gap between expected
loads and resources is discussed in Chapter 9. Portfolios.

d. For natural gas utilities, a determination of the peaking, swing and base-load gas supply
and associated transportation and storage expected for each year of the plan, given
existing resources; and identification of gas supplies (peak, swing and base-load),
transportation and storage needed to bridge the gap between expected loads and
resources;
Idaho Power response:
Not applicable.

e. Identification and estimated costs of all supply-side and demand-side resource options,
taking into account anticipated advances in technology;
Idaho Power response:
Supply-side resources are discussed in Chapter 5. Future Supply-Side Generation and Storage Resources.
Demand-side resources are discussed in Chapter 6. Demand-Side Resources.
Resource costs are discussed in Chapter 8. Planning Period Forecasts and presented in the Technical Appendix, Supply-Side
Resource Data Levelized Cost of Energy.

f. Analysis of measures the utility intends to take to provide reliable service, including
cost-risk tradeoffs;
Idaho Power response:
Resource reliability and cost-risk tradeoffs are covered in Chapter 10. Modeling Analysis and Results

g. Identification of key assumptions about the future (e.g., fuel prices and environmental
compliance costs) and alternative scenarios considered;
Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 107
Idaho Power response:
Key Assumptions including the natural gas price forecast are discussed in Chapter 8. Planning Period Forecasts and in the
Technical Appendix, Key Financial and Forecast Assumptions. Environmental compliance costs are addressed in Chapter 10.
Modeling Analysis and Results.

h. Construction of a representative set of resource portfolios to test various operating
characteristics, resource types, fuels and sources, technologies, lead times, in-service
dates, durations, and general locations – system-wide or delivered to a specific portion
of the system;
Idaho Power response:
Resource portfolios considered for the 2021 IRP are described in Chapter 9. Portfolios.

i. Evaluation of the performance of the candidate portfolios over the range of identified
risks and uncertainties;
Idaho Power response:
Evaluation of the portfolios over a range of risks and uncertainties is discussed in Chapter 10. Modeling Analysis and Results.

j. Results of testing and rank ordering of the portfolios by cost and risk metric, and
interpretation of those results;
Idaho Power response:
Portfolio cost, risk results, interpretations and the selection of the preferred portfolio are provided in Chapter 10. Modeling Analysis and Results.

k. Analysis of the uncertainties associated with each portfolio evaluated;
Idaho Power response:
The quantitative and qualitative uncertainties associated with each portfolio are evaluated in Chapter 10. Modeling Analysis and Results.

l. Selection of a portfolio that represents the best combination of cost and risk for the
utility and its customers
Idaho Power response:
The preferred resource portfolio is identified in Chapter 11. Preferred Portfolio and Action Plan.

Compliance with State of Oregon IRP Guidelines
Page 108 2021 Integrated Resource Plan—Appendix C
m. Identification and explanation of any inconsistencies of the selected portfolio with any
state and federal energy policies that may affect a utility’s plan and any barriers to
implementation; and
Idaho Power response:
Risk associated with the preferred portfolio including coal-unit exits is discussed in Chapter 11. Preferred Portfolio
and
Action Plan.

n. An action plan with resource activities the utility intends to undertake over the next two
to four years to acquire the identified resources, regardless of whether the activity was
acknowledged in a previous IRP, with the key attributes of each resource specified as in
portfolio testing.
Idaho Power response:
An action plan is provided in the Executive Summary and in Chapter 11. Preferred Portfolio and Action Plan.

Guideline 5: Transmission
Portfolio analysis should include costs to the utility for the fuel transportation and electric
transmission required for each resource being considered. In addition, utilities should
consider fuel transportation and electric transmission facilities as resource options, taking
into account their value for making additional purchases and sales, accessing less costly
resources in remote locations, acquiring alternative fuel supplies, and improving reliability.
Idaho Power response:
The fuel costs (including transportation) for each resource being considered is presented in the Technical Appendix, Cost Inputs and Operating Assumptions. Transmission assumptions for supply-side resources considered are included in Chapter
7. Transmission Planning. Transportation for natural gas is discussed in Chapter 8. Planning Period Forecasts.

Guideline 6: Conservation
a. Each utility should ensure that a conservation potential study is conducted periodically
for its entire service territory.
Idaho Power response:
The contractor-provided conservation potential study for the 2021 IRP and is described in Chapter 6. Demand-Side
Resources.

b. To the extent that a utility controls the level of funding for conservation programs in its
service territory, the utility should include in its action plan all best cost/risk portfolio
Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 109
conservation resources for meeting projected resource needs, specifying annual savings
targets.
Idaho Power response:
A forecast for energy efficiency effects is provided in Chapter 6. Demand-Side Resources. The load forecast into AURORA
includes the reduction to customer sales of all future achievable economic energy efficiency potential. In addition to the
baseline energy efficiency potential, the company modeled extra bundles of achievable technical energy efficiency and their
costs in the AURORA model.

c. To the extent that an outside party administers conservation programs in a utility’s
service territory at a level of funding that is beyond the utility’s control, the utility
should:
• Determine the amount of conservation resources in the best cost/risk portfolio
without regard to any limits on funding of conservation programs; and
• Identify the preferred portfolio and action plan consistent with the outside
party’s projection of conservation acquisition.
Idaho Power response:
Idaho Power administers all its conservation programs except market transformation. Treatment of third-party market transformation savings was provided by the Northwest Energy Efficiency Alliance (NEEA) and is discussed in Appendix B: Idaho Power’s Demand-Side Management 2020 Annual Report. NEEA savings are included as savings to meet targets because of the overlap of NEEA initiatives and IPC’s most recent potential study.

Guideline 7: Demand Response
Plans should evaluate demand response resources, including voluntary rate programs, on
par with other options for meeting energy, capacity, and transmission needs (for electric
utilities) or gas supply and transportation needs (for natural gas utilities).
Idaho Power response:
Demand response resources are evaluated in Chapter 6. Demand-Side Resources.
As part of the 2021 IRP’s rigorous examination of the potential for expanded demand response, Idaho Power utilized a
Northwest Power and Conservation Council (NWPCC) assessment of DR potential for the Northwest region to determine the DR potential that may be available in Idaho Power’s service area. Based on this assessment, Idaho Power estimated 584 MW of DR potential in its service area and concluded that any needed capacity from DR would be shifted to later hours of the day than what the current DR programs were designed for. Efforts to redesign each of Idaho Power’s current programs to better align with system needs took place over the summer and early fall of 2021. Based on the results of the analysis, Idaho Power submitted filings with both the IPUC and OPUC to modify the program parameters.

Guideline 8: Environmental Costs
a. Base case and other compliance scenarios: The utility should construct a base-case
scenario to reflect what it considers to be the most likely regulatory compliance future
for carbon dioxide (CO2), nitrogen oxides, sulfur oxides, and mercury emissions.
Compliance with State of Oregon IRP Guidelines
Page 110 2021 Integrated Resource Plan—Appendix C
The utility should develop several compliance scenarios ranging from the present CO2
regulatory level to the upper reaches of credible proposals by governing entities.
Each compliance scenario should include a time profile of CO2 compliance requirements.
The utility should identify whether the basis of those requirements, or “costs,” would be
CO2 taxes, a ban on certain types of resources, or CO2 caps (with or without flexibility
mechanisms such as an allowance for credit trading as a safety valve). The analysis
should recognize significant and important upstream emissions that would likely have a
significant impact on resource decisions. Each compliance scenario should maintain
logical consistency, to the extent practicable, between the CO2 regulatory requirements
and other key inputs.
Idaho Power response:
The carbon price forecasts used in the 2021 IRP are found in Chapter 9. Portfolios. Compliance with existing environmental
regulation and emissions for each portfolio are discussed in Chapter 10. Modeling Analysis and Results. Emissions for each
portfolio are shown in the Technical Appendix.

b. Testing alternative portfolios against the compliance scenarios: The utility should
estimate, under each of the compliance scenarios, the present value revenue
requirement (PVRR) costs and risk measures, over at least 20 years, for a set of
reasonable alternative portfolios from which the preferred portfolio is selected. The
utility should incorporate end-effect considerations in the analyses to allow for
comparisons of portfolios containing resources with economic or physical lives that
extend beyond the planning period. The utility should also modify projected lifetimes as
necessary to be consistent with the compliance scenario under analysis. In addition, the
utility should include, if material, sensitivity analyses on a range of reasonably possible
regulatory futures for nitrogen oxides, sulfur oxides, and mercury to further inform the
preferred portfolio selection.
Idaho Power response:
See Chapter 9. Portfolios and Chapter 10. Modeling Analysis and Results for discussion on the various scenarios and
comparative analysis of the scenarios. The company also evaluated coal unit conversions to natural gas fuel as a compliance
alternative in the portfolios.

c. Trigger point analysis: The utility should identify at least one CO2 compliance “turning
point” scenario, which, if anticipated now, would lead to, or “trigger” the selection of a
portfolio of resources that is substantially different from the preferred portfolio. The
utility should develop a substitute portfolio appropriate for this trigger-point scenario
and compare the substitute portfolio’s expected cost and risk performance to that of
the preferred portfolio – under the base case and each of the above CO2 compliance
scenarios. The utility should provide its assessment of whether a CO2 regulatory future
that is equally or more stringent that the identified trigger point will be mandated.
Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 111
Idaho Power response:
See Chapter 9. Portfolios and Chapter 10. Modeling Analysis and Results for discussion on the various scenarios and
comparative analysis of the scenarios.

d. Oregon compliance portfolio: If none of the above portfolios is consistent with Oregon
energy policies (including state goals for reducing greenhouse gas emissions) as those
policies are applied to the utility, the utility should construct the best cost/risk portfolio
that achieves that consistency, present its cost and risk parameters, and compare it to
those in the preferred and alternative portfolios.
Idaho Power response:
The company evaluated “100% Clean by 2035” and “100% Clean by 2045” scenarios. The results of the portfolios are
presented in the Technical Appendix.

Guideline 9: Direct Access Loads
An electric utility’s load-resource balance should exclude customer loads that are effectively
committed to service by an alternative electricity supplier.
Idaho Power response:
Idaho Power does not have any customers served by alternative electricity suppliers and Idaho Power has no direct
access loads.

Guideline 10: Multi-state Utilities
Multi-state utilities should plan their generation and transmission systems, or gas supply
and delivery, on an integrated-system basis that achieves a best cost/risk portfolio for all
their retail customers.
Idaho Power response:
Idaho Power’s analysis was performed on an integrated-system basis discussed in Chapter 10. Modeling Analysis and Results.
Idaho Power will file the 2021 IRP in both the Idaho and Oregon jurisdictions.

Guideline 11: Reliability
Electric utilities should analyze reliability within the risk modeling of the actual portfolios
being considered. Loss of load probability, expected planning reserve margin, and expected
and worst-case unserved energy should be determined by year for top-performing
portfolios. Natural gas utilities should analyze, on an integrated basis, gas supply,
transportation, and storage, along with demand-side resources, to reliably meet peak,
swing, and base-load system requirements. Electric and natural gas utility plans should
Compliance with State of Oregon IRP Guidelines
Page 112 2021 Integrated Resource Plan—Appendix C
demonstrate that the utility’s chosen portfolio achieves its stated reliability, cost, and risk
objectives.
Idaho Power response:
The capacity planning margin and regulating reserves are discussed in Chapter 9. Portfolios. A loss of load expectation
analysis and regional resource adequacy are discussed in Chapter 10. Modeling Analysis and Results.

Guideline 12: Distributed Generation
Electric utilities should evaluate distributed generation technologies on par with other
supply-side resources and should consider, and quantify where possible, the additional
benefits of distributed generation.
Idaho Power response:
Distributed generation technologies were evaluated in Chapter 5. Future Supply-Side Generation and Storage Resources and in Chapter 8. Planning Period Forecasts.

Guideline 13: Resource Acquisition
a. An electric utility should, in its IRP:
• Identify its proposed acquisition strategy for each resource in its action plan.
• Assess the advantages and disadvantages of owning a resource instead of
purchasing power from another party.
• Identify any Benchmark Resources it plans to consider in competitive bidding.
Idaho Power response:
Idaho Power identifies its proposed acquisition strategy in Chapter 11. Preferred Portfolio and Action Plan. Idaho Power’s
near-term resource procurement strategy is discussed in Chapter 11. Preferred Portfolio and Action Plan.

b. Natural gas utilities should either describe in the IRP their bidding practices for gas
supply and transportation, or provide a description of those practices following IRP
acknowledgment.
Idaho Power response:
Not applicable.

Compliance with State of Oregon IRP Guidelines
2021 Integrated Resource Plan—Appendix C Page 113
COMPLIANCE WITH EV GUIDELINES
Guideline 1: Forecast the Demand for Flexible Capacity
Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the balancing
reserves needed at different time intervals (e.g., ramping needed within 5 minutes) to
respond to variation in load and intermittent renewable generation over the 20-year
planning period;
Idaho Power response:
A discussion of the 2021 IRP’s analysis for the flexibility guideline is provided in Chapter 9. Portfolios.

Guideline 2: Forecast the Supply for Flexible Capacity
Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing
reserves available at different time intervals (e.g., ramping available within 5 minutes) from
existing generating resources over the 20-year planning period;
Idaho Power response:
A discussion of the planning margin and regulating reserves is found at Chapter 9. Portfolios.

Guideline 3: Evaluate Flexible Resources on a Consistent and
Comparable Basis
In planning to fill any gap between the demand and supply of flexible capacity, the electric
utilities shall evaluate all resource options, including the use of EVs, on a consistent and
comparable basis.
Idaho Power response:
Future supply side resource options are discussed in Chapter 5. Future Supply Side Generation and Storage Resources. Future
demand-side resource options are discussed in Chapter 6. Demand-Side Resources. The adoption rate of EVs is discussed in
Appendix A Sales and Load Forecast.

State of Oregon Action Items
Page 114 2021 Integrated Resource Plan—Appendix C
STATE OF OREGON ACTION ITEMS REGARDING
IDAHO POWER’S 2019 IRP
Action Item 1: Jim Bridger Units 1 and 2
Plan and coordinate with PacifiCorp and regulators for early exits from Jim Bridger units.
Target dates for early exits are one unit during 2022 and a second unit during 2026. Timing
of exit from second unit coincides with the need for a resource addition.
Idaho Power response:
The 2021 IRP evaluates early exit dates of Units 1 and 2 compared to conversion to natural gas operations. The
company will continue to work with its partner PacifiCorp to develop the terms necessary to allow for early exit
or conversion to a non-coal fuel source.

Action Item 2: Solar Hosting Capacity
Incorporate solar hosting capacity into the customer-owned generation forecasts for the
2021 IRP
Idaho Power response:
Solar-hosting capacity was assessed as a driver of the customer-owned generation forecast and was determined
to not materially impact the customer-owned generation forecast. The company will continue to assess the
impact of solar hosting capacity in future iterations of the IRP.
Action Item 3: B2H
Conduct ongoing B2H permitting activities. Negotiate and execute B2H partner construction
agreement(s)
Idaho Power response:
Idaho Power continues to include B2H in the preferred portfolio and action items include permitting,
negotiation and execution of partner construction agreements, preliminary construction activities, acquisition of
long-lead materials, and construction of B2H. Discussion and analysis of the completed planning studies and
permitting and regulatory filing is found in Chapter 7. Transmission Planning. Modeling design and analysis
testing B2H in the 2021 IRP is found in Chapter 9. Portfolios and Chapter 10. Modeling Analysis and Results.
Further details will be provided in Appendix D-Transmission Supplement which is anticipated to be filled in the
first quarter of 2022.
State of Oregon Action Items
2021 Integrated Resource Plan—Appendix C Page 115
Action Item 4: B2H
Conduct preliminary construction activities, acquire long-lead materials, and construct the
B2H project.
Idaho Power response:
Idaho Power continues to include B2H in the preferred portfolio and action items include permitting,
negotiation and execution of partner construction agreements, preliminary construction activities, acquisition of
long-lead materials, and construction of B2H. Discussion and analysis of the completed planning studies and
permitting and regulatory filing is found in Chapter 7. Transmission Planning. Modeling design and analysis testing B2H in the 2021 IRP is found in Chapter 9. Portfolios and Chapter 10. Modeling Analysis and Results.
Further details will be provided in Appendix D-Transmission Supplement which is anticipated to be filled in the
first quarter of 2022.

Action Item 5: VER variability and system reliability
Monitor VER variability and system reliability needs, and study projected effects of
additions of 120 MW of PV solar (Jackpot Solar) and early exit of Bridger units.
Idaho Power response:
The 2020 VER Study was completed, and the results of the study were included in the Regulating Reserve
calculations discussed in Chapter 9. Portfolios.
Action Item 6: Boardman
Exit Boardman December 31, 2020.
Idaho Power response:
The Boardman power plant ceased operation in October 2020.

Action Item 7: Jim Bridger Units 1 and 2
Bridger Unit 1 and Unit 2 Regional Haze Reassessment finalized.
Idaho Power response:
The negotiation between the Environmental Protection Agency (EPA), state of Wyoming, and PacifiCorp to
resolve Jim Bridger units 1 and 2 compliance with the Federal Clean Air Act Regional Haze (RH) rules is
ongoing. On November 15, 2021 Wyoming Governor Gordon issued a notice of intent to sue alleging that EPA
failed to perform a nondiscretionary duty under the Clean Air Act when it failed to approve or disapprove
Wyoming’s RH State Implementation Plan revision for Bridger within the time prescribed by law. On
November 16, 2021 the Wyoming Public Service Commission initiated an investigation to determine the effects
on rates, generation adequacy, system reliability, and other aspects of operations by the potential
discontinuation of operations at Jim Bridger Unit 2 due to the EPA’s inaction on the Wyoming Regional Haze
State Implementation Plan.

State of Oregon Action Items
Page 116 2021 Integrated Resource Plan—Appendix C
Action Item 8: VER Integration
Conduct a VER Integration Study.
Idaho Power response:
Idaho Power worked in conjunction with a Technical Review Committee (TRC) for the development of the 2020
VER Study and retained E3 to conduct the study. The study was filed with the OPUC in docket UM 1730(6).

Action Item 9: North Valmy Unit 2
Conduct focused economic and system reliability analysis on timing of exit from Valmy
Unit 2
Idaho Power response:
Idaho Power conducted a system reliability analysis to evaluate the timing of exit from Valmy Unit 2. The results
of the analysis were filed in IPUC docket IPC-E-21-12 and in OPUC docket LC 74. Additionally, in the 2021 IRP
early exit of Unit 2 was evaluated as part of the AURORA capacity expansion modeling, but the AURORA model
did not select Unit 2 for exit earlier than 2025, see Executive Summary. Action Plan and Chapter 8. Planning
Period Forecasts.

Action Item 10: Jim Bridger Units 1 and 2
Continue to evaluate and coordinate with PacifiCorp for timing of exit/closure of remaining
Jim Bridger units.
Idaho Power response:
The 2021 IRP evaluates early exit dates compared to conversion of Units 1 and 2 to natural gas. The company
will continue to work with its partner PacifiCorp to develop the terms necessary to allow for early exit or
conversion to a non-coal fuel source.

Action Item 11: Jim Bridger Units 1 or 2
Subject to coordination with PacifiCorp, exit Jim Bridger unit (as yet undesignated) by
December 31, 2022
Idaho Power response:
In the 2021 IRP analysis, Jim Bridger units 1 and 2 have been identified for conversion to natural gas operations,
with a 2034 exit date.

State of Oregon Action Items
2021 Integrated Resource Plan—Appendix C Page 117
Action Item 12: Jackpot Solar
Jackpot Solar 120 MW on-line December 2022.
Idaho Power response:
Late in the 2021 IRP development process, the project developer informed Idaho Power they may not be able to
meet the in-service date specified in the contract. For IRP purposes, all cases assumed Jackpot Solar was in-
service per the terms of the contract; however, if Jackpot Solar is not online in 2023, the company will have additional load and resource balance deficits in 2023. Given the near-term nature of this possible deficit, the
company’s operations teams are evaluating options.

Action Item 13: North Valmy Unit 2
Exit Valmy Unit 2 by December 31, 2022.
Further analysis will be conducted to evaluate the optimal exit date of Valmy Unit 2,
weighing exit economics and system reliability concerns.
Idaho Power response:
Idaho Power conducted a system reliability analysis to evaluate the timing of exit from Valmy Unit 2. The results
of the analysis were filed in IPUC docket IPC-E-21-12 and in OPUC docket LC 74. Additionally, in the 2021 IRP
early exit of Unit 2 was evaluated as part of the AURORA capacity expansion modeling, but the AURORA model
did not select Unit 2 for exit earlier than 2025, see Chapter 8. Planning Period Forecasts.

Action Item 14: Jim Bridger Units 1 or 2
Subject to coordination with PacifiCorp, exit Jim Bridger unit (as yet undesignated) by
December 31, 2026. Timing of the exit from the second Jim Bridger unit is tied to the need
for a resource addition (B2H).
Idaho Power response:
In the 2021 IRP analysis, Jim Bridger units 1 and 2 have been identified for conversion to natural gas operations,
with a 2034 exit date.

State of Oregon Action Items
Page 118 2021 Integrated Resource Plan—Appendix C