2023 Integrated
Resource Plan
IRP filing for submission to the
California Energy Commission
Pasadena Water and Power
Attachment A
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TABLE OF CONTENTS
1. Acronyms Used in PWP’s IRP 16
2. Disclaimer 19
3. Executive Summary 19
4. Introduction 22
4.1. Introduction ...................................................................................................................................................................... 22
4.2. Pasadena Water and Power Department ............................................................................................................... 24
4.2.1. Pasadena Executive Management and Governing Bodies .............................................................................................................. 27
4.2.2. Regulatory Agencies ........................................................................................................................................................................................ 28
4.3. Statutory Mandate for Integrated Resource Plans .............................................................................................. 29
4.4. Community Outreach ..................................................................................................................................................... 30
4.5. Integrated Resource Plan Objectives ....................................................................................................................... 31
4.6. Integrated Resource Plan Process and Timeline ................................................................................................. 32
4.7. 2023 Integrated Resource Plan Timeline .............................................................................................................. 32
5. Previous Integrated Resource Plans 33
6. Existing Policies and Programs 34
6.1. Distributed Solar ............................................................................................................................................................. 35
6.1.1. Current Programs ............................................................................................................................................................................................. 35
6.1.2. Net Energy Metering ........................................................................................................................................................................................ 35
6.1.3. Community Solar ............................................................................................................................................................................................... 36
6.2. Electric Vehicles ............................................................................................................................................................... 36
6.2.1. Current Electric Vehicle Incentives ........................................................................................................................................................... 37
6.2.2. Current Electric Vehicle Outreach ............................................................................................................................................................. 37
6.2.3. Current Electric Vehicle Fleet ...................................................................................................................................................................... 37
6.2.4. EV Charging Stations ....................................................................................................................................................................................... 40
6.2.5. Pasadena’s Department of Transportation Initiatives ..................................................................................................................... 41
6.2.6. Vehicle-to-Grid Charging ............................................................................................................................................................................... 41
6.3. Energy Efficiency ............................................................................................................................................................. 42
6.3.1. Current Program Incentives ......................................................................................................................................................................... 42
6.3.2. Residential Programs ...................................................................................................................................................................................... 43
6.3.3. Energy Efficiency Regulations ..................................................................................................................................................................... 44
6.3.4. Energy Efficiency Forecast and Goals ...................................................................................................................................................... 46
6.4. Demand Response .......................................................................................................................................................... 47
6.4.1. Current Demand Response Programs ..................................................................................................................................................... 47
6.4.2. Future Demand Response Programs ........................................................................................................................................................ 48
6.5. Green Power Program ................................................................................................................................................... 48
6.5.1. Residential Green Power Program ............................................................................................................................................................ 48
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6.5.2. Commercial Green Power Program .......................................................................................................................................................... 48
6.6. Low‐Income Assistance Programs ............................................................................................................................ 48
6.6.1. Income-Qualified Programs ......................................................................................................................................................................... 49
6.6.2. General Bill Assistance ................................................................................................................................................................................... 50
7. Public Participation 50
7.1. Stakeholder Technical Advisory Group .................................................................................................................. 52
7.2. STAG Meetings .................................................................................................................................................................. 52
7.3. Community Meetings ..................................................................................................................................................... 53
7.4. Public Outreach ............................................................................................................................................................... 53
7.5. Municipal Service Committee and Environmental Advisory Commission Meetings .............................. 53
8. Environmental Regulations and Priorities 53
8.1. PWP’s Environmental Priorities ................................................................................................................................ 53
8.2. Renewable Portfolio Standard and Zero‐Carbon Regulations ........................................................................ 54
8.2.1. State Compliance ............................................................................................................................................................................................... 55
8.3. Cap‐and‐Trade Regulation ........................................................................................................................................... 58
8.4. Other Environmental Points of Note ........................................................................................................................ 59
8.4.1. Power Source Disclosure Program ........................................................................................................................................................... 59
8.4.2. The Cost Impacts of 100% by 2045 .......................................................................................................................................................... 59
8.4.3. Social Cost of Carbon ....................................................................................................................................................................................... 60
9. Resource Adequacy 60
9.1. System Resource Adequacy and Reserve Margin ................................................................................................ 61
9.2. Local Resource Adequacy Capacity ........................................................................................................................... 62
9.3. Flexible Resource Adequacy Capacity ..................................................................................................................... 63
9.4. Slice of Day Proposal ...................................................................................................................................................... 64
9.4.1. Reliability Must-Run Resources ................................................................................................................................................................. 64
10. Model Assumptions 66
10.1. Planning Horizon (POUs) ............................................................................................................................................. 66
10.2. Model ................................................................................................................................................................................... 66
10.3. Model Topology ............................................................................................................................................................... 68
10.4. Power and Fuel Prices ................................................................................................................................................... 69
10.4.1. More About Horizons Energy, LLC’s Forecasting Method .............................................................................................................. 71
10.5. Transmission and Congestion .................................................................................................................................... 72
10.6. Load vs. Resources .......................................................................................................................................................... 73
11. Resources 75
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11.1. Existing Resources .......................................................................................................................................................... 75
11.1.1. Coal .......................................................................................................................................................................................................................... 77
11.1.2. Natural Gas ........................................................................................................................................................................................................... 77
11.1.3. Wind ........................................................................................................................................................................................................................ 78
11.1.4. Landfill Gas .......................................................................................................................................................................................................... 78
11.1.5. Solar ........................................................................................................................................................................................................................ 78
11.1.6. Hydro ...................................................................................................................................................................................................................... 78
11.1.7. Nuclear ................................................................................................................................................................................................................... 78
11.1.8. Geothermal .......................................................................................................................................................................................................... 78
11.2. New Resources ................................................................................................................................................................. 78
11.2.1. New Resource Options ................................................................................................................................................................................... 78
11.2.2. New Resource Parameters ............................................................................................................................................................................ 79
11.2.3. Availability of New Resources ..................................................................................................................................................................... 82
11.2.4. Inflation Reduction Act and Tax Credits ................................................................................................................................................. 83
11.2.5. Contract vs. Ownership and Tax Credits ................................................................................................................................................ 86
11.2.6. Cost of New Resources: The General Market ........................................................................................................................................ 87
11.2.7. Pasadena in the Market .................................................................................................................................................................................. 88
11.2.8. Spotlight Technologies ................................................................................................................................................................................... 92
11.2.9. How Electricity Products Are Priced ........................................................................................................................................................ 95
11.2.10. Cost vs. Value ...................................................................................................................................................................................................... 97
11.2.11. Transmission Access Charge ........................................................................................................................................................................ 97
11.2.12. Exclusions and Other Notes .......................................................................................................................................................................... 98
11.3. Diversified Procurement Portfolio ........................................................................................................................... 98
12. Load Forecast 99
12.1. Requirements ................................................................................................................................................................... 99
12.2. Integrated Energy Policy Report and California Energy Demand Forecast ............................................ 100
12.3. Integrated Resource Plan Method ......................................................................................................................... 102
12.3.1. Additional Achievable Energy Efficiency ............................................................................................................................................. 104
12.3.2. Additional Achievable Fuel Substitution ............................................................................................................................................. 107
12.3.3. Distributed Solar ............................................................................................................................................................................................ 108
12.3.4. Distributed Storage ....................................................................................................................................................................................... 109
12.3.5. Time-of-Use Rates .......................................................................................................................................................................................... 110
12.3.6. Vehicle Electrification .................................................................................................................................................................................. 112
12.3.7. Climate Change ................................................................................................................................................................................................ 116
12.3.8. Native Load ....................................................................................................................................................................................................... 116
12.3.9. CAISO Metered Load ..................................................................................................................................................................................... 117
13. Transmission and Distribution 123
13.1. Bulk Transmission System ....................................................................................................................................... 123
13.2. Bulk Transmission Planning .................................................................................................................................... 123
13.3. Distribution System Planning .................................................................................................................................. 123
14. Localized Pollutants and Disadvantaged Communities 125
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14.1. Emissions Reduction ................................................................................................................................................... 126
14.2. Expanding Transportation Electrification in Pasadena’s DAC .................................................................... 127
14.2.1. EV Rebates and Incentives ......................................................................................................................................................................... 127
14.2.2. Efficiency and Assistance Programs ...................................................................................................................................................... 128
14.3. Supporting Underserved Communities in the Future..................................................................................... 129
15. Defining Scenarios 129
15.1. Scenarios vs. Sensitivities ......................................................................................................................................... 129
15.2. Important Definitions for Scenarios ..................................................................................................................... 130
15.3. Scenario 1: 100% Carbon‐Free by 2030 with No Limit on Internal Resources ..................................... 134
15.4. Scenario 2: 100% Carbon‐Free by 2030 with a Limit on Internal Resources ........................................ 134
15.5. Scenario 3: 100% Carbon‐Free by 2030 with a Limit on Internal Reso urces and Doubled Distributed Resources ............................................................................................................................................................ 135
15.6. Scenario 4: Reference Case (SB 1020) .................................................................................................................. 136
15.7. Scenario 5: Reference Case + Social Cost of Carbon (SB 1020 + SCC) ........................................................ 136
15.8. Scenario 6: Emerging Technology Study .............................................................................................................. 138
15.8.1. Scenario 6: Energy Efficiency Proxy ...................................................................................................................................................... 139
15.8.2. Scenario 6: Demand Response Proxy .................................................................................................................................................... 139
15.9. Modeling a Carbon‐Free Resource Scenario ...................................................................................................... 139
15.10. PWP’s Starting Position ............................................................................................................................................. 141
16. Defining Sensitivities 145
16.1. Sensitivity 1: Heat Wave ............................................................................................................................................ 146
16.1.1. Sensitivity 1: Heat Wave: Data Scraping and Cleaning .................................................................................................................. 147
16.1.2. Sensitivity 1: Heat Wave: Normal Data Creation ............................................................................................................................. 147
16.1.3. Sensitivity 1: Heat Wave: Training Datasets Creation ................................................................................................................... 147
16.1.4. Sensitivity 1: Heat Wave: Prediction Data Creation ....................................................................................................................... 148
16.1.5. Sensitivity 1: Heat Wave: Model Creation and Prediction ........................................................................................................... 148
16.2. Sensitivity 2: Goodrich Transfer Contingency ................................................................................................... 151
16.2.1. Sensitivity 2: Goodrich in 2030 Under Forecasted Normal Operating Conditions ........................................................... 151
16.2.2. Sensitivity 3: High Technology Costs .................................................................................................................................................... 152
16.2.3. Sensitivity 4: Low Technology Costs ..................................................................................................................................................... 152
17. Scenarios and Sensitivities Results 152
17.1. Scenario 1: 100% Carbon‐Free by 2030 (No Limit on Internal Resources) ............................................ 152
17.2. Scenario 2: 100% Carbon‐Free by 2030 – Maximum Limit on Internal Resources ............................. 162
17.3. Scenario 3: 100% Carbon‐Free by 2030 (Maximum Limit on Internal Resources and Doubled Distributed Resources)........................................................................................................................................................... 167
17.4. Scenario 4: Reference Cas e (SB 1020) .................................................................................................................. 172
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17.5. Scenario 5: Reference Case Plus Social Cost of Carbon ................................................................................... 178
17.6. Scenario 6: Emerging Technologies Study Scenario ........................................................................................ 184
17.6.1. Scenario 6: Energy Efficiency Proxy ...................................................................................................................................................... 184
17.6.2. Scenario 6: Demand Response Proxy .................................................................................................................................................... 185
17.7. Scenario Comparisons ................................................................................................................................................ 185
17.8. Sensitivity 1: Heat Wave ............................................................................................................................................ 192
17.9. Sensitivity 2: Goodrich Transfer Contingency ................................................................................................... 197
18. Battery Storage 199
18.1. Storage in the IRP ......................................................................................................................................................... 199
18.2. Storage: Over‐Generation and Evening Ramps ................................................................................................. 200
18.3. Addressing Net Demand in Peak Hours ............................................................................................................... 203
19. Financial Impacts 204
19.1. Present Value Revenue Requirements ................................................................................................................. 204
19.2. Scenario 3 and Distributed Resources ................................................................................................................. 209
19.3. Scenario 5 and the Carbon Tax ................................................................................................................................ 210
19.4. Scenarios and Cap‐and‐Trade Interactions ........................................................................................................ 211
20. Retail Rates 212
21. Greenhouse Gas Emissions 217
21.1. Cap‐and‐Trade Program ............................................................................................................................................ 218
21.2. Carbon Emissions Netting Market Interactions at CAISO Average Carbon Content ............................ 218
21.3. RPS (SB 100) .................................................................................................................................................................. 220
21.4. Renewable and Zero‐Carbon (SB 1020) ............................................................................................................... 221
21.5. Carbon‐Free Hourly (Resolution 9977) ............................................................................................................... 221
21.6. GEAT .................................................................................................................................................................................. 222
22. Implementation Steps – Carbon-Free Pathways 223
22.1. PWP’s Proactive Carbon‐Free Procurement Actions ...................................................................................... 225
22.1.1. Utility-Scale Photovoltaic Solar + Battery ........................................................................................................................................... 226
22.1.2. Geothermal ....................................................................................................................................................................................................... 226
22.1.3. Additional Battery (Local) ......................................................................................................................................................................... 226
22.2. Resource Procurement Guided by the Results of this IRP............................................................................. 226
22.3. Supplemental Near‐Term Actions .......................................................................................................................... 227
22.3.1. Explore DER Expansion and Refine Planning for Internal Resource Sizes and Placement; Revisit the PDMP .... 228
22.3.2. Support Mass Transit and Electric Vehicle Fleet Development, Focusing on Electric Buses (City and School); Pursue Vehicle-to-Grid Charging Opportunities ................................................................................................................................................... 228
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22.3.3. Perform a More Extensive Study on the Future of Glenarm ....................................................................................................... 228
22.3.4. Prepare for a Significant Increase in Expenditures Over the Next 20 Years ....................................................................... 229
22.3.5. Perform a Cost-of-Service Study, Rate Impact Study, and Rate Ordinance Proposal ...................................................... 229
22.3.6. Investigate Rate Structure: Time-of-Use Rates, the Next Net Energy Metering Program, Electric Vehicle Charging Rates, Low-Income Assistance, Any Changes to Customer Incentives or Subsidies, Etc. ................................................................... 229
22.3.7. Expand Demand-Side Management; Explore Advanced Metering Infrastructure Connection Incentives ............ 229
22.3.8. Determine the Future of PWP’s Green Power Program ............................................................................................................... 229
22.3.9. Monitor the Influence of the Building Electrification Ordinance After It Becomes Effective in 2025 ..................... 230
22.3.10. Update the Pasadena Utility Code, Electrical Code, and Fire Code (for Batteries, Hydrogen Fuel Cells, etc.) ...... 230
22.3.11. Continue to Monitor Emerging Technology Developments ........................................................................................................ 230
22.4. Timeline The Longer‐Range Outlook .................................................................................................................... 230
23. Appendix - Required Tables 232
23.1. Capacity Resource Accounting Table .................................................................................................................... 232
23.2. Energy Balance Table (Scenario 4 Example) ...................................................................................................... 233
24. Appendix – Integrated Resource Plan Contrac t and Resource Roles 235
25. Appendix – Opportunities for Future Studies and Analysis 236
26. Appendix - Model Parameters and Additional Reliability Metrics 240
27. Appendix – Cost of New Resources 249
27.1. Utility‐Scale Solar ......................................................................................................................................................... 249
27.2. Commercial Solar ......................................................................................................................................................... 250
27.3. Residential Solar .......................................................................................................................................................... 251
27.4. Utility‐Scale 4‐Hour Storage ..................................................................................................................................... 252
27.5. Utility‐Scale 6‐Hour Storage ..................................................................................................................................... 253
27.6. Utility‐Scale 8‐Hour Storage ..................................................................................................................................... 254
27.7. Utility‐Scale 10‐Hour Storage .................................................................................................................................. 255
27.8. Commercial 4‐Hour Storage ............................................................................................................................... ...... 256
27.9. Residential 2.5‐Hour Storage ................................................................................................................................... 257
27.10. Fuel Cells ......................................................................................................................................................................... 258
27.11. Land‐Based Wind ......................................................................................................................................................... 259
27.12. Offshore Wind ............................................................................................................................................................... 260
27.13. Geothermal ...................................................................................................................... Error! Bookmark not defined.
1. Executive Summary 265
2. Disclaimer 266
3. Portfolio Content Category Requirements 266
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4. Renewable Portfolio Standard Procurement Plan 268
4.1. Supply vs. Load .............................................................................................................................................................. 268
5. Compliance Strategy 269
6. Balanced Portfolio 270
7. PWP’s Renewable Portfolio Standard a nd Carbon-Free Strategy 270
8. PWP’s Renewable Portfolio Standard Procurement Process 271
8.1. Quantitative Analysis .................................................................................................................................................. 272
8.2. Qualitative Analysis..................................................................................................................................................... 272
9. Summary of Renewable Portfolio Standa rd Procurement Plan 273
10. Renewable Portfolio Standard Procurement Plan Limitations and Relief 277
11. Version History 277
28. Purpose 283
29. Renewable Portfolio Standard Procurement Plan Guidelines 283
29.1. Compliance Periods ..................................................................................................................................................... 283
29.2. State RPS Procurement Targets .............................................................................................................................. 283
29.3. Portfolio Content Category Definition and Balance Requirements ........................................................... 285
29.4. Long‐Term Contracts .................................................................................................................................................. 288
29.5. Additional Requirements .......................................................................................................................................... 288
29.6. City Council Discretion ............................................................................................................................................... 288
29.7. Review of the Renewable Portfolio Standard Procurement Plan ............................................................... 289
30. Public Notice for the Renewable Portfolio Standard Procurement Plan 289
31. Excess Procurement 289
32. Renewable Energy Procurement in Excess of Statutory P rocurement Targets 290
33. Renewable Portfolio Standard Enforcement Plan Limitations and Relief 291
34. Reporting 294
35. Enforcement 294
36. Version History 295
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Table of Figures
Figure 1: Acronyms ............................................................................................................................................................... 16 Figure 2: California Energy Commission Guidelines and Location ........................................................................................ 22 Figure 3: Comparison of System Average Interruption Frequency Index and System Average Interruption Duration Index .............................................................................................................................................................................................. 25 Figure 4: Average Residential Bills, Measured at 750 kWh/Month ...................................................................................... 26 Figure 5: Average Commercial Bills, Measured at 3,500 kWh/Month (May 2023) .............................................................. 27 Figure 6: California Energy Commission Requirements ........................................................................................................ 30
Figure 7: PWP's 2023 Integrated Resource Plan Timeline .................................................................................................... 33 Figure 8: 2018 Integrated Resource Plan Progress ............................................................................................................... 33 Figure 9: 2021 Integrated Resource Plan Update Progress .................................................................................................. 34 Figure 10: Total Light‐Duty Electric Vehicles on Grid ............................................................................................................ 39 Figure 11: Annual Sales of Light‐Duty El
ectric Vehicles ........................................................................................................ 39 Figure 12: Map of Electric Vehicle Chargers in PWP’s Territory ........................................................................................... 41 Figure 13: PWP's Actual Cumulative Energy Efficiency Savings ............................................................................................ 44 Figure 14: Past Public Benefit Charge Budgets ..................................................................................................................... 45 Figure 15: Estimated Greenhouse Gas Emissions from Existing Homes and Businesses ..................................................... 45 Figure 16: Incremental Energy Efficiency Savings (MWh) .................................................................................................... 46 Figure 17: Incremental Energy Efficiency Savings (MW) ...................................................................................................... 47 Figure 18: Impact of Energy Efficiency and Customer‐Owned Generation on Electric Sales ............................................... 47 Figure 19: Low‐Income (Electric Utility Assistance Program) ............................................................................................... 49 Figure 20: California Alternate Rates for Energy (Age or Disability Qualification) ............................................................... 49 Figure 21: California Alternate Ra
tes for Energy Plus (Age or Disability Qualification) ........................................................ 49 Figure 22: Comparison of the Composition of the 2018 STAG and the 2023 STAG ............................................................. 52 Figure 23: Renewable Portfolio Standard: Key Legislative Actions in California .................................................................. 54 Figure 24: Se
nate Bill 100 and Senate Bill 1020 Requirements ............................................................................................ 55 Figure 25: Portfolio Content Categories ............................................................................................................................... 56 Figure 26: RPS and Zero‐Carbon Modeled Requirements .................................................................................................... 57 Figure 27: Solar Resource Adequacy Accreditation .............................................................................................................. 62 Figure 28: EnCompass Power Planning Software ................................................................................................................. 67 Figure 29: PWP Integrated Resource Plan Critical Model Constraints ................................................................................. 68 Figure 30: Model Topology ................................................................................................................................................... 68 Figure 31: SP15 7x24 Power Prices ....................................................................................................................................... 70 Figure 32: Fuel Prices ............................................................................................................................................................ 70 Figure 33: Fuel Pricing Assumed in PWP’s 2023 Integrated Resource Plan ......................................................................... 71 Figure 34: Transmission Access Charge Forecast .................................................................................................................. 73 Figure 35: Resources by Lo
cation ......................................................................................................................................... 74 Figure 36: Resource Category by Size ................................................................................................................................... 74 Figure 37: Owned and Contracted Resources ...................................................................................................................... 75 Figure 38: Contracts for Renewable Energy ......................................................................................................................... 76 Figure 39: New Resource Parameters ................................................................................................................................... 79
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Figure 40: Resource Adequacy Accreditation for New Resources ........................................................................................ 81 Figure 41: Bonus Tax Credits for Renewable Resources ....................................................................................................... 84 Figure 42: IRA Tax Credits for Projects in Service After December 2024 ............................................................................. 85 Figure 43: PWP 2023 Integrated Resource Plan Tax Credit Assumptions ............................................................................ 85 Figure 44: Domestic Content Requirements ......................................................................................................................... 87 Figure 45: Reference Market Prices ...................................................................................................................................... 88 Figure
46: Utility‐Scale Solar Nominal Pricing ....................................................................................................................... 89 Figure 47: Utility‐Scale Solar Pricing in Real 2023 $ .............................................................................................................. 90 Figure 48: Real vs. Nominal Values ....................................................................................................................................... 91 Figure 49: Real vs. Nominal Levelized Cost of Energy ........................................................................................................... 91 Figure 50: Different Components of Electricity .................................................................................................................... 95 Figure 51: Different Components of Electricity by Resource Type ....................................................................................... 96 Figure 52: Cost of New Energy Resources ............................................................................................................................ 96 Figure 53: Cost of New Capacity Resources .......................................................................................................................... 97 Figure 54: Transmission Access Charge ................................................................................................................................ 98 Figure 55: Diversity in Load Consumption and Resource Generation .................................................................................. 99 Figure 56: California Energy Demand Forecast Components ............................................................................................. 100 Figure 57: PWP Peak Demand............................................................................................................................................. 103 Figure 58: PWP Energy ........................................................................................................................................................ 104 Figure 59: Technical, Economic, and Market Potential for Energy Efficiency .................................................................... 106 Figure 60: Additional Achievable Energy Efficiency in PWP’s 2023 Integrated Resource Plan .......................................... 107 Figure 61: Additional Achievable Energy Efficiency Percent Reduct ion in Load................................................................. 107 Figure 62: AAFS in PWP’s 2023 IRP ..................................................................................................................................... 108 Figure 63: Distributed Solar in PWP’s 2023 IRP .................................................................................................................. 109 Figure 64: Distributed Storage in 2023 IRP ......................................................................................................................... 110 Figure 65: Time‐of‐Use Rates in PWP’s 2023 Integrated Resource Plan ............................................................................ 111 Figure 66: Average Hourly Impact of Ti
me‐of‐Use Rates in PWP’s 2023 Integrated Resource Plan .................................. 111 Figure 67: Transportation Electrification in PWP’s 2023 Integrated Resource Plan .......................................................... 113 Figure 68: Light‐Duty Electric Vehicle Penetration in PWP’s 2023 Integrated Resource Plan ........................................... 113 Figure 69: Average Hourly Shape for Light‐Duty El ectric Vehicles ..................................................................................... 114 Figure 70: Average Hourly Shape for Medium/Heavy‐Duty Electric Vehicles .................................................................... 114 Figure 71: Average Hourly Load Profile .............................................................................................................................. 115 Figure 72: PWP’s Historical Load ........................................................................................................................................ 116 Figure 73: Percent of PWP Peak During Southern California Edison’s Peak ....................................................................... 117 Figure 74: Load Forecast ..................................................................................................................................................... 118 Figure
75: CAISO Metered Load by Component ................................................................................................................. 119 Figure 76: Hour of CAISO Peak Metered Load .................................................................................................................... 119 Figure 77: PWP Load Comparison ....................................................................................................................................... 121 Figure 78: Average Hourly Load .......................................................................................................................................... 121 Figure 79: Load Duration Curve .......................................................................................................................................... 122 Figure 80: Load Duration Curv e Inflection Points ............................................................................................................... 122 Figure 81. Simplified Diagram of PWP's Sub‐Transmission System .................................................................................... 124
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Figure 82: PWP’s CalEnvironScreen 4.0 Identified Disadvantaged Area Communities ...................................................... 126 Figure 83: Scenario vs. Emerging Technology Scenario vs. Sensitivity ............................................................................... 130 Figure 84: Internal vs. External ........................................................................................................................................... 131 Figure 85: Utility‐Scale or Distributed? ............................................................................................................................... 132 Figure 86: Renewable vs. Zero‐Carbon vs. Carbon‐Free ..................................................................................................... 133 Figure 87: Scenarios ............................................................................................................................................................ 134 Figure 88: Distributed Resources in Load Forecast ............................................................................................................. 135 Figure
89: Social Cost of Carbon ......................................................................................................................................... 137 Figure 90: Carbon Intensity of CAISO .................................................................................................................................. 138 Figure 91: Potential Emerging Technologies ....................................................................................................................... 138 Figure 92: Island vs. Market Access .................................................................................................................................... 140 Figure 93: PWP’s Existing Cumulative Installed Capacity ................................................................................................... 141 Figure 94: PWP’s Firm Capacity Position without Re
source Additions ............................................................................... 142 Figure 95: PWP’s Firm Capacity Position without Resource Additions ............................................................................... 143 Figure 96: Energy Position without Resource Additions ..................................................................................................... 144 Figure 97: Renewable Position without Resource Additions .............................................................................................. 145 Figure 98: Sensitivities ........................................................................................................................................................ 145 Figure 99: Sensitivity Metrics ............................................................................................................................... ............... 146 Figure 100: Peak Load in 2030 ............................................................................................................................................ 146 Figure 101: Heat Wave Data Creation ................................................................................................................................ 149 Figure 102: Simulated Temperatures Under a Heat Wave ................................................................................................. 150 Figure 103: Wind and Solar Profiles Under Heat Wave ...................................................................................................... 150 Figure 104: Heat Wave Prices ............................................................................................................................................. 151 Figure 105: Deman d vs. Goodrich in 2030 .......................................................................................................................... 152 Figure 106: Scenario 1: New Cumulative Installed Capacity ............................................................................................... 152 Figure 107: Scenario 1: Cumulative Installed Capacity by Location ................................................................................... 153 Figure 108: Scenario 1: Summer Resource Adequacy ........................................................................................................ 155 Figure 109: Scenario 1: Winter Resource Adequacy ........................................................................................................... 155 Figure 110: Scenario 1 Resource Adequacy Position .......................................................................................................... 156 Figure 111: Sce
nario 1: Consecutive Model Runs ............................................................................................................... 157 Figure 112: Summer vs. Winter Peaks ................................................................................................................................ 158 Figure 113: Scenario 1: Island – Resources That Load, Storage Charging, and Market Sales are Served By ...................... 158 Figure 114: Scenario 1: Energy Market Access – Energy Position ...................................................................................... 159 Figure 115: CAISO Excess: What is it Worth? ...................................................................................................................... 160 Figure 116: Scen
ario 1: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served By ............................................................................................................................................................................................ 160 Figure 117: Scenario 2: New Cumulative Installed Capacity ............................................................................................... 162 Figure 118: Scenario 2: Cumulative Installed Capacity by Location................................................................................... 162 Figure
119: Scenario 2: Summer Resource Adequacy ........................................................................................................ 164 Figure 120: Scenario 2 Resource Adequacy Position .......................................................................................................... 164 Figure 121: Scenario 2: Island – Resources That Load, Storage Charging, and Market Sales are Served by ...................... 166
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Figure 122: Scenario 2: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served by ............................................................................................................................................................................................ 166 Figure 123: Scenario 2: Energy Market Access – Energy Position ...................................................................................... 167 Figure 124: Scenario 3: New Cumulative Installed Capacity ............................................................................................... 168 Figure 125: Scenario 3: Cumulative Installed Capacity by Location ................................................................................... 169 Figure 126: Sce
nario 3: Summer Resource Adequacy ........................................................................................................ 170 Figure 127: Scenario 3: Resource Adequacy Position ......................................................................................................... 170 Figure 128: Scenario 3: Island – Resources That Load, Storage Charging, and Market Sales are Served By ...................... 171 Figure 129: Scenario 3: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Se rved By ............................................................................................................................................................................................ 171 Figure 130: Scenario 3: Energy Market Access – Energy Position ...................................................................................... 172 Figure 131: Scenario 4: New Cumulative Installed Capacity ............................................................................................... 173 Figure 132: Scenario 4: Cumulative Installed Capacity by Location ................................................................................... 173 Figure 133: Scenario 4: Summer Resource Adequacy ........................................................................................................ 175 Figure 134: Sce
nario 4: Resource Adequacy Position ......................................................................................................... 175 Figure 135: Scenario 4: Summer Qualifying Capacity ......................................................................................................... 176 Figure 136: Scenario 4: Resources That Load, Storage Charging, and Market Sales are Served By ................................... 176 Figure 137: Scenario 4: Energy Position .............................................................................................................................. 177 Figure 138: Wind and Solar vs. Alternative Fuels ............................................................................................................... 178 Figure 139: Scenario 5: Installed Capacity .......................................................................................................................... 178 Figure 140: Scenario 5: Cumulative Installed Capacity by Location ................................................................................... 179 Figure 141: Scenario 5: Summer Resource Adequacy ........................................................................................................ 180 Figure 142: Scenario 5: Resource Adequacy Position ......................................................................................................... 180 Figure 143: Average Resource Costs with Carbon Tax (SCC) .............................................................................................. 181 Figure 144: Scenario
5: Resources That Load, Storage Charging, and Market Sales are Served By ................................... 182 Figure 145: Scenario 5: Energy Position .............................................................................................................................. 183 Figure 146: Total Carbon Emissions Under Cap‐and‐Trade (Scenarios 1 through 5).......................................................... 183 Figure 147: Total Portfolio Carbon Emissions (Netting Market Purchases and Sales) ....................................................... 184 Figure 148: Sce
nario 6: Energy Efficiency Proxy – Results .................................................................................................. 185 Figure 149: Scenario 6: Demand Response Proxy: Results ................................................................................................. 185 Figure 150: Installed Capacity of Scenarios ........................................................................................................................ 186 Figure 151: Installed Capacity of Scenarios by Type in 2031 .............................................................................................. 186 Figure 152: Qualifying Capacity of Scenarios in 2031 ......................................................................................................... 187 Figure
153: Internal vs. External Installed Capacity in 2031 ............................................................................................... 187 Figure 154: Installed Capacity Distributed Resources per Scenario – in Addition to Load Forecast .................................. 188 Figure 155: Net Generation of Scenarios in 2031 ............................................................................................................... 189 Figure 156: Renewable Compliance Across Scenarios ........................................................................................................ 190 Figure 157: Renewable Compliance across Scenarios by Type in 2031 .............................................................................. 190 Figure 158: Annual Zero‐Carbon Requirements by Scenarios ............................................................................................ 191 Figure 159: Zero‐Carbon across Scenarios by Type in 2045 ............................................................................................... 191 Figure 160: Carbon‐Free across Scenarios .......................................................................................................................... 192 Figure 161: Heat Wave Sensitivity Results .......................................................................................................................... 192
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Figure 162: Scenario 1: Heat Wave ..................................................................................................................................... 194 Figure 163: Scenario 1: Heat Wave with Goodrich Maximized .......................................................................................... 194 Figure 164: Scenario 2: Heat Wave with Goodrich Maximized .......................................................................................... 195 Figure 165: Scenario 3: Heat Wave Top 10 Additional Energy Need Hours (September 2030) ......................................... 195 Figure 166: Internal Installed Capacity in 2030 for Scenario 2 and 3 ................................................................................. 196 Figure 167: Sce
nario 4: Heat Wave ..................................................................................................................................... 197 Figure 168: Goodrich Transfer Contingency Results ........................................................................................................... 197 Figure 169: Internal Installed Capacity in 2030 Across Scenarios ....................................................................................... 198 Figure 170: Scenario 4 and 5: Additional Energy Needs Under Heat Wave ....................................................................... 198 Figure 171: Illustration of Degradation Strategi
es for Battery Storage .............................................................................. 200 Figure 172: Installed Storage Capacity in 2031 ................................................................................................................... 201 Figure 173: Net Renewable Generation vs. Load in 2031 ................................................................................................... 202 Figure 174: California Eligible Renewable and Carbon‐Free Resources That Do Not Go Toward Hourly .......................... 202 Figure 175: PWP is Selling or Curtailing X% of Load in Renewable/Zero‐Carbon Resources ............................................. 203 Figure 176: Percent of Hours with Negative Net Load in September 2031 ........................................................................ 203 Figure 177: Hourly Load versus Net Load Across Scenarios for Three Days in September 2031 ....................................... 204 Figure 178: Components of PVRR ....................................................................................................................................... 204 Figure 179: Scenario
1: PVRR .............................................................................................................................................. 205 Figure 180: Scenario 2: PVRR .............................................................................................................................................. 206 Figure 181: Scenario 3: PVRR .............................................................................................................................................. 206 Figure 182: Scenario 4: PVRR .............................................................................................................................................. 207 Figure 183: Scenario 5: PVRR .............................................................................................................................................. 207 Figure 184: PVRR By Category Across Scenarios (Mid Costs) ............................................................................................. 208 Figure 185: PVRRs for Mid, High, Low Costs of New Resources ......................................................................................... 208 Figure 186: Pe
rcent Costs are Higher in 20 Years Compared to Scenario 4 (Reference Costs) ......................................... 209 Figure 187: 2030 $/kWh Costs in Addition to Scenario 4 ................................................................................................... 209 Figure 188: Costs of Forced Distributed Energy Resources in Scenario 3 .......................................................................... 209 Figure 189: Costs of Carbon Tax in Scen
ario 5 .................................................................................................................... 210 Figure 190: Present Value Revenue Requirement if Carbon Tax Returned ........................................................................ 211 Figure 191: Carbon Allowance Sale Prices .......................................................................................................................... 212 Figure 192: PVRR with Cap‐and‐Trade Allowance Sales ..................................................................................................... 212 Figure 193: PWP Historical and Budgeted Retail Rates (Nominal Dollars per kWh) .......................................................... 213 Figure 194: PWP Retail Rate Components as Percent of Total ........................................................................................... 214 Figure 195: Costs Included and Excluded from IRP Modeling ............................................................................................ 214 Figure 196: Annual Bill Impacts for Single‐Family Residential Customers (Moderate Cost Estimates) ............................. 216 Figure 197: Annual Bill Impacts for Single‐Family Residential Customers (High‐Cost Estimates) ...................................... 217 Figure 198: Cumulative Emissions Under Cap‐and‐Trade Program .................................................................................... 218 Figure 199: Cumulative Portfolio Emissions Netting CAISO Purchases and Sales .............................................................. 219 Figure 200: Cost of Avoided Carbon ................................................................................................................................... 219 Figure 201: Renewable Traits .............................................................................................................................................. 220 Figure 202: Over/under procureme
nt for compliance period (MWh) ............................................................................... 220 Figure 203: Renewable and Zero‐Carbon Traits ................................................................................................................. 221
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Figure 204: Hourly‐Carbon‐Free Achievements.................................................................................................................. 221 Figure 205: Adjusted Portfolio emissions ........................................................................................................................... 222 Figure 206 Incremental Installation of Resource Under Scenario 2 ................................................................................... 224 Figure 207: Cumulative New Resource Installed Capacity Through 2031 (MW) ................................................................ 227 Figure 208: 2023 IRP Implementation Timeline ................................................................................................................ 231 Figure 209: 100% Carbon – Free Trajectory to Waypoint in 2028 ...................................................................................... 231 Figure 210: Capacity Resource Accounting
Table Load ...................................................................................................... 232 Figure 211: Energy Balance Table (Scenario 4) Load .......................................................................................................... 233 Figure 212: IRP Contacts and Roles ..................................................................................................................................... 235 Figure 213: Opportunities for Future Studies and Analysis ................................................................................................ 236 Figure 214: Reliability Metrics for First Round Scenario Modeling (C apital Expansion) .................................................... 241 Figure 215: Reliability Metrics for First Round Scenario Modeling (Hourly Dispatch) ....................................................... 242 Figure 216: Reliability Metrics for Second Round Scenario Modeling (Hourly Dispatch)................................................... 242 Figure 217: Scenario 2: Consecutive Model Runs ............................................................................................................... 244 Figure 218: Installed Capacity of Fuel Cells ......................................................................................................................... 245 Figure 219: Resources Towa rd Load ................................................................................................................................... 246 Figure 220: Economic Curtailments Across Scenarios (MWh) ............................................................................................ 247 Figure 221: Utility‐Scale Solar Nominal Costs ..................................................................................................................... 249 Figure 222: Utility‐Scale Solar Real Costs ............................................................................................................................ 249 Figure 223: Commercial Solar Nominal Costs ..................................................................................................................... 250 Figure 224: Commercial Solar Real Costs ............................................................................................................................ 250 Figure 225: Residential Solar Nominal Co sts ...................................................................................................................... 251 Figure 226: Residential Solar Real Costs ............................................................................................................................. 251 Figure 227: Utility‐Scale 4‐Hour Lithium‐Ion Battery Storage Nominal Costs .................................................................... 252 Figure 228: Utility‐Scale 4‐Hour Lithium‐Ion Battery Storage Real Costs ........................................................................... 252 Figure 229: Utility‐Scale 6‐Hour Lithium‐Ion Battery Storage Nominal Costs .................................................................... 253 Figure 230: Utility‐Scale 6‐Hour Lithium‐Ion Battery Storage Real Costs ........................................................................... 253 Figure 231: Utility‐Scale 8‐Hour Lithium‐Ion Battery Storage Nominal Costs .................................................................... 254 Figure 232: Utility‐Scale 8‐Hour Lithium‐Ion Battery Storage Real Costs ........................................................................... 254 Figure 233: Utility‐Scale 10‐Hour Lithium‐Ion Battery Storage Nominal Costs .................................................................. 255 Figure 234: Utility‐Scale 10‐Hour Lithium‐Ion Battery Storage Real Costs ......................................................................... 255 Figure 235: Commercial 4‐Hour Lithium‐Ion Battery Storage Nominal Costs .................................................................... 256 Figure 236: Commercial 4‐Hour Lithium‐Ion Battery Storage Real Costs ........................................................................... 256 Figure 237: Residential 2.5‐Hour Lithium‐Ion Battery Storage Nominal Costs................................................................... 257 Figure 238: Residential 2.5‐Hour Lithium‐Ion Battery Storage Real Costs ......................................................................... 257 Figure 239: Fue
l Cells Nominal Costs .................................................................................................................................. 258 Figure 240: Fuel Cells Real Costs ......................................................................................................................................... 258 Figure 241: Land‐Based Wind Nominal Costs ..................................................................................................................... 259 Figure 242: Land‐Based Win
d Real Costs ............................................................................................................................ 259 Figure 243: Offshore Wind Nominal Costs .......................................................................................................................... 260 Figure 244: Offshore Wind Real Costs ................................................................................................................................ 260 Figure 245: Geothermal Nominal Costs ................................................................................... Error! Bookmark not defined.
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Figure 246: Geothermal Real Costs ..................................................................................................................................... 261
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1. Acronyms Used in PWP’s IRP
Figure 1: Acronyms
Acronym Definition
AAEE Additional Achievable Energy Efficiency
AAFS Additional Achievable Fuel Substitution
AATE Additional Achievable Transportation Electrification AB Assembly Bill
ACES Alliance for Cooperative Energy Services Power Marketing LLC AMI Advanced Metering Infrastructure
APPLE Project Assisting Pasadena People with Limited Emergencies ATB NREL’s Annual Technology Baseline
BEV Battery Electric Vehicle
BRP Business Rebate Program
Btu British thermal units
C&S Codes and Standards
CAISO California Independent System Operator
CalEnvironScreen CalEPA’s California Communities Environmental Health Screening Tool CalEPA California Environmental Protection Agency
CAP City of Pasadena’s Climate Action Plan
CARB California Air Resources Board
CARES California Alternate Rates for Energy
CEC California Energy Commission
CED California Energy Demand Forecast
CES Clean Energy Standard
CIP Customized Incentive Program
CMUA California Municipal Utilities Association
CO2e Carbon dioxide equivalent
CPM Capacity Procurement Mechanism
CPUC California Public Utilities Commission
CRAT Capacity Resource Accounting Table
CS&R Codes, Standards, and Regulations
D&C Distribution & Customer Charge
DAC Disadvantaged Area Communities
DC Direct Current
DER Distributed Energy Resource
DOE U.S. Department of Energy
DOT Department of Transportation
DR Demand Response
E3 Energy and Environmental Economics, Inc.
EAC Environmental Advisory Commission
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Acronym Definition
EBT Energy Balance Table
EEI Edison Electric Institute
EIA Energy Information Administration
ELCC Effective Load Carrying Capability
ESAP Energy Savings Assistance Program
EUAP Electric Utility Assistance Program
EV Electric Vehicle
FERC Federal Energy Regulatory Commission
FY Fiscal Year
GDS GDS Associates, Inc.
GEAT GHG Emissions Accounting Table
GHG Greenhouse Gas
GPP Green Power Program
GRI Global Reporting Initiative
GT Glenarm
GWh Gigawatt‐hours
HE Hour Ending
HELP Home Enhancement Loan Program
HER Home Energy Reports
HIP Home Improvement Program
HVAC Heating/Ventilation/Air Conditioning
IEPR Integrated Energy Policy Report
IPP Intermountain Power Project
IRA Inflation Reduction Act
IRS Internal Revenue Service
ISO Independent System Operator
ITC Investment Tax Credit
kA Kiloampere
kV Kilovolt
kWh Kilowatt‐hours
LADWP Los Angeles Department of Water and Power
LCA Local Capacity Areas
LCFS Low Carbon Fuel Standard
LCOE Levelized Cost of Energy
LCR Local Capacity Requirements
LDV Light‐Duty Vehicles
LIHEAP Low‐Income Household Energy Assistance
LIHWAP Low‐Income Household Water Assistance Program
LRA Local Regulatory Authority
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Acronym Definition
LSE Load Serving Entity
MASH City’s Municipal Assistance, Solutions, and Hiring Program MDHD Medium Duty, Heavy Duty
MIP Mixed Integer Programming
MISO Midcontinent Independent System Operator
MMBtu Metric Million British Thermal Unit
MSC Municipal Services Committee
MVA Megavolt‐ampere
MW Megawatt – a unit of capacity (similar to the amount of water a hose can push on demand) MWh Megawatt‐hour – a unit of energy (similar to the amount of water flowing out of a hose) NBT Net Billing Tariff
NEM Net Energy Metering
NERC North American Electric Reliability Council
NREL National Renewable Energy Laboratory
O&M Operations and Maintenance
PBC Public Benefit Charge
PCC Portfolio Content Category
PCL Power Content Label
PG&E Pacific Gas and Electric
PHEV Plug‐in Hybrid Electric Vehicle
POU Publicly‐Owned Utility
PPA Power Purchase Agreement
PRM Planning Reserve Margin
PSI Pasadena Solar Initiative
PTC Production Tax Credit
PTO Participating Transmission Owner
PUC Public Utilities Commission
PV Photovoltaic
PWP Pasadena Water and Power
RA Resource Adequacy
REC Renewable Energy Certificate
RFP Request for Proposals
RMR Reliability Must‐Run Resources
RPS Renewable Portfolio Standard
RPT RPS Procurement Table
SAIDI System Average Interruption Duration Index
SAIFI System Average Interruption Frequency Index
SASB Sustainability Accounting Standards Board
SB Senate Bill
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Acronym Definition
SCC Social Cost of Carbon
SCE Southern California Edison
SCPPA Southern California Public Power Authority
SDG&E San Diego Gas & Electric
SMUD Sacramento Municipal Utility District
SoCalGas Southern California Gas Company
SPP Southwest Power Pool
STAG Stakeholder Technical Advisory Group
TAC Transmission Access Charge Area
TCFD Task Force on Climate‐Related Financial Disclosures TOU Time of Use (Rates)
TSC Transmission Service Charge
V2G Vehicle‐to‐Grid Charging
WECC Western Electricity Coordinating Council
WeDIP Water and Energy Direct Install Program
ZEV Zero‐Emission Vehicle
2. Disclaimer
PWP’s 2023 IRP was conducted from January through October 2023. In January 2023, PWP’s City Council passed Resolution 9977, which stated that the City Council declares that climate change is an emergency and sets a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by the end of 2030. The Resolution directs the City Manager to use the 2023 IRP process to plan multiple approache
s to transition to this goal and to optimize affordability, rate equity, stability, and reliability of electricity while achieving the goal. The 2023 IRP was therefore designed to meet CEC requirements under the Publicly Owned Utility Integrated Re source Plan Submission and Review Guidelines ‐ Revised Second Edition and begin investigation into carbon‐free pathways.
The 2023 IRP meets the requirements of Resolution 9977, by planning multiple approaches to transition to the goal of 100% carbon‐free sources by the end of 2023, while optimizing affordability, rate equity, stability, and reliability of electric
ity, while satisfying CEC requirements. In its daily business, PWP provides its customers with electric service, in a reliable, affordable, and environmentally responsible manner.
3. Executive Summary
On January 30, 2023, Pasadena City Council passed Resolution 9977, which states that climate change is an emergency.
City Council set a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by the end of 2030 and direct the City Manager to utilize the 2023 IRP process to plan multiple approaches to transition an d to optimize affordability, rate equity, stability, and reliability of electricity while achieving this goal.
PWP conducted its 2023 IRP to meet Resolution 9977 objectives. PWP is also under a regulatory directive to file its 2023 IRP in accordance with CEC’s Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines ‐ Revised Second Edition.
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PWP began the process in earnest in early 2023 and spent most of the year working on its analysis. PWP engaged with individuals across its organization, as well as with City Council, MSC, EAC, STAG, the public, and two external consultants.
PWP is grateful to all that contributed.
PWP modeled five scenarios: three investigated the potential for carbon‐free resou rces to meet load by the end of 2030, one met California requirements, and another met California state requirements and added a carbon tax based on the SCC. PWP stressed the five resulting scenarios to four sensitivities: a month‐long heat wave in summer 2030, a loss of Goodrich in 2030, high cost of new resources, and low cost of new resources. PWP also studied the potential of two different typ
es of emerging technologies: an energy efficiency proxy resource and a demand response proxy resource.
PWP faces upcoming energy, capacity, and renewable needs. In 2025, the 108 MW IPP coal contract will be replaced with 50 MW of natural gas, which will then terminate mid‐year in 2027. By 2031, the carbon‐free scenarios showed that PWP needs between 375 MW and 690 MW of solar, between 0 MW and 60 MW of wind, between 35 MW and 55 MW of geothermal, between 35
MW and 115 MW of fuel cells, and between 305 MW and 685 MW of storage. PWP has a peak of approximately 351 MW in the load forecast by 2031.
Carbon‐free represents a portfolio transformation. Such a transformation must be accompanied by considerations of cost, equity, and reliability. A multit
ude of factors create uncertainty, including, but not limited to, resource costs, resource availability, resource performance under different weather conditions, and load shifts, among others. Cost changes will lead to rate, or rate structure, changes. Such changes must be considered in the context of all PWP ratepayers, including those most at risk.
The scenarios were desig
ned to meet reliability requirements as designed by CAISO. However, requirements may change over time. Glenarm and Goodrich, PWP’s local natural gas generation and interconnection to CAISO, play important roles in meeting load under various conditions, but will require major modificati ons, both physically and operationally, to support a 100% carbon‐free model. PWP found that it must further consider these implications in a carbon‐free future.
Waypoint Framework:
After thorough discussion and vetting of the IRP modeling results and analysis during the October 10, 2023, Municipal Services Committee (MSC) meeting, the Committee directed PWP to return with a Waypoint framework, as a more valued methodology for identifying specific near‐term actions and longer‐term IRP assessments. The Waypoint framework provides alignment with the policy goals of the City of Pasadena, as well as meeting the CEC’s requirements, while also
providing for a defined re‐evaluation point to allow for reassessment of new and emerging technologies that are widely industry accepted to be vital enablers for deeper and broader electric grid decarbonization.
The 2028 Waypoint
framework is informed by the modeling results of the Carbon‐Free Scenarios 1, 2 and 3; and from a planning perspective is identical to Scenario 2, up‐to the 2028 Waypoint. Essentially, the IRP 2028 Waypoint can be loosely attributed to a critical path Carbon‐Free pathway or analysis as informed by the IRP modeling results, as Scenario 2 represents the most ambitious of the Carbon‐Free Scenarios.
Procurement Plan through 2028
Resource procurement and implementation planning for the 2023 IRP are defined by the 2028 Waypoint framework.
Which among other key value adds, represents a point in time where portfolio planning re‐evaluation occurs, and next
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steps are informed by a variety of considerations, including maturity and feasibility of new and emerging technologies such as carbon‐free hydrogen‐based generation or long‐term battery storage.
The IRP 2028 Waypoint framework and associated implementation plan align with Carbon‐Free Scenario 2, and its associated modeling results. Scenario 2 modeling or implementation res ults emphatically affirm resource quantity, resource type, and timeline along with other attributes needed for optimization. The detailed implementation provisions are provided in greater detail in Section 22, but broadly include resource procurements of utility scale solar, utility scale wind, utility scale storage among other resource types.
When comparing to Sta te mandates and the clean energy plans of other utilities, City Resolution 9977 represents one of the most ambitious decarbonization targets in the USA. The 2023 IRP identified resource needs, reliability implications, cost, and equity considerations involved in a transition. PWP looks forward to continuing to build upon effective planning in the transiti
on to 100% carbon‐free electricity.
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4. Introduction
4.1. Introduction
The 2023 PWP IRP is a strategic guidance document, compliance report, and initial action plan for developing and maintaining a diverse portfolio of power supply resources. It is a blueprint for meeting PWP’s future peak load and energy requirements in a business environment with significant uncertainties and risks. It also reaffirms the City of Pasadena’s (Pasadena or the City) commit
ment to providing reliable, affordable, and environmentally responsible electricity. The IRP also plans multiple approaches to transition to the City Council policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by the end of 2030 and to optimize affordability, rate equity, stability, and reliability of electricit y while achieving this goal, as passed in January 2023 through Resolution 9977. The IRP is a living document subject to frequent revisions and updates to address the City’s evolving priorities, technological developments, regulatory requirements, and market changes.
PWP’s last IRP, in 2018, was developed through an extensive com munity stakeholder process. The final report and plan identified resource planning options that would best balance system reliability, fiscal responsibility, and environmental stewardship. The 2018 IRP recommended carbon‐free, long‐term resource commitments, elimination of coal‐fired generation, and aggressive RPS targets and GHG emission reduction targets that exceed state mandates. The 2023 IRP builds on the clean energy
goals of the 2018 and earlier IRPs. The 2023 IRP is designed to be flexible and adaptable as it anticipates significant changes in the electric industry and PWP’s customer energy requirements over the next 25 years.
Future power supply portfolio optimization and regulatory compliance will require frequent reassessment of PWP’s electric load, power supply and demand side options, and energy market changes.
The 2023 IRP was created through a collaborative effort under the guidance of the Mayor of Pasadena, City Council, PWP management and staff, Pasadena residents and businesses, and California laws and regulatio ns.
A reference guide showing the locations of where the CEC guidelines are satisfied is shown in Figure 2.1 Figure 2: California Energy Commission Guidelines and Location CEC Guidelines and Location
Chapter of CEC
Guidelines Description of Guideline 2023 PWP IRP Report Section Chapter 2 A Planning horizon Planning Horizon (POUs)
Chapter 2 B Scenarios and sensitivity analysis Defining Scenarios; Defining Sensitivities; Scenarios and Sensitivities Results
Descriptions Defining Scenarios; Defining Sensitivities Results Scenarios and Sensitivities Results
Chapter 2 C Standardized Tables Filed separately; Appendix ‐ Required Tables 1 https://www.smud.org/‐/media/Documents/Corporate/Environmental‐Leadership/Integrated‐Resource‐Plan.ashx
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CEC Guidelines and Location
Chapter of CEC
Guidelines Description of Guideline 2023 PWP IRP Report Section Chapter 2 D Supporting information Information relevant to IRP creation is included in this document and its Appendices
Chapter 2 E Demand forecast Load Forecast; Requirements; Integrated Energy Policy Report and California Energy Demand
Forecast
Chapter 2 E 1 Reporting requirements Load Forecast
Chapter 2 E 1 2 Demand forecast methodology and
assumptions Load Forecast
Chapter 2 E 1 3 Demand forecast‐ other regions Load Forecast Chapter 2 F Resource procurement plan Scenarios and Sensitivities Results; Implementation Steps – Carbon‐Free Pathways
Chapter 2 F 1 Diversified procurement portfolio Scenarios and Sensitivities Results Chapter 2 F 2 RPS planning requirements RPS (SB 100); Renewable and Zero‐Carbon (SB 1020) Chapter 2 F 2 a Forecasted RPS Procurement Targets In RPT (filed separately) Chapter 2 F 2 b Renewable Procurement In RPT (filed separately) Chapter 2 F 2 c RPS Procurement Plan Appended as separate document Chapter 2 F 2 d Recommended Information Greenhouse Gas Emissions Chapter 2 F 3 Energy efficiency and demand response
resources
Energy Efficiency; Demand Response; Integrated
Resource Plan Method; Scenario 6: Emerging
Technology Study; Scenario 6: Emerging
Technologies Study Scenario
Chapter 2 F 3 a Recommendations for Energy Efficiency and Demand Response Analysis
Energy Efficiency; Demand Response; Integrated
Resource Plan Method; Scenario 6: Emerging
Technology Study; Scenario 6: Emerging
Technologies Study Scenario
Chapter 2 F 3 b Calculating and Reporting Energy Efficiency Impacts In CRAT and EBT (filed separately)
Chapter 2 F 3 c Calculating and Reporting Demand Response Impacts In CRAT (filed separately)
Chapter 2 F 4 Energy storage New Resources; Battery Storage Chapter 2 F 4 a Recommendations for Energy Storage
Analysis Battery Storage
Chapter 2 F 5 Transportation electrification In EBT (filed separately); PWP is investigating options concerning community solar, which would
allow customers unable to install a personal system
to participate in a solar generation project. In a
community solar program, the utility has a solar
system and sells a portion of the system generation
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CEC Guidelines and Location
Chapter of CEC
Guidelines Description of Guideline 2023 PWP IRP Report Section to customers. A constructive complement to
community solar, while delivering similar benefits, is
the Green Power Program which supports the
purchase of renewable energy.
Electric Vehicles; Vehicle Electrification
Chapter 2 F 5 a Recommendations for Transportation
Electrification Analysis
Electric Vehicles; Vehicle Electrification
Chapter 2 F 5 b Calculating and Reporting Transportation Electrification Impacts
In CRAT and EBT (filed separately)
Chapter 2 G System and local reliability Resource Adequacy Chapter 2 G 1 Reliability criteria System Resource Adequacy and Reserve Margin; Battery Storage; in CRAT (filed separately);
Chapter 2 G 2 Local reliability area Local Resource Adequacy Capacity Chapter 2 G 3 Addressing net demand in peak hours Battery Storage; Chapter 2 H Greenhouse gas emissions Greenhouse Gas Emissions; in GEAT (filed separately)
Chapter 2 I Retail rates Retail Rates
Chapter 2 J Transmission and distribution system Transmission and Distribution Chapter 2 J 1 Bulk transmission system Bulk Transmission System; Bulk Transmission Planning
Chapter 2 J 2 Distribution system Distribution System Planning Chapter 2 K Localized air pollutants and disadvantaged communities
Localized Pollutants and Disadvantaged
Communities
Chapter 2 K 1 Reporting Requirements Localized Pollutants and Disadvantaged Communities
Chapter 2 K 2 Other Recommended Topics Localized Pollutants and Disadvantaged Communities
4.2. Pasadena Water and Power Department
PWP, a department of the City of Pasadena, has provided its residents and businesses with reliable, affordable, and environmentally responsible electricity since the early 20th century. As PWP continues this tradition, it must plan for the increasing electricity needs of its customers in a dynamic industry environment, while meeting the priorities of City Council for significant emission reductions and complying with current and proposed federal and state regulations. This ensures that PWP can continue to provide reliable, affordable, and envi ronmentally responsible electricity and energy‐related services for its customers.
Currently, PWP delivers about 1.1 million MWh of energy annually to approximately 65,000 retail customers. PWP has a historical peak load of approximately 320 MW. PWP has a portfolio of diverse resources including natural gas,
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hydroelectric, coal, nuclear, solar, wind, geothermal, and landfill gas. PWP owns natural gas‐fired units at the Glenarm, a share of the Magnolia natural gas‐fired unit in Burbank through an agreement with SCPPA, and the Azusa Hydroelectric Plant. PWP contracts with other resources to benefit from economies‐of‐scale and to share risks. PWP also has ownership and contract rights on various transmission lines, which were operationally transferred to th e CAISO when PWP became
a PTO in 2004.
The City Council, PWP, and the Pasadena community share a strong commitment to environmental responsibility and PWP has a history of meeting its customers’ electricity needs with affordable and increasingly environmentally friendly resources. Over the past 10 years, the Pasadena City Council has demonstrated an ongoing commitment to environmental stewardship by adopting internal goals for renewable energy and carbon emission reduction targets that exceed state mandates. The City also adopted a Climate Action Plan and is a leader in promoting energy ef ficiency. The approval of City Council Resolution 9977 declaring climate change an emergency and establishing a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by the end of 2030 continues the City’s commitment to move beyond current mandates and remain a leader in protecti ng the environment for future generations.
PWP currently offers several energy efficiency rebate programs for both residential and commercial customers. The average annual energy savings of PWP’s past energy efficiency programs is about 175 GWh per year. PWP also offers rebates for EV chargers and has installed several hundred publi c charging stations in Pasadena.
PWP has historically prioritized providing reliable electricity to its ratepayers. Two standard measures of reliability – SAIFI and SAIDI, shown in Figure 3 – illustrate how PWP’s system reliability compares to that of its neighbors. Over the past 10 years (2013‐2022), PWP’s SAIFI and SAIDI have remained among some of the best in the region. While reconstituting its electricity resource portfolio in accordance with this IRP, PWP maintains its commitment to this high level of reliability performance.
Figure 3: Comparison of System Average Interruption Frequency Index and System Average Interruption Duration Index SAIFI
Year SCE Pasadena GWP Burbank Anaheim LADWP
2013 0.85 0.09 0.72 0.19 0.68 0.45
2014 0.84 0.33 0.96 0.24 0.80 0.65
2015 0.83 0.30 0.72 0.17 0.36 0.74
2016 0.95 0.18 1.20 0.39 0.69 0.82
2017 0.84 0.25 1.34 0.52 0.57 0.97
2018 0.71 0.17 1.12 0.33 0.50 0.73
2019 0.85 0.09 1.41 0.32 0.57 0.78
2020 0.85 0.42 1.07 0.38 0.39 0.69
2021 0.96 0.27 0.75 0.31 0.86 0.76
2022 1.10 0.22 0.86 0.22 0.44 0.74
SAIDI
Year SCE Pasadena GWP Burbank Anaheim LADWP
2013 92.5 7.4 22.7 16.5 53.0 64.6
2014 91.5 32.6 37.0 10.0 48.5 77.7
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2015 98.3 21.4 41.7 4.8 35.0 92.4
2016 106.3 15.4 42.5 19.2 27.1 82,8
2017 90.0 30.6 65.4 12.6 35.0 120.9
2018 70.8 20.0 60.6 11.3 27.4 105.4
2019 89.3 14.3 75.1 4.6 42.1 112.8
2020 89.3 35.9 54.0 8.6 26.4 114.1
2021 102.1 29.5 55.9 16.4 70.9 140.2
2022 131.0 26.0 76.2 4.5 25.5 108.9
PWP’s electric rates are established by the Pasadena City Council after review and input from the MSC. The table in Figure 4 was created by the CMUA and shows average electric rates for residential customers who consume 750 kWh (or 1/1,000 of a MWh) per month. PWP’s residential rates are about 45% lower than SCE’s rates.
Figure 4: Average Residential Bills, Measured at 750 kWh/Month PWP commercial rates are also considerably lower than SCE rates.
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Figure 5 (also created by CMUA) shows average rates for commercial customers who use 3,500 kWh per month. PWP’s commercial customer rate is about 20% lower than SCE for similar customers.
Figure 5: Average Commercial Bills, Measured at 3,500 kWh/Month (May 2023) PWP offers two optional rate plans to residential and commercial customers: flat seasonal rates and TOU rates. Each customer may choose which plan makes best economic sense for them. PWP also has economic assistance programs for low‐income residents and medical device users.
4.2.1. Pasadena Executive Management and Governing Bodies Pasadena has a Council‐Manager form of government that includes seven City Council districts, each with an elected Councilmember serving a four‐year term. The Mayor is an elected position that represents the entire City and serves a four‐year term. The City Council is responsible for setting policies, passing ordinances, adopting the City budget , appointing committee members, and hiring the City Manager, City Attorney/City Prosecutor, and City Clerk.
As a department of the City of Pasadena, PWP is subject to the authority and oversight of the City Manager, MSC, and City Council. The City Council determines how PWP provides services in the community, inclu ding the establishment of priorities, policies, rates, and services.
Development of the 2023 IRP was guided by members of the PWP Executive Management team, including the following:
General Manager
Assistant General Manager – Power Supply
Assistant General Manager – Power Delivery
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Assistant General Manager – Finance and Administration During the development process for the 2023 IRP, PWP held regular staff meetings to discuss city policy, guiding principles and key IRP components. PWP Executive Management directed and supported staff on all aspects of production.
PWP first presented the 2023 IRP to the MSC for consideration and recomme ndation. The MSC is a standing committee of four City Council members appointed by Pasadena’s Mayor which reviews the City’s electric, water, transportation, and sanitation services. Following MSC, the IRP was presented to the City Council for approval and adoption.
4.2.2. Regulatory Agencies
The electricity landscape in California is a complex interaction of many entities. While the Pasadena City Council is PWP’s governing body, other state and federal agencies also have regulatory authority.
4.2.2.1. Federal Energy Regulatory Commission
FERC is an independent agency within the U.S. DOE that regulates the interstate transmission of electricity, natural gas, and oil, and approves licenses for hydroelectric projects. FERC oversees related environmental matters. In addition, FERC administers financial reporting regulations and conduct of jurisdictional entities.
4.2.2.2. North American Electric Reliability Council
NERC is a not‐for‐profit international regulatory authority whose mission is to ensure the effective and efficient reduction of risks to the reliability and security of the grid. NERC develops and enforces reliability standards, and annually assesses seasonal and long‐term reliability. Additionally, NERC monitors the bulk power system, and educates, trains, and certifie s industry personnel.
4.2.2.3. California Independent System Operator
CAISO is a non‐profit public benefit corporation that manages the flow of electricity across the high‐voltage, long‐distance power lines that make up 80% of California’s power grid. CAISO provides open and non‐discriminatory access to the transmission grid and supports a competitive energy market for aggregated resources of one MW or greater.
4.2.2.4. California Energy Commission
The CEC is a state energy policy and planning agency, charged with ensuring a reliable and affordable energy supply. The CEC has the following five major responsibilities:
Forecasting future energy needs and maintaining historical energy data Siting and licensing power plants
Promoting energy efficiency through appliance and building standards Developing energ
y technologies and supporting renewable energy
Planning for and directing state response to energy emergencies
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4.2.2.5. California Public Utilities Commission
The CPUC regulates privately‐owned companies that supply telecommunications, electricity, natural gas, water, railroad, rail transit, and passenger transportation. The CPUC is responsible for ensuring that California utility customers have safe and reliable utility services at reasonable rates and are protected from fraud. PWP is not subject to CPUC oversight.
4.2.2.6. California Air Resources Board
CARB’s mission is to promote and protect public health, welfare, and ecological resources through the effective and efficient reduction of air pollutants, while recognizing and considering the effects on the state economy. CARB is responsible for, among other things, administering California’s GHG Cap‐and‐Trade Program.
4.3. Statutory Mandate for Integrated Resource Plans
The CEC creates guidelines for IRP creation and submission for POUs and the CEC’s review of those IRPs. PWP files its 2023 IRP under the Publicly Owned Utility Integrated Resource Plan Submission and Review Guidelines ‐ Revised Second Edition, from 2018.2 As of January 2023, there were proposed guidelines titled Draft Commission Guidelines ‐ Publicly Owned Utility Integrated Resource Plan Submission and Review, dated August 2022.3 Given that the current guidelines are from 2018 and that PWP began its process prior to rule modification, PWP complied with these rules.
According to the CEC, “IRPs are electricity system planning documents that describe how utilities plan to meet their energy and capacity resource needs, policy goals, physical and operational constraints, and other utility priorities (such as reduci
ng rate impacts on customers’ bills).”4 In other words, IRPs are compliance and strategy documents that evaluate a range of risks and opportunities to help a utility plan its next steps. Under PUC Section 9622, the CEC can adopt guidelines to govern the submission of IRP data so it can review the IRP’s consistency with the requirements of PUC Section 9621.The requirements from the CE
C ensure that IRP analysis is robust and complies with state regulations and directives.
PWP is required to file an IRP with the CEC every five years. PWP’s 2023 IRP adoption is due by year end, 2023. PWP needs to file at minimum one scenario, or “a set of assumptions about future conditions used in power system modeling performed to support gene
ration or transmission planning”, with the CEC in a document that also lists assumptions, key considerations, and outputs. The IRP filing should include any additional material that supports the CEC’s review. Results must be filed in four standard tables in Microsoft Exc el templates.
PWP considered multiple scenarios, which are included in this IRP for stakeholder consideration. Requirements from the CEC are shown in Figure 6.
2 https://efiling.energy.ca.gov/GetDocument.aspx?tn=224889&DocumentContentId=55481 3 https://www.energy.ca.gov/publications/2022/publicly‐owned‐utility‐integrated‐resource‐plan‐submission‐and‐review‐guidelines 4 https://efiling.energy.ca.gov/GetDocument.aspx?tn=224889&DocumentContentId=55481
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Figure 6: California Energy Commission Requirements
4.4. Community Outreach
PWP is a not‐for‐profit organization owned and operated by the City of Pasadena, with priorities that include reliability, customer responsiveness, competitive rates, and environmental stewardship. Ongoing engagement with residents, businesses, and civic partners is instrumental to understanding evolving community needs and PWP conducts regular outreach to gauge public opinion on customer satisfaction an d expectations.
Stakeholder and community involvement is also fundamental to IRP development; therefore, PWP has implemented an outreach strategy using a multi‐media marketing campaign. Communication mediums for the 2023 IRP included website postings, social media, bill inserts, print advertising, digital advertising, City‐direct mail newsletters, PWP electronic newsletters, informational videos, press releases, and flyers. PWP also worked closely with the City Manager and the MSC to develop STAG, a diverse cross‐section
of the Pasadena community that provided input into the 2023 IRP development.
PWP hosted 10 STAG meetings to refine the 2023 IRP analysis, develop energy scenarios and addressed interim co mments and questions. PWP also held three Power IRP Community Meetings to ensure that community priorities were also represented in the process. PWP has an extensive history of partnering with the community and appreciates the participation and support of local citizens and businesses in the development of Pasadena’s energy resource plan.
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4.5. Integrated Resource Plan Objectives
The 2023 IRP sought to optimize PWP’s resource mix to achieve a sustainable balance of system reliability, fiscal responsibility, environmental stewardship, and compliance with Council Resolution 9977, SB 350, SB 100, and other applicable legislation and regulatory mandates. Metrics and checklists for these objectives were developed and implemented in this IRP. The following are the components of ea ch objective:
System Reliability
Maintain a resource adequacy reserve margin of at least 15% Maintain CAISO RA requirements in compliance with the CAISO tariff (including System RA, Local RA, and Flexible RA requirements)
Preserve, optimize, and enhance local generation to reduce risk of over‐reliance on a single transmission tie at the T.
M. Goodrich Receiving Station (Goodrich) substation and integrate variable generation, demand‐side management and distributed generation
Fiscal Responsibility
Maintain stable, competitive, and affordable rates
Minimize the impact of market and price volatility in cost factors like fuel and resource procurement Minimize generation‐
related direct costs, including GHG compliance costs
Provide transparency in expected power‐related rates for the average ratepayer Environmental Stewardship
Plan multiple approaches to transition to sourcing 100% carbon‐free electricity supply by the end of 2030 as a policy goal of Resolution 9977
Minimize the environmental impact of meeti
ng Pasadena’s electric energy needs
Comply with all federal, state, and local laws and regulations Meet or exceed required standards for renewables (RPS percentage) as defined by state laws (SB 100) PWP identified the following four categories for scenario evaluation:
1. Cost
2. Stability
3. Reliability
4. Environment
PWP
worked on the IRP from January 2023 through December 2023. Overall, PWP focused on the following two key action items:
1. File an IRP with the CEC to meet state regulatory requirements and guidelines, as mandated by the statute every five years
2. Plan multiple approaches to meet the City’s policy goal of sourcing 100% of Pasadena’s electricity from carbon‐
free sources by the end of 2030, optimizing for affordability, rate equity, stability, and reliability
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While PWP files this IRP by the end of 2023 to remain in compliance with state regulations, PWP anticipates continuously working on its plans to decarbonize its system.
4.6. Integrated Resource Plan Process and Timeline
SB 350 (De León, 2015) requires that POUs with load greater than 700 GWh, such as PWP, develop an IRP by January 1, 2019, and provide updates every five years thereafter. Compliance is regulated by the CEC.
To assist with the development and preparation of the 2023 IRP, PWP issued a combined RFP in April 202 2 for modeling and consulting services. Proposers were given the option of responding to either or both scopes of work. Of the six firms that responded, three offered proposals for both scopes of work. Proposals for each scope of work were separately scored based on criteria described in the RFP. ACES received the highest evaluated scor e for each of the individual scopes of work, based on a combination of relevant experience, quality of technical proposal, and price proposal.5 To ensure transparency in the IRP study results, PWP also contracted with Environmental and Energy Economics Inc. (E3) to review the IRP analysis. A recognized leader in clean energy policy implementation, E3 provides technical, policy, and market analysis, and has worked with clients that include CEC, CPUC, CARB, and a variety of public and private utilities throughout
the nation and the world. E3 has also explored higher RPS standards for SMUD, experience that was especially valuable for PWP’s project considering the goals of Resolution 9977. A summary of involved consultants and their roles is in the Appendix – Integrated Resource Plan Contract and Resource Roles.
PWP’s IRP process evaluates how PWP
can serve its customers given uncertainty. PWP must consider different topics, such as electricity market price forecasting; resource and contract valuation; power flow modeling, including transmission constraints; modeling regulatory mandates, including RPS and GHG emissions requirements; among others.
The 2023 IRP process starts with developing and coll ecting assumptions and baseline data for existing resources and load trends. The next step refines the analysis and develops energy portfolio plans through robust stakeholder input and community engagement to best represent Pasadena’s diverse community and ratepayer interests. The process concludes with providing technical analysis and informing policy makers to aid the m in determining the best path forward to meeting electricity demands and City objectives over the next 25 years.
4.7. 2023 Integrated Resource Plan Timeline
PWP began the 2023 IRP process in January 2023. Inputs for generation, modeling, analysis, stakeholder engagement, and result documentation continued through October. Approval and filing began in the fall of 2023. The 2023 IRP process, by regulatory requirement, was completed in December. See Figure 7. 5 https://ww2.cityofpasadena.net/2022%20Agendas/Sep_19_22/Agenda.asp
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Figure 7: PWP's 2023 Integrated Resource Plan Timeline
Category Action Item Timeline
Input Assumption creation January through May 2023
Input Inputs Finalized June 2023
Output Modeling July 2023
Output Report Drafted August 2023
Output Report Finalized by PWP October 2023
Output IRP Approved by City Council November 6, 2023
Output IRP Submitted to CEC December 1, 2023
5. Previous Integrated Resource Plans
Integrated resource planning is a continuous process that requires regular updates and adjustments to address changes in electricity needs, regulations, and the business environment. The 2023 IRP is the latest rendition of PWP’s resource planning effort and the 2023 results build upon previous IRP goals, where applicable, while meeting or exceeding the requirements of SB 350, SB 100, and other regulat
ions.
The most recent plans are the 2018 IRP and the 2021 update to the 2018 plan. These can be accessed on PWP’s website.6 Previous IRPs (prior to 2018) are also available at PWP’s website.7 Figure 8 summarizes progress toward PWP’s 2018 IRP goals.
Figure 8: 2018 Integrated Resource Plan Progress
Recommendation IRP Goal Status
Increase in Renewable and
Zero‐Carbon Resources in
Portfolio
Ensure all new long‐term energy supply
contracts are renewable and/or zero‐
carbon emitting resources
No new long‐term fossil‐fuel contracts
have been added since this policy was
adopted in 2018
Reduce fossil fuels in the
portfolio
Exit the IPP no later than 2027 The IPP contract terminates effective 6/15/2027; PWP will not participate in
the IPP Renewal Project (natural gas and
hydrogen blend)
Reduce GHG emissions
(specifically carbon) relative
to PWP’s 1990 level
(approximately 198,600
metric tons)
Achieve GHG emissions reduction of at
least 75% below PWP’s 1990 level by
2030 (reduce to approximately 226,000
metric tons)
Current estimate* is 68% below 1990
levels for 2022, and more than 90%**
below by 2030
6 https://pwp.cityofpasadena.net/powerirp/.
7 https://pwp.cityofpasadena.net/powerirparchive/
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Recommendation IRP Goal Status
RPS Achieve at least 60% RPS by 2030 per
requirements of SB 100
Estimated* at 41.25% RPS for 2022 and
on track to meet the 2030 state mandate
of 60%**
*Current estimate to be updated in the 2022 power content label. **Resolution 9977 looks for 100% carbon‐free by 2030.
In
the 2021 IRP Update to the 2018 plan, PWP re‐evaluated its portfolio to address changes to RA standards. ELCC quantifies a resource’s ability to contribute to grid reliability. Currently, it is particularly relevant to solar. The 2021 IRP Update also more closely examined the need and potential for energy storage as a power supply resource. Based on these considerations, PWP revised the 2018 IRP im
plementation plan in terms of resource type, size, and timing. Figure 9 summarizes PWP’s progress toward the 2021 IRP Update recommendations.
Figure 9: 2021 Integrated Resource Plan Update Progress Recommendation IRP Goal Status
Resource Procurement Procure at least 70 MW of accredited capacity by 2025 for RA
Executed a 15‐year 25 MW geothermal
and 20‐year solar plus battery energy
storage system contracts starting in 2027
Energy Storage Study Investigate storage options to meet 50 MW of installed battery energy storage
by 2025
Issued an RFP for construction of a 25
MW utility‐owned system at the Glenarm
RPS Continue efforts to achieve 60% RPS by
2030 and net‐zero carbon by 2045
The 2023 IRP optimizes to comply with
RPS regulations and seeks to exceed
requirements based on City Resolution
9977
Fuel Substitution Study Examine alternative fuel sources, such as biogas or green hydrogen gas, for the
Glenarm local generating stations
Biogas and green hydrogen were
considered in the 2023 IRP (See Section
10.4)
EV Study Refine forecasted growth of EV charging
in Pasadena
The 2023 IRP includes the impact of
current and expected market penetration
rates in the updated Load Forecast
6. Existing Policies and Programs
PWP has developed multiple customer programs to encourage renewable energy generation, increase energy efficiency, provide low‐income assistance, and facilitate electrification. The programs are a result of the community’s values and the City Council’s vision for demonstrating leadership in environmental stewardship and responsible planning.
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6.1. Distributed Solar
6.1.1. Current Programs
Pasadena has customer‐installed PV solar electric generation, which is primarily rooftop solar. The PSI incentivizes customer PV generation through NEM rates.
6.1.2. Net Energy Metering
NEM is a rate and billing structure that allows customers with qualifying PV systems to receive credit for excess generation.
California’s first NEM program, referred to as NEM 1.0, was implemented in 1996. This initial program required California electric utilities, including POUs, to provide customers with PV systems at the full retail value of excess generati on. A net of total annual PV generation and customer usage resulted in either over‐generation or utility‐supplied energy and was credited or billed accordingly on an annual basis. The NEM 1.0 program was designed to stimulate the market for renewable energy and help diversify the resource mix in California.
The California NEM program require
ment for IOUs was replaced in 2017 with NEM 2.0 and again in April 2023 with NEM
3.0. Both program revisions were intended to address cost inequities. The full retail rate for electricity includes more than just the cost for energy – it includes the costs of capacity, fees, wir es, and more. For paying customers the full retail rate is, in effect, a subsidy.
NEM 2.0, also known as the Successor Tariff, was implemented by the CPUC in 2017 to replace NEM 1.0 and applies to IOUs. Primary features include a mandatory one‐time interconnection fee, TOU rate requirements, and bypass charges, such as a grid access fee. The program changes were designed to reduce the system cost impacts of large amounts of PV generation on non‐PV customers.
In 2023, California implemented NEM 3.0, also known as the NBT. The new tariff was created to further help reduce service inequities between customers
with and without distributed generation, and to promote grid reliability, incentivize solar and battery storage, and improve equitable customer electricity costs. According to the CPUC, which regulates IOUs, NEM
3.0 has no impact on existing rooftop solar customers who continue to retain current compensation rates. W hile POUs are not under CPUC jurisdiction, the topic of rate equity and evolution of rates plays an important role in PWP’s future NEM policies.
The goal of the CPUC NEM 3.0 tariff is to promote rate equity by revising rates paid to new solar customers according to the value of the excess ener
gy at the time it is sent to the grid. Typically, when solar is producing midday and there is surplus energy on the grid, the value of solar generation is low. When the distributed solar is not producing (e.g., at night), the value of generation is much higher. This value diff erence has the effect of incentivizing batteries that can store excess solar energy during the day, then discharge that energy at night when it has more value to the utility. NEM 3.0 was designed to promote this incentive.
Potential revisions to PWP’s NEM program to update compensation credits sho uld also include a review of other options and program additions such as virtual or aggregated NEM. Both options allow shared PV systems within customer groups.
All California electric utilities were required to provide NEM 1.0 programs until each met 5% of its total peak demand by solar installations. Once a
chieved, utilities could transition to a replacement program. At this time, PWP still provides
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benefits to its customers under the NEM 1.0 construct, but has met the 5% installation cap (specifically, 14.8 MW based on a peak load of 296 MW). With 21 MW of distributed solar (7% of peak demand) in its service territory as of 2022, PWP now has the option of remaining at NEM 1.0 or transitioning to a successor tariff that could include some or all of the provisions of NEM 2.0 or 3.0.
PWP’s current NEM program (NEM 1.0) offers three billing options to customers with PV systems: annual billing, monthly billing and bi‐monthly. Under the annual option, the customer is billed once a year for electric service. If more electricity is generated than used, the customer may elect to receive compensation for the excess PV generation energy or a credit against future billings.
Under the monthly or bi‐monthly option, PWP calculates energy produced on a monthly or bi‐monthly basis. A customer that produc
es more energy than consumed during the billing period is credited for the excess at the energy services charge rate plus $0.025/kWh for the associated RECs. Additionally, because it is less costly to administer, PWP incentivizes the monthly/bi‐monthly option with a bonus of an additional $0.066/ kWh.
6.1. 2.1. Customer‐Generated RECs
PWP does not currently have a mechanism to track customer‐generated RECs and, therefore, does not consider residential or commercial generated RECs for RPS compliance purposes. However, it is expected that AMI will be implemented within the next five years, at which point PWP could use the RECs to help meet RPS requirements. Further investigation in to compliance with regulation is in progress.
6.1.3. Community Solar
PWP is investigating options concerning community solar, which would allow customers unable to install a personal system to participate in a solar generation project. In a community solar program, the utility has a solar system and sells a portion of the system generation to customers. A constructive complement to community solar, while delivering similar benefits, is the Gre
en Power Program which supports the purchase of renewable energy.
6.2. Electric Vehicles
Transportation accounts for more than 50% of California’s GHG emissions and almost 80% of its nitrogen oxide pollutants.8 Understanding that transportation electrification helps reduce emissions, California recently set a mandate requiring 100% of new car and passenger truck sales in the state to be ZEVs by 2035.
CPUC Section 9621 requires IRPs to discuss how utility rate design and incentives support transportation electrification.9 Since these efforts have positive community benefits, such as reduced local air pollution, PWP looks to align its transportation electrification programs with state initiatives, laws, and regulations, as well as community priorities. PWP 8 https://www.energy.ca.gov/about/core‐responsibility‐fact‐sheets/transforming‐transportation 9 https://openstates.org/ca/bills/20212022/SB437/
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endeavors to study the impact of potential programs on low‐income and disadvantaged communities to reduce PWP’s system and individual driver costs.
6.2.1. Current Electric Vehicle Incentives
PWP offers the following three EV‐related incentives:
The Commercial EV Charger Rebate Program provides a $3,000 rebate for installed, smart level 2 (240 V) chargers.
For Direct Current (“DC”) fast chargers, the rebate ranges up to $6,000 per charger, if installing DC fast chargers accessible to students and patrons of accredited schools, as part of income‐ qualified housing, or in a disadvantaged community. Total incentives are limited to $75,000 per commercial electric customer. For non‐ network charging stations (not internet‐connected), PWP offers a $1,500 rebate per station, up to $15,000 per site/account/customer.10
The Reside
ntial EV Rebate Program provides eligible customers rebates of $250 each for the purchase or lease of up to two plug‐in EVs per address every three years.11 Customers can also receive an additional $250 bonus rebate (up to $500) for purchasing or leasing from a Pasadena auto dealer. Customers enrolled in PWP's income‐qualified Bill Payment Assistance program are eligible for an additional $1,000 rebate. A customer meeting all requirements could receive a total benefit of up to $1,500 per EV.
The Residential EV Charging Rebate offers custom
ers $600 for installing a Wi‐Fi‐enabled EV charger, or $200 for a standard (non‐Wi‐Fi/non‐internet connected) charger.
As of August 2023, PWP has expended almost $2,320,000 on EV incentives.
6.2.2. Current Electric Vehicle Outreach
PWP’s website includes a robust menu of EV‐related educational material for consumers, including a description of EV features, air quality benefits, home charging tips, potential savings, and tips to enhance the driver experience.12 Also included are links to additional resources that provide information for potential EV buyers, including a cost comparison calculation for EVs and gasoline‐fueled vehicles created by the University of California, Davis, and information about available rebates.13 In addition to online EV promotion, PWP provides ongoing outreach through various mediums, such as print and digital advertisements, newsletters, press releases, billboards, bus shelter adverting, public service announcements, flyers, events, bill inserts, on‐hold messages, and social media.
6.2.3. Current Electric Vehicle Fleet
As of 2022, the City of Pasadena had 9,254 light‐duty ZEVs, 98% of which were BEVs or PHEVs registered by citizens. The remainder use hydrogen. Light‐duty ZEVs represent about 6.8% of cars on Pasadena roads. In addition, 2,572 new light‐ 10 https://pwp.cityofpasadena.net/commercialchargerrebate/ 11 https://ww5.cityofpasadena.net/water‐and‐power/ev/
12 https://pwp.cityofpasadena.net/electrification/; https://pwp.cityofpasadena.net/ev/ 13 https://gis.its.ucdavis.edu/evexplorer/#!/locations/start
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duty EVs were sold in 2022, representing 18.8% of the light‐duty vehicles sold locally. Overall, EV adoption is steadily increasing, which experts predict will continue across the industry.
Figure 10 and Figure 11 show the composition of the zero‐emission vehicles by type by year and the composition of annual sales.
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Figure 10: Total Light‐Duty Electric Vehicles on Grid
Figure 11: Annu al Sales of Light‐Duty Electric Vehicles 0%
1%
2%
3%
4%
5%
6%
0 1,000
2,000
3,000
4,000
5,000
6,000
7,000
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Percent of Total Light‐Duty Vehicles on Grid
Number of Light‐Duty EVs on Grid
Total Light‐Duty EVs
BEV >= 200 Miles BEV < 200 Miles PHEV ZEVs (%)
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
0 500
1,000
1,500
2,000
2,500
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Percent of Total Light‐Duty Vehicles Sold
Number of Light‐Duty EVs Sold
Annual Sales of Light‐Duty EVs
BEV >= 200 Miles BEV < 200 Miles PHEV ZEVs (%)
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Medium‐ and heavy‐duty vehicles, by definition14, weigh more than 10,000 pounds and include vans, buses, and trucks.
By spring 2022, there were more than 1,900 medium‐ and heavy‐duty ZEVs on the road in California, 70% of which were buses.15 In 2023, the City arranged to purchase one electric bus in 2024 that will provide an opportunity to learn more about the benefits and challenges to owning and operating electric busses. As part of its Fleet Replacement Program, the City’s DOT is planning a complete conversion to ZEV buses for local services, such as Pasadena Dial‐ A‐Ride and Pasadena Transit by 2033 and 2040, respectively.16
6.2.4. EV Charging Stations
In addition to incentives for customer‐owned charging stations, Pasadena is committed to developing publicly owned EV charging infrastructure throughout the City. 17 Below is a list of charger types, by level. Level 1 Charger
A 120‐volt (standard house outlet) charger using trickle charging, providing roughly three to five miles of range for every hour charged. A Level 1 charger is typically included in every EV purchase. Level 2 Charger
A 240‐volt charger (using a typical house outlet for dryers, ovens, or heating, ventilation, and cooling). These
chargers can charge anywhere from 5.5 miles of range to 60 miles of range per hour of charging, depending on the specific car make and model.
DC Fast Charger (Level 3 Charger)
A DC fast charger differs from the other two levels as it does not need to conve rt the electricity from AC to
DC. Since the battery charges directly from a DC outlet, this results in the fastest charging speed of any chargers on the market today, an estimated 10 miles of range per minute charg ed. Currently, the only DC charging stations available are those installed by utilities and equipped to convert the distribution grid AC electricity into DC.
The City owns 234 charging stations, of which 203 are Level 2 and 31 are DC Fast Chargers. A map of current and planned charging stati
ons is shown in Figure 12. PWP’s website also provides details on where chargers are located.18 14 Medium and Heavy‐Duty Vehicles (ca.gov)
15 https://www.energy.ca.gov/data‐reports/energy‐almanac/zero‐emission‐vehicle‐and‐infrastructure‐statistics/medium‐and‐heavy 16https://ww2.cityofpasadena.net/2023%20Agendas/Jan_30_23/AR%204%20Attachment%20A_Pasadena%20ICT%20Report_Finalre v.pdf
17 https://ww5.cityofpasadena.net/water‐and‐power/ev/
18 https://pwp.cityofpasadena.net/ev/
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Figure 12: Map of Electric Vehicle Chargers in PWP’s Territory
6.2.5. Pasadena’s Department of Transportation Initiatives Pasadena’s DOT is working to expand its bus fleet to include more ZEVs, such as hydrogen fuel cell or plug‐in battery buses.
DOT plans to convert its entire fleet to zero‐emission by 2040, although additional funding opportunities may accelerate the timeline. Converting the DOT bus fleet to zero‐emission will have a large impact on PWP’s future load and infrastructure and the de
partments should collaborate planning to meet this need.19
6.2.6. Vehicle‐to‐Grid Charging
In addition to receiving energy through charging, an EV could deliver energy stored in its battery back to the grid. This is called V2G charging, a form of distributed energy storage that could potentially serve as a resource to a utility. This would require the following:
19https://ww2.cityofpasadena.net/2023%20Agendas/Jan_30_23/AR%204%20Attachment%20A_Pasadena%20ICT%20Report_Finalre v.pdf
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Sensors and communication infrastructure to alert the utility when the EV is connected to a charger, as well as the vehicle’s state of charge (i.e., how full its battery is) Separate metering on the charger
Minor internal modifications to the EV and charger to allow bidirectional energy flow Remote V2G control from the utility to EV via the ch
arger
An agreement between the utility and EV owner detailing the conditions for the battery energy use, compensation rate, payment method, etc.
PWP could use V2G as a potential distributed energy storage option in Pasadena, possibly beginning with electric transit and school buses, due to the relatively large concentration of battery storage in one location and under a single owner.
These conditions would enable PWP to better predict when the vehicles would be connected to chargers and leverage economies of scale when installing associated infrastructure.
6.3. Energy Efficiency
6.3.1. Current Program Incentives
PWP customers pay a PBC, a state‐mandated charge that is included on all electric service bills. This charge is currently set at $0.00685/kWh.20 On average, PWP collects approximately $6.9 million annually through the PBC, which California requires to be allocated to a separate fund and used for the following specific purposes:
Energy efficiency/demand response programs
Renewable resources
Research, development, and demonstration projects
Low‐income rate assistance
Beneficial electrification, according to the City’s Resolution 9977 PBC funds su
pport the commercial and residential programs outlined in the following sections, as well as the three EV programs discussed in Current Electric Vehicle Incentives.
6.3.1.1. Commercial Programs
The BRP provides rebates for energy efficient equipment installations, including LED lighting, certain commercial restaurant equipment, motor controls, commercial appliances, and HVAC systems.21 The program is limited to $24,000 per account, with a cap of 25% of total project cost. For each device installed, PWP can claim a predetermined amount of energy efficiency savings.
20 https://ww5.cityofpasadena.net/water‐and‐power/rates/ 21 https://ww5.cityofpasadena.net/water‐and‐power/businessrebateprogram/
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The CIP provides savings for customized and/or complicated efficiency projects and covers technology not listed in the BRP.22 Limited to $50,000 per account, with a cap of 25% of total project cost, customers are provided a $0.05/kWh rebate on energy savings that are higher than California Green Building Standards Code – Part 11, Title 24, California Code of Regulations (CalGreen) codes for lighting, non‐lighting, and other new construction projects.
For fuel switching projects, ther
e is an additional incentive of $0.15/pound of CO2 reduction. WeDIP applies to small‐ to medium‐sized commercial customers using 50 kW or less.23 Eligible customers can receive up to $7,500 of water and energy savings equipment installed at no cost.
6.3.2. Residential Programs
PWP has the following residential programs:
The Home Energy Rebate Program provides numerous rebates for equipment such as ENERGY STAR‐rated refrigerators, dishwashers, ceiling fans, and room air conditioners. The Refrigerator Recycling Program provides PWP electric customers with free refrigerator recycling services in exchange for a working refrigerator.
The Refrigerator Exchange Program, which applies to income‐qualified customers only, expands on the Refrigerator Recycling Program by providing a free new replacement refrigerator in exchange for a working refrigerator.
The HIP is a direct installation program that provides up to $4,000 in water and energy savings equipment. The program also includes a no‐cost, expert water and energy use evaluation and potential instal lation of devices such as LED light bulbs, advanced power strips, attic insulation, or tune‐up of central AC.24 HERs provide customers wi
th a monthly snapshot of personal energy use as it compares to comparable homes in the area. Recipients also receive tips for lower energy usage.25 ESAP is a coll
aboration with SoCalGas and provides direct installation services for low‐income consumers. The Residential Electric Panel Upgrade Program provides a rebate for an upgrade to a 200‐amp electric panel.26 This program is intended
to assist customers requiring a panel upgrade to support a home EV charger.
With help from the energy efficiency programs, PWP customers saved approximately 174 GWh per year from FY 2011 through FY 2020. 27 This represents a load reduction of approximately 17.2%. See Figure 13. 22 https://ww5.cityofpasadena.net/water‐and‐power/business/ 23 https://ww5.cityofpasadena.net/water‐and‐power/wedip/ 24 https://ww5.cityofpasadena.net/water‐and‐power/homeimprovement/ 25 https://ww5.cityofpasadena.net/water‐and‐power/homereports/ 26 https://pwp.cityofpasadena.net/electricpanelrebate/
27 May 17, 2021 Agenda Report with the subject “Adopt Ten‐Year Energy Efficiency and Demand Reduction Goals for Fiscal Years 2022 through 2031”
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Figure 13: PWP's Actual Cumulative Energy Efficiency Savings
6.3.3. Energy Efficiency Regulations
SB 1037 (2005) requires POUs to acquire cost‐effective, reliable, and feasible energy efficiency and demand response resources before acquiring other resources. 28 The law also requires annual reporting of savings, expenditures, and cumulative processes to the CEC. CMUA uses economies of scale to help its 45‐member POUs submit these reports. PWP’s reports are posted by year on its website.
Under AB 20
21 (2006) and AB 2227 (2012), a POU’s governing board (specifically the Pasadena City Council in this case) must adopt 10‐year energy efficiency and demand reduction goals every four years. These requirements are codified in PUC Section 9505. The Pasadena City Council adopted its most recent energy efficiency goals in FY 2021. Specifically, the City Council ad
opted an annual goal of 11,720 MWh per year in savings and 1.8 MW per year in demand reduction for FY 2022 through 2031. This goal represents a 133.4 GWh reduction in sales cumulatively by Fiscal Year 2031, or 11.3% of forecasted sales. Based on model results and historical data, PWP estimates achieving these goals will cost approximately $3 million per year, or about 1.6% of electric rate revenues, which is consistent with recent spending. As a result, PWP anticipates that the $0.006
85/kWh PBC charge is currently sufficient. Figure 14 includes a summary of past PBC budgets. 28 May 17, 2021, Agenda Report with the subject “Adopt Ten‐Year Energy Efficiency and Demand Reduction Goals for Fiscal Years 2022 through 2031”
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Figure 14: Past Public Benefit Charge Budgets
Annual Cost
($000/Year) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Residential Programs $782 $854 $1,727 $1,935 $1,664 Non‐Residential $2,008 $3,766 $1,267 $1,099 $1,080 Total Program Cost $2,790 $4,620 $2,994 $3,034 $2,744 The City also refers to energy efficiency in its CAP. Specifically, Strategy 2: Energy Efficiency and Conservation discusses prioritization of energy use reduction in existing buildings and new construction. As part of this strategy, CAP Measure E‐
2.1 sets a target to reduce energy use for existing homes and business by 40% (below 2013 levels) by 203 5.
The adopted energy efficiency goals achieve less than 35% reduction, but this comes from electricity only, not from both electricity and natural gas, as in the CAP goal. In fact, the goal was predicted to save 65% more GHG emissions than the CAP goal foresees. See Figure 1529. Overall, PWP is focused on net GHG reduction.
Figure 15: Estimated Greenhouse Gas Emissions from Existing Homes and Businesses 29 “Adopt Ten‐Year Energy Efficiency and Demand Reduction Goals”. Item #16 delivered to City Council on May 24, 2021.
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In August 2022, the City Council adopted a building electrification ordinance. 30 The ordinance noted that 47% of Pasadena’s community‐wide GHG emissions come from residential and commercial occupancies. The ordinance requires that existing multifamily buildings, mixed‐use buildings, commercial buildings, and larger‐scale commercial retrofits be electrified. Exceptions include certain types of food service establishments and essential facilities.
6.3.4. Energy Efficiency Forecast and Goals
In 2021, GDS conducted an energy efficiency potential forecasting study for CMUA, which investigated market potential for residential and nonresidential customers.
GDS performed a study specific to PWP’s service territory. As previously stated above, the Pasadena City Council adopted an annual energy efficiency goal of 117.2 GWh from 2022 to 2031, which equates to an average annual target of 1.06% of total energy use avoided
per year. This goal was based on GDS’ study. These goals appear achievable given Pasadena’s current programs and after assuming a GHG adder on avoided costs. While energy savings associated with CS&R constitute about 40% of these total savings, the CEC no longer allows utilities to report on energ y efficiency stemming from statewide adoption of new codes and standards. Therefore, CS&R contributions were not considered in setting PWP’s goal. For purposes of the IRP, PWP adopted the results of the GDS market potential study, including the GHG adder but not including the potential gains from CS&R advoca
cy.
PWP’s energy efficiency goal in 2017 included CS&R and targeted incremental annual savings of 13,500 MWh in energy efficiency and 2.3 MW of demand reduction per year. If PWP includes CS&R savings in its 2021 goal, PWP’s current goals are 19,524 MWh of savings and 3.5 MW of demand reduction per year. PWP remains committed to the cost‐ effective promotion and adoption of energy efficiency. Programs have become more stringent over time to meet increasingly ambitious goals, as shown in Figure 16 and Figure 17.
Figure 16: Incremental Energy Efficiency Savings (MWh)
Incremental Energy Efficiency Savings (MWh)
2017 Goal 2021 Goal
Applicable Years Fiscal Years 2018 – 2027 Fiscal Years 2022 – 2031 PWP Program Savings 11,338 11,720
CS&R Savings 2,111 7,804
Total Annual Savings 13,500 19,524
Adopted Goal: Total Savings 13,500 11,720
30 Building Electrification Ordinance
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Figure 17: Incremental Energy Efficiency Savings (MW)
Incremental Energy Efficiency Savings (MW)
2017 Goal 2021 Goal
Applicable Years Fiscal Years 2018 – 2027 Fiscal Years 2022 – 2031 PWP Program Savings 1.6 1.8
CS&R Savings 0.7 1.7
Total Annual Savings 2.3 3.5
Adopted Goal: Total Savings 2.3 1.8
Reduced electricity usage means that fixed costs need to be recovered from less sales, which may put upward pressure on rates. PWP experienced a net 22% decline in actual retail electricity sales since FY 2008 – a decrease attributed to energy efficiency, CS&R, distributed generation investments, and other factors, including weather and economic activity.
See Figure 18. Allocating fixed utility co
sts – those that do not vary with the volume of sales, such as costs for wires or reliability components – is a question of rate design.
Figure 18: Impact of Energy Efficiency and Customer‐Owned Generation on Electric Sales
6.4. Demand Response
6.4.1. Current Demand Response Programs
PWP has one DR program currently active ‐ voluntary load curtailment ‐ with others under development. The current program includes large commercial customers who agree to reduce load by a pre‐determined amount upon request. PWP has already identified, tested, and secured more than 2.5 MW of on‐call load reduction from 20 of its largest electric ity customers.
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6.4.2. Future Demand Response Programs
PWP could explore the potential for additional DR programs. Future programs may be feasible when PWP upgrades to AMI in the next few years.
6.5. Green Power Program
The GPP is a voluntary rate structure that offers customers renewable or green electricity produced by technologies such as solar, wind, geothermal, small hydro, and biomass for a price. The GPP accounts for 5% of total load supplied to PWP customers.31
6.5.1. Residential Green Power Program32
As of 2023, under the Residential GPP, customers have the following three purchase options for green power:
200 kWh block for $3.60 a month
400 kWh block for $7.30 a month
100% of electricity consumed is renewable for $0.018/kWh PWP currently has 260 residential GPP accounts, which represent 0.4% of all PWP customers.
6.5.2. Commercial Green Power Program33
Commercial customers have the following two options when signing up for the GPP:
1,000 kWh blocks (any number) for $18 each per month
100% of electricity consumed as renewable at $0.018/kWh PWP currently has 88 commercial GPP accounts, which represents 0.13% of all PWP customers.
6.6. Low‐Income Assistance Programs
PWP offers several programs to help customers use energy more efficiently and reduce their utility bills, particularly financially vulnerable households. The assistance programs listed in the following sections represent the majority of PWP’s available benefits.
31 https://pwp.cityofpasadena.net/greenpoweroption/
32 https://pwp.cityofpasadena.net/wp‐content/uploads/2017/08/Residential‐Green‐Power‐Option‐Fillable‐8.2020.pdf 33 https://pwp.cityofpasadena.net/wp‐content/uploads/2020/08/Green‐Power‐Commercial‐App‐Fillable‐8.2020.pdf
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6.6.1. Income‐Qualified Programs
6.6.1.1. Monthly Bill Payment Assistance
Low‐income customers between the ages of 18 and 61 who qualify according to the table in Figure 19 can receive a $10 bill credit per month.34
Figure 19: Low‐Income (Electric Utility Assistance Program) Household Size 1 2 3 4 5 6 Each Additional Person EUAP income level $41,700 $47,650 $53,600 $59,550 $64,940 $74,380 +$9,440 Low
‐income seniors (ages 62 and over) or customers with a permanent disability who qualify according to Figure 20 are eligible to receive a $10 bill credit per month and a waiver of their monthly PBC charge.35 Figure 20: California Alternate Rates for Energy (Age or Disability Qualification) Household Size 1 2 3 4 5 6 Each Additional Person CARES income level $41,700 $47,650 $53,600 $59,550 $64,940 $74,380 +$9,440 Low
‐income seniors (ages 62 and over), and customers with a permanent disability at the income shown in Figure 21 are eligible to receive a $10 bill credit per month and a waiver of their monthly PBC and Utility Users Tax.36 Figure 21: California Alternate Rates for Energy Plus (Age or Disability Qualification) Household Size 1 2 3 4 5 6 Each Additional Person CARES plus income
level $12,000 $16,000 $20,000 $24,000 $28,000 $32,000 +$4,000 Qualifying res
idential account holders may apply online at any time, or in person by appointment, and must provide proof of income for all persons living in the household.37
6.6.1.2. Other Income‐Based Assistance Programs
The following are PWP’s other income‐based assistance programs:
Payment Arrangements
PWP offers payment arrangements for customers experiencing financial hardship. For more information, or to enroll, customers are invited to call PWP Customer Service at (626) 744‐4005.38 34 https://pwp.cityofpasadena.net/billassistance/
35 https://pwp.cityofpasadena.net/billassistance/
36 https://pwp.cityofpasadena.net/billassistance/
37 https://pwp.cityofpasadena.net/billassistance/
38 https://pwp.cityofpasadena.net/paymentarrangement/
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LIHEAP
This is a federally‐funded program administered locally by the Maravilla Foundation. LIHEAP is designed to help low‐income households with a one‐time payment to help pay heating and cooling bills. This long‐ standing federal program has helped low‐income families nationwide for more than 40 years. More information is available on the Maravilla Foundation website (www.maravilla.org).39 LIHWAP
This is also a federally‐funded program administered locally by the Maravilla Foundation. This is designed to help low‐income households with a one‐time payment for outstanding residential water or wastewater bills. The federal government established LIHWAP as part of legislation to ease the financial impacts of the COVID‐19 pa
ndemic. LIHWAP expired in August 2023.
6.6.2. General Bill Assistance
PWP also offers non‐income‐based bill assistance.
Residential electric customers with qualifying electric‐powered medical equipment can receive a $10 bill credit per month under the Medical Equipment Assistance program. Qualifying equipment includes aerosol tents, apnea monitors, compressors or concentrators, electrostatic or ultrasonic nebulizers, electric nerve stimulators, hemodialysis machines, kidney dialysis machines, intermittent positive pressure breathing machines, iron lungs, pressure pads, pressure pumps, respirators or ventilators, suction machines, motorized wheelchairs, and electric beds.40 The Water Leak Assistance Program assists customers with certain property‐related water leaks that result in excessive water waste and high utility bills. The program provides a partial bill adjustment to qualifying customers, in order received, until the $50,000 annual funding cap is reached.41
7. Public Participation
A key theme in the development of PWP’s 2023 IRP is extensive outreach, coordination, and collaboration between PWP, stakeholder groups, and the Pasadena community. Public participation has been essential to PWP’s portfolio refinement efforts and proved especially valuable to the formulation of data assumptions and simulation model inputs for the IRP study.
The Pasadena City Council will utilize the IRP as an i
nformation resource to help determine the best policy path forward.
With this goal in mind, PWP worked closely with the Pasadena City Manager, City Council, MSC, and EAC throughout the IRP process to ensure that stakeholder and community input were included. PWP provided periodic updat es to these governing bodies, which facilitated direct feedback from policymakers and the Pasadena community. 39 https://pwp.cityofpasadena.net/liheap/
40 https://pwp.cityofpasadena.net/medical/
41 https://pwp.cityofpasadena.net/water‐leak‐assistance‐program/
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While developing the 2023 IRP, PWP engaged a variety of stakeholders through a comprehensive outreach process to seek input from customers, communities, and policymakers. The outreach process included the following activities listed in Figure 22.
Figure 22: IRP Stakeholders Outreach
Meeting Date Topic
STAG #1 December 14, 2022 Introductions
STAG #2 January 18, 2023 Introduction of ACES and IRP Process STAG #3 February 15, 2023 Decarbonization Pathways
Community Meeting #1 February 22, 2023 Start of IRP Process and Where is PWP Now? STAG #4 March 1, 2023 Proposed Scenarios and Sensitivity Tests Municipal Services Committee March 14, 2023 Informational Update Environmental Advisory
Commission March 14, 2023 Informational Update
STAG #5 March 15, 2023 Assumption Data Discussion
STAG #6 April 12, 2023 Cost of New Resources
STAG #7 April 19, 2023 Final Scenarios and Sensitivity Tests Community Meeting #2 April 27, 2023 What will be studied in the 2023 IRP (Scenarios, Sensitivity Tests, and Study)
Municipal Services Committee May 9, 2023 Informational Update Environmental Advisory
Commission May 9, 2023 Informational Update
STAG #8 May 17,2023 Load Forecast
STAG #9 August 16, 2023 Results of 2023 IRP Scenarios Environmental Advisory
Commission September 12, 2023 Informational Update
STAG #10 September 20, 2023 Wrap‐up
Virtual Community Meeting #3 September 21, 2023 Results of 2023 IRP and Steps Going Forward Municipal Services Committee October 10, 2023 Recommend Approval and Adoption City Council November 6, 2023 Approval and Adoption
Numerous Frequently Asked
Questions and Email
Communications
December 2022 –
October 2023
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7.1. Stakeholder Technical Advisory Group
Public input and transparency are important aspects of the IRP development process. PWP worked closely with the City Manager and the MSC to assemble the STAG for the 2023 IRP with the goal of recruiting a diverse group of community representatives that could provide input on crucial aspects of the plan including energy suppl y and power source mixes.
Following the March 4, 2022 website announcement, extensive public outreach was conducted by PWP and City leaders to recruit participation from ratepayers throughout Pasadena.
The 2023 STAG, which was established by the City Manager in November 2022, included 13 residents and four City officials representing different interests, sectors, and districts. The STAG incl uded residential customers, small and large
businesses, low income/disadvantaged/senior communities, environmental advocacy groups, and educational institutions. Since the IRP is a long‐term plan that affects all Pasadena ratepayers, it was important to ensure that PWP’s entire customer base would be represented in the group. See Figure 233.
Figure 23: Comparison of the Composition of the 2018 STAG and the 2023 STAG Using input from the 2023 STAG, PWP developed a variety of IRP data assumptions and model inputs, including environmental assumptions, fuel prices, resource types, new resource costs, load forecast, scenarios, and sensitivity tests.
IRP modeling approaches were also discussed with the STAG.
7.2. STAG Meetings
The 10 STAG meetings that were held from December 2022 through September 2023 were instrumental in the IRP development process and analysis. A general outline of discussion topics include:
The IRP background, goals, and schedule
PWP’s current generation portfolio, customer programs and internal resources The electric industry business and regulatory environment and markets The process for updating PWP
’s load forecast for the IRP
The use of modeling in IRP analysis including scenario development and sensitivity analysis, and resource options and costs
0 1
2 3
4 5
Church/Low
Income/Senior
Residential Business City Educational
Institution
Environmental
Advocacy
STAG Members
Sector
2018 and 2023 STAG Composition Comparison
2018 2023
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Approaches and pathways to decarbonization of the electric portfolio
7.3. Community Meetings
PWP hosted three virtual community meetings for residential customers, business customers, and community organizations to introduce the 2023 IRP and collect feedback. The virtual meetings were promoted through a multi‐media marketing campaign, including website postings, social media, bill inserts, print and digital advertising, PWP electronic newsletters, press releases, and flyers. The meetings were held on Fe bruary 22, April 27, and September 21, 2023. In the first two meetings, PWP presented an overview of the IRP process and discussed the use of scenario analysis in resource planning. In the last meeting, PWP presented the preliminary analysis results and potential resource addition and program change recomm
endations.
7.4. Public Outreach
In April 2022, PWP updated its website to focus on the 2023 IRP process and added electronic links to all past IRPs. To gauge community interest, PWP utilized social media and community events requesting participation in the IRP process.42
7.5. Municipal Service Committee and Environmental Advisory Commission Meetings PWP staff provided updates to the MSC and EAC from November 2022 through November 2023, including status of work performed and next steps. Additionally, PWP received guidance from the MSC on desired direction of the 2023 IRP, as well as public comments. The sentiments and ideas expressed in these meetings helped shape the scope and the analys is of the 2023 IRP.
8. Environmental Regulations and Priorities
8.1. PWP’s Environmental Priorities
PWP is committed to reducing GHG emissions through a balanced and sustainable combination of energy sources, planning, and community outreach. In 2018, the City Council approved the Pasadena Climate Action Plan (CAP), which strives for a 52% reduction (compared to 1990 levels) in citywide GHG emissions associated with energy, transportation, water, and solid waste by 2035.43 By the end of 2021, PWP reduced energy‐related emissions by 50% (compared to 1990 levels) and anticipated reaching a 90% reduction by 2030.44 On January 30, 2023, the City Council adopted Resolution 9977, which declares a climate emergency in Pasadena and sets a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by 2030.45
42 https://pwp.cityofpasadena.net/powerirp/
43 https://www.cityofpasadena.net/planning/planning‐division/community‐planning/climate‐action‐plan/ 44 https://pwp.cityofpasadena.net/pcl/
45 https://ww2.cityofpasadena.net/2023%20Agendas/Jan_30_23/Agenda.asp
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8.2. Renewable Portfolio Standard and Zero‐Carbon Regulations More than one‐half of U.S. states have an RPS in place.46 California’s RPS was established in 2002 by SB 1078 (Sher) and sparked more than two decades of increasingly aggressive regulatory mandates that increased the required percentage of eligible renewable resources comprising an electric utility’s retail sales. Most recently, SB 100 (2018) sets the RPS to be 60% by 2030. The CEC oversees the RPS program, publishes the RPS Eligibility Guidebook, and certifies qualify ing resources.
SB 100 also stated that 100% should be met with renewable and zero‐carbon resources by 2045. In 2022, SB 1020 expanded the 100% by 2045 zero‐carbon goal of SB 100 by adding interim targets. A 2021 joint agency report titled 2021 SB 100 Joint Agency Re
port: Charting a Path to a 100% Clean Energy Future, issued by the CEC, CPUC, and CARB, identifies zero‐carbon resources as energy resources that qualify as renewable according to the most recent RPS Eligibility Guidebook, and/or that generate zero‐GHG on site.47 The report acknowledges that even though certain renewable resources (such as geothermal or landfill gas) may produce de minimis carbon emissions, the joint agency study treats them as zero‐carbon resources.48
Figure 244 illustrates key policies driving California’s environmental efforts.
Figure 24: Renewable Portfolio Standard: Key Legislative Actions in California Senate
Bill Title Author Enacted Percentage of Load That Must be Met by Renewables
1078 Renewable Energy California
Renewables Standard Program
Sher 2002 20% by eligible renewable resources by
2017
350 Clean Energy and Pollution Reduction
Act of 2015
De León 2015 50% by eligible renewable resources by
2030; 65% must be in long‐term contracts
100 California Renewables Portfolio
Standard Program: emissions of
greenhouse gasses
De León 2018 60% by eligible renewable resources by
2030; 100% by renewable and zero‐
carbon resources by 2045
1020 Clean Energy, Jobs, and Affordability
Act of 2022
Laird 2022 90% by renewable and zero‐carbon
resources by 2035; 95% by renewable and
zero‐carbon by 2040; 100% by renewable
and zero‐carbon by 2045
46 https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/electric‐power‐procurement/rps/rps‐program‐overview 47 https://www.energy.ca.gov/publications/2021/2021‐sb‐100‐joint‐agency‐report‐achieving‐100‐percent‐clean‐electricity 48 https://www.energy.ca.gov/publications/2021/2021‐sb‐100‐joint‐agency‐report‐achieving‐100‐percent‐clean‐electricity
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PWP has set more aggressive environmental targets. Resolution 9977 set a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by 2030.49 Carbon‐free resources are not defined by California. Further discussion on how PWP referred to carbon‐free resources in the 2023 IRP is included in Section 15.9 of the IRP.
8.2.1. State Compliance
California has both RPS and zero‐carbon compliance requirements. The CEC identifies and investigates RPS violations and may refer suspected incidents to CARB for enforcement.
RPS compliance is monitored with RECs. RECs are tradeable instruments representing the environmental attributes of 1 MWh of energy. A REC represents only the environmental quality of the energy, not the energy. As a result, a REC can be sold with ele
ctricity (bundled) or sold alone (unbundled).
8.2.1.1. Renewable Portfolio Standards Procurement Quantity Requirement RPS compliance is evaluated over the span of compliance periods, which are three‐year or four‐year evaluation periods.
Under SB 350, and later updated by SB 100, PWP must supply 44% of its retail sales with eligible renewable resources by the end of 2024, 52% by the end of 2027, and 60% by the end of 2030, with progressively increasing target s in the interim years.
RPS compliance requirements are included in Figure 255 and are reflected in the IRP models.
Figure 25: Senate Bill 100 and Senate Bill 1020 Requirements50 Compliance Period (PUC
399.30) Year SB 100 RPS% SB 1020 RPS + Zero‐
Carbon%
Compliance Period 4 2021 35.75
2022 38.50
2023 41.25
2024 44.00
Compliance Period 5 2025 46.00
2026 50.00
2027 52.00
Compliance Period 6 2028 54.67
2029 57.33
2030 60.00
Beyond Current Compliance
Periods
2035 90.00
2040 95.00
2045 100.00
49 https://ww2.cityofpasadena.net/2023%20Agendas/Jan_30_23/Agenda.asp 50 https://www.energy.ca.gov/publications/2022/renewables‐portfolio‐standard‐verification‐and‐compliance‐methodology‐report
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8. 2.1.2. Portfolio Balance Requirement
Pasadena must procure a balanced portfolio of eligible renewable energy resources that covers different classifications of REC products. These are referred to as PCCs. PCC descriptions are included in Figure 266.
Figure 26: Portfolio Content Categories
Type Definition Example (Generic) PWP Portfolio Share of Overall Requirement
PCC 0 Historical carryover (i.e.,
grandfathered) contracts
or ownership agreements
executed before
6/1/2010
A 2009 wind agreement
that is still delivering RECs
Chiquita Canyon Landfill,
PPM (also called Avangrid,
or High Winds Project, or
Iberdrola), and Milford
Wind
PCC 1 Bundled RECs;
the first point of
interconnection is in
California, or within a
California Electric
Balancing Authority Area
and transmitted directly
into California
A project located in
California, or in Washington
if delivered into California
without any substitute
energy
Puente Hills Landfill,
Windsor Reservoir Solar,
Antelope Solar, Kingbird
Solar, Columbia Two Solar,
Summer Solar, COSO
Geothermal
At least 75%
PCC 2 Firmed and shaped
outside California and
substituted with energy
scheduled within
California
A project in Washington
without transmission to
California; generation is
firmed and shaped with
substitute energy that is
scheduled into a California
Electric Balancing Authority
Area
Avangrid Powerex No more than
25%
PCC 3 Unbundled (no
associated energy)
A renewable energy
certificate/ownership of
environmental attributes
from an RPS‐eligible facility
various short‐term
contracts
No more than
10%
Renewable electricity products acquired after June 1, 2010 are classified by their environmental quality (highest to lowest value).
While the 2023 IRP assumes that PWP will meet all future RPS requirements with California‐generated PCC 1 products, the actual PCC 1 supply may be limited, which would result in the need to secure other REC products. Moreover, variations in load and generation may also require procurement of PCC 2 and PCC 3 products to bala nce PWP’s compliance cost‐ effectively.
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8.2.1.3. Long‐term procurement requirement
For the compliance period beginning January 1, 2021, and for each compliance period thereafter, at least 65% of the electricity products applied toward RPS compliance must be from long‐term contracts (10 years or more in duration).
8.2.1.4. Renewable and zero‐carbon requirements
Beginning in 2035, PWP must supply 90% of its electricity from eligible renewable or zero‐carbon resources. In 2022, PWP’s portfolio consisted of approximately 28% renewable energy, as reported on its Power Content Label (PCL).51 Note that the PCL reflects a 2019 CEC calculation modification that excludes unbundled/PCC3 RECs. Under the RPS compliance methodology, which involves different disposition requirements and continues to consider PCC 3, PWP’s renewables portfolio increases to approximately 40%.
To help avoid significant environmental performance gaps and to support a smooth transition to zero‐carbon sources, PWP modeled an increasing per
centage of load that must be met with renewable and zero‐carbon sources prior to the 2035 goal. These interim goals are shown in Figure 277. Values in black bold text indicate the requirements, while values in grey italics represent the modeled interim values.
Figure 27: RPS and Zero‐Carbon Modeled Requirements
Percent of Load
Year RPS Zero‐Carbon
2022 38.50 37.07
2023 41.25 41.14
2024 44.00 45.21
2025 46.00 49.29
2026 50.00 53.36
2027 52.00 57.43
2028 54.67 61.50
2029 57.33 65.57
2030 60.00 69.64
2031 60.00 73.71
2032 60.00 77.79
2033 60.00 81.86
2034 60.00 85.93
2035 60.00 90.0
2036 60.00 91.00
2037 60.00 92.00
51 https://ww5.cityofpasadena.net/water‐and‐power/pcl/
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Percent of Load
Year RPS Zero‐Carbon
2038 60.00 93.00
2039 60.00 94.00
2040 60.00 95.0
2041 60.00 96.00
2042 60.00 97.00
2043 60.00 98.00
2044 60.00 99.00
2045 60.00 100.0
8.3. Cap‐and‐Trade Regulation
California’s Cap‐and‐Trade program, which CARB administers, was established in 2006 under AB 32 and phased in from 2013 through 2015.52 Amended seven times since adoption, the program’s current objective is to reduce statewide carbon emissions by 40% below 1 990 levels by 2030, as SB 32 (2016) requires. Covering more than 80% of the state’s GHG and over 450 different entities, the program establishes an annual cap of allowable emissions which declines over time.
Covered entities include electric generators, large industrial facilities, transportation providers, and distributors of natural gas or other fuels. Entities that annually produce
at least one metric ton (1,000 kilograms, or 2,200 pounds) of carbon dioxide equivalent emissions must acquire an allowance, or a permit to emit. The Cap‐and‐Trade program measures compliance over distinct time intervals, or compliance periods. Each year, an entity must surrender a llowances that represent 30% of its prior year emissions, with the full remainder due at the end of the compliance period.53 CARB allots a certain number of free, tradeable allowances to specific entities, including electric distribution utilities such as PWP.
Other entities can purchase allowances or offsets in auctions that CARB periodically conducts. These auctions are designed to establish stable prices for allowances over time and to help incentivize general investment and movement toward lower‐
polluting sources.
In practice, awareness of the current allowance price, as determined by trading and auctions, factors into an entity’s decision about how to price its generation output. This is how carbon is priced into the electricity sector in California.
Future cost estimates for allowances are publicly available on the CPUC’s website.54 However, for the purposes of the IRP, the Cap‐and‐Trade program functions as it sounds – as a cap. Each year, PWP may emit from IPP, Glenarm, and Magnolia the amount of carbon corresponding to its current allowances, as prescribed by 52 https://ww2.arb.ca.gov/resources/documents/faq‐cap‐and‐trade‐program 53 Chapter 1: How Does The Cap‐And‐Trade Program Work?” at https://ww2.arb.ca.gov/our‐work/programs/cap‐and‐trade‐ program/about
54 https://files.cpuc.ca.gov/energy/modeling/EmissionForecast.csv at https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐ energy/electric‐power‐procurement/long‐term‐procurement‐planning/2022‐irp‐cycle‐events‐and‐materials/unified‐ra‐and‐irp‐ modeling‐datasets‐2022
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regulation, without penalty or additional cost.55 While the Cap‐and‐Trade program is currently slated to expire in 2030, this IRP assumes that PWP would continue to adhere to the principle of the program. The 2023 IRP therefore ramps down allowed emissions to zero by the mid‐2040s. PWP elected to use this modeling method because it limits PWP’s emission s during simulated operations.
8.4. Other Environmental Points of Note
8.4.1. Power Source Disclosure Program
PWP reports its PCL every year as required. The PCL is a detailed summary of its power mix and carbon emissions intensity.
PCLs are similar in concept and appearance to food nutrition labels, as they provide product health data to the consumer.
The PCL is a requirement of the CEC‐administered Power Source Disclosure program, which provides eas y‐to‐understand information to consumers about local power sources.56 Utilities are required to report PCLs annually to the CEC and to make these reports available to customers. PWP’s PCL is posted on both the CEC’s and PWP’s websites.
PWP’s 2022 power mix included 27.73% renewable energy: specifically, 5.7% total solar, 13.7% total wind, and 8.3% biomass/biowaste. The balance was comprised of 24.3% coal, 4.2% large hydroelectri c, 13.1% natural gas, 8.4% nuclear, and 22.3% unspecified power.57 Also, as previously noted, unbundled/PCC 3 RECs are not included in the PCL calculation, which, along with different disposition rules, results in a variance from the RPS Compliance report, which shows 40% renewables for the same year. PWP’s power mix is impacted by the carbon intensity attributed with the IPP coal contract, which will expire in 2027. After tha
t time, the IPP contract will be fully terminated, eliminating its carbon emitting GHG contribution from the PWP portfolio.
8.4.2. The Cost Impacts of 100% by 2045
Under SB 100, the CEC, CPUC, and CARB were required to issue a joint report by January 2, 2021, and every four years thereafter, to provide policy implementation information.58 The initial report, which analyzed the required statewide resources and their costs, found that the 100% by 2045 zero‐carbon goal would increase system costs by 6% as compared to earlier RPS goals.59 Furthermore, to reach the target, California must triple its power capacity.60 Specifically, solar and wind would need to be installed at three times the 2021 pace and batteries at eight times the 2021 pace. 55 https://ww2.arb.ca.gov/sites/default/files/2021‐02/ct_reg_unofficial.pdf at https://ww2.arb.ca.gov/our‐work/programs/cap‐and‐ trade‐program/allowance‐allocation/edu‐ngs
56 https://www.energy.ca.gov/programs‐and‐topics/programs/power‐source‐disclosure 57 https://ww5.cityofpasadena.net/water‐and‐power/pcl/
58 https://www.energy.ca.gov/publications/2021/2021‐sb‐100‐joint‐agency‐report‐achieving‐100‐percent‐clean‐electricity 59 https://www.energy.ca.gov/sb100
60 https://www.energy.ca.gov/publications/2021/2021‐sb‐100‐joint‐agency‐report‐achieving‐100‐percent‐clean‐electricity
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8.4.3. Social Cost of Carbon
For environmental policies that might increase or decrease carbon, government agencies and policymakers may consider the Social Cost of Carbon (SCC). The SCC is an estimated monetary value of the overall downstream impact of emitting an additional metric ton of carbon dioxide. The U.S. EPA established the most recent SCC values in September 2022. 61 Pasadena considered the SCC in its 2018 IRP and 2021 IRP Update. During simulations, this effectively prevented some generation that would otherwise have been economical. For the 2023 IRP, PWP studied and allocated a scenario specific to model impacts.
It is important to note that carbon is already priced in the electricity generation sector via the Cap‐ and‐Trade and RPS programs. If the SCC were applied as an extra charge to IPP, Magnolia, or Glenarm, the following could occur in the simulation:
Economical fossil fuel generation would be deployed less because it is now more expensive More renewable resources or other resourc es would be selected Although the CEC guidelines do not require any use of the SCC, PWP’s 2023 IRP modeling includes it in a scenario.
9. Resource Adequacy
RA is a regulatory construct that helps quantify resources’ ability to meet energy needs at all times.
PWP is subject to regulatory requirements related to RA. PWP must, at a minimum, meet the planning reserve requirement and reliability criteria assigned to it by the WECC Board of Trustees. Since PWP is a municipal utility, with ultimate governing autho
rity held by its City Council, PWP is its own LRA. An LRA has authority to dictate some RA requirements that must be met by its jurisdictional LSEs. PWP is an LSE because it provides electricity to end users and is regulated accordingly. In short, PWP is both an LRA and an LSE.
Because it participates in the CAISO market, PWP has obligations regarding the following three typ es of resource
adequacy:
System
Ability to meet load, plus an added PRM to cover forecast uncertainty and/or outages Local
Ability to meet regional load and prevent system ov erload. CAISO identifies local areas of concern Flexible or Flex
Ramping capabilities to meet load, especially during the evening hours 61 https://www.epa.gov/environmental‐economics/scghg
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Since California is now operating a grid with higher levels of renewable resource generation, CAISO finds that flexible resources that can ramp up or down on short notice to meet fluctuation in load and intermittent energy help support reliability
Additional details on how PWP plans to meet System, Local, and Flexible RA capacity requirements du ring the 2023 IRP study period are described in the following sections.
9.1. System Resource Adequacy and Reserve Margin
PWP has deferred to a PRM of 15% following the CAISO tariff. The PRM is required monthly using a 1‐in‐2 peak demand forecast, which assumes a 50% probability that forecasted peak will be either greater or less than actual peak. 62 Accordingly, PWP’s system RA obligation is equal to its monthly peak load plus the 15% PRM. PWP needs to meet this with a combination of PWP’s owned and contracted resources.
Due to increases in renewable resources and the intermittent nature of renewables, reserve margins in markets across the U.S. are increasing. For example, in 2023, MISO released i nformation showing higher seasonal reserve margins, and SPP moved from a reserve margin of 12% to 15%.63 For 2022, CAISO recommended that the CPUC adopt a 17.5% PRM for its jurisdictional entities. The CPUC adopted a 16% PRM for 2023 and a 17% PRM for 2024, and requested jurisdictional LSEs procure additional resources to meet an effective PRM of 20% to 22.5% for summer 2022 and 2023.64 CAISO has not yet proposed an increase to the 15% tariff default, but it is presumed to increase in the near future. 65 For the 2023 IRP, PWP elected to model a 15% reserve margin through 2025, increasing to 17.5% for the remainder of the study. PWP believes this reflects market trends.
The installed capacity of a generating resource is not indicative of its ability to support system reliability. For example, a solar resource may be hindered on a cloudy day, or a natural gas plant may experience reduced output due to constraints on natural gas pipelines during cold days. As a result, a resource’s reliability contribution is often not equivalent to its installed capacity. RA accreditation for resources is a function of technology type and the ability of the resource to delive r its full capacity onto the grid given fuel, transmission, and other constraints. PWP uses the CAISO net default qualifying capacity for its resources. For the 2023 IRP, PWP assumes that the ELCC of solar specifically, which varies based on month, will decline over time.
In
the IRP modeling, PWP assumed monthly accreditation patterns for its resources. This information is based on CAISO data and some of the underlying CPUC data.66
62 https://www.caiso.com/Documents/Resource‐Adequacy‐Fact‐Sheet.pdf 63 https://cdn.misoenergy.org/20220906%20LOLEWG%20Item%2003%20PY%202023‐ 24%20Preliminary%20LOLE%20Study%20Results626211.pdf; https://www.spp.org/spp‐documents‐filings/?id=21069 64 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M488/K540/488540633.PDF; https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M428/K821/428821475.PDF 65 https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M371/K105/371105687.PDF 66 https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M452/K750/452750851.PDF; https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M488/K540/488540633.PDF;
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Figure 288 shows the annual capacity accreditations for solar in CAISO for select years. In the instance of solar, the more resources online, the later in the day the net peak (actual demand minus renewable resources) occurs. As a result, the hour of operational concern shifts to later in the day when solar is less available.
Figure 28: Solar Resource Adequacy Accreditation
Percent of Installed Capacity Eligible for System/Local RA Year Solar
2025 12.0
2030 9.8
2035 8.7
2040 8.0
2045 7.5
9.2. Local Resource Adequacy Capacity
California’s grid contains 10 LCAs. These are areas with transmission constraints that limit power imports, so local generation is required for system reliability. Every year, CAISO performs a Local Capacity Technical Study that evaluates local resource needs for a 1‐in‐10 peak forecast scenario.67 It then delegates LCRs to entities within the constrained areas.
Based on CAISO tariff Section 40.3.2, PWP’s obligation is its proportionate share of SCE’s transmission area load at the time of the CAISO’s annual coincident peak demand.68
The local capacity of each resource is calculated using the same methods as system capacity. All local capacity is system capacity, but not all system capacity is local capacity.
PWP needs these resources to be located in the SCE TAC area. According to Section 40.3.2 of the CAISO tariff: "An LSE or CPE may meet its MW re
sponsibility, as assigned under this Section, by procuring Local Capacity Area Resources in any Local Capacity Area in the TAC Area." The SCE transmission access charge area includes two sub‐areas: L.A. Basin and Big Creek/Ventura. PWP meets its local RA requirement with Glenarm, Puen te Hills, Chiquita Canyon, Antelope Solar, Kingbird Solar, and Summer Solar resources.
PWP’s load is in the L.A. Basin sub‐area of the SCE TAC area. Glenarm and Puente Hills are in the L.A. Basin sub‐area.
Chiquita Canyon, Antelope Solar, Kingbird Solar, and Summer Solar are in the Big Creek/Ventura sub‐ area. There may be regulatory risk if the location of load and resources in sub‐areas diverge, should CAISO decide to pursue a more granular approach to local RA in the future.
https://www.caiso.com/planning/Pages/ReliabilityRequirements/Default.aspx; https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K666/496666765.PDF 67 Calculation includes the impact of storage charging. 68 https://www.caiso.com/Documents/Final2023LocalCapacityTechnicalReport.pdf
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Glenarm (with nameplate capacity of 196 MW) that can provide quick ramping support fulfills the need for local and flexible RA requirements. Additionally, it is anticipated that local requirements will likely increase over time. Local RA capacity is currently a scarce product in the market with high prices and less liquidity than System RA capacity. This tre nd is anticipated to continue as fossil fuel resources in California are decommissioned or reach the end of their natural lives.
9.3. Flexible Resource Adequacy Capacity
The Flexible RA capacity requirement is based on the largest three‐hour net load ramp in a month and was implemented in 2015 to address the increased need for grid flexibility given greater renewable resource penetration. CAISO uses load and renewable resource data to determine the overall Flex RA capacity needed for each month, then allocates requirements based on ea
ch LRA’s contribution to the load ramp under Section 40.10.2.69 PWP must have sufficient Flex RA from owned and contracted resources to cover its obligations.
CAISO tariff Section 40.10.3 details the following three types of Flexible Capacity: 70 Category 1 (Base Flexibility)
Available seven days per week, all days per month
Must be capable of bidding into the day‐ahead and real‐time markets from 5:00 a.m. to 10:00 p.m. Pacific Prevailing Time
Must be capable of providing energy for a minimum of six hours at capacity Must be able to provide the minimu
m of two start‐ups per day for every day of the month or 60 starts per month, or the number of start‐ups allowed by its operational limits, including minimum up and minimum down times
No monthly or annual limitations on number of starts or energy limits that translate to less than the daily requirements
Category 2 (Peak Flexibility)
Available seven days per week, all days per month
Must be capable of bidding into the day‐ahead and real‐time markets for a five‐hour block that is determined seasonally
Must be capa
ble of providing energy for a minimum of three hours at capacity Must be capable of at least one start‐up per day
No monthly or annual limitations on number of starts or energy limits that translate to less than the daily requirements
Base ramping counts for peak ramping
Category 3 (S
uper‐Peak Flexibility)
Available all non‐holiday weekdays per month
69 http://www.caiso.com/InitiativeDocuments/Final2023FlexibleCapacityNeedsAssessment.pdf 70 https://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Reliability%20Requirements
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Must be capable of bidding into the day‐ahead and real‐time markets for a five‐hour block that is determined seasonally
Must be capable of providing energy for a minimum of three hours at a capacity Must be capable of at least one start‐up per day
Must be capable of responding to at least five disp
atches per month during the five‐hour period of the
must‐offer obligation
Base ramping and peak ramping counts for super peak ramping Flexible RA capacity is distinct from System RA and Local RA capacity. It has its own accreditation methods. Generally, Flexible RA capacity is bundled with System RA (or Local RA) capacity at a slight premium. It is not generally traded as a stand‐alone product since the CPUC requires all Flexible RA to be bundled with System RA for CPUC‐jurisdictional entities, and most of the load is served by CPUC‐jurisdictional entities. Given that CAISO allows Flexibl e RA and System RA to be scheduled separately, it is possible that these products could trade separately for non‐jurisdictional entities, although that is not currently the common practice.
Glenarm with its unique capabilities such as quick start, ramping ability, minimum run time, and other econ omics, is highly desirable in supporting forecast dependent resources such as wind and solar and their inherent variability. Glenarm currently provides all of PWP’s Flexible RA capacity requirements.
9.4. Slice of Day Proposal
The Slice of Day proposal was adopted by CPUC in the 2022 RA proceeding and is currently applicable only to CPUC‐ jurisdictional LSEs.71 Under the Slice of Day construct, an LSE must show that it has sufficient capacity and reserve margin in each hour of the “worst day” of every month. This includes having sufficient energy available to charge energy storage resources. The test year for this construct is 2024, and 2025 will be binding with associated penalties for deficie ncies. As of February 2023, the CPUC and stakeholders were still developing the mechanics. While PWP is not directly affected, there may be some aspects that CAISO adopts, though there are no current discussions. The Slice of Day construct may ultimately affect RA trading in the future.
9.4.1. Reliability Must‐Run Resources
Some generation is crucial in maintaining system reliability and may not be allowed to retire without a detailed and stringent backup plan. These units are designated as RMR resources. According to CAISO, RMRs are:
"Generation that the CAISO determines is required to be on‐line to meet Applicable Reliability Criteria requirements. This includes i) Generation co nstrained on‐line to meet NERC and WECC reliability criteria for interconnected systems operation; ii) Generation needed to meet Load demand in constrained areas; and iii) Generation needed to be operated to provide voltage or security support of the CAISO or a local area."
71 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M488/K540/488540633.PDF
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RMRs are covered in Section 41 of the CAISO tariff.72
The Glenarm resource is on the PWP load side of a 280 MW interconnection into CAISO via the Goodrich intertie line.
Operations are critical as PWP is a transmission‐constrained electric system. Given Glenarm’s strategic importance in preventing load shed, any decisions regarding its operations would be subject to CAISO analysis, which is based in part on NERC reliability standards.
The following are the circ
umstances that cause Glenarm to come online:
Glenarm helps serve load above the Goodrich intertie limit Glenarm is economic enough to provide reliability benefits to the grid Goodrich is unavailable due to unexpected failure or needs routine maintenance Glenarm alleviates constraints on the distribution system One or both 220kV trans
mission lines from SCE experience unexpected failure or need routine maintenance Glenarm provides additional reliability benefits, such as Reactive Power (VAR) support to maintain CAISO‐ required voltage bandwidth
Glenarm supports renewable resources and can compensate for their output variability attributed to the uncertainty of wind speeds and solar illumination. The CAISO makes Glenarm unit commitment decisions in these cases where required
PWP is part of CAISO, thus Glenarm is part of CAISO. If Glenarm is online, it is not in complete control of its operations, as it must follow instructions from CAISO. CAISO is similar to a financial cl earinghouse; it identifies the most cost‐effective
sources of power and dispatches them based on physical constraints. Optimizing multiple resources over a wider territory can produce savings for the larger system. CAISO may find that Glenarm is one of the more cost‐effective sources of power and call on it to provide energy. Given the lower
dispatch of the Glenarm units, it is unlikely that Glenarm will be called on frequently because of economics. It is more likely that CAISO instructs Glenarm to come online to help with grid reliability.
Glenarm helps provide reli
ability benefits to the grid, as included in its RA characteristics. Under CAISO rules, resources that qualify for RA have to offer in CAISO’s day‐ahead markets. This is referred to as a must‐offer obligation. There are limits to what price a resource can offer in CAISO. These rules exist to prevent market manipu lation or an abuse of market power. Given that Glenarm is an RA resource, it has to offer into the CAISO markets at a reasonable rate, as determined by the CAISO tariff.
72 https://www.caiso.com/Documents/Section41‐Procurement‐of‐ReliabilityMust‐RunResources‐asof‐Aug15‐2022.pdf
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10. Model Assumptions
10.1. Planning Horizon (POUs)
In accordance with CEC guidelines, the planning horizon of an IRP must begin no later than January 1 of the year of adoption by a POU’s governing board.73 The 2023 IRP will be presented to the Pasadena City Council for approval in late 2023 and will therefore be considered in effect on January 1 of that year. While current regulations require the planning horizon to run through 2030, the CEC 2022 draft IRP guidelines extend this timeline to 2045, suggesting an attempt to align
with evolving clean energy laws and regulations, including the following:
AB 1279, which expands on SB 32’s statewide 40% by 2030 GHG emissions reduction requirement to achieve carbon neutrality no later than 2045 and reduce anthropogenic GHG by 85% compared to 1990 levels. SB 1020, which accelerates SB 100’s 100% renewa ble and zero‐carbon resources by 2045 requirement for faster adoption by adding interim targets that go beyond 2030.
Also, since resources in the modeled portfolios will likely continue to be operational beyond 2045, the 2023 IRP uses a 27‐ year planning horizon that starts in 2023 and ends in 2050 (Study Period). While not required by the CEC, it is expected that the longer Study Period will be usef
ul for evaluating capacity and resource performance.
10.2. Model
PWP’s IRP leverages Anchor Power’s EnCompass software, a premier capacity expansion and production cost modeling software developed and maintained by Anchor Power Solutions. 74 EnCompass is a state‐of‐the‐art power planning simulation software designed for modeling evolving power markets, decarbonization, and sustainability. Encompass was created with enhanced capabilities to evaluate new technologies, assess renewable resources and storage, model reductions in GHG emissions, and optimize decarbonization strategies, and is the industry‐model of choice for a variety of entities, including municip
al utilities, investor‐owned utilities, electric cooperatives, and consultants. It has been the basis for regulatory filings in 17 states.
EnCompass provides capacity expansion, nodal and zonal hourly chronological production cost modeling, risk analysis, scenario analysis, and financial revenue requirement modeling. Figure 29 provides a summary of the model options. The 2023 PWP IRP was modeled using the zonal construct.
73 https://www.energy.ca.gov/rules‐and‐regulations/energy‐suppliers‐reporting/clean‐energy‐and‐pollution‐reduction‐act‐sb‐350‐0 74 https://anchor‐power.com/encompass‐power‐planning‐software/
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Figure 29: EnCompass Power Planning Software
EnCompass minimizes total costs and maximizes total revenue of electricity systems, subject to constraints. The model selects and operates the least‐cost, best‐fit resource mixes given assumptions. In the IRP modeling results, dollars are nominal, unless otherwise noted. The model uses a nominal discount rate of 5% and an annual inflation rate of 2.5%, with results reflected in calenda
r years. The three critical model constraints used for PWP’s IRP are shown in Figure 3030.
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Figure 30: PWP Integrated Resource Plan Critical Model Constraints PWP IRP Critical Model Constraints
Energy Resource Adequacy Environmental Priorities
PWP is a transmission‐constrained
system with limited ability to import
energy from outside its service
territory. The model considered
transmission import constraints
when selecting new resources and
their preferred locations.
Resource selection is optimized to
meet RA requirements. RA is monthly
peak load plus a PRM. The PRM is
modeled at 15% and increases to
17.5% in 2025.
A resource's ability to meet the RA
requirements is dependent on
resource type. More information is
included in Figure 4041.
California RPS regulations require 60%
of retail sales to be met with
renewable resources by 2023,
increasing to 100% renewable and
zero‐carbon resources by 2045. Carbon
emissions must also decline over time
in accordance with the Cap‐and‐Trade
Regulation.
Pasadena City Council Resolution 9977
declares a climate emergency and sets
a policy goal to source 100% of
Pasadena’s electricity from carbon‐free
resources by the end of 2030 while
optimizing for affordability, rate
equity, stability, and reliability.
10.3. Model Topology
PWP’s system was modeled according to the topology shown in Figure 311. This setup mimics the system on a transmission level.
Figure 31: Model Topology
PWP serves load within its service territory with internal resources (Glenarm or distributed resources) and by importing energy from CAISO at Goodrich.
PWP is a transmission‐constrained electric system. Currently, Goodrich can import up to 280 MW under normal operating system conditions. This is expected to increase to 336 MW in July 2032 with the completion of system upgrades descri bed
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in Transmission and Distribution. PWP has also executed contracts for resources located outside its service territory. The energy from these external resources moves through the CAISO controlled system and is delivered to the Goodrich substation.
10.4. Power and Fuel Prices
The external area is CAISO. CAISO operates financial markets for electricity and helps ensure reliable power delivery by monitoring and controlling the operation of power plants and transmission lines. 75 CAISO, which PWP joined in 2004, also helps plan with rigorous studies and requirements.
The IRP model uses forecasted power and natural gas prices for the CAISO area surrounding PWP. This accounts for trends in the larger California area. Price trends are based on forecasted resource mixes and include financial and emission factors.
The power prices for SP15 (the CAISO zone for
which PWP prefers to price contracts) and the natural gas prices for the Southern California City Gate location come from the Horizons Energy, LLC (Horizons Energy) Fall 2022 Advisory.76 Horizons Energy generates fundamental forecasts for 78 North American electricity markets across nine scenarios for energy, fuel, capacity, renewable energy, emissions pricing, and ancillary services.77 It uses the EnCompass database to create price curves. ACES also uses Horizons Energy data to assist in the management and evaluation of more than 50,000 MW of load and generation for its clients.
For 2023 through 2027, the 2023 IRP uses power and natural gas prices based on market quotes with a trade date of December 30, 2022. This is the latest tr
ade date that allows for full‐year 2023 data. Beginning 2028, ACES blended the prices into Horizons Energy price forecast curves at 10% per year, such that prices reflect 100% Horizons Energy data in 2037. This blending process ensures price forecasts in the early years that are as close to actual and execut able pricing as possible, with later years mimicking the long‐term fundamental price forecast. Power and natural gas pricing are included in Figure 322 and Figure 333, respectively.78 Prices are normally subject to confidentiality agreements, but Horizons Energy graciously allowed for release.
75 https://www.caiso.com/Pages/default.aspx
76 https://www.horizons‐energy.com/
77 https://www.horizons‐energy.com/advisory‐services/advisory‐service/ 78 The opinions expressed in this report are based on Horizons Energy’s judgment and analysis of key factors expected to affect the outcomes of electric power markets. However, the actual operation and results of power markets may differ from those projected herein. Horizons Energy makes no warranty or guarantee regarding the accuracy of any proje ctions, estimates, or analyses, or that such work products will be accepted by any legal, financial, or regulatory body.
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Figure 32: SP15 7x24 Power Prices
Source: Hor izons Energy Fall 2022 Advisory
Figure 33: Fuel Prices
Source for Natural Gas: Hor izons Energy Fall 2022 Advisory Figure 344 in
cludes additional estimates of fuel pricing for green hydrogen and biofuel, which were created from publicly available sources.
$0
$20
$40
$60
$80
$100
$120Nominal $/MWh
SP15 7x24 Power Prices
$0
$10
$20
$30
$40
$50
$60
Nominal $/MMBtu
Fuel Prices
Natural Gas Green Hydrogen Biofuel
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Figure 34: Fuel Pricing Assumed in PWP’s 2023 Integrated Resource Plan Fuel Pricing Assumed in PWP’s 2023 IRP
Timeframe Power Natural Gas Biogas Green Hydrogen
Starting Point 2023 through 2027
based on market
quotes with a trade
date of December 30,
2022*
2023 through 2027
based on market
quotes with a trade
date of December 30,
2022*
Assume an initial
price of
$25/MMBtu79
Start at $5.80/kg80
Convert from gallons
to MMBtu81
Intermediate Years Horizons Energy
forecast blended at
an additional 10%
per year
Horizons Energy
forecast blended at
an additional 10%
per year
Price declines linearly
through 2040
Price declines linearly
through 2050
Ending Point 100% Horizons
Energy forecast in
2037 and beyond
100% Horizons
Energy forecast in
2037 and beyond
Assume $24/MMBtu
(in real 2019 $) in
2040; maintain a
linear decline
afterwards82
Assume a final price
of $1.15/kg (in real
2019 $) in 205083
*Last trade date that allows for full 2023 data
Biofuel and hydrogen may benefit from tax credits under the IRA. Because of the forecast dependency on public source data pre‐IRA, such benefits are not directly included. PWP will evaluate the market, public and private sources of information, to investigate these fuels if needed. The IRA is discussed in 11.2.4 of the IRP.
10.4.1. More About Horizons Energy, LLC’s Forecasting Method Horizons Energy uses a fundamentals‐based methodology to forecast energy, capacity, environmental and ancillary service prices for 78 North America market areas. Based on Anchor Power’s EnCompass power planning model, Horizons Energy simulates the operation of each region of North America. EnCompass is recognized in the industry for its flexibility and breadth of technical capability, i ncorporating extensive details in generating unit operating characteristics and constraints, transmission constraints, generation analysis, unit commitment/operating conditions, and market system operations. This fundamental approach utilizes the operating characteristics of more than 16,000 generating assets, fuel prices, hourly demand, transmission transfer capabilities, market rules of ISOs and other factors. 79 https://gasfoundation.org/2019/12/18/renewable‐sources‐of‐natural‐gas/ 80 https://www.utilitydive.com/news/green‐hydrogen‐prices‐global‐report/627776/ 81 https://www.altenergymag.com/story/2020/03/%E2%80%98hydrogen‐economy‐offers‐promising‐path‐to‐ decarbonization/32929/
82 https://gasfoundation.org/2019/12/18/renewable‐sources‐of‐natural‐gas/ 83 https://data.bloomberglp.com/professional/sites/24/BNEF‐Hydrogen‐Economy‐Outlook‐Key‐Messages‐30‐Mar‐2020.pdf
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The EnCompass power planning model utilizes this database of market information and simulates both annual capital decisions as well as the operational commitment and dispatch of resources. The model simultaneously determines energy, capacity, environmental and ancillary service prices with hourly resolution and across scenarios. Horizons Energy forecasts market prices throughout North America through the 2050 forecast horizon .
Horizons Energy utilizes a variety of sources like Natural Gas Intelligence (NGI) to obtain forwards and historical costs, the U.S. Energy Information Administration (EIA) Annual Energy Outlook, and other published sources. In the base scenario, Horizons Energy assumes future market prices from NGI for 10 years, then applies a trend thereafter base d on internal research and other published sources.
Horizons Energy developed the wind and solar profiles from NREL data. The wind is based on the class of wind and turbine height, whereas solar is based on radiance, fixed or tilt axis, and number of axes.
10.5. Transmission and Congestion
When PWP contracts for new resources, costs associated with congestion and transmission access are generally not included in the contract price.
Electric grids are similar to road systems – there are busy roads and costs associated with that congestion. PWP must pay to transport power from where it is generated to where it is needed. Congestion costs are not included in the IRP modeling.
However, congestion could be a significant cost in the future, and should be considered when PWP is evaluating contracts.
The TAC is a fee that CAISO charges participants for use of the transmission system. These are general infrastructure usage fees. TAC is separate and distin
ct from congestion costs. The IRP assumes that the TAC, which applies to external resources and is estimated by CAISO, escalate by 2.1% (the average annual growth rate) after 2036 when the CAISO forecast ends.84 Figure 355 shows a forecast of TAC fees.
84 http://www.caiso.com/Pages/DocumentsByGroup.aspx?GroupID=7A2CFF1E‐E340‐4D46‐8F39‐33398E100AE7
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Figure 35: Transmission Access Charge Forecast
Elec
tric grids are complex, interconnected systems. Power is injected and consumed across the grid, and transmission lines transport electricity from where it is produced to where it is needed. Additionally, electricity must be produced (or released from storage) the moment it is needed. There are physical (and many other) constraints that underline this system, making long‐
term planning a multifaceted optimization that considers various factors, such as location, cost, resource type, timing, and environmental impact. Transmission considerations, in terms of availability and cost, are made at the implementation stage, when the relative merits and challenges of specific candidate projects are assessed.
10.6. Load vs. Resources
The following two sections outline PWP’s resources and load. Existing Resources provides details on PWP’s existing resource fleet, while New Resources provides information on new resource options.
Overall, resources are located internally (connected electrically anywhere within PWP’s power system) or externally (located outside PWP’s service territory (i.e., “the grid.”)). Figure 366 lists the internal and extern al resources used in the model, as well as the distributed resources included in the load forecast. Additional details regarding electric load and what is included is shown in the Load Forecast of the IRP. Figure 377 classifies resource size. $0
$5
$10
$15
$20
$25
$30
$35
Nominal $/MWh
TAC Forecast
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Figure 36: Resources by Location
External Resource Options Internal Resource Options Included in Load Forecast Onshore wind
Onshore wind paired with 4‐
hour batteries
Offshore wind
Utility‐scale solar
Utility‐scale solar paired with 4‐
hour batteries
Geothermal
4‐hour storage
8‐hour storage
10‐hour storage
Fuel cells
Community (utility‐scale) solar
4‐hour storage
6‐hour storage
8‐hour storage
10‐hour storage
Commercial batteries
Fuel cells
Residential solar
Residential batteries
Commercial solar
Commercial batteries
Biogas (defined as renewable)
Energy efficiency
Distributed solar
Residential storage
Commercial storage
Figure 37: Resource Category by Size
Category Description
Utility‐Scale Large (~1 MW or larger). Lowest costs per unit due to economies of scale. Utility‐scale resources are usually large projects located in open areas, such as fields.
Community Large (often utility‐scale) and usually owned/contracted by the utility. Allows consumers with limited roof space to opt‐in and get a share of the solar output.
Distributed
(Commercial)
Medium (~714 kW); usually owned/contracted by consumer.85 Examples: panels on a parking garage or on a larger industrial building.
Distributed
(Residential)
Small (~6 kW); usually owned/contracted by consumer.86 Example: panels on a house. 85 https://atb.nrel.gov/electricity/2022/commercial_pv
86 https://atb.nrel.gov/electricity/2022/residential_pv
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11. Resources
11.1. Existing Resources
PWP has accumulated a diverse mix of resources to reduce its overall portfolio risk. PWP’s current resource portfolio consists of City‐owned natural gas generation and a variety of contracted energy, capacity, and renewable resources. In 2023, PWP’s portfolio included approximately 200 MW of City‐owned natural gas generation and 247 MW of other contracted resources. A su
mmary of resources is provided in Figure 388.
Figure 38: Owned and Contracted Resources87
Facility Owned or
Contracted
Retirement or
Exit Date Fuel Type PWP Share
(MW) RA Class Renewable
Class
IPP Coal Contracted 6/30/2025 Coal 108 System,
Flexible
None
IPP Natural
Gas
Contracted 6/30/2027 Natural Gas
Combined
Cycle
54 System,
Flexible
None
Glenarm Owned Not Applicable Natural Gas –
132 MW
Combustion
Turbine and
65 MW
Combined
Cycle
197 System, Local,
Flexible
None
Magnolia Contracted 7/1/2036 Natural Gas
Combined
Cycle
14 System, Local,
Flexible
None
Hoover Hydro Contracted (Beyond 2050) Hydroelectric 14 System None Palo Verde
Nuclear
Contracted 2045‐2047 (3
units)
Nuclear 10 System None
Milford Wind Contracted 11/14/2029 Wind 5 System PCC0 PPM (also
called
Avangrid, or
High Winds
Project, or
Iberdrola)
Wind
Contracted 12/31/2023 Wind 2 System PCC0
87 Azuza Hydro, a 15 MW contracted resource, is currently out of service and does not contribute to PWP’s resource portfolio
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Facility Owned or
Contracted
Retirement or
Exit Date Fuel Type PWP Share
(MW) RA Class Renewable
Class
Chiquita
Landfill
Contracted 11/22/2030 Landfill Gas 6 System, Local, Flexible
PCC0
Puente Hills
Landfill
Contracted 12/31/2030 Landfill Gas 10 System, Local, Flexible
PCC1
Coso
Geothermal
Contracted 12/31/2046 Geothermal 10‐ 20 System PCC1 Geysers
Geothermal
Contracted 12/31/2041 Geothermal 25 System PCC1
Antelope Solar Contracted 12/31/2041 Solar 7 System, Local Solar Columbia Two
Solar
Contracted 12/18/2034 Solar 2 System PCC1
Kingbird Solar Contracted 12/31/2036 Solar 20 System PCC1 Summer Solar Contracted 12/31/2041 Solar 7 System, Local PCC1 Windsor
Reservoir
Solar
Contracted 5/30/2031 Solar 1 None PCC1
Sapphire Solar
+ Battery
Contracted 12/31/2046 Solar, with
Battery Energy
Storage
System
39 (Solar); 20
(Battery)
System PCC1
The renewable en
ergy in Figure 399 is identified by category for compliance with California’s RPS rules. Further information is available in the IRP and on PWP’s website.88 Figure 39: Contracts for Renewable Energy
Renewable Category Quantity (MWh) Contract Year
PCC1 Bundled Renewable Energy and RECs (Powerex PCC1) 70,000 (Annually) 2020‐2030 88 https://ww5.cityofpasadena.net/water‐and‐power/pwppowersources/
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Renewable Category Quantity (MWh) Contract Year
PCC1 Bundled Renewable Energy and RECs (Avangrid) 10,000 2023 PCC1 Bundled Renewable Energy and RECs (Avangrid) 120,000 2024 PCC2 Bundled Renewable Energy and RECs (Avangrid) 70,000 2023 PCC2 Bundled Renewable Energy and RECs (Powerex) 70,000 2024 PCC3 RECs (STX) 30,000 2023
PCC3 RECs (STX) 35,000 2024
Additional inf
ormation on owned or contracted resources is outlined in the following sections.
11.1.1. Coal
PWP has a long‐term contract for 108 MW of coal‐fired power generation from the IPP facility in Utah. Thirty‐five participants in six states, including neighboring cities of Los Angeles, Anaheim, Burbank, Riverside, and Glendale, contract for power and capacity from the two‐unit, 1,800 MW coal‐fired steam plant. PWP’s annual share of IPP generation is modeled as
450 GWh of must‐take energy which is approximately 39% of PWP’s annual load.
IPP will transition from coal‐fired generation to natural gas‐combined cycle in July 2025 and PWP has contracted for 54 MW of the combined cycle output through the end of June 2027. Th e repowered facility will provide approximately 375 GWh of energy, or about 33% of PWP’s annual load. PWP’s share of IPP current and future generation facilities is fixed.
PWP’s participation in IPP will end in 2027 and PWP will not participate in plans for the facility to transform to a renewable energy an
d hydrogen hub. 89
11.1.2. Natural Gas
PWP both owns and contracts for a combined total of 264 MW of natural gas energy and capacity.
Like coal resources, natural gas resources have resource‐specific carbon‐emission factors. The corresponding carbon output for these resources are covered under California’s Cap‐and‐Trade program, and count against PWP’s emission allowance. Despite this carbon content, the trajectory has been increasing percen tages of clean and renewable energy in PWP’s portfolio as incremental renewable procurements have and will occur.
11.1.2.1. Owned
PWP owns 197 MW of natural gas capacity from the Glenarm in Pasadena, which is comprised of four combustion turbines and one combined‐cycle unit. These resources are located on the PWP‐side of the Goodrich. Goodrich is PWP’s interconnection facility with the CAISO transmission system.
Glenarm provides key reliability benefits when PWP system loads exceed the Goodrich tra nsfer limits or when PWP’s distribution system reaches internal transfer limits.
89 https://www.ipautah.com/ipp‐renewed/
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The Glenarm units also provide significant resource adequacy capacity that help meet reliability requirements under CAISO’s tariff.
11.1.2.2. Contracted
As mentioned above, PWP will begin receiving 54 MW of natural gas‐fired generation output from IPP after its conversion from coal in 2025.
PWP has also contracted for up to 14 MW of energy and capacity from the Magnolia in Burbank, California, of which 6 MW is modeled as must‐take energy. Any early termination of the Magnolia contract, which currently runs through June 2036, would be subject to the terms and conditions as stated in the contract.
11.1.3. Wind
PWP has contracted for 7 MW of wind capacity from the Milford Wind and PPM Wind Projects.
11.1.4. Landfill Gas
PWP has contracted for 16 MW of landfill gas from the Puente Hills and Chiquita facilities.
11.1.5. Solar
PWP has contracts for 37 MW of solar from five facilities and recently executed an agreement for the Sapphire Solar + Storage Project (Sapphire). Sapphire is slated to begin commercial operations by the end of 2026 and will add 39 MW of contracted installed capacity to PWP’s existing 37 MW of installed solar capacity.
11.1.6. Hydro
PWP purchases up to 14 MW of the output of the Boulder Canyon Project at the Hoover Dam. The daily and hourly capacity and energy from Boulder Canyon varies due to river flow requirements. The annual output varies due to hydrology, storage conditions and environmental constraints.
11.1.7. Nuclear
PWP has a long‐term contract for 10 MW of the Palo Verde Nuclear facility in Arizona. Palo Verde is modeled as a baseload must‐take resource. Its expected output is based on historic generation patterns and its maintenance schedule.
11.1.8. Geothermal
Prior to 2023, PWP contracted for 10 MW of the Coso geothermal facility that is planned to begin delivering to PWP in 2027 and expected to increase to 20 MW of installed capacity in 2037. In 2023, PWP executed an agreement for 25 MW of the Geysers Geothermal Project (Geysers), which will begin delivering to PWP in 2027. Both Coso and Geysers are modeled as
must‐take baseload resources.
11.2. New Resources
11.2.1. New Resource Options
The IRP simulation model (EnCompass, detailed in Model of the IRP) selects from a variety of resources to provide future energy, capacity, renewable, and zero‐carbon energy based on need, location, and economics. For the 2023 IRP, resources
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are generally modeled in increments of 5 MW or greater. This is considered utility scale, and the increment at which PWP is currently willing to transact. However, PWP would consider smaller increments of distributed resources – commercial and residential solar and batteries are modeled as 1 MW increments. This represents aggregations of smaller projects.
The following are the resource options available in the mode l are:
Utility‐scale wind
Onshore land‐based
Onshore land‐based paired with 4‐hour lithium‐ion battery storage Offshore
PV
Utility‐scale
Commercial
Residential
Utility‐scale paired with 4‐hour lithium‐ion battery storage Lithium‐ion battery storage
4‐hour utility‐
scale
6‐hour utility‐scale
8‐hour utility‐scale
10‐hour utility‐scale
4‐hour commercial
2.5‐ hour residential
Utility‐scale fuel cells using renewably derived hydrogen Utility‐scale geothermal
The load forecast incl
udes the impacts of existing and naturally expected forecasted energy efficiency, demand response, distributed solar, distributed storage, electric vehicles, and fuel substitution. See Load Forecast for more details.
Distributed resources, in addition to those included in the load forecast, are optimized as new resource installations. The 2023 IRP assumes, for study purposes, that PWP would finance, control, and register the additional distribu ted resources
as some form of CAISO resource that can provide energy, capacity, and/or renewable benefits.
11.2.2. New Resource Parameters
Resources are modeled with a 20‐year contract term and the parameters shown in Figure 4040. All resources, except possibly stand‐alone batteries, provide renewable and carbon‐free energy.
Figure 40: New Resource Parameters
New Resource Parameters
Resource Type Size Capacity Factor Location Additional Details Land‐based
(onshore) wind
10 MW 35% External
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New Resource Parameters
Resource Type Size Capacity Factor Location Additional Details Land‐based
(onshore) wind
paired with 4‐hour
lithium‐ion battery
storage
10 MW wind and 5
MW storage;
interconnection
limited at 10 MW
35% for wind; 17%
for storage
External 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year90
Offshore Wind 10 MW 46% External
Utility‐scale
photovoltaic solar
10 MW 32% External
Commercial
photovoltaic solar
1 MW 19% Internal 1 MW represents an
aggregation of smaller
resources
Residential
photovoltaic solar
1 MW 19% Internal 1 MW represents an
aggregation of smaller
resources
Utility scale
photovoltaic solar
paired with 4‐hour
lithium‐ion battery
storage
10 MW solar and 5
MW storage;
interconnection
limited at 10 MW
32% for solar; 17%
for storage
External 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year
4‐hour utility scale
lithium‐ion battery
storage
10 MW 17% External and internal 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year
6‐hour utility scale
lithium‐ion battery
storage
10 MW 25% External 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year
8‐hour utility scale
lithium‐ion battery
storage
10 MW 33% External 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year
10‐hour utility scale
lithium‐ion battery
storage
10 MW 42% External 85% roundtrip
efficiency for lithium‐
90 https://atb.nrel.gov/electricity/2022/utility‐scale_battery_storage
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New Resource Parameters
Resource Type Size Capacity Factor Location Additional Details ion storage; limited to
365 cycles per year
4‐hour commercial
lithium‐ion battery
storage
1 MW 17% Internal 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year; 1
MW represents an
aggregation of smaller
resources
2. 5‐ hour
residential lithium‐
ion battery storage
1 MW 10% Internal 85% roundtrip
efficiency for lithium‐
ion storage; limited to
365 cycles per year; 1
MW represents an
aggregation of smaller
resources
Renewable
Hydrogen‐ Powered
Fuel Cells
10 MW Fuel dependent External 6,469 British thermal
units (Btu)/kWh heat
rate91
Burns green hydrogen
Geothermal 10 MW 90%92 External
Monthly capacity accreditation values for different resource types in 2030 are shown in Figure 411. PWP assumed the accreditation for solar was consistent across size. PWP also assumed 100% accreditation for storage Figure 41: Resource Adequacy Accreditation for New Resources Seasonal Qualifying Capacity in 2030 for a 100 MW Installed Capacity Plant (MW) Resource Type January February May August September Land‐based
(onshore) wind
21.90 23.40 21.80 13.80 14.20
Offshore Wind 35.00 39.00 31.00 53.00 43.00
Utility‐scale
photovoltaic solar
0.27 2.04 4.36 8.44 7.56
91 https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf 92 https://atb.nrel.gov/electricity/2022/geothermal
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Seasonal Qualifying Capacity in 2030 for a 100 MW Installed Capacity Plant (MW) Resource Type January February May August September Commercial
photovoltaic solar
0.27 2.04 4.36 8.44 7.56
Residential
photovoltaic solar
0.27 2.04 4.36 8.44 7.56
Renewable
Hydrogen‐
Powered Fuel
Cells93
99 99 99 99 99
Geothermal 98.30 95.98 92.75 95.09 92.77
4‐ Hour (or
greater) storage
100.00 100.00 100.00 100.00 100.00
2.5 ‐Hour Storage 62.5 62.5 62.5 62.5 62.5
11.2.3. Availability of New Resources
The IRP model can add up to 1 GW of each of the resources listed in Figure 4040 to the PWP portfolio each calendar year.
At any one point, the model allows a maximum of 2 GW of each new resource type online simultaneously.
All new resource options are available in 2025 except offshore wind and fuel cells. PWP assumes that offshore wind and fuel cells are available for deployment as soon as 2030, which allows additional time for technology maturation.
Given that PWP has a peak of 320 MW in 2023, these build limits in the model are larger than what PWP may be willing to pursue. This currently prevents the mode
l from constraining PWP’s potential actions. Market availability will determine when and how much of each different resource type is available. PWP anticipates participating in the market frequently and will adjust procurement based on market intelligence.
PWP assumes that the following resources could be physically located in PWP’s service territory:
200 MW of 4‐hour batteries, or any one of the following:
150 MW of 6‐hour batteries
100 MW of 8‐hour batteries
50 MW of 10‐hour batteries
5 MW of utility scale solar
5 MW of fuel cells
Distributed resourc
es (residential solar, commercial solar, residential storage, commercial storage) 93 This is the weighted average value from Glenarm. Glenarm is a proxy for a dispatchable, fuel dependent resource.
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Other resources would be located outside PWP’s service territory.
11.2.4. Inflation Reduction Act and Tax Credits
The IRA, which was enacted in 2022, provides for significant investments to promote decarbonization in the U.S. Current assessments of the impact of the IRA indicate up to a 10% decrease in net emissions by 2030 (compared to 2005 levels).94 The IRA includes $369 billion over the next decade for energy and climate initiatives – the largest investment in climate to date.95 The majority of this investment will be in the form of tax credits.
The IRA extends and modifies the previously available investment and production tax credits. With the ITC, the credit received is a percentage of the cost of a project. The PTC is similar, but the amount compensated depends on anticipated energy production versus project cost.
The ITC and PTC have be
en in place for decades in the U.S. and have helped encourage development of renewable generation. While eligibility has historically been limited to certain technologies, under the IRA, the ITC and PTC become new technology‐neutral incentives starting in 2025. This is also the first year for addition of new resources in the 2023 IRP; therefore, the te
chnology‐neutral incentives will be included in resource costs.
To qualify for the technology‐neutral PTC under the new Section 45Y of the Internal Revenue Code, resources must emit zero emissions based on a lifecycle assessment. The 2023 IRP as sumes that onshore wind and geothermal projects will incorporate the PTC.
Energy storage now qualifies under the technology‐neutral ITC according to the new Internal Revenue Code Section 48D.
Previously, storage eligibility required that associated charging be from a renewable resource. That no longer applies. The 2023 IRP assumes that storage, offshore wind, solar, and fuel cells will use the IT C.
The Federal Government revamped the ITC and PTC to support U.S. labor and supply chains. Generally, there is both a base ITC and PTC which are multiplied by a factor of five if developers meet prevailing wage and apprenticeship requirements. There are additional 10% adders if domestic content requirements are met, or if the project is in an energy community. Details on these multipliers appear in Figure 422.96 Figure 433 shows the general tax credits. The IRP cost inputs assume that prevailing wage and apprenticeship requirements have been met.
There are also grants, loans, and loan financing available under the IRA. These may provide opportunities for PWP to reduce or offset future costs. PWP is pursing grant opportunities while also considering self‐build IRA crit eria. 94 https://rhg.com/research/climate‐clean‐energy‐inflation‐reduction‐act/ 95 https://www.cohnreznick.com/insights/inflation‐reduction‐act‐renewable‐energy‐tax‐incentives 96 Jenkins, Jesse D.; Farbes, Jamil; Jones, Ryan; and Mayfield, Erin N. (2022), "REPEAT Project Section‐by‐Section Summary of Energy and Climate Policies in the 117th Congress," B23 REPEAT Project, http://bit.ly/REPEAT‐Policies. doi: 10.5281/zenodo.6993118; https://docs.google.com/spreadsheets/d/1X2PORZp5JzP2yWbdUSbXphElIGPEOlJNI‐T12gz7n1s/edit#gid=1108881515
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Figure 42: Bonus Tax Credits for Renewable Resources
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Figure 43: IRA Tax Credits for Projects in Service After December 2024 Figure 444 summarizes the IRA tax credits applied to new resources in the 2023 PWP IRP study and modeling process.
Figure 44: PWP 2023 Integrated Resource Plan Tax Credit Assumptions
ITC/PTC
Component
2025 to
2032 2033 2034 2035 2036+ Notes
PTC
Section 45Y (Clean
Electricity
Production Tax
Credit)
100% 100% 75% 50% 0% Apply to onshore wind,
geothermal
ITC
Section 48E (Clean
Electricity
Investment Tax
Credit)
30% 30% 22.5% 15% 0% Apply to solar, storage, fuel cells, offshore wind
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ITC/PTC
Component
2025 to
2032 2033 2034 2035 2036+ Notes
Section 25D 30% 26% 22% 0% 0% Residential solar and residential storage
For homeowners that own solar
and ≥3 kWh storage systems97
This assumes that homeowners
will purchase the solar and
storage, and that PWP will
compensate them
There are various factors that may change tax credit selection and utilization. For example, PWP understands that tax credits may be extended. PWP also may find that solar may elect to use the PTC instead of the ITC. PWP will endeavor to stay abreast of market developments and may study the impacts of various tax credit assumptions.
11.2.5. Contract vs. Ownership and Tax Credits
In the 2023 IRP, modeled resource costs are the estimated price that can be obtained in the market for a PPA. In actual practice. PWP will pursue the most economic option relative to PPA’s vs. ownership or self‐build. The IRP identifies the best fit resources, without regard for ownership structure. The process for acquiring additional specific resources for PWP’s resource portfolio includes evaluation of cost, availability, risk profile, and other factors relevant at the time.
Under the IRA, tax‐exempt entities, including government agencies, can receive direct payments from the Treasury Department for technologies such as carbon capture, energy storage, and traditional renewables. Direct pay applies to the new ITC and PTC and includes domestic content requirements. Specifically, for a project to meet the domestic content requirements, iron or steel that is not part of manufactured products must be made in the U.S., and a certain percentage of the total cost of the manufactured products must be made in the U.S. See Figure 4598 .
For projects that begin construction in 2024 or 2025 that do not meet domestic content requirements, the direct pay credit is reduced by 10% and 15%, respectively. The credit is eliminated altogether for non‐conforming projects that begin in 2026 or later. Since meeting domestic content requirements adds 10% to the base PTC and ITC, direct pay implies a minimum 40% ITC. The Treasury Secretary can provide exemptions if these requirements increase the overall cost of construction by more than 25% or if the requisite quantity and quality of U.S. products are unavailable. As of early 2022, the IRS is expected to provide additional clarification and guidance on the domestic content requirement of the IRA and Congress has implied it will attempt to address issues that have been identified with implementation of this provision. 97 https://www.seia.org/initiatives/solar‐investment‐tax‐credit‐itc; https://www.mcguirewoods.com/client‐ resources/Alerts/2022/12/inflation‐reduction‐act‐creates‐new‐tax‐credit‐opportunities‐for‐energy‐storage‐projects 98 https://docs.google.com/spreadsheets/d/1X2PORZp5JzP2yWbdUSbXphElIGPEOlJNI‐T12gz7n1s/edit#gid=313301748
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Figure 45: Domestic
Content Requirements
% of the Total Cost of the Manufactured Products That Must Be Made in the U.S.
Construction Start Date Offshore Wind All Other Technologies Begin construction before 2025 20% 40%
Begin construction in 2025 27.5% 45%
Begin construction in 2026 35% 50%
Begin construction after 2026 45% 55%
Begin construction in 2027 45% 55%
Begin construction after 2027 55% 55%
11.2.6. Cost of New Resources: The General Market
Estimated resource costs available from public sources are different than actual PPA pricing and project costs. Individual projects have location and technology specific factors, and timelines that influence prices. There has also been exceptional market pressure on costs in the past few years.
Over the past three years, supply chain issues caused by the COVID‐19 pande mic have dramatically increased costs in the short term. Additionally, solar has been impacted by the Uyghur Forced Labor Prevention Act in the U.S., which requires verification that there is no forced labor in supply chains. Since most of the solar supply chain is in China, this regulation has reduced U.S. domestic supplies from China. According to a Utility Dive article, “Extreme market condi tions in 2021 and
the early months of 2022 may have added some 13‐15% in costs to solar prices beyond what long‐term trends would have predicted, according to NREL’s price analysis report for the first quarter of 2022, released Nov. 30.”99 LevelTen Energy, a firm that provides a central, standardized service for renewable developers to submit project cost data for buyers interested in projects and pricing, publishes a “PPA Index Report” every quarter. While the full report is available only with a paid subscription, the free version provides insights into solar and wind pricing trends.100 The 25th percentile of CAISO solar bids are in the mid‐$40/MWh range, an increase of between 10% and 15% from the previous quarter and an increase of approximately 50% from one year ago. These bids are for future delivery of solar, meaning that the commercial date of operations for the projects is in the 2024‐2027 range.
Supply issues caused by COVID‐19 and regulatory concerns have also been exace rbated by other market factors. Resources
across the grid are retiring. Additionally, non‐utilities, such as financial corporations, have entered the market, all contributing to the great demand for projects.
Furthermore, to conne ct additional renewable energy supply, the grid will require significant transmission upgrades. A study by Princeton University titled Net‐Zero America found that reaching net‐zero GHG emissions by 2050 will require a 99 https://www.utilitydive.com/news/nrel‐benchmark‐solar‐pricing‐cost‐report/637919/ 100 https://www.leveltenenergy.com/post/q1‐2023‐north‐america‐ppa‐price‐index
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60% expansion of the nation’s transmission system by 2030 and 200% by 2050.101 The costs for transmission additions would be paid by grid users.
11.2.7. Pasadena in the Market
PWP is an active market participant and evaluates new resource offers both independently and through its relationship with SCPPA. SCPPA is a Joint Powers Authority comprised of 11 municipalities and one irrigation district. SCPPA realizes operational efficiencies and cost savings through joint procurement and financing of projects and services. PWP recently executed agreements for addi
tional resources that showed price impacts of market forces such as supply chain constraints, IRA‐related tax credits, and other factors. The new agreements are for solar energy paired with storage and geothermal energy from the Geysers in northern California. PWP also evaluated a potential wind energy PPA. The price of these resources is shown in Fig
ure 466.
Figure 46: Reference Market Prices
Market Prices for New Resources
Type Year Online Price
Land‐based onshore wind 2025 $45.00/MWh – $70.00/MWh
Utility‐scale photovoltaic solar (EDF Sapphire) 2027 $28.00/MWh – $35.36/MWh 4‐hour utility‐scale lithium‐ion battery storage (EDF Sapphire)
2027 $7.00/kW‐Month – $11.70/kW‐
Month
Geothermal (Calpine Geysers) 2027 $70.00/MWh – $110.00/MWh Another resource cost reference available for use in the 2023 IRP comes from NREL, a national laboratory under the U.S.
DOE. Every year, NREL releases its ATB report, a public source for current and future costs according to technology types and locations. NREL provides cost estimates for generic projects.
PWP has observed that current market prices are higher than NREL’s near‐term esti mates. One reason is that NREL provides broad, bottom‐up pricing for the U.S. that is not equivalent to actionable project pricing for specific areas.
Different ways of quantifying pricing – for example, using the LCOE as a proxy for available prices – come with assumptions on financing, resource performanc
e, and more. Also, NREL has stated in multiple forums, publications, and webinars that its ATB report does not account for near‐term market changes. Furthermore, NREL explains, in the context of solar, the purpose of the ATB report and how it may vary from market prices as follows: 102 “It is important to understand what the NREL benchmarks are and are not, and for what purposes they should be used. The benchmarks are bottom‐up cost estimates of all major inputs to typical PV and energy storage system configurations and installation practices. Bottom‐up costs are based on national averages and do not necessarily represent typic
al costs in all local markets.
101 https://netzeroamerica.princeton.edu/?explorer=year&state=national&table=2020&limit=200 102 https://www.nrel.gov/news/program/2022/nrel‐tracks‐pv‐and‐energy‐storage‐prices‐in‐volatile‐market.html
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The primary purpose of the NREL benchmarks is to provide insight into the long‐term trajectories of PV and storage system costs, including which system components may be driving installed prices and where there are opportunities for price reductions. The benchmarks are also used to project future system prices, provide transparency, and facilitate engageme nt with industry stakeholders.
NREL’s benchmarks are often compared with other PV and storage system cost metrics, including reported prices and other modeled benchmarks. However, there is significant variation within and between these metrics because of the various methods and assumptions used to develop them, and different benchmarks are useful for different pur poses.”
Given this context, NREL’s estimates do not reliably reflect actual cost information in the near‐term. Adopting NREL’s estimates today may drastically understate the actual cost of procuring a resource such as solar in this market environment. Figure 477 and Figure 488 show a detailed example of solar pricing. The pric ing is provided in nominal dollars and in real 2023 dollars.
Figure 47: Utility‐Scale Solar Nominal Pricing
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Figure 48: Utility‐Scale Solar Pricing in Real 2023 $
Evaluating nominal versus real values can often lead to confusion. See Figure 499 for an example of how real versus nominal values – based on the same data – can appear. Nominal dollars reflect the present value of goods and services exchanged in the marketplace. However, using real dollars gives the true value of goods and services produced or sold because it strips out the effects of inflat
ion. Using nominal costs and discounting at the nominal discount rate is the equivalent of using real costs and discounting at the real discount rate. Using nominal costs and discounting at the nominal discount rate is standard industry practice for IRPs. Market pric es for natural gas and electricity are generally quoted in nominal terms. Using nominal dollars is not an artificial impact on costs, rather it shows the cost in a specific future year.
NREL provides additional information on real versus nominal dollars.103 This IRP usually presents the cost of new resources in nominal dollars using the nominal discount rate.
103 https://youtu.be/v‐objUKg3tA?t=1338; https://www.nrel.gov/docs/legosti/old/5173.pdf
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Figure 49: Real vs. Nominal Values
It is important to note that nominal values in real dollars are not equivalent to real values in real dollars. See Figure 50.
NREL calculates real values in real dollars. The IRP calculates nominal values in nominal dollars and translates them into real dollars.
PWP’s 2023 IRP uses the best available information to develop near‐term b enchmarks for long‐term projections for the cost of new technologies. How prices will change in the future is unknown. For example, there could be relaxed financial pressures induced by IRA incentives, or conversely, constraining pressures induced by transmission costs. Because of this uncertainty, once the resource mixes were i dentified, PWP re‐evaluated the costs of new resources using sensitivity tests to quantify potential cost variation.
Figure 50: Real vs. Nominal Levelized Cost of Energy
Real vs. Nominal LCOEs (2030)
Solar (Utility Scale, Single Axis Tracking) Real LCOE Nominal LCOE GDP Deflator for Nominal to Real 1.280
Inflation Rate 2.5% 2.5%
Tax Rate (Federal and State) 25.7% 25.7%
Present Value ‐ Depreciation (PV‐DEP) 0.875 0.875
Interest During Construction 4.5% 4.5%
WACC 2.44% 5.0%
Recovery Live (years) 30 30
Capital Recovery Factor (CRF) 4.7% 6.5%
ITC (Model Schedule) 30% 30%
Overnight Capital Cost ($/kW‐AC) $734.33 $940.01
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Solar PPA, Nominal $/MWh Solar, Real 2023 $/MWh
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Real vs. Nominal LCOEs (2030)
Solar (Utility Scale, Single Axis Tracking) Real LCOE Nominal LCOE Fixed O&M ($/kW‐year‐AC) $15.22 $19.48
Capacity Factor 32% 32%
Project Finance Factor (No ITC) 1.043 1.043
Project Finance Factor (with ITC) 0.685 0.685
Construction Finance Factor 1.022 1.017
LCOE Calculations
No ITC $18.67 $30.09
ITC (Model) $14.12 $22.14
No ITC (2020 Actual Amount) $23.51
ITC (2020 Actual Amount) $17.30
The IRP uses available
market cost data and initial project production date to reflect the best‐available information of current market conditions. These prices were then blended into NREL estimates over a period of several years. By 2032, these prices fully merge into the moderate cost estimates from NREL. NREL cost estimates have been updated to include the impa
cts of the IRA. Under the IRA, tax credits will expire when electricity‐sector related annual greenhouse gas emissions are less than or equal to 25% of 2022’s emissions, or in the year 2032, whichever occurs later. PWP’s IRP assumes that tax credits will substantially decrease in 2032 and fully expire by 2036.
PWP provided the Excel files with raw data, citations, and the blending methodology to the STAG in April 2023. The discussion of these costs, and how they were derived, extended over at least two STAG meetings. These meetings generated approximately 20 questions on this topic, and PWP provided the answers to all STAG members. New resources costs are in the Appendix – Cost of New Resources.
However, there remains a great deal of uncertainty on future pricing. In the EDF Sapphire Project (Sapphire), the project developer included a floor and a ceiling price for the solar and storage components. PWP provided details on this to the Pasadena City Council on November 14, 2022.104 The final contract price is still subject to change as the project advances toward completion. The IRP uses low and high cost curves by blending low and high market prices into NREL’s advanced and conservative scenarios. This allows the IRP to run sensitivity tests on portfolios to test how much specific resource mixes could cost if prices change.
11.2.8. Spotlight Technologies
The following subsections provide spotlight information on some technologies. 104 https://ww2.cityofpasadena.net/2022%20Agendas/Nov_14_22/Agenda.asp
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11.2.8.1. Spotlight on Fuel Cells
Like a cross between a natural gas turbine and a battery, a fuel cell consumes hydrogen as fuel and electrochemically transforms that hydrogen fuel into electricity, water, and heat. Fuel cells do not produce carbon emissions or air pollutants that cause smog.105 If the hydrogen is generated using renewable energy, then fuel cells count as renewable resources in California.106
According to the EIA, as of October 2021, there were 166 fuel cell plants with total capacity of 260 MW, the largest of which is 16 MW. All but six use natural gas for the hydrogen source. 107 Fuel cells are an earlier stage generation technology.
NREL does not report on fuel cell costs in the ATB. For PWP’s IRP, fuel cell data came from the EIA.108
11.2.8.2. Spotlight on Geothermal
Calpine’s Geysers project, a geothermal project that PWP contracted for, will begin delivery to PWP in 2027 and is located north of San Francisco. It is the single largest geothermal operation in the world and was the first commercial geothermal plant to operate in the Western hemisphere.109 According to Calpine, the plants extract hot steam to turn turbines that generate electricity.110 This appears to match the hydro‐flash geothermal technology described by NREL, so PWP’s IRP uses that benchmark for future projections.111
11.2.8.3. Spotlight on Offshore Wind
Offshore wind may be a key resource to assist with decarbonization. Approximately 80% of the U.S. population lives in coastal areas. Offshore wind also has a generation pattern that may complement that of solar.
Offshore wind is a nascent but growing global industry. According to the DOE, the global installed capacity of offshore wind was more than 50 GW in
2021.112 For comparison, the size of the entire U.S. grid is 1,144 GW.113 There are two operational offshore wind farms in the U.S.: the 30 MW Block Island Wind Farm and the 12 MW Coastal Virginia Offshore Wind pilot project.114 Offshore wind deployment in the U.S. has been spurred by state decarbonization policy. As of May 2022, the pipeline for offshore wind projects in the U.S. was more than 40 GW by 2040 and concentrated across eight 105 https://www.energy.gov/eere/fuelcells/fuel‐cells
106 https://www.energy.ca.gov/programs‐and‐topics/programs/renewables‐portfolio‐standard 107 https://www.eia.gov/energyexplained/hydrogen/use‐of‐hydrogen.php 108 https://www.eia.gov/outlooks/aeo/supplement/excel/suptab_55.xlsx; fixed O&M was assumed to be 2.5% of capital costs, which matches NREL’s O&M assumption for batteries.
109 https://www.calpine.com/operations/power‐operations/technologies/geothermal; https://geysers.com/ 110 https://player.vimeo.com/video/58388368
111 https://player.vimeo.com/video/58388368
112 https://www.energy.gov/eere/wind/articles/offshore‐wind‐market‐report‐2022‐edition 113 https://www.eia.gov/energyexplained/electricity/electricity‐in‐the‐us‐generation‐capacity‐and‐sales.php 114 https://www.energy.gov/eere/wind/articles/offshore‐wind‐market‐report‐2022‐edition
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states on the East Coast.115 This does not include California’s goal of 5 GW of offshore wind by 2030 and 25 GW by 2045.
The Biden Administration has set a 30 GW offshore wind goal by 2030.
When sea depths exceed 60 meters, offshore wind technology changes from fixed‐bottom to floating. The Atlantic Coast has shallower waters than the Pacific Coast , which allows for fixed‐bottom versus floating technology. As of 2021, more than 99% of the global operational offshore wind farms had fixed‐bottom foundations. Floating technologies are in earlier development stages. Globally, there is a total of 123.4 MW of installed floating offshore wind capacity.116 The West Coast must rely on floating technologies due to the depth of the Pacific Ocean in favorable wind resource areas.117 The Biden Administration is targeting an additional 15 GW of offshore wind in floating technology by 2035 and is looking to support innovation to reduce costs by more than 70% to reach a targeted cost of $45/MWh.118 For fixed‐bottom technologies online between 2020 and 2025 in the U.S., prices (in 2021 dollars) range from $149/MWh (Skipjack and U.S. Wind) to $75/MWh (Mayflower Wind). Costs could decrease to $60/MWh (in 2021 dollars) for fixed‐ bottom technologies by 2030.
Floating technologies costs are uncertain given their limited deployment. The DOE currently cites costs from around $200/MWh (in 2021) to between $58/M
Wh and $120/MWh (in 2021 dollars) by 2030.119 NREL produced cost projections specific to five offshore areas in California, and assuming PTC eligibility, costs in 2030 are expected to range from $79/MWh to $88/MWh (in 2021 dollars).120 In 2022, the U.S. Bureau of Ocean Energy Management (BOEM) held an auction for onshore leases for five areas – three in Morro Bay and two in Humboldt County.121 The CPUC’s 2021 Preferred System Plan included 1.7 GW of offshore wind by 2032.122 NREL had to make a series of assumptions regarding the price trajectory of offshore wind. For example, it was assumed that port and grid infrastructure is available; therefore, costs for land‐based substation or bulk transmission upgrades were not included in pricing. CAISO estimates between $5.8 and $8 billion in upgrade costs for 4 GW of offshore wind in the Humboldt area and $0.11 billion for 6 GW in the Diablo Canyon‐Morro Bay areas.123 California is also investing in the requisite supply chain and port infrastructure.124 NREL also assumes a 1 GW installation for its California cost estimates and that plants and turbines will get bigger over time, which will lead to cost reductions. Future decreases in costs are also 115 https://www.energy.gov/eere/wind/articles/offshore‐wind‐market‐report‐2022‐edition; https://cnee.colostate.edu/wp‐ content/uploads/2021/07/OffshoreWind‐July‐2021.pptx.pdf 116 https://www.energy.gov/eere/wind/articles/offshore‐wind‐market‐report‐2022‐edition 117 https://www.nrel.gov/wind/offshore‐resource.html
118 https://www.whitehouse.gov/briefing‐room/statements‐releases/2022/09/15/fact‐sheet‐biden‐harris‐administration‐ announces‐new‐actions‐to‐expand‐u‐s‐offshore‐wind‐energy/ 119 https://www.energy.gov/eere/wind/articles/offshore‐wind‐market‐report‐2022‐edition 120 https://www.nrel.gov/docs/fy21osti/77384.pdf
121 https://www.boem.gov/renewable‐energy/state‐activities/california 122 https://www.energy.ca.gov/news/2022‐08/cec‐adopts‐historic‐california‐offshore‐wind‐goals‐enough‐power‐upwards‐25 123 http://www.caiso.com/InitiativeDocuments/20‐YearTransmissionOutlook‐May2022.pdf 124 https://www.energy.ca.gov/news/2022‐03/state‐approves‐105‐million‐prepare‐port‐humboldt‐bay‐offshore‐wind
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dependent, in part, on lessons learned from fixed‐bottom installations on the Atlantic Coast and from other installations around the world. Overall, offshore wind costs are uncertain.
11.2.8.4. Spotlight on Hybrids
Different technology types can be located at the same site, and when they are designed to work together as a single installation, the result is often called a hybrid resource. Simply siting different technology types together (often called co‐ location) can reduce costs associated with site preparation, site acquisition, site permitting, interconnection upgrades, installation, and hardware, among other costs. Projects usually share an interconnection point and connect to each other.
However, there could be more value from siting resources apart rather than together. For example, storage may unlock more revenue closer to load, and solar in areas with higher irradiance.
Currently, the most common hybrid resources are storage sited wi th solar. Prior to the IRA, storage had to charge from a renewable resource to be eligible for the ITC, and solar proved to be the market’s dominant choice for this application.
In the 2022 NREL ATB, NREL notes that the dominant architecture for solar and storage pairings is still unkn own and could evolve over time based on grid composition, performance, and incentives. The PWP 2023 IRP assumes an AC‐coupled system when generation and storage form a hybrid installation. In an AC‐coupled system the grid has a separate interface with each component (generation and storage). The capital cost of a co‐located AC‐ coupled system is 7% lower than if PV and storage were sited separately, according to NREL. The IRP assumes this capital cost reduction, as well as a 2:1 renewable to storage ratio. PWP’s IRP includes both wind and solar paired with 4‐hour battery storage.
11.2.9. How Electricity Products Are Priced
Electricity is comprised of different components. Defining the different components, or attributes, ensures reliability and allows the components to be financially traded. See Figure 51 for examples on the different components of electricity (definitions in the table are simplified).
Figure 51: Different Components of Electricity
Part Simplified Definition Standard Units
Energy The flow of energy MWh
Resource Adequacy The ability to flow when needed kW‐Month Renewable Green REC
Clean Zero carbon MWh
Some technologies are better than others at providing certain attributes of electricity. See Figure 52 for examples.
Resources are typically priced in metrics that best reflect their strongest value streams. Wind and solar are common energy resources, so they are priced in terms of energy. Storage is a prevalent capacity resource, so it is priced in terms of capacity. Costs for
the 2023 IRP in Figure 53 and Figure 54 are priced at their industry‐standard units. Costs are presented in nominal dollars per unit of installed (non‐accredited) capacity.
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Figure 52: Different Components of Electricity by Resource Type The Flow Stability
Assistance
The Ability to Flow
When Needed Green Zero Carbon
Value Energy Ancillary
Services RA Renewable Clean
Wind
Geothermal
Solar
Batteries
Natural Gas
Figure 53: Cost of New Energy Res
ources
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Utility‐scale solar Commerical solar Residential solar
Land‐based wind Offshore wind Geothermal
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Figure 54: Cost of New Capacity Resources
11.2.10. Cost vs. Value
There is a difference between cost and value. Costs include factors such as capital expenditures, financing, permitting, transmission interconnections, operations, and maintenance. LCOE is a commonly cited industry metric that spreads all the costs for a resource over the lifetime of anticipated generation.
Value is what the resource earns in the energy, ancillary service, RA , renewable, and clean energy markets. Value depends on factors such as grid composition (e.g., percentage of renewable energy), grid location, and time of day. The IRP model optimizes between cost and value. The lowest‐cost resources do not always provide the greatest value. Evaluating both cost and value helps explain resource decisions.
11.2.11. Transmission Access Charge
The TAC is a rate charged by CAISO for transmission use. In the case of Pasadena, this is charged on any load brought into CAISO, or any contracted resources in CAISO. In other words, this applies to everything but resources internal to PWP, including Glenarm, storage located within PWP, or distributed resources. CAISO provides estimates of their TAC.125 Figure 55 has the TAC applied to external resources in the IRP model. 125 http://www.caiso.com/Pages/DocumentsByGroup.aspx?GroupID=7A2CFF1E‐E340‐4D46‐8F39‐33398E100AE7 $0
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Price ($ Nominal/kW‐Month)
Cost of New Resources: Lithium‐Ion Battery Storage
4‐hour 6‐hour 8‐hour 10‐hour 4‐hour commmerical 2.5‐hour residential
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Figure 55: Transmission Access Charge
11.2.12. Exclusions and Other Notes
PWP has excluded the following from consideration in its 2023 IRP:
New long‐term fossil‐fueled generation capacity
New long‐term fossil‐fueled generation capacity does not align with PWP’s environmental goals New nuclear capacity
Small modular reactors or new nuclear builds were excluded due to cost, timeline, and location limi tations Non‐lithium‐ion storage
Limited data is available for modeling alternative battery technologies at this time As projects are piloted or as costs mature in the markets, PWP will consider all zero‐carbon resource alternatives that will support reliability and reduce costs for consumers.
11.3. Diversified Procurement Portfolio
The 2018 CEC guidelines note that “The IRP Filing must address procurement for a diversified procurement portfolio consisting of both short‐term and long‐term electricity, electricity‐related, and demand response products.” As part of the IRP filing, POUs must submit four standardized tables covering capacity, energy, RPS, and GHG emissions.
These are filed separately.
PWP conside
red the following sources of diversity in its portfolio:
Resource types
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PWP is committed to supporting a portfolio that includes a variety of resource types. Figure 56 illustrates the different operational profiles of various resources. Resource diversity reduces risk by limiting reliance on the performance profile a particular resource.
Resource locations
Varying resource location is another form of risk reduction. For exam ple, weather events in one area may not affect resources in another area. Different resource locations can also help hedge transmission congestion costs.
Duration of contracts
Contract terms can vary from monthly to annual. Using varying contract terms provides flexibility, particularly in tight resource markets.
Figure 56: Diversity in Load Consumption and Resource Generation
12. Load Forecast
12.1. Requirements
The California Public Utilities Code Section 9621 specifies the process and content of IRPs to meet California regulatory requirements. It requires the development of a load forecast, which is a prediction of energy consumption (in MWh) and peak load demand (in MW). The load forecast is a necessary and critical IRP input because it is the starting point for determining total
energy, renewable energy, clean energy, and capacity requirements. The CEC requests that an IRP explain the method and assumptions used to create the load forecast, and that the utility submitting it include public sources in the IRP’s supporting material, as applicable.
In its 2017, 2018, and proposed 2022 re
gulations, the CEC recommends that POUs leverage the CED that is a part of the IERP process. The CED is an hourly forecast of electricity demand in the future. Following CEC recommendations, this IRP 0 20
40 60
80 100
120
140
160
180
200
Load or Generation (MW)
Diversity in Load Consumption and Resource Generation
Metered Load (2030) Light‐Evs (2030) Medium/Heavy‐Duty Evs (2030) 100 MW Solar 100 MW Wind
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derived its load forecast from the California Energy Demand Update, 2022‐2035 that is part of the 2022 Integrated Energy Policy Report Update.126
12.2. Integrated Energy Policy Report and California Energy Demand Forecast The CEC produces an IEPR every year, which investigates the state’s energy issues and proposes solutions.127 Under the IEPR process, the CEC must produce forecasts of energy products, including electricity forecasts.
The CEC created the California Energy Demand Forecast Update, 2022‐2035, as part of its 2022 Integrated Energy Policy Report Update.128 The 2022 CED updates economic, demographic, and rate data from 2021, and refreshes the IEPR’s methods for scenario design and for modeling the growth of transportation electrification.129 The CED has hourly forecasts of electricity demand for four entities: the three investor‐owned utilities (PG&E, SCE, and SDG&E) and CAISO. There are two different forecasts: a planning forecast used in RA and IRP planning, with moderate assumptions for most items, and a Local Reliability Scenario that includes higher electrification and lower energy efficiency assumptions used
for transmission planning.130
The CED forecasts contain hourly estimates of different components of electricity load for 2023 through 2035. These components are shown in Figure 57.
Figure 57: California Energy Demand Forecast Components CED Update, 2022 ‐ 2035 Description
Treatment in
PWP IRP
Modeling
Adds
to
Load?
Subtracts
from
Load?
Modified in
PWP’s 2023
IRP?
UNADJUSTED_CONSUMPTION System load without
pumping and with
distributed solar load
added back in
Native Load
PUMPING Native Load
CLIMATE_CHANGE Climate Change
LIGHT_EV CEC uses a demand side
model
Light‐Duty EVs
126 https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report/2022‐integrated‐energy‐policy‐report‐update‐ 2; https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report/2022‐integrated‐energy‐policy‐report‐update 127 https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report 128 https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report/2022‐integrated‐energy‐policy‐report‐update‐ 2 129 Bailey, Stephanie, Jane Berner, David Erne, Noemí Gallardo, Quentin Gee, Akruti Gupta, Heidi Javanbakht, Hilary Poore, John Reid, and Kristen Widdifield. 2022. Draft 2022 Integrated Energy Policy Report. California Energy Commission. Publication Number:
CEC‐100‐2022001‐CMD.
130 https://efiling.energy.ca.gov/GetDocument.aspx?tn=247951&DocumentContentId=82234
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CED Update, 2022 ‐ 2035 Description
Treatment in
PWP IRP
Modeling
Adds
to
Load?
Subtracts
from
Load?
Modified in
PWP’s 2023
IRP?
MEDIUM_HEAVY_EV CEC uses a demand side
model
Medium‐
/Heavy‐Duty
EVs
TOU_IMPACTS The effect of TOU rates TOU Rates
OTHER_ADJUSTMENTS Adds to zero over time Native Load
BTM_PV Photovoltaic Solar
generation located
behind the meter
Distributed
Solar
BTM_STORAGE_RES Energy storage located
behind the meter –
residential
Distributed
Storage
BTM_STORAGE_NONRES Energy storage located
behind the meter –
commercial and
Industrial
Distributed
Storage
AAEE AAEE AAEE
AAFS AAFS AAFS
AATE_LDV Additional Achievable
Transportation
Electrification
Includes supply‐side
drivers of adoption.131
Light‐Duty EVs
AATE_MDHD AATE Medium/Heavy‐
Duty EVs
MANAGED_NET_LOAD UNADJUSTED_CONSUMP
TION + PUMPING +
CLIMATE_CHANGE+LIGH
T_EV +
MEDIUM_HEAVY_EV +
TOU_IMPACTS +
OTHER_ADJUSTMENTS
+ BTM_PV +
BTM_STORAGE_RES +
Metered Load
131 https://www.energy.ca.gov/event/webinar/2022‐11/ca‐energy‐demand‐forecast‐aaee‐and‐aate‐results‐dawg‐meeting
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CED Update, 2022 ‐ 2035 Description
Treatment in
PWP IRP
Modeling
Adds
to
Load?
Subtracts
from
Load?
Modified in
PWP’s 2023
IRP?
BTM_STORAGE_NONRES
+ AAEE + AAFS
+AATE_LDV +AATE_MHD
12.3. Integrated Resource Plan Method
Following the CEC’s recommendation, this IRP is based on the CED and aims to leverage extensive work completed by California to quantify various drivers of electricity demand, including economic and demographic activity, energy efficiency and fuel substitution programs, historical electricity, and natural gas consumption, among other factors. The CEC’s website contains additional information on the CED.132
The CED does not include a specific forecast for PWP since it is smaller than the other entities explicitly modeled. Instead, PWP’s forecast is regarded as part of SCE’s.133 Since the CED’s planning forecast is used in other IRP proceedings, PWP’s 2023 IRP utilizes the planning scenario forecast for SCE as the reference for PWP’s load forecast.
In developing the 2023 IRP, PWP utilized the services of a subcontractor hired by ACES, an external vendor, to generate 2021 hourly load data for SCE and PWP.134 PWP’s load is calculated as a percentage of SCE’s 2021 load. As an initial forecast, the resulting hourly percentages were applied to the hourly CED forecast through 2035. Also, since the CED runs through 2035 only, the IRP forecast extrapolates these trends and applies them to the remainder of the forecast through 2050.
Because the CED differentiates the s
ubcategories that comprise the net electricity demand, this method of load forecasting produces estimates for energy efficiency, building electrification, fuel substitution, light‐duty EVs, heavy‐duty EVs, distributed solar, and distributed storage.
However, historical data and consideration of respective land use/availability shows that PWP’s service territory does not precisely mirror the load growth behavior of the larger SCE service territory. Therefore, when investigating the results of certain components, the IRP made modifications to the following:
AAEE
Distributed storage
Distributed solar
TOU rates
132 https://www.energy.ca.gov/data‐reports/reports/integrated‐energy‐policy‐report/2021‐integrated‐energy‐policy‐report/2021‐1 133 https://efiling.energy.ca.gov/GetDocument.aspx?tn=248366 134 https://www.yesenergy.com/
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Light‐duty EVs
Native (remaining) load
These changes were necessary to reflect PWP’s historical load experience and expectations for the future. Changes to these respective components and the associated impact on the overall load forecast, are detailed in the following subsections.
PWP’s annual peak and energy values are shown in Figure 58 and Figure 59. These values are metered at PWP’s interface with CAISO, so they incl
ude the impact of distribution system losses. PWP considers distribution losses at around 4%.
Figure 58: PWP Peak Demand
Year Peak (MW) Reserve Margin (%) Peak + Reserve Margin (MW) 2023 330.00 15.0% 379.50
2024 332.63 15.0% 382.52
2025 335.26 17.5% 393.93
2026 337.90 17.5% 397.03
2027 340.53 17.5% 400.12
2028 343.16 17.5% 403.21
2029 345.79 17.5% 406.30
2030 348.42 17.5% 409.39
2031 351.06 17.5% 412.50
2032 353.69 17.5% 415.59
2033 356.32 17.5% 418.68
2034 358.95 17.5% 421.77
2035 361.59 17.5% 424.87
2036 363.39 17.5% 426.98
2037 365.21 17.5% 429.12
2038 367.04 17.5% 431.27
2039 368.87 17.5% 433.42
2040 370.72 17.5% 435.60
2041 372.57 17.5% 437.77
2042 374.43 17.5% 439.96
2043 376.30 17.5% 442.15
2044 378.19 17.5% 444.37
2045 380.08 17.5% 446.59
2046 381.98 17.5% 448.83
2047 383.89 17.5% 451.07
2048 385.81 17.5% 453.33
2049 387.74 17.5% 455.59
2050 389.67 17.5% 457.86
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Figure 59: PWP Energy
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2023 1,156,320 84,240 1,047,923 1,029,197
2024 1,162,535 84,480 1,059,784 1,034,933
2025 1,173,224 240 1,156,277 1,126,064
2026 1,185,899 ‐ 1,173,515 1,138,463
2027 1,201,519 ‐ 1,192,802 1,153,458
2028 1,220,842 ‐ 1,215,253 1,172,009
2029 1,241,853 ‐ 1,239,018 1,192,179
2030 1,265,577 ‐ 1,265,082 1,214,954
2031 1,290,067 ‐ 1,291,633 1,238,464
2032 1,312,076 ‐ 1,315,006 1,259,593
2033 1,333,660 ‐ 1,338,073 1,280,313
2034 1,352,810 ‐ 1,358,607 1,298,697
2035 1,364,639 ‐ 1,371,814 1,310,054
2036 1,375,921 ‐ 1,384,239 1,320,884
2037 1,386,185 ‐ 1,395,351 1,330,738
2038 1,396,148 ‐ 1,405,369 1,340,302
2039 1,405,362 ‐ 1,414,512 1,349,147
2040 1,414,327 ‐ 1,422,988 1,357,754
2041 1,422,855 ‐ 1,430,986 1,365,941
2042 1,430,863 ‐ 1,438,674 1,373,629
2043 1,438,698 ‐ 1,446,195 1,381,150
2044 1,446,483 ‐ 1,453,669 1,388,624
2045 1,454,323 ‐ 1,461,195 1,396,150
2046 1,462,298 ‐ 1,468,851 1,403,806
2047 1,470,471 ‐ 1,476,698 1,411,652
2048 1,478,887 ‐ 1,484,777 1,419,732
2049 1,487,577 ‐ 1,493,119 1,428,074
2050 1,496,556 ‐ 1,501,739 1,436,694
Other loads will include
load from storage charging and will vary based on scenarios. Net energy for load will vary based on storage load and is included in filed charts.
12.3.1. Additional Achievable Energy Efficiency
State minimum requirements are set forth in Title 24 and contains specific regulations for energy efficiency and water conservation. As part of its commitment to environmental stewardship and innovation, PWP is dedicated to expanding its energy efficiency and demand reduction programs whenever new cost‐effective and achievable program elements are
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identified. Details of current PWP energy efficiency and demand response programs are included in Energy Efficiency of the IRP.
PUC Section 9621 requires IRPs for POUs to address the procurement of energy efficiency and demand response as dictated in Section 9651, which states “Each local publicly owned electric utility, in procuring energy to serve the load of its retail end‐use customers, shall
first acquire all available energy efficiency and demand reduction resources that are cost effective, reliable, and feasible.”135 In other words, energy efficiency is the resource of first choice.
In 2021, PWP, through its membership in CMUA, worked with GDS to identify the level of energy efficiency that PWP could cost‐effectively support in its territory.136 This study became the foundation for the energy efficiency goals that the Pasadena City Council adopted in May 2021. For Fiscal Years (FY) 2022 (which began on July 1, 2021) through FY2031 (which began on July 1, 2030), PWP’s energy efficiency goal is to achieve 11,720 MWh per year in savings and 1.8 MW per year in deman
d reduction. The annual energy efficiency and demand reduction goals were derived from the 10‐year average of the forecasted figures developed by GDS, in collaboration with PWP. These goals were adopted to represent the AAEE for the 2023 IRP.
The 2021 GDS energy efficiency study quanti fied the following three types of potential penetration of energy efficiency:
137
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nical (i.e., feasible): savings without regard to economic or other factors Economic (i.e., cost‐effective): savings when benefit is greater than cost Market (both feasible and cost‐effective): savings that consider other utility‐specific factors, such as existing penetration, past customer behavior, economic conditions, etc.
PWP adopted its goals based on market potential. Figu re 60 shows a comparison of the three potential efficiencies. 135 https://law.justia.com/codes/california/2021/code‐puc/division‐4‐9/section‐9615/ 136 https://www.cmua.org/files/CMUA%202020%20EE%20Potential%20Forecast.pdf 137 https://www.cmua.org/sb1037‐reports
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Figure 60: Technical, Economic, and Market Potential for Energy Efficiency Energy effi
ciency savings are expressed as either gross (total impact) or net (total impact minus the impact of customers who would have pursued the programs anyway). Programs are also quantified by incremental savings (annual values) or cumulative savings (total savings summed over time). PWP’s goal is based on incremental net savings, which are approximately 96% of gross market potential savings.
The 2023 IRP uses PWP’s en
ergy efficiency goal for its estimate of AAEE through 2031, then 96% of gross market potential for 2032 through 2041 when the goal expires. Since trends are leveling out, suggesting saturation of potential efficiency opportunities, AAEE remains flat from 2042 through the end of the IRP study period in 2050. Figure 61 shows the IRP forecast of AAEE. The negative values on the Y axis indicate energy saved. (600)
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Figure 61: Additional Achievable Energy Efficiency in PWP’s 2023 Integrated Resource Plan The perce
nt reduction in load is shown in in Figure 62.
Figure 62: Additional Achievable Energy Efficiency Percent Reduction in Load
12.3.2. Additional Achievable Fuel Substitution
AAFS estimates the impacts of building electrification and fuel substitution on electricity demand and energy consumption and is included in the load forecast. Fuel substitution occurs when a device or system using a regulated fuel (fossil fuel or renewable gas) is replaced with a system using electricity. Replacements under these programs are not yet committed, but likely to occur in the future due to economics or regulation. Th e 2023 IRP assumes the allocation of AAFS from the
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CED based on the forecasting methodology outlined in this IRP. AAFS is 2% of CAISO’s metered load by the end of the study period. Figure 63 shows an AAFS projection for PWP.
Figure 63: AAFS in PWP’s 2023 IRP
12.3.3. Distributed Solar
PWP had 23 MW of distributed solar in 2022. Assuming an average installation size of 7 kW per residential rooftop and 58,291 residential customers, approximately 6% of PWP’s households had solar.138 However, the CED method attributed 52 MW of solar to PWP in 2023. PWP, as a dense urban area, is likely more space‐constrained than SCE on average, resulting in actual installations to be less than the CED estimates. PWP’s IRP calculated the annual rate of change in the CED and applied it to PWP’s 2022 starting poin t. Extrapolating forward, approximately 12% of households would have solar in 2030 and 23% would have solar in 2045. This is within the range identified for LADWP in 2045 in NREL’s LA100 study, and, given uncertainties regarding rooftop solar potential, future rate incentives, and other factors, PWP found these values reasonable for the 2023 IRP.139 Figure 64 shows the estimated solar capacity included in the IRP load forecast. 138 https://emp.lbl.gov/tracking‐the‐sun
139 https://www.nrel.gov/docs/fy21osti/79444‐4.pdf
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Figure 64: Distributed Solar in PWP’s 2023 IRP
12.3.4. Distributed Storage
PWP had 1.4 MW of distributed storage in 2022. The CED suggested 0.5 MW across PWP’s residential and non‐residential sectors in 2023. To calibrate the starting point, PWP’s existing penetration was added to the CED forecast resulting in a starting capacity of 1.9 MW of distributed storage.
It is likely that distributed storage will be paired with distributed solar in the future. In the LA100 study, NREL noted that, in 2019, 9.6% of residential PV adopters also installed storage at a storage‐to‐PV capacity ratio of 0.92.140 NREL projected that 91% of residential solar adopters would also install storage by 2045. PWP estimated total storage adoption given its anticipated solar penetration using this heuristic and applied the rate of change embedded in that resulting penetration to its starting point. Overall, this method generated a larger distributed storage capacity than the CED method estimate d, and it produced an estimate more in line with expectations. See Figure 65. 140 https://www.nrel.gov/docs/fy21osti/79444‐4.pdf
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Figure 65: Distributed Storage in 2023 IRP
As a reminder,
the method used in PWP’s IRP to leverage the CED helps align its load forecast to the CEC’s expectations.
However, this method is just that – a method. Modifications such as those made for solar and storage adjust the forecast to actual conditions, experience, and expectations specific to PWP.
12.3.5. Time‐of‐Use Rates
The CED method used in the IRP produced a forecast for the impact of TOU rates. As of 2023, PWP does not have the Advanced Metering Infrastructure (AMI) needed to fully benefit from the implementation of TOU rates. PWP may need to develop some form of TOU rate to facilitate a significant expansion of distributed solar and storage resources and address the resource cost impacts that will occur. PWP currently estimates that AMI will come online in its full capacity around 2030. Therefore, TOU impacts for PWP’s forecast are only included in 2030 and beyond. Energy and peak impacts are shown in Figure 66 and Figure 67.
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Figure 66: Time‐of‐Use Rates in PWP’s 2023 Integrated Resource Plan Figure 67: Avera ge Hourly Impact of Time‐of‐Use Rates in PWP’s 2023 Integrated Resource Plan In
addition to the impact of TOU rates, AMI could also help enable additional demand response. AMI would potentially allow PWP the ability to aggregate and control the consumption profile of various consumer devices to support savings for all PWP customers.
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12.3.6. Vehicle Electrification
Emissions from transportation constitute the largest source of GHGs in California and represent more than double the GHGs associated with the electricity sector. 141 Electrifying transportation can help reduce emissions. California has aggressive transportation electrification goals. Executive Order B‐48‐18 signed by Governor Brown in 2018 set a target for 5 million zero‐emission vehicles and 250,000 public EV charging stations by 2030.142 In 2020, Governor Newsom set a goal under Executive Order N‐79‐20 for all in‐state sales of new passenger and new medium/heavy‐duty vehicles to be zero‐ emission by 2035 and 2045, respectively. PWP is committed to supporting the transportation electrification goals set by California and align with the GHG emissions reduction targets outlined in th e City’s CAP.
As of 2022, PWP had 9,254 electric‐based (battery EVs, PHEV, and fuel cell EVs) vehicles registered across the eight zip codes in its service territory, which is approximately 7% of all vehicles in PWP’s service territory. 143 Assuming around 3 MWh per vehicle, per year (based on assumptions developed in PWP’s 2021 IRP Update), PWP’s EV load is higher than what the CED would indicate. The IRP load forecast was adjusted to account for the higher initial load in 2023. The 2027 CED forecast was adopted in 2023 and the forecast moved up accordingly. Ap proximately 36% of light‐duty vehicles in PWP’s territory are expected to be electric in 2030, and 65% are expected to be electric by 2045. No adjustments were made to the CED’s medium/heavy‐duty EV forecast. Overall, EV charging is 14% of PWP’s CAISO metered ener gy in 2030 and 28% in 2045, as shown in Figure 68 and Figure 69.
141 https://ww2.arb.ca.gov/ghg‐inventory‐data
142 https://www.cpuc.ca.gov/industries‐and‐topics/electrical‐energy/infrastructure/transportation‐electrification 143 https://www.energy.ca.gov/data‐reports/energy‐almanac/zero‐emission‐vehicle‐and‐infrastructure‐statistics/light‐duty‐vehicle; Used the following zip codes: 91001,91101,91103, 91104, 91105, 91106, 91107, 91123
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Figure 68: Transportation Electrification in PWP’s 2023 Integrated Resource Plan Figure 69: Light‐Duty Electric Vehicle Penetration in PWP’s 2023 Integrated Resource Plan Hourly load shapes for
the light‐ and medium/heavy‐duty sectors are shown in Figure 70 and Figure 71. These hourly load shapes come from the CED. EV charging load peaks in hour ending (HE) 24, on average each year. The charging shapes indicate that EVs are charging mid‐day and overnight. This could imply, or inform, some form of TOU rate. If EVs were charged during PWP’s peak hour, PWP’s peak could be 8% higher in 2030 than indicated and 13% higher by 2045. The 2023 IRP assumes that education and voluntary behavior will mitigate the potential impacts of EV charging. However, PWP 0%
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will keep in mind the potential impacts of EV charging and may further investigate the potential to treat EV charging behavior as a tool to reduce overall portfolio costs.
Figure 70: Average Hourly Shape for Light‐Duty Electric Vehicles Figure 71: Average Hourly Shape for Medium/Heavy‐Duty Electric Vehicles 0 10
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The average contribution of EV charging to average hourly load in 2030 is shown in Figure 72. EV charging seeks to take advantage of midday opportunities, likely when solar generation is at its highest and market prices are lower. TOU rates can be used to incentivize charging when solar generation is abundant and disincentive it whe n market prices are high.
Figure 72: Average Hourly Load Profile
PUC Section 9621 requires IRPs to discuss rate design, incentives, education, and outreach to achieve the statewide carbon neutrality goal by at least 2045, as set by the 2018 Executive Order B‐55‐18. 144 PWP does not currently have transportation‐specific rates for electric vehicles. As further detailed in Electric Vehicles, PWP offers rebates to residential customers for both EVs and EV chargers. PWP also offers rebates on EV chargers for commercial customers. PWP’s website has additional details on these incentives.145 However, given planned AMI deployment, PWP could consider implementing rates for the transportation sector. For example, PWP could consider redesigning demand charges, creating EV‐specific TOU rates, or developing targeted EV tariffs.
PWP will likely consider rates, incentives, customer education, and customer outreach to support transportation electrification. Electrifying transportation can help achieve California’s carbon reduction goals while also al igning with the City’s CAP. PWP will aim to design programs that decrease costs for EV customers and the overall grid. PWP is committed 144 https://codes.findlaw.com/ca/public‐utilities‐code/puc‐sect‐9621/; https://www.ca.gov/archive/gov39/wp‐ content/uploads/2018/09/9.10.18‐Executive‐Order.pdf
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to ensuring that potential impacts on low‐income customers and disadvantaged communities are a primary consideration when designing such programs.
PWP is also committed to considering the emission reduction opportunities associated with transportation electrification.
PWP estimates that by 2030, more than 33% of its light‐duty fleet in Pasadena could be electric and approximately 65% could be electric by 2045. If the fossil
‐fuel vehicles were to remain on the road, the fleet would emit around 0.75 million metric tons of carbon in 2030 and 4.2 million metric tons in 2045.
12.3.7. Climate Change
The CED forecast includes the potential load impacts associated with climate change. Overall, the CED looks at 30 years of history, with recent years selected more often. Per the CED documentation, baseline peak and energy forecasts were weather‐normalized, and future years were adjusted for anticipated modifications for climate change. Climate change increases overall load expectations. From 2023 through 2050, the effect of clim ate change is about 0.3% of annual metered
energy.
12.3.8. Native Load
Native load is effectively all load that is not represented in Section 12.3. Figure 73 shows how PWP’s native load has decreased over time. The CED generally anticipates increases in energy consumption in the future. Pasadena is relatively fully built and, consequently, expects little load growth from expansion. In the 2023 IRP load forecast, native load is adjusted to match PWP's historical
and peak load data, as well as future expectations for its more densely developed system. PWP has a 10 MW distributed generator (a customer‐owned distributed energy resource) that has reduced its historical peak load. This facility is anticipated to retire in 2025, so the load forecast was incr eased by 10 MW in this IRP to reflect the facility’s retirement (the facility is modeled as a distributed resource prior to its retirement).
Figure 73: PWP’s Historical Load
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12.3.9. CAISO Metered Load
Metered load is the load as metered at the transmission interconnection and is the load brought into the CAISO markets.146 Metered load is higher than retail sales because it includes the impact of losses.
Metered load is calculated according to the following equation:
𝑀𝑒𝑡𝑒𝑟𝑒𝑑 𝐿𝑜𝑎𝑑 ൌ ሺ𝑁𝑎𝑡𝑖𝑣𝑒 𝐿𝑜𝑎𝑑 𝐿𝑖𝑔ℎ𝑡 𝐷𝑢𝑡𝑦 𝐸𝑉𝑠 𝑀𝑒𝑑𝑖𝑢𝑚 𝑎𝑛𝑑 𝐻𝑒𝑎𝑣𝑦 𝐷𝑢𝑡𝑦 𝐸𝑉𝑠 𝐴𝐴𝐹𝑆 𝐷𝑖𝑠𝑡𝑟𝑖𝑏𝑢𝑡𝑒𝑑 𝑆𝑡𝑜𝑟𝑎𝑔𝑒 ሻ ሺ 𝑇 𝑂 𝑈 𝑅𝑎𝑡𝑒𝑠 𝐴𝐴𝐸𝐸 𝐷𝑖𝑠𝑡𝑟𝑖𝑏𝑢𝑡𝑒𝑑 𝑆𝑜𝑙𝑎𝑟ሻ Figure 74 shows a comparison between PWP’s forecast and SCE’s forecast from the CED.
Figure 74: Percent of PWP Peak During Southern California Edison’s Peak Percent of PWP Peak During SCE's Peak
Mo
nth 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 1 99% 98% 91% 90% 93% 92% 95% 91% 90% 89% 86% 90% 87% 2 99% 100% 98% 97% 96% 97% 86% 87% 99% 99% 88% 83% 77% 3 88% 79% 81% 84% 86% 79% 80% 76% 77% 80% 91% 85% 80% 4 89% 80% 75% 68% 81% 77% 75% 75% 72% 76% 80% 78% 72% 5 89% 62% 62% 59% 76% 74% 56% 63% 68% 64% 67% 70% 73% 6 100% 85% 84% 78% 79% 61% 65% 68% 73% 74% 70% 67% 63% 7 100% 82% 89% 85% 100% 72% 73% 73% 62% 68% 65% 66% 62% 8 100% 81% 81% 98% 97% 68% 62% 53% 62% 64% 68% 64% 54% 9 100% 88% 89% 87% 69% 78% 77% 74% 71% 86% 88% 81% 79% 10 100% 77% 86% 79% 78% 73% 79% 73% 76% 64% 72% 80% 81% 11 100% 94% 96% 91% 87% 90% 81% 90% 91% 82% 83% 81% 68% 12 100% 95% 96% 98% 96% 97% 97% 92% 93% 95% 94% 92% 94% Figure 75
shows PWP’s annual energy and peak forecast. Positive values for energy refer to consumption and negative values refer to avoided energy consumption. Figure 76 provides a graphical representation of CAISO’s energy use. PWP has a load factor of approximately 43%, on average, across the study period. Load factor measures actual energy as a fraction of wh
at could occur if PWP experiences peak energy usage every hour. 146 This is what the CED refers to as managed net load.
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Figure 75: Load Forecast
Year Metered Peak
(MW)
Peak
Hour
(HE)
Metered Load
(MWh)
Native Load
(MWh) AAEE (MWh) AAFS
(MWh)
Distributed
Storage
(MWh)
Distributed PV
(MWh)
TOU
Rates
(MWh)
Climate
Change
(MWh)
Light‐Duty
EVs (MWh)
Medium/
Heavy‐Duty
EVs (MWh)
2023 330.00 15 1,156,320.00 1,190,015.58 (19,506.21) 2,914.28 406.89 (57,838.32) ‐ 657.59 39,427.81 242.38 2024 332.63 17 1,162,534.86 1,193,110.93 (25,886.41) 4,798.36 500.72 (62,350.33) ‐ 993.75 50,945.23 422.60 2025 335.26 16 1,173,223.68 1,195,460.70 (31,471.95) 6,832.52 590.76 (66,608.08) ‐ 1,332.50 64,260.02 2,827.21 2026 337.90 17 1,185,898.62 1,198,668.53 (36,512.71) 8,429.86 694.40 (71,103.10) ‐ 1,676.94 79,439.30 4,605.41 2027 340.53 17 1,201,518.83 1,201,422.94 (40,983.11) 10,124.06 799.01 (75,793.42) ‐ 2,027.71 96,969.56 6,952.10 2028 343.16 15 1,220,842.31 1,206,299.11 (45,045.88) 11,932.07 914.05 (80,664.81) ‐ 2,379.37 115,251.26 9,777.13 2029 345.79 18 1,241,853.21 1,210,557.08 (48,790.91) 13,819.78 1,032.05 (85,713.68) ‐ 2,735.97 135,436.09 12,776.82 2030 348.42 17 1,265,577.17 1,215,678.99 (52,216.66) 15,789.63 1,165.85 (90,950.17) (11.60) 3,095.60 157,144.46 15,881.07 2031 351.06 17 1,290,066.51 1,219,706.54 (55,384.83) 17,831.60 1,318.96 (96,365.78) (12.40) 3,457.98 179,725.54 19,788.91 2032 353.69 17 1,312,076.32 1,226,367.29 (57,721.15) 19,923.91 1,472.71 (101,934.12) (12.56) 3,821.76 196,481.33 23,677.15 2033 356.32 15 1,333,659.83 1,232,249.48 (60,166.46) 21,927.21 1,642.50 (107,616.56) (11.98) 4,189.34 211,388.76 30,057.54 2034 358.95 15 1,352,809.51 1,238,103.03 (62,405.96) 23,779.00 1,811.55 (113,373.76) (11.84) 4,559.49 224,442.33 35,905.66 2035 361.59 15 1,364,639.33 1,238,103.03 (64,333.16) 25,448.24 1,997.00 (119,170.35) (12.35) 4,931.19 235,736.88 41,938.85 2036 363.39 15 1,375,921.35 1,239,341.14 (65,994.23) 26,855.70 2,184.36 (125,152.00) (12.67) 5,220.75 245,423.99 48,054.33 2037 365.21 15 1,386,185.48 1,240,580.48 (67,305.27) 28,108.82 2,377.28 (131,237.21) (12.97) 5,483.60 253,680.04 54,510.72 2038 367.04 15 1,396,148.14 1,241,821.06 (67,777.88) 29,215.40 2,575.85 (137,418.52) (13.25) 5,720.29 260,685.24 61,339.94 2039 368.87 15 1,405,361.54 1,243,062.88 (68,088.44) 30,185.76 2,780.19 (143,688.31) (13.50) 5,931.99 266,611.15 68,579.82 2040 370.72 15 1,414,326.69 1,244,305.94 (67,952.51) 31,031.63 2,990.49 (150,038.91) (13.73) 6,120.21 271,614.17 76,269.39 2041 372.57 15 1,422,855.36 1,245,550.25 (67,755.48) 31,765.27 3,206.93 (156,462.57) (13.93) 6,286.70 275,833.01 84,445.17 2042 374.43 15 1,430,863.42 1,246,795.80 (67,755.48) 32,398.87 3,429.72 (162,951.52) (14.12) 6,433.32 279,388.36 93,138.46 2043 376.30 15 1,438,697.53 1,248,042.59 (67,755.48) 32,944.10 3,659.06 (169,497.99) (14.29) 6,561.97 282,383.89 102,373.67 2044 378.19 15 1,446,483.15 1,249,290.64 (67,755.48) 33,411.83 3,895.15 (176,094.26) (14.44) 6,674.47 284,907.96 112,167.28 2045 380.08 15 1,454,322.83 1,250,539.93 (67,755.48) 33,812.06 4,138.16 (182,732.67) (14.58) 6,772.57 287,035.34 122,527.49 2046 381.98 15 1,462,298.13 1,251,790.47 (67,755.48) 34,153.77 4,388.48 (189,405.66) (14.71) 6,857.92 288,829.13 133,454.20 2047 383.89 18 1,470,471.26 1,253,042.26 (67,755.48) 34,444.98 4,646.28 (196,105.77) (14.82) 6,932.02 290,342.41 144,939.39 2048 385.81 18 1,478,887.37 1,254,295.30 (67,755.48) 34,692.76 4,911.79 (202,825.71) (14.92) 6,996.24 291,619.76 156,967.63 2049 387.74 20 1,487,576.57 1,255,549.59 (67,755.48) 34,903.32 5,185.25 (209,558.30) (15.01) 7,051.80 292,698.60 169,516.80 2050 389.67 20 1,496,555.89 1,256,805.14 (67,755.48) 35,082.04 5,466.86 (216,296.59) (15.09) 7,099.82 293,610.35 182,558.85
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Figure 76: CAISO Metered Load by Component
CAISO’s me
tered peak load occurs on the dates and hours shown in Figure 77.
Figure 77: Hour of CAISO Peak Metered Load
Hour of CAISO Peak Metered Load
Year Month Day Hour
2023 9 5 15
2024 9 13 17
2025 8 28 16
2026 8 27 17
2027 9 7 17
2028 9 5 15
2029 8 30 18
2030 9 13 17
2031 8 28 17
2032 9 7 17
2033 9 6 15
(500)
0 500
1,000
1,500
2,000
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
Energy (GWh)
CAISO Metered Load
Native Load AAEE AAFS
Distributed Storage Distributed PV TOU Rates
Climate Change Light‐Duty EVs Medium/Heavy‐Duty EVs
Metered Load
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Hour of CAISO Peak Metered Load
Year Month Day Hour
2034 9 5 15
2035 9 4 15
2036 9 4 15
2037 9 4 15
2038 9 4 15
2039 9 4 15
2040 9 4 15
2041 9 4 15
2042 9 4 15
2043 9 4 15
2044 9 4 15
2045 9 4 15
2046 9 4 15
2047 8 30 18
2048 8 30 18
2049 9 4 20
2050 9 4 20
PWP’s energy forecast is compared to previous forecasts in Figure 78. By 2030, the energy forecast in the 2023 IRP is 9% higher than predicted in the 2018 IRP forecast due to increased electrification.
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Figure 78: PWP Load Comparison
PWP’s averag
e hourly load shape for 2023 through 2050 is shown in Figure 79. Load increases in the morning and ramps in the evening. When evaluating future resource potential, PWP will consider its load profile and what resources can help meet load cost effectively.
Figure 79: Average Hourly Load
0 200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
Energy (GWh)
CAISO Metered Load
2023 IRP 2019 IRP 2021 IRP Update Historic
0 50
100
150
200
250Average Load (MW)
Average Hourly Load
2023 2025 2030 2035 2040 2045 2050
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In addition to average shape, PWP is mindful of the breakdown of its distribution of load, which is shown in Figure 80 and Figure 81.
Figure 80: Load Duration Curve
Figure 81: Load Duration Curve Inflection Poi nts
Number of Hours by Year
Load Equal or Greater Than 2023 2025 2030 2035 2040 2045 2050 185 MW 745 761 954 1,318 1,609 1,988 2,418
280 MW 22 44 73 140 164 204 250
330 MW 1 2 5 25 37 46 55
Percent of Hours by Year
Load Equal or Greater Than 2023 2025 2030 2035 2040 2045 2050 185 MW 9% 9% 11% 15% 18% 23% 28%
280 MW 0% 1% 1% 2% 2% 2% 3%
330 MW 0% 0% 0% 0% 0% 1% 1%
PWP’s system needs to be designed to meet load in all hours. Certain hours of the year can drive resource planning needs. ‐
50 100
150
200
250
300
350
400
450
1 238
475
712
949
1186
1423
1660
1897
2134
2371
2608
2845
3082
3319
3556
3793
4030
4267
4504
4741
4978
5215
5452
5689
5926
6163
6400
6637
6874
7111
7348
7585
7822
8059
8296
8533
Metered Load (MW)
Hour
Load Duration Curve
2023 2025 2030 2034 2040 2045 2050
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13. Transmission and Distribution
13.1. Bulk Transmission System
CAISO was created in 1998 to manage the portions of the regional transmission grid owned and operated by the IOUs specifically, PG&E, SDG&E, and SCE. As a CAISO‐certified Scheduling Coordinator and PTO, PWP’s owned and contracted transmission rights have been delegated to CAISO for operation and planning.
The PWP system interconnects to the CAIS O power grid at the T.M. Goodrich substation (Goodrich). Power is received via two 220kV transmission lines from SCE’s Mesa and Gould substations, which are located southeast and north of Pasadena, respectively. The 220kV equipment at Goodrich is owned by PWP but maintained and operated by SCE under CAISO’s direction. Contractually, the Goodrich interconnecti on may import up to 336 MW. However, the import capacity is currently limited to 280 MW so that PWP can address N‐1 contingency operations under its distribution system limitations.
N‐1 is an industry planning standard that ensures continued operation in the event a system’s single largest element fails.
13.2. Bulk Transmission Planning
CAISO’s annual transmission plan is an evaluation of grid reliability requirements, upgrades required to achieve State policy goals, and potential projects that could bring economic benefits to consumers. The system reliability assessment included in the 2022‐2023 plan raises no concerns that would require any new corrective action plans to meet NERC requirements. Since
PWP does not operate any part of the bulk transmission system, there are no identified transmission concerns that need to be addressed in the 2023 IRP.
13.3. Distribution System Planning
PWP’s electric distribution system consists of three receiving stations (Goodrich, Glenarm, and Santa Anita) and nine distribution substations. Imported power from CAISO is delivered into the PWP system at Goodrich through three 112 MVA power transformers that step the voltage down from 220kV to 34.5kV. PWP also has a 40 MW, 34.5kV interconnection betw
een Glenarm Receiving Station and LADWP’s St. John Receiving Station, which is located west of Pasadena. PWP’s Glenarm Power Plant (Glenarm) includes five generating units that connect to Glenarm Receiving Station. The St. John interconnection is currently not synchronized with the PWP distribution system and, therefore, cannot be operated in parallel to PWP’s con nection to the CAISO grid. Its use is limited to emergencies or CAISO‐mandated load curtailment requirements. See Figure 82.
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Figure 82. Simplified Diagram of PWP's Sub‐Transmission System PWP
utilizes an underground 34.5kV sub‐transmission system, and a combination of overhead and underground 4kV and 17kV systems, to deliver electricity to customers through the distribution substations.
The 73‐circuit‐mile underground sub‐transmission network is comprised of 285 miles of 34.5kV cable. The network includes eight 34.5kV circuits that form the cross‐town backbone of the sub‐transmission system and connect directly from Goodrich throug
h the Santa Anita Substation to Glenarm Substation. The design of the 34.5kV substations are double bus/double breaker, which provides operating flexibility and a high level of reliability.
In coordination with the 2018 IRP, PWP developed a Power Delivery Master Plan (PDMP), which was approved by the Pasadena City Council in June 2022. The PDMP provides a high‐level guide for planning, operating, and maintaining PWP’s electric distribution system over the next 20 years. It describes the utility’s infrastructure, assesses its current condition, and provides an ambitious long‐term capital improvement plan of projects designed to en hance reliability, safety, and cost effectiveness. The PDMP describes PWP’s electric distribution system as reliable, despite aging infrastructure, and identifies a few crucial areas that need to be addressed systematically.
The PDMP specifically identifies several improvements directly related to the 2023 IRP. As previously stated, PWP has a contractual
ability to import up to 336 MW, but it is limited to 280 MW due to distribution system limitations. The primary limitations are Goodrich transformer capacities, 34.5kV sub‐transmission system power flow constraints, and high short circuit duty (~40 kA). The PDMP outlines the following initiatives for implementation on PWP’s sub‐transmission system to address these issues:
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Within five years, upgrade the capacity and protection of the 34.5kV mini‐cross‐town sub‐transmission lines that connect Glenarm and Santa Anita Receiving Stations through the distribution substations to increase overall system power flow capability. Once the lines are upgraded, they would be reconfigured to create a second cross‐ town connection for redundancy and im
proved capacity. This upgrade is necessary before PWP can perform the sub‐transmission line replacement work between Glenarm and Santa Anita Receiving Station described in the following bullet.
Replace/upgrade the four aging 34.5kV cross‐town sub‐transmission lines between Glenarm and Santa Anita Receiving Stations.
Upgrade the 220kV/34.5kV Goodrich tr
ansformers at the interconnection with CAISO to increase PWP’s power import capacity from 280 MW to the contractual 336 MW import limit. Reduce the short circuit duty in the 34.5kV sub‐transmission system to ~25 kA. To accomplish this, PWP plans to split the 34.5kV sub‐transmission system el ectrically in coordination with the Goodrich transformer upgrades. This would significantly reduce potential damage to PWP’s sub‐transmission and distribution assets should faults (short circuits) occur.
These projects would not be completed simultaneously, rather they would be completed in operational order and/or in a manner that best minimizes community impacts. The collective scope is expected to be completed within 10 years.
The upgrades would not only improve system reliability and longevity, but also facilitate the growth of DER utility‐scale energy storage and utility‐side renewable energy projects, such as community solar, within the PWP system. Precise locations, types, sizes and installation dates of new generation and storage projects con nected to PWP’s distribution
system have yet to be determined and will require the PDMP be revised to address distribution system impacts based upon incremental engineering evaluations.
14. Localized Pollutants and Disadvantaged Communities
PWP recognizes that air pollution represents only one of the possible community impacts of supplying electric service to its customers. While the remainder of this section focuses on air quality, PWP remains committed to holistic mindfulness of the communities it serves, including noise and traffic ramifications of its utility operations. In so doing, PWP continually strives to perform as a good nei
ghbor – not only in the present but also in charting and realizing Pasadena’s energy future.
As directed by SB 535, the CalEPA defines and designates Disadvantaged Area Communities (DACs) based on geographic, socioeconomic, public health, and environmental hazard criteria. CalEPA’s CalEnvironScreen uses U.S. Census data and 21 indicators to identify com
munities most affected by various sources of pollution. DACs are considered California’s most environmentally burdened areas, so CARB’s GHG programs such as Cap‐and‐Trade and the Low Carbon Fuel Standard (LCFS) tend to concentrate their investments in these communities to improve public health , quality of life, and economic opportunities in underserved areas. According to CalEnvironScreen, PWP’s service territory includes one DAC. This location, shown Figure 83, encompasses 0.6 square miles in northwest Pasadena and includes a population of more than 6,000 people.
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Figure 83: PWP’s CalEnvironScreen 4.0 Identified Disadvantaged Area Communities Source: CalEnvironScreen 4.0
14.1. Emissions Reduction
Glenarm, the only utility‐scale generating station in Pasadena for PWP, is located outside this DAC. Nonetheless, PWP has been aggressively reducing its emissions footprint and cutting emissions below the limits set by SB 32 and AB 1279 to benefit all area communities. PWP had reduced emissions from its power supply portfolio by 50% compared to 1990 levels by the end of 2021. In January
2023, the Pasadena City Council adopted Resolution 9977, which sets a more ambitious goal of 100% zero‐carbon energy resources by 2030, thereby accelerating the 2045 state target by 15 years. Resolution 9977 directs PWP to use the 2023 IRP process to defi ne multiple paths to this goal in a way that optimizes stability, service reliability, affordability, and rate equity.
Following its core mission, PWP constructs, operates, and maintains its power system facilities to provide stable and reliable electric service to all its customers, regardless of their respective locations. By also actively promoting rate e quity,
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PWP provides a benefit of special importance to its DAC area. As noted in the IRP Executive Summary, PWP will explore additional actions that would support the overall carbon reduction goals of the IRP including:
Perform a rate design study that explores various options working to further address rate equity. Explore expansion of distributed
energy resources, both customer‐ and utility‐owned.
Evaluate possible changes to customer incentives or subsidies, including low‐income assistance.
Prioritizing the DAC and rate equity is essential as PWP undergoes planning and implementation of clean energy projects and programs. Additionally, this effort will be done in compliance with regulatory requirements under SB 32, SB 585, AB 1279, and other ap
plicable statutes.
14.2. Expanding Transportation Electrification in Pasadena’s DAC For more than a decade, PWP has helped support EV adoption in the community by installing EV supply equipment for both fleet and public use. Pasadena has one of the nation’s highest percentages of registered EVs.
As a participant in the CARB’s LCFS program since 2016, PWP receives credits for usage on EV supply equipment and then can sell cred
its to transportation fuel producers and importers who have met specified average carbon intensity requirements for fuel according to CARB’s regulations. PWP directs a percentage of LCFS program credit proceeds to projects and services that directly benefit qualified DACs and/or low‐income customers. In accordance with the LCFS regulation, PWP allocated 30% of LC
FS proceeds to qualifying programs and projects in calendar year 2022. This requirement increased to 40% in calendar year 2023 and will increase to 50% in 2024 and subsequent years.
Although pandemic‐related supply chain issues have delayed PWP’s overall LCFS project timelines, most of these projects progressed in calendar year 2022, inc
luding the start of construction of 25 public EV chargers at Robinson Park Recreation Center in northwest Pasadena. The project, which is scheduled to be completed and become operational by December 2023, will provide the DAC with convenient, freeway‐accessible charging to encour age EV adoption in the area. PWP has also installed three public chargers at the entrance of the City Maintenance Yards, also located in northwest Pasadena, which is home base for a majority of the heavy‐duty and light‐duty fleet vehicles that PWP and the Public Works Department operate. These
three public chargers add to the 55 existing employee vehicle and fleet chargers located directly on the facility grounds. Moreover, the Advanced Clean Fleets rule recently developed by CARB requires that 50% of new fleet purchases be qualifying zero emission vehicles (ZEV) by 2024. This requirement increases to 100% effective 2027 and will contribute si
gnificantly toward overall emissions reduction in the DAC and its surrounding neighborhoods.
Both budgetarily and operationally, PWP is fulfilling its DAC requirements under SB 535 and the LCFS.
14.2.1. EV Rebates and Incentives
To expand interest in EV adoption throughout the community, PWP has long offered incentives for the purchase or lease of an EV or EV equipment, with rebates issued in calendar year 2022 more than double rebates in the previous year.
Income‐qualified customers are eligible for additional rebates to help improve the affordability of an EV investment.
Likewise, commer
cial customers that install EV equipment in DAC locations and income‐qualified structures become eligible for additional incentives to encourage and support EV adoption in Pasadena’s disadvantaged communities.
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In 2023, PWP launched an e‐Bike rebate pilot program, which will further incentivize adoption of affordable clean transportation options. The program was fully subscribed in fall 2023. Looking forward, the City will evaluate the pilot program results, benefits and challenges for future discussion of this and similar programs.
14.2.2. Efficiency and Assistance Programs
PWP offers numerous programs supporting both the DAC and income‐qualified customers throughout the community.
Chapter 6 of the IRP (Existing Policies and Programs) outlines these programs. The descriptions in the following subsections highlight several key programs available to these customers. Aside from programs exclusively open to income‐qualified customers, PWP offers these programs to all customers. That said, the in come‐qualified programs particularly benefit DAC/LI customers.
14.2.2.1. Bill Assistance
The EUAP, together with the CARES and CARES Plus programs, provide monthly bill assistance to residents, seniors, and disabled customers who meet income requirements based on household size. Additionally, Project A.P.P.L.E. (Assisting Pasadena People with Limited Emergencies) provides a one‐time payment assistance to any income‐qualified residential customer who faces the risk of power disconnection due to non‐ payment. The Medical Equipment Assistance Program provides a monthly bill credit to any residential electric customer who operates eligible electric‐powered medical equipment, regardless of income.
PWP also provides information on other available state and federal assistance programs to expand options for those experiencing financial hardships.
14.2 .2.2. Energy Efficiency and Electrification Incentives and Services Residential customers are eligible to receive rebates and services for energy efficient appliances and home improvements that help reduce GHG emissions. The Home Energy Rebate Program (HIP) provides incentives for the purchase of ENERGY STAR®‐certified appliances and other qualifying all‐electric equipment, as well as home insulation and air conditioning measures. The program also offers additional incentives and benefits to eli gible income‐qualified customers.
14.2.2.3. Whole House Services
PWP offers various direct installation programs that help qualifying homeowners improve overall home comfort and efficiency. Both PWP’s HIP and SoCalGas’ ESAP provide no‐cost home efficiency evaluations, installations, and upgrades that include LED lighting, air‐conditioning tune‐ups, weatherization, high efficiency toilets, smart thermostats, and smart irrigation systems. The Under One Roof Program provides qualifying residents with guid ance on program eligibility requirements and assistance with service coordination on all City efficiency and home improvement programs.
Income‐qualified residents are also eligible to receive general home maintenance services such as painting, wheelchair ramp installations, and broken window replacements through the City’s MASH Program. Pasadena’s Housing Department has also partnered with Neighborhood Housing Services of Los Angeles County to offer low/no‐interest home rehabilitation loans through HELP.
Maintenance is an important step in improving home efficiency, and PWP is committed to providing an array of resource and assistance options to all members of the community.
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14.2.2.4. Energy and Water Usage Reports
To help residential electric customers gain a better understanding of how personal energy and water consumption compares to that of similar neighborhood residents, PWP provides quarterly home energy and water reports that provide customer‐specific savings tips and neighborhood comparisons to motivate efficient practices and behaviors.
14.2.2.5. Commercial Programs
WeDIP, available since 2013, provides no‐cost water and energy efficiency upgrades to small business customers who may not have the time or financial resources to participate in PWP’s large commercial customer efficiency rebate programs.
Through a $1.2 million grant from the California Department of Water Resources, WeDIP was expanded in 2018 to include medium‐
sized businesses, with 76% of the grant funding directed to small‐ and medium‐ sized businesses within a DAC census tract. Additional information on PWP’s programs is included on its website.147
14.3. Supporting Underserved Communities in the Future
PWP will continue to tailor education, outreach, and programs to engage and benefit low‐income customers and its DAC census tract to ensure its customers have the opportunity to help reduce Pasadena’s carbon footprint.
15. Defining Scenarios
15.1. Scenarios vs. Sensitivities
PWP is required to file a resource plan with the CEC that complies with various state requirements, including PUC Section 9621. However, the CEC also encourages POUs like PWP to evaluate scenarios and sensitivities to consider the feasibility, cost effectiveness, and rate impacts of alternative options.
In its 2018 IRP guidelines, the CEC defines a scenario as “a set of assumptions about future conditions used in power system modeling performed to support generation or transmission planning” and a sensitivity study as “a technique that determines how scenario analysis changes when an assumption is varied with all other scenario assumptions unchanged.” In other words, a scenario produces a combination of resources buil t over time that aim to optimally meet energy, capacity, and environmental goals. Sensitivities stress scenarios to see how they would perform under different conditions.
In the 2023 IRP, PWP studied five scenarios and one emerging technology scenario. PWP also elected to model the five scenarios under four sensit
ivities. See Figure 84 for a primer on how PWP regarded the five scenarios versus the emerging technology scenario versus sensitivities.
147 https://pwp.cityofpasadena.net/savemoney/
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Figure 84: Scenario vs. Emerging Technology Scenario vs. Sensitivity Scenario Emerging Technology Scenario Sensitivity
A mix of resources optimized
under given conditions
An avoided cost study
Load is shifted, and new
resource mixes are created
The emphasis is not on what is
installed, but on the cost
differences
This quantifies a potential
maximum financial value to PWP
for a specified load or peak
reduction
A stress of variables applied to
scenarios
On January 30, 2023, the Pasadena City Council approved Resolution 9977, declaring a Climate Emergency and setting a policy goal to reach 100% carbon‐free electricity by the end of 2030. Resolution 9977 further directs PWP to use the 2023 IRP process to plan multiple pathways to meet this goal while optimizing affordability, rate equity, stability, and reliability.
As a result of this resolutio
n, the 2023 IRP serves not only to meet CEC obligations but also to launch PWP’s investigation into planning and operating a carbon‐free system.
PWP has the following two objectives of note for the 2023 IRP:
File an IRP with the CEC as required by statu
te every five years
Plan multiple approaches to transition to the goal of 100% carbon‐free sources by the end of 2030, and optimize affordability, rate equity, stability and reliability
The second objective is likely one of the most ambitious decarbonization goals in the world, and far more aggressive than the ambitious California’s 100% Clean Energy goals. As identified in the SB 100 Scoping Plan, the St ate’s plan relies upon
unprecedented build rates of renewable resources, as well as comprehensive electric grid transmission additions to accomplish a 2045 target implementation date.
PWP acknowledges that working
towards achieving such a goal will require intensive and concentrated efforts that stretch across CAISO processes, CEC planning and coordination with government agencies across the state. While PWP must file an IRP by the end of 2023 to remain in compliance with state regulations, PWP anticipates continuing its de monstrated decarbonization trend, as GHG reductions of 68% have been realized as compared to 1990 levels. Therefore, the 2023 IRP represents its initial planning effort to contextualize what a carbon‐free transition could entail. PWP will conduct further economic, reliability, rate, environmental, and other studies to help identify risks and opportunities.
15.2. Important Definitions for Scenarios
There are important definitions to note related to scenarios. The scenarios differentiate between internal and external resources. PWP’s service territory is internal, whereas the grid outside its territory is external. See Figure 85.
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Figure 85: Internal vs. External
Internal External
PWP is modeled as an area with load and its Glenarm
power plant. Load is adjusted to include the impacts of energy efficiency, electric vehicles, distributed solar, and distributed storage. The IRP will refer to everything in this area as “internal.” This area is PWP’s service
territory.
Goodrich is PWP’s connection to the larger energy
markets within California. Goodrich is modeled as a
connection to these larger markets. The larger market is the grid outside of PWP's service territory and is
referred to as the external area.
PWP also categorizes resources as utility‐scale, residential, commercial, distributed, or community. See Figure 86 for a brief description of each category. Additional information on NREL’s 2022 ATB, as referenced in Figure 86, is available online.148
148 https://atb.nrel.gov/
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Figure 86: Utility‐Scale or Distributed?
Utility‐Scale
Installed in
larger sizes,
so less
expensive
from a per‐
unit
installation
viewpoint
In NREL's
2022 ATB,
utility‐scale
PV is 100
MW and
battery
storage is 60
MW (240
MWh)
A limited
amount can
be installed
internally,
and more
can be
installed
externally
Community
These are
utility‐scale
resources
installed for
subscribers
within the
community
Typically
support a
green or
clean rate
program
Can be
installed
internally in
the 2023 IRP
Distributed
Installed in
smaller sizes,
so more
expensive
from a per‐
unit
installation
viewpoint
Installed
Internal to
PWP
Commercial
A subset of
distributed
resources
installed in a
commerical
space
In NREL's 2022
ATB,
commerical
solar is sized at
200 kW, and
commerical
batteries at
600 kW (2,400
kWh)
Residential
A subset of
distributed
sresources
installed in
residential
space
In NREL's 2022
ATB,
residential
solar is sized at
7.15 kW, and
residential
batteries at 5
kW (20 kWh)
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Resolution 9977 requests carbon‐free sources by the end of 2030. While renewable and zero‐carbon are phrases defined by California, carbon‐free is a concept developed by PWP. See Figure 87. PWP defined carbon‐free resources as those that do not emit any carbon. This excludes some resources that California defines as renewable and, by that distinction, also as zero‐carbon. PWP and its stakeholders also defined the goal as hourly for the purposes of the 2023 IRP. RECs, offsets,
or other financial tools were not permitted.
Figure 87: Renewable vs. Zero‐Carbon vs. Carbon‐Free
Renewable Zero‐Carbon Carbon‐Free
Who defines this? California California 2023 IRP
Includes (examples) Wind, solar, geothermal,
renewable‐powered fuel
cells, landfill gas, biogas
Wind, solar, geothermal,
renewable powered fuel
cells, landfill gas, biogas,
hydroelectric, nuclear,
carbon‐capture
Wind, solar, geothermal,
renewable‐powered fuel
cells, hydroelectric,
nuclear, storage (if
charged by carbon‐free
energy)
Excludes (examples) Fossil Fossil Fossil
Landfill gas, biogas,
current carbon capture
technology
Measured Annually Annually Hourly
Source of Requirement? SB 100 SB 1020 Resolution 9977 Scenario an
alysis in the 2023 IRP helps PWP identify risks, opportunities, and inflection points. In the 2023 IRP, PWP assumed different ways to achieve a carbon‐free resource portfolio by 2030. Four of the scenarios (including Scenario 6) follow the Resolution 9977 direction to study a carbon‐free system, while one scenario (Scenario 4) follows state requirements. Scenario 5 s
tudies the impact of a carbon tax. Figure 88 includes the list of scenarios.
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Figure 88: Scenarios
Each scenario genera
ted a least‐cost, best‐fit resource mix within the constraints of its assumptions. The IRP used an industry‐standard planning model, EnCompass, by Anchor Power Solutions. See Section 10.2 of the IRP for more details on the model. The scenarios are further described in the following subsections.
15.3. Scenario 1: 100% Carbon‐Free by 2030 with No Limit on Internal Resources In addition to all relevant regulatory requirements, PWP will seek to meet 100% of its hourly energy load with carbon‐free resources. Carbon‐free resources include onshore wind, offshore wind, solar, and renewable hydrogen‐powered fuel cells, but do not include natural gas, landfill gas, biofuel, or market purchases. Different durations of battery stora ge can also meet capacity needs. Battery storage should be charged by carbon‐free resources post‐2030.
PWP has a limited amount of space available within its service territory to site new generation or storage facilities.
However, this scenario allows for a virtually unlimited number of resources to be located internal to PWP. The results of this scenario demonstrate the types and aggregate sizes of resources needed to meet its load every hour with carbon‐free resources. This serves as the foundation for what PWP could seek to acquire, in practice. This may also help PWP identify the number, sizes, and scale of facilities needed.
15.4. Scenario 2: 100% Carbon‐Free by 2030 with a Limit on Internal Resources PWP has a limited amount of space available within its service territory to site new generation or storage facilities. Based on best‐available information and estimates, PWP believes it can site 200 MW of 4‐hour storage, 150 MW of 6‐hour storage, 100 MW of 8‐hour storage, or 50 MW of 10‐hour storage in its service territory. PWP also believes it could site up to 5 MW of hydrogen‐powered fuel cells and 5 MW of utility‐scale (community) solar. This scenario sets these limits as the maximum amounts of these internal resources that PWP could choose. In other words, the model could ele ct to install up to those amounts of resources internally. If those limits bind (i.e., if the results maximize any one of those limits), the model would seek to install the next best thing. This could be residential or commercial solar or storage within PWP’s Scenario 1: 100% Carbon Free by 2030 with No Limit on Internal Resources Scenario 2: 100% Carbon Free by 2030 with a Limit on Internal Resources Scenario 3: 100% Carbon Free by 2030 with a Limit on Internal Resources and Doubled Distributed Resources Scenario 4: Reference Case (SB1020)
Scenario 5: Reference Case + Social Cost of Carbon (SB1020 + SCC) Scenario 6: Emerging Technologies Study Scenario
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service territory, or carbon‐free resources located external to PWP that PWP could import through Goodrich. Should the space constraints detailed in Scenario 2 arise in practice, PWP could consider how to proceed.
15.5. Scenario 3: 100% Carbon‐Free by 2030 with a Limit on Internal Resources and Doubled Distributed Resources
This scenario copies the carbon‐free goals and internal resource availability assumptions mentioned in Scenario 2 but doubles the amount of distributed solar and storage embedded in the load forecast. See Figure 89. The distributed solar and storage capacity embedded in the load forecast represents PWP’s estimate of what will happen naturally given current incentives and state tr
ends. In this scenario, PWP also adds that amount online as resources. The doubling of distributed solar and storage assumes a decision to prioritize customer‐side resources.
Figure 89: Distributed Resources in Load Forecast
Installed Capacity of Distributed Resources in Load Forecast (MW) Year Distributed Solar Distributed Storage
2023 30 2
2024 32 2
2025 34 3
2026 37 3
2027 39 4
2028 42 4
2029 44 5
2030 47 6
2031 50 7
2032 53 8
2033 56 9
2034 59 9
2035 62 11
2036 65 12
2037 68 13
2038 71 14
2039 74 15
2040 78 17
2041 81 18
2042 84 20
2043 88 21
2044 91 23
2045 95 25
2046 98 26
2047 102 28
2048 105 30
2049 108 32
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Installed Capacity of Distributed Resources in Load Forecast (MW) Year Distributed Solar Distributed Storage
2050 112 34
Across
all scenarios, all resources have associated costs. The IRP presumes that DER already included in the load forecast puts no incremental cost burden on PWP. Additional DER would come at an additional cost, and the IRP identifies this cost component for informational guidance.
15.6. Scenario 4: Reference Case (SB 1020)
This scenario demonstrates PWP’s ability to comply, or exceed with all applicable state regulatory mandates, including the following:
Utility‐specific GHG reduction targets established by CARB that reflect the electricity sector’s achievement of economy‐wide GHG emissions reductions of 40% lower than 1990 levels by 2030 Renewable energy procurement target of 60% by 2030
100% renewable resource and zero‐
carbon goal by the end of 2045
Scenario 4 gives PWP a base case against which to compare other scenarios.
15.7. Scenario 5: Reference Case + Social Cost of Carbon (SB 1020 + SCC) PWP meets all relevant regulatory requirements. Also, a hypothetical additional carbon tax based on the SCC applies to all carbon‐generating resources. The SCC is a dollar value estimate of the damage to society caused by CO2 emissions. PWP referred to an estimate developed by the EPA in 2022. See Figure 90149. PWP used the 1.5% discount rate in this estimate, which generates the highest SCC for study purposes.
149 https://www.epa.gov/controlling‐air‐pollution‐oil‐and‐natural‐gas‐industry/epa‐issues‐supplemental‐proposal‐reduce
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Figure 90: Social Cost of Carbon
Carbon‐
producing resources include natural gas, landfill gas, biogas, and market purchases. The IRP assumed that the carbon‐intensity of the market declines over time, as carbon‐emitting resources are replaced by lower‐emitting alternatives. PWP adopted the market estimate using NREL’s Cambium 2022 mid‐case data, depicted in Figure 91.150 150 https://scenarioviewer.nrel.gov/
‐
100
200
300
400
500
600
700
800
900
1,000
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
$Nominal/Short Ton of Carbon
Social Cost of Carbon
2.5% Discount Rate 2% Discount Rate 1.5% Discount Rate
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Figure 91: Carbon Intensity of CAISO
Scenario 5 allows the capa
city associated with carbon‐producing resources to help meet overall requirements. However, the carbon tax would, in theory, encourage additional renewable generation to replace carbon‐emitting resources.
15.8. Scenario 6: Emerging Technology Study
Emerging technologies represent opportunities to achieve carbon‐free goals at lower costs and greater reliability.
Emerging technologies is a general term referring to technologies that may become available during the IRP Study Period (2023 through 2050). Figure 92 shows examples of potential emerging technologies.
Figure 92: Potential Emerging Technologies
Emergi
ng technologies, by nature, are not currently available commercially. Therefore, PWP does not have the data on costs and operational parameters that it has for more advanced technologies. ‐
100
200
300
400
500
600
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
Pounds of Carbon/MWh
CAISO's Carbon Intensity
Long‐Duration
Energy Storage
Hydrogen Burning
Engines and
Turbines
Demand Response
Tools
Energy Efficiency
Tools
Small Modular
Nuclear Reactors
Carbon Capture
and Sequestration
Different Energy
Storage
Chemistries
Technology
Intersections With
Other Industries
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PWP seeks to be a leader in making and achieving carbon reduction goals. To support this, PWP ran an Emerging Technology Scenario. This is an additional scenario that evaluates the impacts of emerging technologies on a single given scenario, which is Scenario 2 in this IRP. Scenario 2 is the most constrained in terms of new resour ces that can be installed.
As a result, the value of emerging technologies to PWP may be highest in Scenario 2.
While PWP cannot predict what emerging technologies could best help it achieve its carbon reduction goals cost effectively, the following are two performance traits of particular inte rest to PWP:
Less energy usage overall
Examples include energy efficiency, distributed resources, a base load plant, etc. Less energy usage at net peak load times
Examples include demand response technologies, long‐duration energy storage, dispatchable clean technologies, etc.
In the Emerging Technology Scenario, PWP sought answer s to the following questions:
What is the proxy value to reduce energy and peak load across all hours of a year by 1%, 2%, or 3%? What is the proxy value to reduce the top 0.5%, 1%, and 1.5% of peak load hours each year by 30 MW? To answer these questi
ons, PWP ran two series of studies: an energy efficiency proxy study and a demand response proxy study.
15.8.1. Scenario 6: Energy Efficiency Proxy
In the first study under Scenario 6, PWP’s load is reduced by 0.5%, 1%, and 2% across all hours of the year for a given scenario (in this case Scenario 2). The cost difference between these results and the original scenario result is a potential maximum value to PWP for technologies that reduce overall load.
Scenario 2 is the most constrained s
cenario, which results in a higher bound of financial value to PWP for an emerging technology that reduces load.
15.8.2. Scenario 6: Demand Response Proxy
In this second study under scenario 6, PWP’s load is reduced by 30 MW (approximately 10% of its peak load) across the top 0.5%, 1%, and 2% of load hours each year. The cost differences between these results and that of the original scenario is a higher bound of value to PWP for technologies that reduce load duri ng peak hours. Again, PWP conducted this study on Scenario 2.
15.9. Modeling a Carbon‐Free Resource Scenario
Resolution 9977 requests that the IRP plan multiple approaches to meet the City’s policy goal of sourcing 100% of Pasadena’s electricity from carbon‐free sources by the end of 2030. PWP is part of CAISO and, as such, PWP needs to consider its carbon emissions in the context of its interactions with CAISO.
The carbon associated with CAISO market purch
ases can be assessed in at least the following two ways:
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Average
There are different resource types producing energy. The energy generation over one year can translate to an average emission rate. A forecasted estimate of CAISO’s carbon intensity is shown in Figure 91. Marginal
The carbon intensity of CAISO could also default to the carbon intensity of natural gas. This has historically been the last resource to go online to meet load.
Given that the market has embedded carbon,
PWP wanted to understand how it could replace market purchases with traceable, carbon‐free energy. To be carbon‐free on an hourly basis, PWP would need to purchase enough zero‐carbon resources
to avoid CAISO purchases in each hour of the year.
In modeling PWP’s carbon‐free system, the 2023 IRP made the following assumptions:
Glenarm and Magnolia are retired December 31, 2029
The debt associated with Glenarm must be repaid. There is an estimated $85 million in outstanding debt associated with Glenar
m that was not included in the modeling. Additionally, any decisions regarding Glenarm operations would be subject to CAISO in‐depth analysis, which is based in part on NERC reliability standards.
Glenarm does not require fuel source modification, adaptation, or conversion for Scenarios 4 and
5. The Carbon‐Free Scenarios require Glenarm to be either replaced, converted, or adapted with carbon‐free dispatchab
le alternatives such as carbon capture, green hydrogen, biofuels or other future technologies as they emerge, and prior to 2030
Magnolia’s contract runs through June 30, 2036. There may be fees, must‐take, or other financial obligations associated with an early exi
t. Participation in this project is through SCPPA and requires an in‐ depth analysis and potential bilateral negotiations with other SCPPA project participants. No biogas as a new resource starting in 2030
No market access – assume the average emission rate for carbon From a planning persp
ective, PWP operationally modeled its system as an island to avoid the markets inherent carbon content (i.e., without CAISO access). However, PWP currently interacts daily with CAISO. The differences between these approaches is shown in Figure 93.
Figure 93: Island vs. Market Access
Island Energy Market Access
Modeling PWP adds resources so it can operate a
reliable, 100% carbon‐free system on an
hourly basis.
Once the resources are selected as though PWP
is an island, they can dispatch within the CAISO
markets.
Carbon Implications PWP can meet its load with carbon‐free resources each hour.
Resources may dispatch differently given market
signals. Market interactions come with carbon
implications.
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Island Energy Market Access
Cost Implications Scenario costs will appear higher. This is the high bookend.
PWP’s resources cannot sell excess
energy to the market.
Scenario costs will appear higher. This is the low
bookend. PWP’s resources could sell excess
energy to the market. Given that many factors
influence revenue earned in the markets, PWP
may need to study other cost implications to
answer the question, “What is excess worth?”
15.10. PWP’s Starting Position
PWP has an existing fleet of owned and contracted resources that help meet energy, capacity, and environmental needs.
PWP’s existing installed capacity is shown in Figure 94.
Figure 94: PWP’s Existing Cumulative Installed Capacity 2023 2024 2025 2026 2027 2028 2029 2030 2031
Total Existing Resources 407 405 337 337 287 287 287 282 271 Existing Coal 108 108 0 0 0 0 0 0 0
Existing Natural Gas Combined Cycle 80 80 130 130 80 80 80 80 80 Intermountain Repower NG 0 0 50 50 0 0 0 0 0
GT ‐ 5 66 66 66 66 66 66 66 66 66
Magnolia 14 14 14 14 14 14 14 14 14
Existing Natural Gas Combustion Turbine 132 132 132 132 132 132 132 132 132 GT ‐ 1 22 22 22 22 22 22 22 22 22
GT ‐ 2 22 22 22 22 22 22 22 22 22
GT ‐ 3 45 45 45 45 45 45 45 45 45
GT ‐ 4 42 42 42 42 42 42 42 42 42
Existing Large Hydroelectric (Hoover) 14 14 14 14 14 14 14 14 14 Existing Nuclear (Palo Verde) 10 10 10 10 10 10 10 10 10 Existing Wind 7 5 5 5 5 5 5 0 0
Milford Wind 5 5 5 5 5 5 5 0 0
PPM (Avangrid) Wind 2 0 0 0 0 0 0 0 0
Existing Landfill 10 10 10 10 10 10 10 10 0
Puente Hills Landfill 4 4 4 4 4 4 4 4 0
Chiquita Landfill 6 6 6 6 6 6 6 6 0
Existing Utility‐Scale Solar PV 36 36 36 36 36 36 36 36 36 Antelope Solar 7 7 7 7 7 7 7 7 7
Columbia Two Solar 2 2 2 2 2 2 2 2 2
Kingbird Solar 20 20 20 20 20 20 20 20 20
Summer Solar 7 7 7 7 7 7 7 7 7
Windsor Reservoir Solar 1 1 1 1 1 1 1 1 0
Existing Demand Response 10 10 0 0 0 0 0 0 0
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Total New Contracted Resources 0 0 335 335 428 478 478 478 478 New Geothermal 0 0 0 0 35 35 35 35 35
Calpine Geysers 0 0 0 0 25 25 25 25 25
Coso Geothermal 0 0 0 0 10 10 10 10 10
New Utility‐Scale Solar PV 0 0 5 5 44 44 44 44 44 EDF Sapphire Solar 0 0 0 0 39 39 39 39 39
New 4‐Hour Storage (projected) 0 0 80 80 100 150 150 150 150 EDF Sapphire Storage 0 0 0 0 20 20 20 20 20
Peak Load (MW) 330 333 335 338 341 343 346 348 351 Installed capacity is not the same as qualifying capacity. Qualifying capacity represents the resources’ reliability contributions, which CAISO quantifies. Figure 95 shows PWP’s existing RA position without any resource additions.
Figure 95: PWP’s Firm Capacity Position without Resource Additions 0 100
200
300
400
500
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response Contracted Geothermal Contracted Solar Contracted Storage Load Requirements
Load
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Figure 96 shows the firm capacity of these resources in greater detail.
Figure 96: PWP’s Firm Capacity Position without Resource Additions Monthly Load (MW) 2023 2024 2025 2026 2027 2028 2029 2030 2031 July 288 297 311 323 310 297 300 306 322
August 305 323 335 338 334 313 337 330 351
September 330 333 324 322 341 343 346 348 344
Summer Peak Load (MW) 330 333 335 338 341 343 346 348 351 Reserve Margin (%) 15% 15% 18% 18% 18% 18% 18% 18% 18% Peak Month 09 09 08 08 09 09 09 09 08
Required Reserves (MW) 50 50 59 59 60 60 61 61 61 Summer Load Requirements (MW) 380 383 394 397 400 403 406 409 412 Total Existing Resources 356 355 289 288 238 238 238 237 230 Existing Coal 105 105 0 0 0 0 0 0 0
Existing Natural Gas
Intermountain 0 0 50 50 0 0 0 0 0
Glenarm 195 195 195 195 195 195 195 195 195
Magnolia 14 14 14 14 14 14 14 14 14
Existing Large Hydroelectric 9 9 9 9 9 9 9 9 9 Existing Nuclear 9 9 9 9 9 9 9 9 9
Existing Wind 0 0 0 0 0 0 0 0 0
Existing Landfill 8 8 8 8 8 8 8 8 0
Existing Utility‐Scale Solar PV 4 4 4 4 3 3 3 3 3 Existing Demand Response 12 12 0 0 0 0 0 0 0
Total New Resources 0 0 0 0 55 55 55 55 56
New Geothermal
Contracted (Calpine Geysers
and Coso) 0 0 0 0 32 32 32 32 33
New Solar
Contracted (EDF Sapphire Solar) 0 0 0 0 3 3 3 3 3 New Storage
Contracted (EDF Sapphire Storage) 0 0 0 0 20 20 20 20 20 Length/(Shortage) (24) (27) (105) (109) (107) (111) (114) (117) (127) Calpine Geys
ers, Coso Geothermal, and EDF Sapphire and Solar were all contracted in 2021 to 2023 to help address upcoming qualifying capacity needs. Without these planned resources, capacity shortages in the summer increase to 105 MW in 2025 and to 162 MW in 2027. Even with these resources, shortages remain at 105 MW in summer 2025 and 107 MW in summer 2027.
Across
scenarios, 2025 and 2027 show resource needs because 108 MW of installed capacity from IPP coal retires on June 30, 2025. Approximately 50 MW of installed capacity from IPP natural gas begins on July 1, 2025, and expires on June 30, 2027.
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Capacity shortages result in greater net interactions with CAISO’s energy markets. Figure 97 shows that PWP will serve approximately two‐thirds of its annual energy with contracted resources by 2030, assuming its contracted resources come online as planned.
Figure 97: Energy Position without Resource Additions
Capacity shortages
also result in increasing renewable energy needs over time, as shown in Figure 98. As it stands, PWP needs more renewable energy to fulfill its state requirement of 60% renewables by 2030. 0 500
1,000
1,500
2,000
Generation (GWh)
Energy Position
Existing Coal Existing Natural Gas Combined Cycle
Existing Natural Gas Combustion Turbine Existing Large Hydroelectric Existing Nuclear Existing Wind
Contracted Solar Existing Landfill
Existing Utility‐Scale Solar PV Existing Demand Response Contracted Geothermal Energy (GWh)
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Figure 98: Renewable Position without Resource Additions
16. Defining Sensitivities
Scenarios are selections of resources optimized to meet capacity, energy, and renewable needs. Sensitivity tests push stressors onto scenarios to determine how the scenarios would perform under different conditions. Scenarios 1, 2, 3, 4, and 5 had the sensitivity tests applied after the initial modeling. These tests help identify potential vulnerabilities and considerations. There are four proposed sensitivities, as shown in Figure 99.
Figure 99: Sensitivities
The sensi
tivities seek to answer fundamental questions. See Figure 100. Sensitivities 1 and 2 focus on reliability, and Sensitivities 3 and 4 focus on cost.
‐
500,000
1,000,000
2023 2024 2025 2026 2027 2028 2029 2030
Renewable (GWh)
Renewable Position
Contracted Solar Contracted Geothermal
Renewable Energy Credits (RECs) Existing Utility‐Scale Solar PV Existing Landfill Existing Wind
Pasadena Renewable Resources Requirement (MWh)
Sensitivity 1: Heat Wave
Sensitivity 2: Goodrich Transfer Contingency
Sensitivity 3: High Technology Costs
Sensitivity 4: Low Technology Costs
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Figure 100: Sensitivity Metrics
16.1. Sensitivity 1: Heat Wave
This sensitivity tests scenarios against a persistent, record‐setting heat wave. Daily temperatures are set between 90 degrees Fahrenheit (°F) and 120°F for four weeks. Power prices, natural gas prices, wind generation, solar generation, and load are all impacted because of the heat. This tests the ability of each scenario to meet load.
In 2030, peak load tim
es occur in late August through early September. See Figure 101. As a result, this scenario ran from August 15, 2030, through September 15, 2030. Dates and times of peak are highly uncertain. This scenario is one estimate of load created for the 2023 IRP.
Figure 101: Peak Load in 2030
Date Month Day Hour Ending Demand (MW)
September 11, 2030 9 11 17 348
September 11, 2030 9 11 16 343
September 11, 2030 9 11 18 342
September 1, 2030 9 1 17 340
September 1, 2030 9 1 16 332
August 27, 2023 8 27 16 330
Sensitivity 1:
Heat Wave
What are
the
additional
energy
needs in the
month?
Total MWh
of additional
energy
needs
What is the
maximum
hourly value
for an
additional
energy
need?
Maximum
MW of
additional
energy need
How many
hours does
PWP need
additional
energy?
Additional
energy
required
(hours)
How many
days does
PWP need
additional
energy?
Additional
energy
required
(days)
Sensitivity 2:
Goodrich
Transfer
Contingency
What are
the
additional
energy
needs in the
month?
Total MWh
of additional
energy
needs
How many
hours does
PWP need
additional
energy?
Additional
energy
required
(hours)
How many
days does
PWP need
additional
energy?
Additional
energy
required
(days)
Sensitivity 3:
High
Technology
Costs
How much
would costs
increase?
Percent
increase in
scenario
compared to
itself
Sensitivity 4:
Low
Technology
Costs
How much
would costs
decrease?
Percent
decrease in
scenario
compared to
itself
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Date Month Day Hour Ending Demand (MW)
September 11, 2030 9 11 15 329
August 25, 2023 8 25 17 328
August 27, 2023 8 27 17 328
September 1, 2030 9 1 18 328
Power prices,
natural gas prices, wind generation, solar generation, and load were correlated to heat to create conditions that mimic a heat wave. The explanation in the following subsection provides additional details on the method used to create the data.
16.1.1. Sensitivity 1: Heat Wave: Data Scraping and Cleaning The following historical hourly data from 2008 to 2022 (excluding 2012 due to irreconcilable inconsistences in the data) came from Yes Energy, subcontracted through ACES:
Temperature in Pasadena
CAISO load
CAISO wind generation
CAISO solar generation
Real‐time prices at SP‐15 Hub
Daily natural gas price at SoCal City Gate
The data was cleaned by rem
oving missing values and negative solar and wind generation. To compare solar and wind generation across years, the data was converted to a percentage of the maximum generation for the year to estimate capacity factors. This is the cleaned data.
16.1.2. Sensitivity 1: Heat Wave: Normal Data Creation
The wind and solar capacity factors for each hour of the year were averaged from 2008 through 2022. This produced a normal 8,760 capacity factor shape for wind and solar, covering all the hours in a typical year. Hours were then filtered to only the hours in September. The prevailing seasonal and temperature relationships were extracted from the averaged shapes to remove noise, such as histor
ical localized weather patterns. This normal data was used to compare a normal September to the modelled heat wave, and this served as the basis for multipliers derived by dividing the heat wave scenario by the normal scenario, allowing easy switching between the two.
16.1.3. Sensitivity 1: Heat Wave: Training Datasets Creation Hourly training data is required for the predictions that use hourly granularity (hourly load, power prices, and wind output) and was generated from an August to October subset of the cleaned data (shoulder months are included so that there is more data to enable the model to generate relationships). Hourly data was filtered to isolate only those observations where the temperature
is greater than 75°F and the real‐time power price and natural gas price are greater than zero.
This filtering led to linear trends to use in modeling a heat wave.
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Daily training data is required for the predictions that use daily granularity (natural gas and solar output) and was generated from the same subset as the hourly training data. To convert the hourly solar capacity factor into a usable daily metric, a daily maximum was taken as an ordinal variable with 0.05 width bins from 0 to 1. However, the wind capacity factor and the load we
re converted from hourly values to daily means. As a final step, predictive variables of mean temperature, maximum temperature, and minimum temperature were generated along with temporal variables, such as the year, time of week, and time of year. The hourly training da ta (and the prediction data in the next step) also included temporal predictive variables with the additional inclusion of the time of day.
16.1.4. Sensitivity 1: Heat Wave: Prediction Data Creation PWP defined a heat wave as a four‐week period when temperatures do not dip below 90°F and do not exceed 120°F during September 2030. By using a sine curve function for daytime warming and a logarithmic decay function for nighttime cooling, hourly temperature estimates were based on an idealized daily temperature curve for a given latitud e that interpolates hourly data between the calculated time when the daily minimum and the daily maximum occur.
16.1.5. Sensitivity 1: Heat Wave: Model Creation and Prediction The load model was trained on the hourly training data. The hourly prediction data was fed into the fitted model to create hourly load predictions. Next, an identical model was created to reflect the exclusion of temperature as a predictive variable, and it was fitted on the cleaned data. The new model predicts norm al load for that time of year. By taking the heat wave modeled load and dividing it by the normal load, a multiplier was generated that models the magnitude of change between a normal scenario and a heatwave. This multiplier was also fed into the model.
The wind generation capacity factor model was train ed on the hourly training data, then the model was used on the hourly prediction data to predict hourly wind generation capacity factors for the heat wave. These predictions were divided by the normal wind generation capacity values (calculated in a prior step) to generate multipliers.
The solar generation capac
ity factor model was trained on the daily training data, and then the model was fed the daily prediction data to predict daily maximum solar generation capacity factors; however, the prediction for each of the maximum capacity factors was the same, so only a single multiplier was needed. Therefore, the center of the predicte d bin was taken as the single predicted capacity factor and used to rescale the normal data. The original normal data was then divided by the new normal data, and the average was taken to derive a multiplier.
The daily natural gas price model was trained on the daily training data, then the mode l was used on the daily prediction data to predict daily gas prices for the heat wave.
The real‐time pricing model for power prices was trained on the hourly training data, then the model was used on the hourly prediction data to predict hourly power prices values for the heat wave.
For some of the models, a previous model’s predictions were used as inputs for its own predictions.
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Figure 102: Heat Wave Data Creation
Response
Variable
Model Type
Response
Transformation
Temporal
Granularity
Temperature
Time of Day
Time of Week
Time of Year
Year
Temperature
Interaction
Wind Capacity
Factor
Solar Capacity
Factor
Natural Gas Price
Real‐Time CAISO
Load
Real‐Time
CAISO
Load
Multivariate
Linear None Hourly
Wind
Capacity
Factor
Multivariate
Linear Logarithmic Hourly
Daily
Solar
Capacity
Factor
Multinomial Ordinal +
Maximum Daily
SoCal City
Gate
Natural
Gas Price
Multivariate
Linear Logarithmic Daily
SP‐15
Real Time
LMP
Multivariate
Linear None Hourly
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Overall, assumed temperatures average 104°F, as shown in Figure 103.
Figure 103: Simulated Temperatures Under a Heat Wave
During a heat wave, rene
wable output changes. Solar increases by 3.6% and wind is 12% of its normal output. See Figure 104 for details.
Figure 104: Wind and Solar Profiles Under Heat Wave
Load increase
s to approximately 1.5 times its typical amount during a heat wave due to air conditioning demand. 80 85
90 95
100
105
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115
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125
09‐01‐2030 HE1
09‐01‐2030 HE21
09‐02‐2030 HE17
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09‐08‐2030 HE13
09‐09‐2030 HE9
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09‐13‐2030 HE13
09‐14‐20
30 HE9
09‐15‐2030 HE5
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09‐16‐2030 HE21
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09‐18‐2030 HE13
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09‐21‐2030 HE1
09‐21‐2030 HE21
09‐22‐2030 HE17
09‐23‐2030 HE13
09‐24‐2030 HE9
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09‐26‐2030 HE1
09‐26‐20
30 HE21
09‐27‐2030 HE17
09‐28‐2030 HE13
09‐29‐2030 HE9
09‐30‐2030 HE5
Temperature (°F)
Simulated Temperatures Under a Heat Wave
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123456789 1 0 1 1 1 2 1 3 1 4 1 5 1 6 1 7 1 8 1 9 2 0 2 1 2 2 2 3 2 4 Generation as Percent of Nameplate (%)
HE
Wind and Solar Profiles Under Heat Wave: September 2030 Wind (Reference) Solar (Reference) Wind (Heat) Solar (Heat)
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Power and natural gas prices also increase during a heat wave, with natural gas prices averaging $35/MMBtu. In September 2030, the reference forecasted price was $5.50/MMBtu. Figure 105 shows the pricing assumed in the IRP.
Power prices averaged $447/MWh for this sensitivity. For September 2030, the reference case forecasted price was $69/MWh. These prices ar
e in nominal dollars.
Figure 105: Heat Wave Prices
16.2. Sensitivity 2: Goodrich Transfer Contingency
Under normal operating conditions, Goodrich can import up to 280 MW until July 2032. It is anticipated that planned upgrades will allow up to 336 MW thereafter. For purposes of this sensitivity, Goodrich’s import capability is reduced by one‐half to 140 MW in 2030 to reflect a single transmission line outage into the station for one week during th e summer.
There are different circumstances such as planned system maintenance or unplanned (forced) outages that could cause such an event. These could originate at Goodrich, or on the lines feeding into Goodrich. This sensitivity would help PWP compare the value of internal versus external resources.
16.2.1. Sensitivity 2: Goodrich in 2030 Under Forecasted Normal Operating Conditions The model ran the week of September 8, 2030, through September 14, 2030, when peak loads in 2030 are likely to occur.
Figure 106 shows how demand compares to Goodrich’s capability. 0 5
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09‐01‐2030 HE1
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09‐06‐2030 HE13
09‐07‐2030 HE11
09‐08‐2030 HE9
09‐09‐2030 HE7
09‐10‐2030 HE5
09‐11‐2030 HE3
09‐12‐2030 HE1
09‐12‐2030 HE23
09‐13‐2030 HE21
09‐14‐2030 HE19
09‐15‐20
30 HE17
09‐16‐2030 HE15
09‐17‐2030 HE13
09‐18‐2030 HE11
09‐19‐2030 HE9
09‐20‐2030 HE7
09‐21‐2030 HE5
09‐22‐2030 HE3
09‐23‐2030 HE1
09‐23‐2030 HE23
09‐24‐2030 HE21
09‐25‐2030 HE19
09‐26‐2030 HE17
09‐27‐2030 HE15
09‐28‐2030 HE13
09‐29‐20
30 HE11
09‐30‐2030 HE9
Gas Price ($Nominal/MMBtu)
Power Price ($Nominal/MWh)
Power and Gas Prices Under A Heat Wave
Gas Price ($Nominal/MMBtu) Power Price ($Nominal/MWh)
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Figure 106: Demand vs. Goodrich in 2030
16.2.2. Sensitivity 3: High Technology Costs
All scenarios used mid‐cost estimates of new resources. However, the 2023 IRP produced low, mid, and high estimates of capital costs for new resources. See Appendix – Cost of New Resources. This sensitivity stresses the results of the scenarios under the high estimates for new resource costs.
16.2.3. Sensitivity 4: Low Technology Costs
This sensitivity tests the results of the scenarios under the low estimates for new resource costs. See Appendix – Cost of New Resources
17. Scenarios and Sensitivities Results
17.1. Scenario 1: 100% Carbon‐Free by 2030 (No Limit on Internal Resources) The installed capacity of new resources in Scenario 1 is shown in Figure 107.
Figure 107: Scenario 1: New Cumulative Installed Capacity 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total New Resources 355 375 468 468 468 788 818 830 899 885 New Wind 0 0 0 0 0 0 0 0 30 30
New Geothermal
Contracted (Calpine Geysers and
Coso) 0 0 35 35 35 35 35 46 0 0
New 0 0 0 0 0 0 0 0 0 0
New Solar
0 50
100
150
200
250
300
350
400
9/8/2030
9/9/2030
9/10/2030
9/11/2030
9/12/2030
9/13/2030
9/14/2030
Load or Goodrich Import/Export Capability
(MW)
Demand vs. Goodrich Capacity in 2030
Demand (MW) Goodrich Import/Export Capability (MW)
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Contracted (EDF Sapphire Solar) 0 0 39 39 39 39 39 39 39 0 Utility‐Scale Solar 280 300 300 300 300 300 300 300 320 330 Community 0 0 0 0 0 0 0 0 0 0
Commercial 0 0 0 0 0 0 0 0 0 0
Residential 0 0 0 0 0 0 0 0 0 0
New Storage
Contracted (EDF Sapphire Storage) 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage 75 75 75 75 75 195 195 195 195 185 New 6‐Hour Storage 0 0 0 0 0 80 90 90 90 90
New 8‐Hour Storage 0 0 0 0 0 10 10 10 40 30
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New Commercial 0 0 0 0 0 0 0 0 0 0
New Residential 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 110 130 130 165 220
Figure 108: Scenario 1: Cumulative Installed Capacity by Location 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total Installed Capacity 692 712 755 755 755 859 875 867 919 899 Total Existing Resources 337 337 287 287 287 70 57 37 20 14 Total New Resources 355 375 468 468 468 788 818 830 899 885 New Onshore Wind 0 0 0 0 0 0 0 0 30 30
New Land‐Based External Wind 0 0 0 0 0 0 0 0 30 30 New Offshore Wind 0 0 0 0 0 0 0 0 0 0
New Geothermal 0 0 35 35 35 35 35 46 0 0
Calpine Geysers 0 0 25 25 25 25 25 25 0 0
Coso Geothermal 0 0 10 10 10 10 10 21 0 0
New Utility‐Scale Solar PV 280 300 339 339 339 339 339 339 359 330 EDF Sapphire Solar 0 0 39 39 39 39 39 39 39 0 New Internal Solar 270 290 290 290 290 290 290 290 310 320 New Internal Solar (Storage Paired) 10 10 10 10 10 10 10 10 10 10 New PWP‐Funded Commercial Solar PV 0 0 0 0 0 0 0 0 0 0 New PWP‐Funded Residential Solar PV 0 0 0 0 0 0 0 0 0 0 New 4‐Hour Storage 75 75 95 95 95 215 215 215 215 185 EDF Sapphire Storage 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage (Internal Solar
Paired) 5 5 5 5 5 5 5 5 5 5
New 4‐Hour Internal Storage 70 70 70 70 70 190 190 190 190 180 New 6‐Hour Storage 0 0 0 0 0 80 90 90 90 90
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New 6‐Hour Internal Storage 0 0 0 0 0 80 90 90 90 90 New 8‐Hour Storage 0 0 0 0 0 10 10 10 40 30
New 8‐Hour Internal Storage 0 0 0 0 0 10 10 10 40 30 New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New PWP‐Funded Commercial Storage 0 0 0 0 0 0 0 0 0 0 New PWP‐Funded Residential Storage 0 0 0 0 0 0 0 0 0 0 New Fuel Cells 0 0 0 0 0 110 130 130 165 220
New Internal Fuel Cells 0 0 0 0 0 110 130 130 165 220 New Biogas Conversion for Glenarm 0 0 0 0 0 0 0 0 0 0 Peak Load (MW) 335 338 341 343 346 348 362 371 380 390 PWP
adds more than its peak load in installed capacity in 2025. In the same year, the IPP coal resource retires. PWP also increases its reserve margin from 15% to 17.5%, a shift that requires an additional 9 MW.
By 2030, PWP’s installed capacity of owned and contracted resources is 859 MW, compared to peak load of 348 MW. In other words,
PWP’s installed capacity in 2030 is more than 2.5 times its peak load. In Scenario 1, 806 MW of the installed capacity located internal to PWP, which may entail land use issues beyond the scope of this document.
Scenario 1 installs 280 MW of internal, utility‐scale solar in 2025. Th is includes a 10 MW solar facility with attached storage, with a total of 300 MW by 2027 (excluding the EDF Sapphire Solar project). Scenario 1 also installs 75 MW of internal 4‐ hour storage in 2025, including 5 MW of storage attached to solar, and with 195 MW in total located internally by 2030.
Furthermore, there is 90 MW of 6‐hour and 10 MW of 8‐hour storage by 2035. An additional 110 MW of fuel cells in 2030 also supports reliability, which increases to 130 MW of fuel cells by 2035.
The summer and winter capacity positions are shown in Figure 109 , Figure 110, and Figure 111. The renewable category,
as annotated by an asterisk, and includes renewable hydrogen power fuel cells and landfill gas, as allowed by the State of California.
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Figure 109: Scenario 1: Summer Resource Adequacy
Figure 110: Scen ario 1: Winter Resource Adequacy
0 100
200
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400
500
600
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 1 Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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600
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 1 Winter RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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Figure 111: Scenario 1 Resource Adequacy Position
Summer RA Position (MW)
2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Summer Load
Requirements 380 383 394 397 400 403 406 409 425 436 447 458 Existing Resources
Qualifying Capacity 356 355 289 288 238 238 238 29 20 19 14 9 Length/(Shortage)
Before New Additions (24) (27) (105) (109) (162) (166) (169) (381) (405) (417) (432) (449) New Resources
Qualifying Capacity 0 0 104 104 155 154 153 472 499 511 536 548 Length/(Shortage) After
New Additions (24) (27) (1) (4) (7) (11) (15) 91 94 95 104 99 Winter RA Position (MW)
2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Winter Load
Requirements 185 190 192 197 198 198 208 208 226 236 243 261 Existing Resources
Qualifying Capacity 354 353 286 286 236 236 236 27 18 18 18 9 Length/(Shortage)
Before New Additions 169 163 94 89 38 38 28 (181) (208) (218) (225) (252) New Resources
Qualifying Capacity 0 0 83 84 138 135 135 454 483 494 521 535 Length/(Shortage) After
New Additions 169 163 177 173 177 174 163 273 275 276 297 284 As shown in
the above charts, there is more capacity installed in Scenario 1 than is necessary for RA. Internal fuel cells specifically help serve load under normal operating conditions.
In order to serve load in each hour with carbon‐free resources, Scenario 1 requires at least 110 MW of fuel cells in 2030 (compared to the first round of modeling results of 20 MW) and 220 MW of fuel cells in 2050 (compared to the first round
of modeling results of 120 MW), as shown in Figure 112 Fuel cells were added to the first round of modeling results because Scenario 1 allowed for unlimited internal resources. Fuel cells are dispatchable, car bon‐free resources that can operate for extended periods of time and provide qualifying capacity. Other resources could cover this gap.
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Figure 112: Scenario 1: Consecutive Model Runs
Additional Energy Needs (MWh) Additional Energy Needs (% of Total Load) Year Energy
(MWh)
With 20 MW Fuel Cells
Located Internally at
Minimum
With 110 MW of Fuel
Cells Located Internally
at Minimum
With 20 MW Fuel Cells
Located Internally at
Minimum
With 110 MW of Fuel
Cells Located Internally
at Minimum
2023 1,156,000 0 0 0.0% 0.0%
2024 1,163,000 0 0 0.0% 0.0%
2025 1,173,000 0 0 0.0% 0.0%
2026 1,186,000 0 0 0.0% 0.0%
2027 1,202,000 0 0 0.0% 0.0%
2028 1,221,000 0 0 0.0% 0.0%
2029 1,242,000 0 0 0.0% 0.0%
2030 1,266,000 10,960 0 0.9% 0.0%
2031 1,290,000 15,462 0 1.2% 0.0%
2032 1,312,000 9,663 0 0.7% 0.0%
2033 1,334,000 9,890 0 0.7% 0.0%
2034 1,353,000 9,136 0 0.7% 0.0%
2035 1,365,000 12,330 0 0.9% 0.0%
2036 1,376,000 12,814 0 0.9% 0.0%
2037 1,386,000 5,735 0 0.4% 0.0%
2038 1,396,000 7,408 0 0.5% 0.0%
2039 1,405,000 8,781 0 0.6% 0.0%
2040 1,414,000 11,833 0 0.8% 0.0%
2041 1,423,000 15,601 0 1.1% 0.0%
2042 1,431,000 21,173 0 1.5% 0.0%
2043 1,439,000 19,013 0 1.3% 0.0%
2044 1,446,000 20,397 0 1.4% 0.0%
2045 1,454,000 11,656 1 0.8% 0.0%
2046 1,462,000 7,011 1 0.5% 0.0%
2047 1,470,000 6,625 2 0.5% 0.0%
2048 1,479,000 7,532 2 0.5% 0.0%
2049 1,488,000 7,052 2 0.5% 0.0%
2050 1,497,000 560 0 0.0% 0.0%
This cali
bration is an indication that alternative ways to evaluate and design opportunities to build and operate a carbon‐ free system that can be studied. This would include exploring new resource options, identifying ways to incentivize lower load, and consider ongoing feedback from City leaders and the community. Calibration details for the carbon‐free scenarios are provided in Appen
dix ‐ Model Parameters and Additional Reliability Metrics.
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Serving load with carbon‐free resources leads to excess RA not only in the summer but also in the winter. As shown in Figure 113, peak load in the summer is approximately double the peak load in winter. As shown across all scenarios, meeting summer peaks results in excess RA during the winter.
Figure 113: Summer vs. Winter Peaks
Scenario 1 do
es not install additional geothermal resources. Since geothermal resources must be located externally in this IRP, they would have to pay the TAC.
The TAC is a CAISO charge that funds transmission infrastructure. This charge is different from congestion; congestion increases (or decreases) the value of energy from a project. Scenario 1 demonstrates a preference for resources installed internal to PWP in part because of this avoided charge. The other reason for this expressed preference is reliability.
No additional commercial or residential solar is installed in this scenario. Cost preferences will defer to utility‐scale because utility‐scale resources have a lower per‐unit cost due to economies of scale.
As shown in Figure 114, loa
d in Scenario 1 can be met with carbon‐free resources every hour by the end of 2030 (there is landfill gas that expires by the end of 2030). In this scenario, it appears as though PWP operates like an island without interactions in the CAISO markets.
Figure 114: Scenario 1: Island – Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 24% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
Large Hydroelectric 3% 3% 3% 3% 3%
Nuclear 5% 4% 4% 4% 0%
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Summer Load Summer Requirements Winter Load Winter Requirements
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Resource Type 2023 2030 2031 2040 2050
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 4% 0% 0% 0%
Geothermal 0% 18% 18% 22% 0%
Wind 1% 0% 0% 0% 6%
Solar 8% 68% 69% 63% 60%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 30% 0% 0% 0% 0%
Fuel Cells 0% 3% 6% 8% 32%
However, PWP
will still interact with the CAISO markets in the foreseeable future. See Figure 115.
Figure 115: Scenario 1: Energy Market Access – Energy Position If PWP
does interact in the CAISO markets, excess renewable energy or RA could be sold. What the excess is worth depends on what is going on in the market. Some factors driving value are shown in Figure 116. Market value is uncertain. Financial studies are explored in Financial Impacts of the IRP. There are also carbon im plications of continued market interactions.
See Section 21 of this IRP.
0 500
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Generation or Load (GWh)
Scenario 1: Energy Market Access ‐ Energy Position
Coal Natural Gas Large Hydroelectric Nuclear
Biofuel Landfill Gas Geothermal Wind
Solar Demand Response Market Purchases Fuel Cells
Load Storage Charging Market Sales
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Figure 116: CAISO Excess: What is it Worth?
Scenarios 1,
2, and 3 select new resources as though PWP operates like an island. The results of these studies have the “island” label. This is done so that carbon‐free resources meet load each hour. These results will present an upper bound of costs because excess renewable energy is not being sold.
However, given that PWP operates within CAISO, Scenarios 1, 2, and 3 are run again with access to CAISO’s energy market.
This sets a lower boundary of cost estimates, as excess renewable energy is being sold. These results may also report greater carbon emissions because PWP has access to CAISO. These results are referred to as “ener gy market access”.
Figure 117 shows how PWP would meet load if it interacts with the markets. This is different from Figure 114 because market purchases/sales and storage charging can occur at different times.
The modeling of new and installed resources for Scenario 1, was calculated based upon a variety of factors to include RA reliability requirements. The Carbon‐Free scenarios require Glenarm to be either replaced, converted or adapted with carbon‐free dispatchable alternatives such as carbon capture, green hydrogen, biofuels or other future technologies as they emerge, and prior to 2030. Until such future technologies become available at scale, the availability of the Glenarm facility will be required across all Scenarios.
Figure 117: Scenario 1: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 24% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 3% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 3% 0% 0% 0%
Geothermal 0% 14% 14% 18% 0%
Wind 1% 0% 0% 0% 5%
Solar 8% 54% 55% 51% 50%
Energy
•Time of day or year?
•Move market?
•Basis?
RECs
•Type?
•Green or clean?
Capacity
•Month?
•Location?
•Accreditation?
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Demand Response 7% 0% 0% 0% 0%
Market Purchases 30% 23% 25% 26% 42%
Fuel Cells 0% 1% 0% 0% 1%
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17.2. Scenario 2: 100% Carbon‐Free by 2030 – Maximum Limit on Internal Resources The resources shown in Figure 118 are installed under Scenario 2. By 2030, PWP has 4.3 times its peak in installed capacity.
Figure 118: Scenario 2: New Cumulative Installed Capacity 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total New Resources 300 300 393 393 403 1,418 1,493 1,505 1,542 1,550 New Wind 30 30 30 30 30 30 30 30 60 70
New Geothermal
Contracted (Calpine
Geysers and Coso) 0 0 35 35 35 35 35 46 0 0
New 0 0 0 0 0 10 10 10 30 20
New Solar
Contracted (EDF Sapphire
Solar) 0 0 39 39 39 39 39 39 39 0
Utility‐Scale Solar 180 180 180 180 180 180 240 240 220 260 Community 5 5 5 5 5 5 5 5 5 5
Commercial 0 0 0 0 0 400 400 400 400 400
Residential 0 0 0 0 0 0 0 0 0 0
New Storage
Contracted (EDF Sapphire
Storage) 0 0 20 20 20 20 20 20 20 0
New 4‐Hour Storage 85 85 85 85 95 265 280 280 290 260 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New Commercial 0 0 0 0 0 400 400 400 403 400
New Residential 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 35 35 35 75 135
Figure 119: Scenario 2: Cumulative Installed Capacity by Location 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total Installed Capacity 637 637 680 680 690 1,489 1,550 1,542 1,562 1,564 Total Existing Resources 337 337 287 287 287 70 57 37 20 14 Total New Resources 300 300 393 393 403 1,418 1,493 1,505 1,542 1,550 New Onshore Wind 30 30 30 30 30 30 30 30 60 70 New Land‐Based External Wind 20 20 20 20 20 20 20 20 50 60 New Land‐Based External Wind
(Storage Paired) 10 10 10 10 10 10 10 10 10 10 New Offshore Wind 0 0 0 0 0 0 0 0 0 0
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New Geothermal 0 0 35 35 35 45 45 56 30 20
Calpine Geysers 0 0 25 25 25 25 25 25 0 0
Coso Geothermal 0 0 10 10 10 10 10 21 0 0
New External Geothermal 0 0 0 0 0 10 10 10 30 20 New Utility‐Scale Solar PV 185 185 224 224 224 224 284 284 264 265 EDF Sapphire Solar 0 0 39 39 39 39 39 39 39 0 New External Solar 180 180 180 180 180 180 230 230 210 250 New External Solar (Storage
Paired) 0 0 0 0 0 0 10 10 10 10
New Community Solar 5 5 5 5 5 5 5 5 5 5
New PWP‐Funded Commercial
Solar PV 0 0 0 0 0 400 400 400 400 400
New Commercial Solar 0 0 0 0 0 400 400 400 400 400 New PWP‐Funded Residential Solar
PV 0 0 0 0 0 0 0 0 0 0
New 4‐Hour Storage 85 85 105 105 115 285 300 300 310 260 EDF Sapphire Storage 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage (Land‐Based
External Wind Paired) 5 5 5 5 5 5 5 5 5 5
New 4‐Hour Storage (External
Solar Paired) 0 0 0 0 0 0 5 5 5 5
New 4‐Hour External Storage 0 0 0 0 0 70 70 70 90 50 New 4‐Hour Internal Storage 80 80 80 80 90 190 200 200 190 200 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New PWP‐Funded Commercial
Storage 0 0 0 0 0 400 400 400 403 400
New PWP‐Funded Residential
Storage 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 35 35 35 75 135
New External Fuel Cells 0 0 0 0 0 30 30 30 70 130 New Internal Fuel Cells 0 0 0 0 0 5 5 5 5 5
New Biogas Conversion for
Glenarm 0 0 0 0 0 0 0 0 0 0
Peak Load (MW) 335 338 341 343 346 348 362 371 380 390 Similar to Sc
enario 1, after the first round of modeling, Scenario 2 required additional internal resources to support load.
In Scenario 2, a minimum of 400 MW of commercial storage and 400 MW of commercial solar is needed in 2030 (compared to zero) and in 2050 (compared to 3 MW of commercial storage and 8 MW of commercial solar). This ensures load is
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served in every hour with carbon‐free electricity. Additional details are included in Appendix ‐ Model Parameters and Additional Reliability Metrics.
In 2025, PWP needs 300 MW of installed capacity (in addition to the 50 MW of natural gas from IPP) to cover the 108 MW capacity retirement from IPP. PWP installs 1,015 MW of new capacity in 2030 to repla ce 212 MW of natural gas. The resulting summer capacity position is shown in Figure 120. Details are quantified in Figure 121.
Figure 120: Scenario 2: Summer Resource Adequacy
Figure 121: Scen ario 2 Resource Adequacy Position
Summer RA Position (MW)
2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Summer Load Requirements 380 383 394 397 400 403 406 409 425 436 447 458 Existing Resources Qualifying Capacity 356 355 289 288 238 238 238 29 20 19 14 9 Length/(Shortage) Before New Additions (24) (27) (105) (109) (162) (166) (169) (381) (405) (417) (432) (449) New Resources Qualifying Capacity 0 0 108 107 160 159 169 812 826 839 867 863 Length/(Shortage) After New Additions (24) (27) 3 (1) (2) (6) (0) 432 422 423 434 414 Winter RA Position (MW)
2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Winter Load Requirements 185 190 192 197 198 198 208 208 226 236 243 261 Existing Resources Qualifying Capacity 354 353 286 286 236 236 236 27 18 18 18 9 Length/(Shortage) Before New Additions 169 163 94 89 38 38 28 (181) (208) (218) (225) (252) New Resources Qualifying Capacity 0 0 97 97 151 150 160 782 797 807 840 839 Length/(Shortage) After New Additions 169 163 190 186 189 188 188 601 589 589 616 588 0 200
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2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 2 Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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Because utility‐scale resources are limited in Scenario 2, Scenario 2 leverages distributed resources.
In the 2023 IRP, the qualifying capacity of distributed resources is defaulted to the qualifying capacity of their utility‐scale counterparts. The qualifying capacity of distributed resources depends on how they are registered with CAISO. These resources could be classified as demand response resources and collectively regis tered as a Proxy Demand Response resource. CAISO’s tariff sets the rules for how this works. Distributed resources could also be classified as Distributed Energy Resource Aggregations. As of early 2022, these rules remained to be developed between CAISO and entities like PWP. Per FERC's response to CAISO's FERC Order
2222 compliance filing:
"Finally, we find AEE/SFP’s request that the Commission direct CAISO to take various actions to help enable Distributed Energy Resource Aggregations to provide resource adequacy to be outside of the scope of Order No. 2222. Order No. 2222 requires each RTO/ISO to establish ta riff provisions that allow distributed energy resource aggregations to participate directly in RTO/ISO markets, which the Commission defined as “the capacity, energy, and ancillary services markets operated by the RTOs and ISOs.”101 The California resource adequacy program is not an RTO/ISO‐administered capacity market and, therefore, is outside the scope of the Commission’s directives in Order No. 2222. However, we acknowledge CAISO’s commitmen
t to continue working with the CPUC and other Local Regulatory Authorities to develop methods for allowing Distributed Energy Resource Aggregations to provide resource adequacy capacity.”151
If distributed resources were not registered as supply side resources, they could reduce the load (and reserve) obligations PWP must cover. There is uncertainty regarding distributed resource accreditation and operation.
Scenario 2 meets its energy obligations with 100% carbon‐free energy if it operates like an island (Figure 122). Figure 123 shows how PWP meets is energy obligations if marke
t access is allowed.
The modeling of new and installed resources for Scenario 2, was calculated based upon a variety of factors to include RA reliability requirements. The Carbon‐Free Scenarios require Glenarm to be either replaced, converted or adapted with carbon‐free dispatchable alternatives suc h as carbon capture, green hydrogen, biofuels or other future technologies as they emerge, and prior to 2030. Until such future technologies become available at scale, the availability of the Glenarm facility will be required across all Scenarios.
151 http://www.caiso.com/Documents/Jun17‐2022‐OrderPartialAccepting‐RequestingComplianceFiling‐FERCOrderNo2222‐ER21‐ 2455.pdf
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Figure 122: Scenario 2: Island – Resources That Load, Storage Charging, and Market Sales are Served by Resource Type 2023 2030 2031 2040 2050
Coal 24% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 3% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 3% 0% 0% 0%
Geothermal 0% 16% 16% 20% 8%
Wind 1% 5% 5% 5% 11%
Solar 8% 72% 75% 71% 75%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 30% 0% 0% 0% 0%
Fuel Cells 0% 0% 0% 0% 4%
Figure 123: Scenario 2: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served by Resource Type 2023 2030 2031 2040 2050
Coal 24% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 2% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 2% 0% 0% 0%
Geothermal 0% 14% 14% 17% 6%
Wind 1% 4% 4% 4% 9%
Solar 8% 57% 60% 59% 58%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 30% 19% 18% 17% 25%
Fuel Cells 0% 0% 0% 0% 0%
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The energy position, assuming energy market access, is shown in Figure 124.
Figure 124: Scenario 2: Energy Market Access – Energy Position
17.3. Scenario 3: 100% Carbon‐Free by 2030 (Maximum Limit on Internal Resources and Doubled Distributed Resources)
Scenario 3 evaluates a focused effort into distributed resource deployment on behalf of PWP. Some distributed solar and storage is embedded in the load forecast. This scenario adds that same amount as resources, so the total amount of distributed solar and storage growth each year is double what would have occurred normally in that year. The resources are split
between residential and commercial installations.
The installed capacity of resources in Scenario 3 is shown in Figure 125. In 2025, 300 MW are added. In 2030, 859 MW are added to replace 212 MW of natural gas and 5 MW of wind.
PWP has 3.9 times its peak in installed capacity by 2030. 0 500
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Scenario 2: Energy Market Access –E n e r g y Position
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Biofuel Landfill Gas Geothermal Wind
Solar Demand Response Market Purchases Fuel Cells
Load Storage Charging Market Sales
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Figure 125: Scen
ario 3: New Cumulative Installed Capacity
2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total New Resources 300 306 399 410 415 1,274 1,358 1,376 1,466 1,424 New Wind 60 60 60 60 60 60 80 80 70 70
New Geothermal
Contracted (Calpine Geysers
and Coso) 0 0 35 35 35 35 35 46 0 0
New 0 0 0 0 0 10 20 20 20 10
New Solar
Contracted (EDF Sapphire
Solar) 0 0 39 39 39 39 39 39 39 0
Utility‐Scale Solar 100 100 100 100 100 100 120 120 180 200 Community 5 5 5 5 5 5 5 5 5 5
Commercial 31 31 31 31 31 350 357 359 375 350 Residential 17 21 21 22 22 23 38 39 57 57
New Storage
Contracted (EDF Sapphire
Storage) 0 0 20 20 20 20 20 20 20 0
New 4‐Hour Storage 85 85 85 95 95 245 245 245 260 200 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 50
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New Commercial 1 2 2 2 6 350 360 360 363 350
New Residential 1 2 2 2 3 3 5 8 12 17
New Fuel Cells 0 0 0 0 0 35 35 35 65 115
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Figure 126: Scenario 3: Cumulative Installed Capacity by Location 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total Installed Capacity 637 643 686 697 702 1,345 1,415 1,413 1,486 1,438 Total Existing Resources 337 337 287 287 287 70 57 37 20 14 Total New Resources 300 306 399 410 415 1,274 1,358 1,376 1,466 1,424 New Onshore Wind 60 60 60 60 60 60 80 80 70 70 New Land‐Based External Wind 60 60 60 60 60 60 80 80 60 60 New Land‐Based External Wind
(Storage Paired) 0 0 0 0 0 0 0 0 10 10
New Offshore Wind 0 0 0 0 0 0 0 0 0 0
New Geothermal 0 0 35 35 35 45 55 66 20 10
Calpine Geysers 0 0 25 25 25 25 25 25 0 0
Coso Geothermal 0 0 10 10 10 10 10 21 0 0
New External Geothermal 0 0 0 0 0 10 20 20 20 10 New Utility‐Scale Solar PV 105 105 144 144 144 144 164 164 224 205 EDF Sapphire Solar 0 0 39 39 39 39 39 39 39 0 New External Solar 90 90 90 90 90 90 110 110 170 190 New External Solar (Storage
Paired) 10 10 10 10 10 10 10 10 10 10
New Community Solar 5 5 5 5 5 5 5 5 5 5
New PWP‐Funded Commercial Solar
PV 31 31 31 31 31 350 357 359 375 350
New Commercial Solar 31 31 31 31 31 350 357 359 375 350 New PWP‐Funded Residential Solar
PV 17 21 21 22 22 23 38 39 57 57
New Residential Solar 17 21 21 22 22 23 38 39 57 57 New 4‐Hour Storage 85 85 105 115 115 265 265 265 280 200 EDF Sapphire Storage 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage (Land‐Based
External Wind Paired) 0 0 0 0 0 0 0 0 5 5
New 4‐Hour Storage (External
Solar Paired) 5 5 5 5 5 5 5 5 5 5
New 4‐Hour External Storage 0 0 0 0 0 40 40 40 70 60 New 4‐Hour Internal Storage 80 80 80 90 90 200 200 200 180 130 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 50
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New PWP‐Funded Commercial
Storage 1 2 2 2 6 350 360 360 363 350
New PWP‐Funded Residential
Storage 1 2 2 2 3 3 5 8 12 17
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New 2‐Hour Residential Storage 1 2 2 2 3 3 5 8 12 17 New Fuel Cells 0 0 0 0 0 35 35 35 65 115
New Biogas Conversion for Glenarm 0 0 0 0 0 0 0 0 0 0 Peak Load (MW) 335 338 341 343 346 348 362 371 380 390 The table sho
ws 942 MW of installed internal capacity beyond that attributable to normal projected DER growth included in the load forecast. In 2030, PWP’s peak is 348 MW. The resulting summer capacity position is shown in Figure 127.
Figure 127: Scenario 3: Summer Resource Adequacy
Overall
RA is shown in Figure 128.
Figure 128: Scenario 3: Resource Adequacy Position
MW 2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Summer Load Requirements 380 383 394 397 400 403 406 409 425 436 447 458 Existing Resources Qualifying
Capacity 356 355 289 288 238 238 238 237 229 214 209 204 Length/(Shortage) Before New
Additions (24) (27) (105) (109) (162) (166) (169) (172) (196) (222) (237) (254) New Resources Qualifying Capacity 0 0 115 115 171 221 221 221 222 233 237 251 Length/(Shortage) After New
Additions (24) (27) 10 6 9 55 52 49 26 11 (0) (3) Winter Load Requirements 185 190 192 197 198 198 208 208 226 236 243 261 0 200
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1,000
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 3 Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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MW 2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Existing Resources Qualifying
Capacity 354 353 286 286 236 236 236 236 227 213 213 204 Length/(Shortage) Before New
Additions 169 163 94 89 38 38 28 28 1 (23) (30) (57) New Resources Qualifying Capacity 0 0 131 131 186 242 242 242 245 256 216 237 Length/(Shortage) After New
Additions 169 163 225 220 224 281 271 270 246 233 186 180 A
minimum of 350 MW of commercial storage and of commercial solar (compared to 14 MW of commercial storage and 31 MW of commercial solar) is needed in 2030 and in 2050 (compared to 31 MW of commercial storage and 67 MW of commercial solar) to cover additional energy needs.
Scenario 3 can meet its load , sales, and storage charging with zero‐carbon resources. Figure 129 and Figure 130 show how PWP meets load as an island and with energy market access, respectively.
The modeling of new and installed resources for Scenario 3, was calculated based upon a variety of factors to include RA reliability requirements. The Carbon‐Free Scen
arios require Glenarm to be either replaced, converted or adapted with carbon‐free dispatchable alternatives such as carbon capture, green hydrogen, biofuels or other future technologies as they emerge, or prior to 2030. Until such future technologies become available at scale, the availability of the Glenarm facility will be required ac
ross all Scenarios.
Figure 129: Scenario 3: Island – Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 25% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 3% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 3% 0% 0% 0%
Geothermal 0% 18% 22% 24% 4%
Wind 1% 10% 10% 12% 12%
Solar 8% 62% 62% 58% 73%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 29% 0% 0% 0% 0%
Fuel Cells 0% 0% 0% 0% 9%
Figure 130: Scenario 3: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 25% 0% 0% 0% 0%
Natural Gas 16% 0% 0% 0% 0%
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Resource Type 2023 2030 2031 2040 2050
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 3% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 3% 0% 0% 0%
Geothermal 0% 15% 18% 20% 3%
Wind 1% 8% 8% 10% 9%
Solar 8% 48% 49% 48% 55%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 29% 22% 21% 17% 31%
Fuel Cells 0% 0% 0% 0% 0%
The resulting energy
position is shown in Figure 131.
Figure 131: Scenario 3: Energy Market Access – Energy Position
17.4. Scenario 4: Reference Case (SB 1020)
Scenario 4 meets and exceeds state environmental requirements and serves as the basis for comparison for the other scenarios. Installed capacity under this scenario is shown in Figure 132. By 2030, installed capacity is 2.2 times PWP’s peak load.
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Load Storage Charging Market Sales
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Figure 132: Scenario 4: New Cumulative Installed Capacity 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total New Resources 335 335 428 478 478 478 488 500 698 729 New Wind 250 250 250 250 250 250 260 260 20 70 New Geothermal
Contracted (Calpine Geysers and
Coso) 0 0 35 35 35 35 35 46 0 0
New 0 0 0 0 0 0 0 0 0 0
New Solar
Contracted (EDF Sapphire Solar) 0 0 39 39 39 39 39 39 39 0 Utility‐Scale Solar 0 0 0 0 0 0 0 0 430 440
Community 5 5 5 5 5 5 5 5 5 5
Commercial 0 0 0 0 0 0 0 0 0 0
Residential 0 0 0 0 0 0 0 0 0 0
New Storage
Contracted (EDF Sapphire Storage) 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage 80 80 80 130 130 130 130 130 180 210 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New Commercial 0 0 0 0 0 0 0 0 4 4
New Residential 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 0 0 0 0 0
Figure 133: Scenario 4: Cumulative Installed Capacity by Location 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total Installed Capacity 672 672 715 765 765 760 757 735 915 941 Total Existing Resources 337 337 287 287 287 282 269 235 218 212 Total New Resources 335 335 428 478 478 478 488 500 698 729 New Onshore Wind 250 250 250 250 250 250 260 260 20 70 New Offshore Wind 0 0 0 0 0 0 0 0 0 0
New Geothermal 0 0 35 35 35 35 35 46 0 0
Calpine Geysers 0 0 25 25 25 25 25 25 0 0
Coso Geothermal 0 0 10 10 10 10 10 21 0 0
New Utility‐Scale Solar PV 5 5 44 44 44 44 44 44 474 445 EDF Sapphire Solar 0 0 39 39 39 39 39 39 39 0 New External Solar 0 0 0 0 0 0 0 0 430 430
New External Solar (Storage Paired) 0 0 0 0 0 0 0 0 0 10 New Community Solar 5 5 5 5 5 5 5 5 5 5
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New PWP‐Funded Commercial Solar PV 0 0 0 0 0 0 0 0 0 0 New PWP‐Funded Residential Solar PV 0 0 0 0 0 0 0 0 0 0 New 4‐Hour Storage 80 80 100 150 150 150 150 150 200 210 EDF Sapphire Storage 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage (Land‐Based
External Wind Paired) 0 0 0 0 0 0 0 0 0 5
New 4‐Hour Storage (External Solar
Paired) 0 0 0 0 0 0 0 0 0 5
New 4‐Hour Internal Storage 80 80 80 130 130 130 130 130 180 200 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New PWP‐Funded Commercial Storage 0 0 0 0 0 0 0 0 4 4 New PWP‐Funded Residential Storage 0 0 0 0 0 0 0 0 0 0 New Fuel Cells 0 0 0 0 0 0 0 0 0 0
New Biogas Conversion for Glenarm 0 0 0 0 0 0 0 0 0 0 Peak Load (MW) 335 338 341 343 346 348 362 371 380 390 In
2025, PWP brings its peak installed capacity online. This is the first year that resources can be installed in the model.
Installed capacity totaling 108 MW from IPP coal expires June 30, 2025, and is replaced by 50 MW of natural gas from that facility. Of the 335 MW of new capacity brought on line in 2025, 250 MW is wind, 80 MW is storage, and 5 MW is community solar. Due to the RA contribution of renewables being smaller compared to fossil fuels, more installed capacity is needed to replace the coal. In Scenario 4, this is apparent with wind, which does not replace coal at a 1:1 ratio.
PWP has proactively executed cont
racts for the 93 MW brought online in 2027. The 35 MW of geothermal resources is planned from Coso Geothermal and Calpine Geysers Geothermal, and 39 MW of solar and 20 MW of storage come from the EDF Sapphire Solar project. These resources, in addition to the resources installed in 2025, help cover the loss of 50 MW of installed capacity from the IPP natural gas facility on June 30, 2027. By 2028, there is another 50 MW of new storage installed to assist with the natural gas contract expiration. Then, through the 2030s, re tirements and additions are smaller (+/‐ 15 MW). The resulting capacity position is shown in Figure 134 and Figure 135. 201
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Figure 134: Scenario 4: Summer Resource Adequacy
Figure 135: Scen ario 4: Resource Adequacy Position
MW 2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Summer Load Requirements 380 383 394 397 400 403 406 409 425 436 447 458 Existing Resources Qualifying Capacity 356 355 289 288 238 238 238 237 229 214 209 204 Length/(Shortage) Before New Additions (24) (27) (105) (109) (162) (166) (169) (172) (196) (222) (237) (254) New Resources Qualifying Capacity 0 0 115 115 171 221 221 221 222 233 237 251 Length/(Shortage) After New Additions (24) (27) 10 6 9 55 52 49 26 11 (0) (3) Winter Load Requirements 185 190 192 197 198 198 208 208 226 236 243 261 Existing Resources Qualifying Capacity 354 353 286 286 236 236 236 236 227 213 213 204 Length/(Shortage) Before New Additions 169 163 94 89 38 38 28 28 1 (23) (30) (57) New Resources Qualifying Capacity 0 0 131 131 186 242 242 242 245 256 216 237 Length/(Shortage) After New Additions 169 163 225 220 224 281 271 270 246 233 186 180 In
this IRP, PWP assumes that storage receives 100% of nameplate capacity in qualifying capacity. This is the current accreditation for 4‐hour storage in 2022. As shown in Figure 136, wind receives 14% of its nameplate capacity in qualifying capacity in August. In 2025, solar receives 10% of its nameplate capacity in qualifyin g capacity in August. This IRP forecasts the qualifying capacity for solar to decrease to 8% by 2031. 0 100
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2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 4: Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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Figure 136: Scenario 4: Summer Qualifying Capacity
There is signi
ficant uncertainty regarding resources’ future qualifying capacity. For example, if the qualifying capacity of storage declines, PWP would need to install or purchase additional capacity. Markets across the country, including California, are considering the long‐term qualifying capacity of storage and how it may decline for shorter duration resources. 152
Figure 137 and Figure 138 show the resources that PWP’s load, storage, and market sales are met by under Scenario 4.
Figure 137: Scenario 4: Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 24% 0% 0% 0% 0%
Natural Gas 16% 10% 10% 5% 0%
Large Hydroelectric 3% 2% 2% 2% 2%
Nuclear 5% 3% 3% 3% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 5% 3% 0% 0% 0%
Geothermal 0% 14% 14% 19% 0%
Wind 1% 40% 40% 43% 10%
152 https://www.cpuc.ca.gov/‐/media/cpuc‐website/divisions/energy‐division/documents/demand‐side‐management/acc‐models‐ latest‐version/2022‐acc‐capacity‐avoided‐cost‐v1b.xlsx
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Fossil Large Hydro & Nuclear & Landfill Wind Geothermal Solar Storage Demand Response
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Resource Type 2023 2030 2031 2040 2050
Solar 8% 11% 12% 8% 59%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 30% 16% 18% 19% 28%
Fuel Cells 0% 0% 0% 0% 0%
Figure 138: Scenario 4: Energy Position
Scenario 4 el
ects to install more wind rather than other combustion resources, such as biofuel or green hydrogen, to meet renewable requirements. Forecasts for hydrogen and biofuel prices were created from publicly available resources.
Incentives embedded in new legislation, or local circumstances, may change the economics of these alternative fuels.
Figure 139 includes an estimate of costs from hydrogen assuming a 6,469 Btu/kWh heat rate and from bio fuel assuming a 10,500 Btu/kWh heat rate.
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Figure 139: Wind and Solar vs. Alternative Fuels
17.5. Scenario 5: Reference Case Plus Social Cost of Carbon Scenario 5 incorporates an additional carbon tax on fossil‐fuel, landfill, and market resources. The resulting installed capacity is shown in Figure 140. In 2025, PWP brings 610 MW of wind online, as well as 30 MW of storage and 5 MW of community solar. By 2030, PWP has 3 times its peak capacity in installed capacity.
Figure 140: Scenario 5: Installed Capacity
2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total New Resources 645 655 748 748 748 768 768 800 697 728 New Wind 610 610 610 610 610 610 610 610 0 40 New Geothermal
Contracted (Calpine Geysers
and Coso) 0 0 35 35 35 35 35 46 0 0
New 0 0 0 0 0 0 0 0 0 0
New Solar
Contracted (EDF Sapphire
Solar) 0 0 39 39 39 39 39 39 39 0
Utility‐Scale Solar 0 0 0 0 0 0 0 0 440 470
Community 5 5 5 5 5 5 5 5 5 5
Commercial 0 0 0 0 0 0 0 0 2 2
Residential 0 0 0 0 0 0 0 0 0 0
New Storage
Contracted (EDF Sapphire
Storage) 0 0 20 20 20 20 20 20 20 0
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$Nominal/MWh
Wind and Solar vs. Alternative Fuels
Wind ($/MWh) Solar ($/MWh) Hydrogen ($/MWh) Biofuel
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New 4‐Hour Storage 30 40 40 40 40 60 60 80 190 210 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New Commercial 0 0 0 0 0 0 0 0 1 1
New Residential 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 0 0 0 0 0
Figure 141: Scenario 5: Cumulative Installed Capacity by Location 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Total Installed Capacity 982 992 1,035 1,035 1,035 1,050 1,037 1,035 914 940 Total New Resources 645 655 748 748 748 768 768 800 697 728 New Onshore Wind 610 610 610 610 610 610 610 610 0 40 New Land‐Based External
Wind 610 610 610 610 610 610 610 610 0 30
New Offshore Wind 0 0 0 0 0 0 0 0 0 0
New Geothermal 0 0 35 35 35 35 35 46 0 0
Calpine Geysers 0 0 25 25 25 25 25 25 0 0
Coso Geothermal 0 0 10 10 10 10 10 21 0 0
New Utility‐Scale Solar PV 5 5 44 44 44 44 44 44 484 475 EDF Sapphire Solar 0 0 39 39 39 39 39 39 39 0 New External Solar 0 0 0 0 0 0 0 0 440 460
New External Solar (Storage
Paired) 0 0 0 0 0 0 0 0 0 10
New Community Solar 5 5 5 5 5 5 5 5 5 5
New PWP‐Funded Commercial
Solar PV 0 0 0 0 0 0 0 0 2 2
New PWP‐Funded Residential
Solar PV 0 0 0 0 0 0 0 0 0 0
New 4‐Hour Storage 30 40 60 60 60 80 80 100 210 210 EDF Sapphire Storage 0 0 20 20 20 20 20 20 20 0 New 4‐Hour Storage (Land‐
Based External Wind Paired) 0 0 0 0 0 0 0 0 0 5 New 4‐Hour Storage
(External Solar Paired) 0 0 0 0 0 0 0 0 0 5
New 4‐Hour External
Storage 0 0 0 0 0 0 0 0 10 10
New 4‐Hour Internal Storage 30 40 40 40 40 60 60 80 180 190
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 New 6‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 8‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New 10‐Hour Storage 0 0 0 0 0 0 0 0 0 0
New PWP‐Funded Commercial
Storage 0 0 0 0 0 0 0 0 1 1
New PWP‐Funded Residential
Storage 0 0 0 0 0 0 0 0 0 0
New Fuel Cells 0 0 0 0 0 0 0 0 0 0
New Biogas Conversion for
Glenarm 0 0 0 0 0 0 0 0 0 0
Peak Load (MW) 335 338 341 343 346 348 362 371 380 390 The i
nstalled capacity under Scenario 5 creates the RA position in Figure 142 and Figure 143.
Figure 142: Scenario 5: Summer Resource Adequacy
Figure 143: Scen ario 5: Resource Adequacy Position
MW 2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Summer Load
Requirements 380 383 394 397 400 403 406 409 425 436 447 458 Existing Resources
Qualifying Capacity 356 355 289 288 238 238 238 237 229 214 209 204 0 100
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300
400
500
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Qualifying Capacity (MW)
Scenario 5 Summer RA Position
Existing Coal Existing Gas Existing Clean
Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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MW 2023 2024 2025 2026 2027 2028 2029 2030 2035 2040 2045 2050 Length/(Shortage)
Before New
Additions
(24) (27) (105) (109) (162) (166) (169) (172) (196) (222) (237) (254) New Resources
Qualifying Capacity 0 0 115 125 182 182 182 202 201 231 242 245 Length/(Shortage)
After New
Additions
(24) (27) 9 16 20 16 13 30 6 9 5 (9)
Winter Load
Requirements 185 190 192 197 198 198 208 208 226 236 243 261 Existing Resources
Qualifying Capacity 354 353 286 286 236 236 236 236 227 213 213 204 Length/(Shortage)
Before New
Additions
169 163 94 89 38 38 28 28 1 (23) (30) (57)
New Resources
Qualifying Capacity 0 0 155 165 220 237 237 257 257 288 218 227 Length/(Shortage)
After New
Additions
169 163 249 254 258 275 265 285 257 265 189 171 Adding the so
cial cost of carbon (SCC) to carbon‐emitting resources incentivizes other renewable resources. The SCC is so high that, in some instances, the model would opt for a $2,000/MWh penalty charge rather than turning on the Glenarm units (Figure 144).
Figure 144: Average Resource Costs with Carbon Tax (SCC) Average Cost of Energy ($Nominal/MWh) New PPAs
($Nominal/MWh)
Year GT ‐ 1 GT ‐ 2 GT ‐ 3 GT ‐ 4 GT ‐ 5 IPP Coal IPP Gas Magnolia Wind Solar 2023 $674.83 $707.78 $385.66 $429.20 $266.28
2024 $527.20 $574.66 $400.00 $434.82 $229.25
2025 $578.77 $450.61 $442.78 $208.48 $234.86 $58.00 $33.00 2026 $583.22 $215.28 $240.01 $52.52 $33.00
2027 $535.31 $705.54 $222.72 $250.34 $47.04 $33.00 2028 $503.21 $485.49 $403.27 $408.34 $359.50 $257.91 $41.55 $30.98 2029 $689.04 $538.77 $398.22 $265.40 $36.07 $28.95 2030 $538.41 $515.76 $408.17 $418.79 $377.20 $272.21 $30.59 $26.93 2031 $530.91 $578.07 $461.82 $400.50 $279.28 $25.11 $24.90 2032 $288.07 $19.63 $22.88
2033 $295.63 $19.59 $23.26
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Average Cost of Energy ($Nominal/MWh) New PPAs
($Nominal/MWh)
Year GT ‐ 1 GT ‐ 2 GT ‐ 3 GT ‐ 4 GT ‐ 5 IPP Coal IPP Gas Magnolia Wind Solar 2034 $303.66 $25.55 $25.61
2035 $311.27 $31.80 $28.32
2036 $320.62 $44.65 $33.14
Wind
generation helps produce the energy position shown in Figure 146 and Figure 147.
Figure 145: Scen
ario 5: Resources That Load, Storage Charging, and Market Sales are Served By Resource Type 2023 2030 2031 2040 2050
Coal 10% 0% 0% 0% 0%
Natural Gas 4% 2% 2% 0% 0%
Large Hydroelectric 4% 2% 2% 2% 2%
Nuclear 6% 2% 2% 2% 0%
Biofuel 0% 0% 0% 0% 0%
Landfill Gas 6% 2% 0% 0% 0%
Geothermal 0% 10% 10% 13% 0%
Wind 1% 69% 70% 70% 6%
Solar 8% 8% 8% 6% 62%
Demand Response 7% 0% 0% 0% 0%
Market Purchases 53% 5% 6% 7% 30%
Fuel Cells 0% 0% 0% 0% 0%
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Figure 146: Scenario 5: Energy Position
Scenario 5 pr
oduces less carbon than Scenario 4 under the Cap‐and‐Trade Program, which, in this IRP, includes emissions from Glenarm, IPP coal, IPP natural gas, and Magnolia (Figure 147).
Figure 147: Total Carbon Emissions Under Cap‐and‐Trade (Scenarios 1 through 5) Another me
thod of quantifying carbon would be to credit or debit market sales or purchases from PWP’s portfolio assuming the carbon intensity of CAISO. PWP would have to be cautious of avoiding any claims to renewable 0 500
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3,000
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Generation or Load (GWh)
Scenario 5: Energy Position
Coal Natural Gas Large Hydroelectric Nuclear
Biofuel Landfill Gas Geothermal Wind
Solar Demand Response Market Purchases Fuel Cells
Load Storage Charging Market Sales
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Short Tons of Carbon
Carbon Emissions Under Cap‐and‐Trade
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Carbon Cap
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characteristics if the energy is sold. As shown in Figure 148, by that calculation, because of PWP’s sales, PWP could offset emissions elsewhere on the grid.
Figure 148: Total Portfolio Carbon Emissions (Netting Market Purchases and Sales)
17.6. Scenario 6: Emerging Technologies Study Scenario
Scenario 6 investigates at what value emerging technologies could provide to PWP. It attempts to answer the following questions:
If PWP reduces energy load and peak power demand over all hours by 1%, 2%, or 3%, how much would ratepayers save?
If PWP reduces the top 0.5%, 1%, and 1.5% of peak hours in a ye ar by 30 MW, how much would ratepayers save? The savings translate into a cost that represents a financial viability point for an emerging technology that could accomplish either of the above two goals. Note that the load forecast already includes resources that are cost effective, such as energy efficie
ncy and demand response.
17.6.1. Scenario 6: Energy Efficiency Proxy
Scenario 2 has the greatest costs because it is the most constrained. Emerging technology would provide the most value under Scenario 2. For the energy efficiency proxy, Scenario 2 is re‐run with 1%, 2%, and 3% less load across all hours. New resources can be selected to meet load.
The difference in cost between these model runs can show where a point of financial viability is for this type of resource.
For another 1% of energy efficiency in addition to what is in the load forecast, under Scenario 2, a financial viability point 0 100,000
200,000
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Short Tons of Carbon
Total Carbon Emissions Includes Market Purchases/Sales
Scenario 1 (Island) Scenario 1 (Energy Market Access)
Scenario 2 (Island) Scenario 2 (Energy Market Access)
Scenario 3 (Island) Scenario 3 (Energy Market Access)
Scenario 4 Scenario 5
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is around $259/MWh (in $2030). For the next 1%, a point of financial viability is $127/MWh (in 2030 dollars), and it is not as cost effective afterward in Scenario 2, as shown in Figure 149. Figure 149 also contains the average costs for the entirety of the 1%, 2%, or 3% avoided.
Figure 149: Scenario 6: Energy Efficiency Proxy – Results 20‐Year $/MWh Avoided
(2030 $, 2030‐2049) Reduce 1% of Load Reduce 2% of Load Reduce 3% of Load Incremental Cost $259 $127 ($140)
Average Cost $259 $193 $82
17.6.2. Scenario 6: Demand Response Proxy
The same type of study was run for a demand response type of resource. The model is run three times, with load reduced by 30 MW across 0.5%, 1%, or 1.5% of peak hours. The model may build new resources each time. The IRP calculates the difference in cost between each model run. This is how much PWP could be w illing to pay for a resource that can reduce peaks across a given number of hours in a year.
From 2030 through 2049, in 2030 dollars, a financial viability point is $12.29/kW‐month for 1.5% of peaks, and $10.61/kW‐ month for 1.0% of peaks. Reducing only 0.5% of pe aks each year does not avoid a new resource build during this time under this model run. See Figure 150.
Figure 150: Scenario 6: Demand Response Proxy: Results
Average Cost 0.5% of Peaks 1.0% of Peaks 1.5% of Peaks 20‐Year $/kW‐Month Avoided (2030 $,2030‐2049) (2.79) 10.61 12.29 The Sc
enario 6 is run under one set of normal operating conditions under one load forecast. Additional model runs for other scenarios or other conditions may provide a greater range of avoided costs.
17.7. Scenario Comparisons
Across scenarios, the amount of installed capacity by 2031 (the first full year of hourly carbon‐free energy) ranges from 750 MW (Scenario 4) to 1,509 MW (Scenario 3). This is equivalent to two to four times PWP’s peak load. See Figure 151 and Figure 152. By 2031, PWP needs between 80 MW (Scenarios 4 and 5) and 690 MW (Scenario 2) of solar. By 2031, PWP needs between 0 MW (Scenario 1) and 610 MW (Scenario 5) of wind. By 203 1, PWP needs between 80 MW (Scenario 5)
and 685 MW (Scenario 2) of batteries.
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Figure 151: Installed Capacity of Scenarios
Figure 152: Installe d Capacity of Scenarios by Type in 2031 PWP
will have to bring online more than its peak in installed capacity. The installed capacity is higher than peak load for two reasons: qualifying capacity and reliability.
‐
200
400
600
800
1,000
1,200
1,400
1,600
1,800
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Installed Capacity (MW)
Installed Capacity (MW)
Peak Load Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 ‐
500
1,000
1,500
2,000
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Installed Capacity (MW)
Installed Capacity By 2031
Gas/Oil:Combined Cycle Gas/Oil:Combustion Turbine Fuel Cells Hydro Nuclear Geothermal
Solar Wind Battery
Peak (2031)
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RA answers the question: “What reliability contribution does that installed capacity bring PWP?” The contribution of solar has declined over time. It is anticipated that this trend will continue. The qualifying capacity of the installed resources in 2031 is shown in Figure 153.
Figure 153: Qualifying Capacity of Scenarios in 2031
PWP
assumes 100% qualifying capacity for storage (of any chosen duration) in this IRP. It is anticipated that the capacity accreditation of storage will decline over time in markets across the U.S. If this occurs, PWP would need additional installed energy and/or storage capacity.
The other reason PWP requires more installed capacity than peak is reliability . Internal resources are required to help serve load reliably given that PWP is a transmission‐constrained system. See Figure 154 for a breakdown of resources installed internal to PWP. Additional transmission interconnections would reduce the need for internal resources. PWP is constrained in terms of how many utility‐scale resources it can install inside its service territory because the city is mostly developed and densely built.
Figure 154: Internal vs. External Installed Capacity in 2031 Installed Capacity in 2031 (MW)
External (CAISO) Internal (Pasadena) Total
Scenario 1 153 701 854
Scenario 2 508 1,001 1,509
Scenario 3 408 939 1,347
Scenario 4 417 333 750
Scenario 5 777 263 1,040
0 200
400
600
800
1,000
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Qualifying Capacity (MW)
Qualifying Capacity in 2031
Gas/Oil:Combined Cycle Gas/Oil:Combustion Turbine Fuel Cells Hydro Nuclear Geothermal
Solar Wind Battery
PWP Load PWP Requirements
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For internal capacity, there are varying amounts of distributed versus utility‐scale resources depending on the Scenario (Figure 155).
Figure 155: Installed Capacity Distributed Resources per Scenario – in Addition to Load Forecast New 2‐Hour
Residential
Storage (MW)
New 4‐Hour Commercial Storage (MW) New Commercial Solar (MW) New
Residential
Solar (MW)
Year Scenario
3 2 3 4 5 2 3 5 3
2025 1 1 31 17
2026 2 2 31 21
2027 2 2 31 21
2028 2 2 31 22
2029 3 6 31 22
2030 3 400 350 400 350 23
2031 3 400 350 400 350 25
2032 4 400 360 400 350 26
2033 4 400 360 400 357 28
2034 5 400 360 400 357 31
2035 5 400 360 400 357 38
2036 6 400 360 400 357 38
2037 6 400 360 400 357 38
2038 7 400 360 400 357 38
2039 8 400 360 400 357 38
2040 8 400 360 400 359 39
2041 9 400 360 400 360 40
2042 10 400 364 400 375 46
2043 11 403 364 2 400 375 46
2044 11 403 364 4 1 400 375 46
2045 12 403 363 4 1 400 375 2 57
2046 13 403 362 4 1 400 375 2 53
2047 14 403 362 4 1 408 375 2 53
2048 15 403 362 4 1 408 375 2 52
2049 17 403 358 4 1 408 381 2 58
2050 17 400 350 4 1 400 350 2 57
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By 2031, PWP is generating between 100% and 200% of its energy needs (Figure 156). Solar is generating between 17% and 113% of PWP’s energy annual needs and wind between 0%and 141% because PWP has excess capacity. This would result in overgeneration, but PWP could sell the excess generation in certain hours.
Figure 156: Net Generation of Scenarios in 2031
This gen
eration translates into wind and solar generation in excess of PWP’s California regulatory renewable requirements. By 2031, PWP is producing two (Scenario 4) to three (Scenario 5) times its 2031 RPS requirements. PWP can exceed its requirement to have 60% of its load covered by renewable energy by two or three times. See Figure 157. 0 50
100
150
200
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Percent of PWP"s Load (%)
Net Generation in 2031
Gas/Oil:Combined Cycle Gas/Oil:Combustion Turbine Fuel Cells Hydro Nuclear Geothermal
Solar Wind Battery
Annual Load (2031)
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Figure 157: Renewable Compliance Across Scenarios
This renewable resource r
equirement met not only through wind and solar but also through geothermal and renewable hydrogen fuel cells. By 2031, PWP produces between 28% (Scenario 4) and 189% (Scenario 2) of its RPS requirements in solar and between 0% (Scenario 1) and 235% (Scenario 5) of its RPS requirements in wind. See Figure 158.
Figure 158: Renewable Compliance across Scenarios by Type in 2031 0 500
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Renewable Resources (GWh)
Annual CA Renewable Requirements
RPS Requirements Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 ‐
50 100
150
200
250
300
350
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Percent of PWP's RPS Requirements (%)
Annual CA RPS Requirements (2031)
Fuel Cell Geothermal Solar Wind RPS Requirements
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Renewable resources are eligible as zero‐carbon resources to meet California’s annual State environmental requirements.
All scenarios meet California requirements to serve energy with renewable and zero‐carbon resources by 2045. By 2045, in the carbon‐free scenarios, PWP has excess renewable and zero‐carbon energy (Figure 159).
Figure 159: Annual Zero‐Carbon Requirements by Scenarios Those
requirements are met by resources like solar (Figure 160).
Figure 160: Zero‐Carbon across Scenarios by Type in 2045 0 500
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(GWh)
Annual CA Zero‐Carbon Requirements
Renewable & Zero‐Carbon Requirements Scenario 1
Scenario 2 Scenario 3
Scenario 4 Scenario 5
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50 100
150
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5
Percent of PWP's RPS Requirements (%)
Annual CA Renewable & Zero‐Carbon Requirements (2045)
Fuel Cell Hydro
Nuclear Geothermal
Solar Wind
Renewable & Zero‐Carbon Requirements
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By the end of 2030, PWP can operate a 100% carbon‐free hourly system under the carbon‐free scenarios (Figure 161).
PWP has landfill gas that contractually expires toward the end of 2030, so compliance occurs by 2031. Under Scenario 4 PWP can operate above a 60% hourly carbon‐free system, and under Scen ario 5 above 80%.
Figure 161: Carbon‐Free across Scenarios
Year Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2023 17% 17% 16% 17% 21%
2024 16% 16% 16% 16% 20%
2025 34% 36% 39% 40% 64%
2026 32% 34% 37% 38% 62%
2027 49% 51% 52% 55% 76%
2028 53% 55% 56% 59% 80%
2029 54% 55% 57% 60% 80%
2030 96% 97% 97% 60% 78%
2031 100% 100% 100% 62% 81%
The informa
tion in Figure 161 represents single model runs conducted under normal operating conditions. Sensitivity analyses regarding load, power prices, fuel prices, cost of new resources, and others could provide additional information on capacity and generation required to meet goals.
17.8. Sensitivity 1: Heat Wave
A significant stressor like a heat wave causes reliability concerns. These reliability concerns appear as additional energy needs. These needs are spread across a certain number of hours, and those hours occur across a certain number of days.
The IRP model can also identify the maximum hourly demand for additional resource needs. This could be thought of as a potential resource size to help alleviate the reliability concerns.
Scenarios 4 and 5 maximize the Goodrich connection, so additional resources would be needed. For Scenarios 1, 2, and 3, additional utility‐scale resources could be located outside PWP and imported over the Goodrich interconnection or located internal to PWP. The last two columns in
Figure 162 show the amount of resources that would have to be installed internally and externally.
Figure 162: Heat Wave Sensitivity Results
Scenario
Additional
Energy
Required
(MWh)
Additional
Energy
Required
(Hours)
Additional
Energy
Required
(Days)
Largest
Hourly
Demand
for
Additional
Energy
(MW)
Additional
Resources That
Have To Be Located
Internally
Additional Resources
That Could Be Located
Externally
Scenario 1 1,991 32 9 248 40 MWh total with a
29 MW maximum
1,951 MWh total with a
219 MW maximum
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Scenario
Additional
Energy
Required
(MWh)
Additional
Energy
Required
(Hours)
Additional
Energy
Required
(Days)
Largest
Hourly
Demand
for
Additional
Energy
(MW)
Additional
Resources That
Have To Be Located
Internally
Additional Resources
That Could Be Located
Externally
Scenario 2 8,252 188 24 327 1,755 MWh total
with a 240 MW
maximum
6,497 MWh total with an
87 MW maximum
Scenario 3 22,959 370 30 406 3,041 MWh total
with a 241 MW
maximum
19,918 MWh total with a
165 MW maximum
Scenario 4 6 8 6 1 6 MWh total with a
1 MW maximum
None (Goodrich is fully
importing)
Scenario 5 133 23 12 36 133 MWh total with
a 36 MW maximum
None (Goodrich is fully
importing)
This is the
total
additional
energy
need in the
month.
This is how
many
unique
hours this
energy
need
shows up.
This is how
many
unique
days this
energy
need
shows up.
This is the
maximum
need in an
hour.
The scenarios have
the reliability needs
indicated in the first
four columns.
If PWP allows the
maximum capacity
over Goodrich, this
amount would have
to be located
internally, and the
remainder would
have to be located
externally.
For Scenarios 1, 2, and 3,
some resources could be
located external to PWP.
There is still excess
capacity over the
Goodrich connection.
There
are 32 hours over nine days in Scenario 1 when there are additional energy needs. Overall, there is a total of 1,991 MWh of additional energy needs in this month under the Heat Wave. The hour with the largest energy need is Hour Ending (HE) 18 on September 11, 2030, when an extra 248 MW is needed . See Figure 163.
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Figure 163: Scenario 1: Heat Wave
However, PWP
could import another 219 MW across Goodrich in that hour. In this case, PWP would need an additional 29 MW located internally. See Figure 164. When Goodrich increases from 280 MW to 336 MW, this capacity could be external.
Figure 164: Scenario 1: Heat Wave with Goodrich Maximized 0 100
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300
400
500
600
1 2 3 4 5 6 7 8 9 1 01 11 21 31 41 51 61 71 81 92 02 12 22 32 4 MW
Hour Ending
Scenario 1: Heat Wave – September 11, 2030
External Resources New 4‐Hr Internal Storage
New 4‐Hr Storage (Internal Solar Paired) New 6‐Hr Internal Storage New 8‐Hr Internal Storage New Internal Fuel Cells
New Internal Solar New Internal Solar (Storage Paired)
Windsor Reservoir Solar Demand (MW)
0 200
400
600
800
123456789 1 0 1 1 1 2 1 3 1 4 1 5 1 6 1 7 1 8 1 9 2 0 2 1 2 2 2 3 2 4 MW
Hour Ending
Scenario 1: Heat Wave – September 11, 2030
External Resources New 4‐Hr Internal Storage
New 4‐Hr Storage (Internal Solar Paired) New 6‐Hr Internal Storage New 8‐Hr Internal Storage New Internal Fuel Cells
New Internal Solar New Internal Solar (Storage Paired)
Windsor Reservoir Solar Potential Imports
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In Scenario 2, even if Goodrich imports additional carbon‐free power up to its maximum potential, PWP could need an additional 240 MW in a given hour to help serve load (Figure 165).
Figure 165: Scenario 2: Heat Wave with Goodrich Maximized Based on the top 10 hours of additional energy nee
ds in Scenario 3, there are some high‐risk days and high‐risk hours. The high‐risk hours in this forecast are HE 16 though HE 20. See Figure 166.
Figure 166: Scenario 3: Heat Wave Top 10 Additional Energy Need Hours (September 2030) Scenario 3: Heat Wave – Top 10 Additional Energy Need Hours (September 2030) Day Interval
(HE)
Demand
(MW)
External
Resources
(MW)
Distributed
Storage
(MW)
Distributed
Solar (MW)
Utility
Solar
New 4‐
Hour
Internal
Storage
New
Internal
Fuel Cells
Additional
Energy
Needs?
Potential
Imports?
Remaining
Needs?
6 19 394 96 0 0 0 0 5 293 184 109
10 19 387 97 0 0 0 0 5 285 183 102
11 16 565 248 0 139 5 0 5 169 32 137
11 17 562 187 0 63 3 0 5 305 93 212
11 18 539 115 0 12 1 0 5 406 165 241
11 19 482 95 0 0 0 0 5 382 185 197
11 20 428 98 0 0 0 0 5 325 182 143
21 17 454 161 0 52 2 0 5 234 119 115
21 18 422 102 0 6 0 0 5 309 178 131
21 19 386 97 0 0 0 0 5 283 183 101
(100)
0 100
200
300
400
500
600
MW
Month_Day_Hour Ending
Scenario 2: Heat Wave – September 10 and 11, 2030
External Resources New 4‐Hr Commerical Storage New 4‐Hr Internal Storage New Commercial Solar New Community Solar New Internal Fuel Cells Windsor Reservoir Solar Potential Imports Demand (MW)
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Scenario 3 shows more additional energy needs under a heat wave than Scenario 2 because of differences in amounts of installed capacity (Figure 167). In 2030, Scenario 2 has 1,001 MW installed internally, while Scenario 3 has 937 MW (64 MW less than Scenario 2). Furthermore, the breakdown of technology types and amounts is different between the tw o scenarios. Different technology mixes interact differently during a heat wave.
Figure 167: Internal Installed Capacity in 2030 for Scenario 2 and 3 Resource Scenario 2 (MW) Scenario 3 (MW)
New 2‐Hour Residential Storage
3 New 4‐Hour Commercial Storage 400 350
New 4‐Hour Internal Storage 190 200
New Commercial Solar 400 350
New Community Solar 5 5
New Internal Fuel Cells 5 5
New Residential Solar
23 Windsor Reservoir Solar 1 1
Total 1,001 937
Scenario 4 als
o shows additional energy needs; however, there is availability on the Glenarm units. See Figure 168. In the model, paying a $2,000/MWh penalty is preferable to paying to start the unit given high fuel costs.
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Figure 168: Scenario 4: Heat Wave
Day HE Demand
(MW)
External
Resources
(MW)
Market
Purchases
(MW)
Glenarm
(GT) (MW)
Other
Internal
(MW)
Additional
Energy
Needs?
(MW)
GT Spare
Capacity?
(MW)
1 17 478 128 151 153 44 0 45
8 15 439 132 147 153 5 1 45
10 15 449 150 130 153 16 0 45
14 15 459 127 153 153 26 1 45
14 17 457 115 165 153 24 0 45
21 17 454 108 170 111 62 1 45
21 18 422 86 192 111 30 1 45
28 16 437 147 132 111 45 1 45
Scenario 5 shows
additional energy needs ranging from 1 MW to 36 MW across six consecutive hours. Scenario 5 includes 60 MW of installed internal storage by 2030 compared to 130 MW in Scenario 4.
The following are the three primary findings from the heat wave sensitivity test:
There are additional energ y needs.
There is a need for additional internal resources or increased transmission capacity. There are certain hours of interest (HE 15 through HE 18).
17.9. Sensitivity 2: Goodrich Transfer Contingency
PWP is a transmission‐constrained system. Goodrich is the one gateway that is currently operating constantly. This sensitivity test evaluates what happens if the capacity at Goodrich is reduced by one‐half.
As shown in Figure 169, under a single week of highest demand under normal operating conditions outside the Goodrich contingency, all
scenarios can operate reliably.
Figure 169: Goodrich Transfer Contingency Results
Week of September 8 – 14, 2030 2030 Full Year
Scenario
Additional
Energy
Required
(MWh)
Additional
Energy
Required
(Hours)
Additional
Energy
Required
(Days)
Additional
Energy
Required
(MWh)
Additional
Energy
Required
(Hours)
Additional
Energy
Required
(Days)
1 0 0 0 0 0 0
2 0 0 0 0 0 0
3 0 0 0 0 0 0
4 0 0 0 2 7 7
5 0 0 0 25 18 28
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The carbon‐
free scenarios have sufficient additional resources installed internally to support reliability. The total amounts of internal resources in 2030 are shown in Figure 170.
Figure 170: Internal Installed Capacity in 2030 Across Scenarios Installed Capacity (MW) Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Resources in CAISO 163 488 408 427 787
Resources In PWP Service Territory 696 1001 937 333 263 The peak week is not always the week of greatest
reliability concern. There can also be reliability needs in winter (February in this IRP). Compared to Scenarios 1‐3, Scenarios 4 and 5 do not have the same quantity of internal resources installed, so they may require additional resources to help serve energy needs in Fe bruary. The monthly needs for Scenarios 4 and 5 are shown in Figure 171.
Figure 171: Scenario 4 and 5: Additional Energy Needs Under Heat Wave Scenario 4 Scenario 5
Month
(2030)
Additional
Energy Needs
(Hours)
Additional
Energy Needs
(Days)
Additional
Energy Needs
(MWh)
Additional
Energy Needs
(Hours)
Additional
Energy Needs
(Days)
Additional
Energy Needs
(MWh)
January 1 1 0 4 3 1
February 2 2 1 8 4 19
March 1 1 0 2 2 1
April 0 0 0 0 0 0
May 0 0 0 5 4 6
June 2 2 1 1 1 0
July 1 1 0 1 1 0
August 0 0 0 2 2 0
September 0 0 0 0 0 0
October 0 0 0 0 0 0
November 0 0 0 2 1 2
December 0 0 0 0 0 0
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18. Battery Storage
18.1. Storage in the IRP
Battery storage is commercially available peaking capacity. Multiple storage technologies currently exist or have had promising breakthroughs, but lithium‐ion remains the most implemented type of battery storage type.153 PWP included battery storage as a selectable resource in its IRP.
Storage applications are defined by a set of cost and operating parameters, including the following:
Cost
Costs are commonly shown in $/kWh, which can be converted to $/kW by multiplying by the duration of the storage project. For PWP’s IRP, all battery costs are assumed to be added via PPAs, so capital and fixed O&M costs were levelized into a flat $/kW‐month rate depending on the year of installation. This represents a fixed capacity or demand charge that will be paid regardless of the operation of the battery. Size
Battery sizes are determin
ed by the installed capacity or inverter size (MW). In the IRP, this value represents how much the battery can inject onto the grid in any given hour. The other size component is the energy (MWh), which is dependent on the installed capacity and the duration. For exam ple, a 4‐hour duration battery will be represented by 10 MW/40 MWh. This battery project at full charge can inject 10 MW for four hours before being depleted.
PWP modeled different duration types for utility‐scale storage in the IRP: 4‐hour, 6‐hour, 8‐hour, and 10‐hour. Th
e cost for these durations are scaled linearly based on NREL estimates. Commercial and residential energy storage were also considered as candidate resources for the IRP using cost scalars for early‐year installations and blending into the NREL commercial and residential storage costs by the mid‐2030s.
Round‐trip efficiency
Round‐trip
efficiency is the measure of how much energy that goes into the battery can be utilized. PWP modeled all battery storage types with an 85% round‐trip efficiency in the model. Cycle limitations
Battery resources were assumed to have an equivalent cycle capability of one cycle per day or 365 cy cles per year. This was entered as a capacity factor limit in the model. For example, a 4‐hour battery storage project has an upper limit of a 16.67% capacity factor (4 hours/24 hours). Augmentation/degradation
Similar to the lithium‐ion battery in a cell phone, util ity‐scale batteries can lose energy over time with use.
Developers and utilities have several ways to account for this:
153 https://www.eia.gov/todayinenergy/detail.php?id=41813
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Assume the battery project will just degrade and that is factored into the cost and forecasted operating capability.
Oversize the project so that the desired size is guaranteed throughout the life of the project. Include regular or projected augmentation, or cell replacement, throughout the life of the project. Consistent with NREL, PWP
assumed that the PPA includes battery replacement costs such that the energy of the battery stays the same.154
Figure 172: Illustration of Degradation Strategies for Battery Storage
18.2. Storage: Over‐Generation and Evening Ramps
Storage may help store renewable energy when it is not needed and allow for later use. Storage could help meet evening ramps (perhaps with stored solar energy), which may reduce or replace the need for natural gas generation or market purchases.
In the carbon‐free scenarios, natural gas was retired, and storage helped replace its capaci ty. See Figure 173 for installed storage capacity in 2031. The IRP optimized new resource selection, which in most cases, included storage. Storage helped meet reliability and environmental obligations in a cost‐effective manner given scenario assumptions. The IRP itself is a quantitative analysis that helps evaluate the cost effectiveness of multi‐hour storage compared to other resources.
154 https://atb.nrel.gov/electricity/2022/utility‐scale_battery_storage#LJT3875D 1 2 3 4 5 6 7 8 9 1 01 11 21 31 41 5
Years
MWh
Desired
Oversizing
Augmentation
No Augmentation
Illustrative Only
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Figure 173: Installe
d Storage Capacity in 2031
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Natural Gas/Oil: Combined Cycle 80 80
Natural Gas/Oil: Combustion Turbine 132 132
Natural Gas/Oil: Fuel Cell 115 35 35
New External Fuel Cells 30 30
New Internal Fuel Cells 115 5 5
Battery 305 685 618 150 80
EDF Sapphire Storage 20 20 20 20 20
New 2‐Hour Residential Storage 3
New 4‐Hour Commercial Storage 400 350
New 4‐Hour External Storage 70 40
New 4‐Hour Internal Storage 190 190 200 130 60
New 4‐Hour Storage (External Solar Paired) 5
New 4‐Hr Storage (Internal Solar Paired) 5
New 4‐Hr Storage (Land‐Based External
Wind Paired) 5
New 6‐Hr Internal Storage 80
New 8‐Hr Internal Storage 10
RA requirements reflect, in part, th
e ability of resources to meet peak‐hour capacity needs. Storage helps meet PWP’s RA requirements.
As shown in Figure 174, PWP is producing more energy than needed on an annual basis. Excess could be sold or stored.
Batteries are a net consumer of energy due to roundtrip losses. PWP will seek to monitor grid conditio ns, learn from others, and gain its own experience to understand how excess renewable generation and storage can interact to serve PWP and California customers.
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Figure 174: Net Renewable Generation vs. Load in 2031
How
much renewable and zero‐carbon generation exceeds hourly load? Because PWP is a part of CAISO, allocating what resources go toward load versus elsewhere is a contractual exercise. Post optimization, the amount of California‐eligible renewable and zero‐carbon energy in excess of hourly load obligations was calculated and summed over the year.
Resources were stacked in the order gi
ven in Figure 220. See Figure 175 for results.
Figure 175: California Eligible Renewable and Carbon‐Free Resources That Do Not Go Toward Hourly (500)
‐
500
1,000
1,500
2,000
2,500
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5L o a d Net Generation (GWh)
Annual Net Renewable Generation vs. Load in 2031
Geothermal Solar PV Wind Battery Load
‐
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
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2034
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2036
2037
2038
2039
2040
2041
2042
2043
2044
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2046
2047
2048
2049
2050
Generation or Load (MWh)
California Eligible Renewable and Zero‐Carbon
That Do Not Go Toward Hourly Load
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Annual Load
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The IRP selected the amount of storage necessary to meet obligations, but PWP is still generating excess. See Figure 176.
Figure 176: PWP is Selling or Curtailing X% of Load in Renewable/Zero‐Carbon Resources PWP is Selling or Curtailing X% of its
Load in Renewable/Zero‐Carbon
Resources
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2031 56% 98% 79% 44% 110%
2035 50% 94% 79% 38% 98%
2040 47% 90% 75% 32% 92%
2045 37% 75% 69% 56% 56%
2050 30% 70% 57% 52% 55%
PWP
will continue to investigate the potential and roles of storage, and how storage could leverage renewable potential.
18.3. Addressing Net Demand in Peak Hours
According to the CEC 2018 guidelines, “PUC Section 9621 requires the governing board of a local POU to consider how existing renewable generation, grid operational efficiencies, energy storage, and distributed generation resources, including energy efficiency, will meet energy and reliability needs during the hours of net‐peak demand (net of demand met by variable renewable energy resources.” The IRP model optimi zes to cover obligations, which includes meeting needs
during hours of net peak demand through energy and RA obligations.
PWP can consider net peak demand or hourly peak demand minus variable renewable generation. Evaluating September 2031, anywhere from 39% to 65% of hours in the month have negative net peak demand (in other wor ds, hours when wind, solar, and geothermal energy are greater than hourly load). See Figure 177. Figure 178 shows a graphical representation.
Figure 177: Percent of Hours with Negative Net Load in September 2031 Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Percent of Hours with Negative
Net Load in September 2031 39% 42% 40% 41% 65%
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Figure 178: Hourly Load versus Net Load Across Scenarios for Three Days in September 2031 Exc
ess renewable generation that leads to negative net peak demand represents risks and opportunities to the system.
PWP may consider further study and investigation of this topic.
19. Financial Impacts
The following sub‐sections outline some of the financial implications of the different scenarios.
19.1. Present Value Revenue Requirements
PVRRs are a concept used in IRPs to explain future anticipated costs. PVRR is the current total worth of the expected future revenue requirements associated with a scenario. This IRP analyzes some, but not all, of the cost components involved in PWP’s rate structure. Costs in the IRP can be broken into the categories shown in Figure 179.
Figure 179: Components of PVRR
20‐Year PVRR (2030 $ in Millions, 2030‐2049)
Expenses ($ in Millions)
Energy Purchases Cost of hourly energy purchases from CAISO Fuel Cost of natural gas for Glenarm, Magnolia, and IPP Variable O&M Variable costs for IPP, Glenarm, and Magnolia; PPA costs; TAC Fixed O&M EDF Sapphire Storage capacity charge
Start Cost Startup costs for Glenarm
Emissions REC purchases
Cost of New Resources PPA costs for new resources
Total Revenue Requirement ‐ Grossed Up Sum of all expenses ‐600
‐400
‐200
0 200
400
9/10/2
031
9/11/2
031
9/12/2
031
MW
September 10‐12, 2031
Hourly Load versus Net Load Across Scenarios
Load Scenario 1 Net Load Scenario 2 Net Load
Scenario 3 Net Load Scenario 4 Net Load Scenario 5 Net Load
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20‐Year PVRR (2030 $ in Millions, 2030‐2049)
Less: Revenues from Energy and Capacity Sum of all expenses minus revenue Energy Revenue ($ in Millions) Revenue from hourly energy sales to CAISO Incremental Revenue Requirement Expenses – energy revenue The PVRR values for each scenario, und
er mid, low, and high technology costs, are shown in Figure 180 through Figure 184. Scenarios 1, 2, and 3 have costs associated with an island system and with energy market access.
Figure 180: Scenario 1: PVRR
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2023
2024
2025
2026
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2029
2030
2031
2032
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2048
2049
2050
PVRR ($ in Nominal Millions)
Scenario 1: Technology Costs
Scenario 1: Cost Range
Scenario 1: Cost Range (Energy Market Access)
Scenario 1: Mid Costs Scenario 1: Mid Costs (Energy Market Access)
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Figure 181: Scenario 2: PVRR
Figure 182: Scen ario 3: PVRR
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2023
2024
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2026
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2050
PVRR ($ in Nominal Millions)
Scenario 2: Technology Costs
Scenario 2: Cost Range
Scenario 2: Cost Range (Energy Market Access)
Scenario 2: Mid Costs Scenario 2: Mid Costs (Energy Market Access) $0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2023
2024
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PVRR ($ in Nominal Millions)
Scenario 3: Technology Costs
Scenario 3: Cost Range
Scenario 3: Cost Range (Energy Market Access)
Scenario 3: Mid Costs Scenario 3: Mid Costs (Energy Market Access)
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Figure 183: Scenario 4: PVRR
Figure 184: Scen ario 5: PVRR
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2023
2024
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2050
PVRR ($ in Nominal Millions)
Scenario 4: Technology Costs
Scenario 4: Cost Range Scenario 4: Mid Costs
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2023
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PVRR ($ in Nominal Millions)
Scenario 5: Technology Costs
Scenario 5: Cost Range Scenario 5: Mid Costs
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Error! Not a valid bookmark self‐reference.5 shows the breakdown of costs by type across scenarios.
Figure 185: PVRR By Category Across Scenarios (Mid Costs) 20‐Year PVRR (2030 $ in Millions, 2030‐2049)
Scenario
1: Energy
Market
Access
Scenario
1: Island
Scenario 2:
Energy
Market
Access
Scenario
2: Island
Scenario 3:
Energy
Market
Access
Scenario
3: Island Scenario 4 Scenario 5
Expenses
($ in Millions) $2,611 $2,644 $3,555 $3,289 $3,404 $3,162 $2,080 $2,871 Energy
Purchases $324 $0 $263 $0 $267 $0 $235 $193
Fuel $5 $362 $1 $16 $1 $36 $76 $11
Variable O&M $545 $545 $833 $815 $781 $773 $845 $1,087 Fixed O&M $30 $30 $30 $30 $30 $30 $30 $30
Start Cost $0 $0 $0 $0 $0 $0 $6 $0
Emissions $1 $1 $1 $1 $1 $1 $1 $72
Book
Depreciation $1,706 $1,706 $2,426 $2,426 $2,323 $2,323 $887 $1,476 Total Revenue
Requirement ‐
Grossed Up
$2,611 $2,644 $3,555 $3,289 $3,404 $3,162 $2,080 $2,871 Less: Revenues
from Energy and
Capacity
Energy
Revenue
($ in Millions)
$300 $0 $694 $0 $621 $0 $275 $473
Incremental
Revenue
Requirement
$2,311 $2,644 $2,861 $3,289 $2,782 $3,162 $1,806 $2,398 Overall, the PV
RR values (in 2030 dollars) are shown in Figure 186.
Figure 186: PVRRs for Mid, High, Low Costs of New Resources 20‐Year PVRR
(2030 $ in Millions, 2030‐2049) Low Costs Mid Costs High Costs Scenario 1 (Island System) 2,247 2,644 2,982
Scenario 1 (Energy Market Access) 1,915 2,311 2,650
Scenario 2 (Island System) 2,614 3,289 3,855
Scenario 2 (Energy Market Access) 2,186 2,861 3,427
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20‐Year PVRR
(2030 $ in Millions, 2030‐2049) Low Costs Mid Costs High Costs Scenario 3 (Island System) 2,512 3,162 3,722
Scenario 3 (Energy Market Access) 2,132 2,782 3,342
Scenario 4 1,596 1,806 2,001
Scenario 5 2,084 2,398 2,725
Figure 187
shows the percent increase in costs compared to Scenario 4. Costs increase in the carbon‐free scenarios between 28% and 82%.
Figure 187: Percent Costs are Higher in 20 Years Compared to Scenario 4 (Reference Costs) Percent Costs are Higher in 20 Years Compared to Scenario 4 (Reference Costs) 20‐Year PVRR
(2030 $ in Millions, 2030‐2049) Energy Market Access Island System Scenario 1 28% 46%
Scenario 2 58% 82%
Scenario 3 54% 75%
Scenario 4 0%
Scenario 5 33%
These PVRR costs
can be translated into cents per kWh of load served. This can show the costs incurred on top of Scenario 4. See Figure 188.
Figure 188: 2030 $/kWh Costs in Addition to Scenario 4
Scenario 1 Scenario 2 Scenario 3 Scenario 5
Energy
Market
Access
Island
Energy
Market
Access
Island
Energy
Market
Access
Island
2030, $/kWh, 2030 ‐ 2049 $2.77 $4.62 $5.80 $8.21 $5.37 $7.51 $3.33
19.2. Scenario 3 and Distributed Resources
Expected distributed resource deployment is in the load forecast. Those resources are customer‐financed resources given business as usual. Resources installed in addition to PWP’s load forecast are resources that would require additional incentives from various potential sources. Scenario 3 forced some distributed resources online.
The costs of the resources forced online in Scenario 3 are shown in Figure 189. From 2030 thr ough 2049, there is almost $1.4 billion (in 2030 dollars) in costs for these resources.
Figure 189: Costs of Forced Distributed Energy Resources in Scenario 3 Distributed Resource Costs
Forced Online Residential Solar Commercial
Solar
Residential
Storage
Commercial
Storage
10‐Year PVRR (2023 $ in Millions, 2023‐2032) $82.97 $62.37 $21.11 $8.36
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Distributed Resource Costs
Forced Online Residential Solar Commercial
Solar
Residential
Storage
Commercial
Storage
20‐Year PVRR (2023 $ in Millions, 2023‐2042) $292.34 $247.51 $120.87 $47.23 28‐Year PVRR (2023 $ in Millions, 2023‐2050) $418.32 $406.03 $214.01 $105.34 20‐year PVRR (2030 $ in Millions, 2030‐2049) $495.33 $479.19 $263.51 $126.42 The costs of the additional distrib
uted resources represent 17% to 23% of the scenario costs in 2030, and 51% to 54% of the scenario costs by 2050.
19.3. Scenario 5 and the Carbon Tax
Scenario 5 assumes that resources that contain carbon (fossil, landfill gas, and CAISO market purchases) are charged a carbon tax based on the EPA’s social cost of carbon under a 1.5% discount rate. See Scenario 5: Reference Case + Social Cost of Carbon (SB 1020 + SCC). Scenario 5 optimized new resource builds and resource operations under a carbon tax.
PWP, as a participant of CA
ISO, needs to follow the rules and regulations of CAISO’s tariff; there are rules and regulations regarding how resources can bid into the CAISO markets. These rules exist to prevent manipulation or misuse of market power. PWP would need to furt her investigate how its carbon preferences would not fall afoul of the CAISO tariff.
Furthermore, CAISO prices carbon through the following three mechanisms at minimum:
Renewable portfolio standard under SB 100
Renewable and zero‐carbon requirements under SB 1020
Cap‐and‐trade regulations under CARB
Any additional pricing of carbon into PWP’s rates may be consid ered as non‐cost based. Therefore, that could be a
tax, which, under Proposition 26, must be approved by a two‐thirds vote of the residents of Pasadena.
Revenue from a carbon tax may be returned to consumers or used to support other activities. The carbon tax, and resulting scenario costs, are given in Figure 190.
Figure 190: Costs of Carbon Tax in Scenario 5
Nominal Millions Carbon Tax Scenario 5 Scenario 5 (Carbon Tax Returned) 2023 $64.2 $172.0 $107.8
2024 $70.7 $160.7 $90.0
2025 $47.5 $147.5 $100.0
2026 $38.4 $148.2 $109.8
2027 $25.3 $167.3 $142.0
2028 $12.5 $155.9 $143.4
2029 $10.9 $177.7 $166.8
2030 $12.6 $171.7 $159.2
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Nominal Millions Carbon Tax Scenario 5 Scenario 5 (Carbon Tax Returned) 2031 $10.7 $180.5 $169.8
2032 $12.1 $195.4 $183.3
2033 $12.3 $197.0 $184.6
2034 $12.6 $201.3 $188.7
2035 $11.5 $198.7 $187.2
2036 $4.6 $196.1 $191.5
2037 $0.9 $194.7 $193.8
2038 $0.9 $195.6 $194.6
2039 $1.0 $196.2 $195.1
2040 $0.9 $196.5 $195.6
2041 $0.8 $196.9 $196.1
2042 $0.9 $179.5 $178.6
2043 $0.8 $181.5 $180.7
2044 $0.5 $184.7 $184.3
2045 $0.0 $139.7 $139.7
2046 $0.0 $142.3 $142.3
2047 $0.0 $145.5 $145.5
2048 $0.0 $147.3 $147.3
2049 $0.0 $150.1 $150.1
2050 $0.0 $151.6 $151.6
Resulti
ng comparisons are in Figure 191.
Figure 191: Present Value Revenue Requirement if Carbon Tax Returned 20‐Year PVRR
(2030 $ in Millions, 2030‐2049) Mid Costs
Scenario 1 (Island System) $2,644
Scenario 1 (Energy Market Access) $2,311
Scenario 2 (Island System) $3,289
Scenario 2 (Energy Market Access) $2,861
Scenario 3 (Island System) $3,162
Scenario 3 (Energy Market Access) $2,782
Scenario 4 $1,806
Scenario 5 $2,398
Scenario 5 (Carbon Tax Returned) $2,326
19.4. Scenarios and Cap‐and‐Trade Interactions
The 2023 IRP designed the scenarios to remain under PWP’s allocated allowances. PWP could sell excess allowances. Using low, mid, and high estimates of GHG allowances from the 2022 IEPR shown in
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Figure 192, scenarios could generate additional savings shown in Figure 193.
Figure 192: Carbon Allowance Sale Prices
Figure 193: PVR R with Cap‐and‐Trade Allowance Sales
20‐Year PVRR
(2030 $ in Millions, 2030‐2049) No Return Return Price Floor
Return Mid
Case
Return High
Case
Scenario 1 (Energy Market Access) 2,311 2,218 2,076 2,021 Scenario 1 (Island System) 2,644 2,551 2,408 2,353
Scenario 2 (Energy Market Access) 2,861 2,768 2,625 2,570 Scenario 2 (Island System) 3,289 3,196 3,053 2,998
Scenario 3 (Energy Market Access) 2,782 2,689 2,547 2,492 Scenario 3 (Island System) 3,162 3,069 2,927 2,872
Scenario 4 1,806 1,754 1,679 1,649
Scenario 5 2,398 2,309 2,172 2,119
Overall, Scen
ario 4 remains the lowest cost. If excess credits under the Cap‐and‐Trade Program are sold at the price floor, cost increases over Scenario 4 range from 26% to 82%. If estimates of allowances are high, other scenarios become 23% to 82% more costly than Scenario 4.
20. Retail Rates
PWP power resources staff worked closely with PWP finance staff to consider the impact the IRP will have on retail rates for PWP customers. Model outputs provided by the consultant, coupled with additional analysis by PWP staff, $0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
2023
2024
2025
2026
2027
2028
2029
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2031
2032
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2049
2050
Carbon Price (Nominal$/metric ton CO2e)
2022 IEPR (CED 2022 Update) GHG Allowance Price Projections Price Floor Mid Price Scenario High Price Scenario
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were used to develop the cost and rate analysis for the rate components impacted by the IRP. The IRP will increase the rates for customers. As a non‐profit, publicly owned utility, rates sustain and reinvest in the operations.
The overall financial impact of the IRP will be fully evaluated after adoption and incorp orated into a cost‐of‐ service study expected to begin in 2024.
PWP’s retail rates primarily consist of the following components:
Customer Charge ‐ A flat fee to recover costs associated with billing metering, customer service and PWP’s call center.
Distribution Charge – A volumetric charge to recover the cost of delivering electricity from substations to customers. It includes operation and ma
intenance, capital investment and debt service.
Grid Access Charge – A flat fee to recover fixed costs associated with the electric grid. Transmission Services Charge (“TSC”) ‐ A volumetric charge to recover costs of delivering electricity from generating plants to sub‐stations.
Public
Benefit Charge (“PBC”) – A volumetric charge to provide funding for incentive and rebate programs for energy efficiency, local solar programs, demand side management and low‐income assistance. Energy Services Charge (“ESC”) – A volumetric charge to recover the costs to procure and generate electric resources.
Prior to July 2014, the D
istribution and Customer Charge (“D&C”) was a combined charge. The charge was separated into two components beginning in July 2014. A Grid Access Charge was implemented in July 2019. The following figures include these three charges combined to illustrate rate trends.
Figure 194 depicts PWP’s historical and budge
ted rates from 2003 through 2024. Figure 195 shows the breakdown of the rates by percent of total.
Figure 194: PWP Historical and Budgeted Retail Rates (Nominal Dollars per kWh)
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
Nominal $/kWh
D&C Energy TSC PBC
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The primary focus of the IRP is the energy component of the rate (the ESC) and, particularly, a subset of that energy component that relates to energy production and market purchases and sales. Historically, the costs considered in the IRP represent about 57% of the total costs in the energy rate.
Figure 195: PWP Retail Rate Components as Percent of Total Figure
196 shows the various rate components that are included and excluded in the IRP modeling.
Figure 196: Costs Included and Excluded from IRP Modeling Included Excluded
Fuel costs
Variable costs
PPA costs
TAC costs
Costs of new resources
Congestion costs experienced by resources
Other CAISO fees
Costs from distribution programs
Distribution cost increases
Transmission cost increases
Costs from PWP people operations
There is a significant amount of uncertainty in all rate projections, and a multitude of factors could change the outcome, including, but not limited to, the following for the ESC:
Procurement costs
PPA and/or resource acquisition costs associated with new resources added in each portfolio could be higher or lowe
r than projected.
23% 27% 28% 27% 26% 31% 32% 29% 30% 31% 31% 30% 31% 32% 34% 36% 38% 38% 40% 40% 40% 40% 34% 68% 58% 58% 59% 60%
60% 59% 61% 60% 59% 60% 61% 59% 59% 57% 53% 50% 50% 50% 49% 49% 49% 55% 7% 11% 11% 11% 11% 7% 6% 6% 6% 6% 6% 6% 6% 5% 5% 6% 7% 8% 7% 7% 7% 8% 7% 2% 4% 3% 2% 3% 2% 2% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 4% 3% 4% 3% 3% 0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
D&C Energy TSC PBC
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Congestion costs
If PWP needs to add resources outside its internal load area, PWP could be exposed to congestion costs if PPAs are settled as the busbar of a particular resource. These costs are not included in the IRP.
Load forecasts
Changing residential and commercial load patterns could emerge, which would change the resulting resource mix neede
d.
For the other components of retail rates, that were not studied in this report:
Distribution and transmission costs
Additional costs associated with distribution and transmission beyond the rate of inflation are not considered in this analysis.
In 2022, the Distribution Master Plan was adopted, with investme nts totaling $821 Million identified as needed by 2042.
These nominal figures do not include the fact that 2021 costs were used, which was prior to increasing costs due to inflation and supply chain issues. The Distribution Master Plan was also prior to this IRP which include s investments that were not considered or are requiring more projects to be implemented on a tighter timeline. The Distribution Master Plan was completed prior to the IRP, so feasibility of implementation was not considered nor the impact on the pricing of construction. One such factor is that the IRP calls for extra capital investments required for electrical distrib ution system support of battery storage infrastructure.
CAISO, as the primary infrastructure planner for the state has a proactive approach to meet California’s long‐term clean energy goals that calls for investments of $7.3 Billion in the approved 2022‐2023 Investment Plan155. These investments will have an additive impact to customer rates. Other costs
Other operating cost to be considered are the finance, administration, information technology and customer service components of expenses.
Cost of future debt financing and credit risk.
The tables below show estimated impacts and are intended to provide a sense of the financial implica tions to the utility and customers based on each scenario. The amounts shown are provided for illustrative purposes only and represent “just in time” rates that would be needed for the different “moderate” and “high” costs in order to recover costs. Varying rate structures, capital financing plans, and rate offsets (such as grant funding) will all be actively
pursued but cannot confidently be projected and as such are not included in this analysis. 155 https://www.caiso.com/Documents/caiso‐2022‐2023‐transmission‐plan‐approved.pdf
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The Energy Charge projections are based on single‐family residential customers on an annual basis. The projections assume usage of 500 kWh per month (6,000 kWh annually). Rates will accelerate during the first seven years of the plan due to cost recovery associated with the compressed timeline and will remain elevated after 2030 to support the portfolio costs.
Figure 197: Annual Bill Impacts for Single‐Family Residential Customers (Moderate Cost Estimates) Scenario
Power
Supply
NPV
Moderate
Cost ($ in
Billions)
Current Energy
Charge Portion
of Customer Bill
in 2023 ($/single
family
residential
customer,
Annualized)
Energy
Charge
Portion of
Customer Bill
in 2030
($/single‐
family
residential
customer,
Annualized)
% Change in
Energy
Charge
Portion of
Customer Bill
from 2024 to
2030
Energy Charge
Portion of
Customer Bill
in 2045
($/single
family
residential
customer,
Annualized)
% Change in
Energy Charge
Portion of
Customer Bill
from 2024 to
2045
1 $2.456 $836.12 $1,254.18 50% $1,367.06 64%
2 $3.003 $836.12 $1,596.99 91% $1,549.08 85%
3 $2.926* $836.12 $1,530.10 83% $1,484.20 78%
4 $1.937 $836.12 $1,153.85 38% $1,061.54 27%
5 $2.426 $836.12 $1,588.63 90% $1,429.77 71%
*The total power supply Net Present Value (“NPV”) moderate cost in the table above for Scenario 3 includes the cost of doubling the growth of distributed solar and storage from the load forecast in the amount of $632.33 million.
All Scenarios studied in the 2023 IRP have included an embedded Distributed Energy Resource (“DER”) growth rate built in
to the load forecast. Scenario 3 takes this natural growth rate and doubles to study the value of DERs. The IRP modeling captures the estimated costs as they are an additional cost, regardless of the funding source.
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Figure 198: Annual Bill Impacts for Single‐Family Residential Customers (High‐Cost Estimates) Scenario
Power Supply
NPV High Cost
($ in Billions)
Energy Charge
Portion of
Customer Bill
in 2023
($/single family
residential
customer,
annualized)
Energy
Charge
Portion of
Customer
Bill in2030
($/single‐
family
residential
customer,
annualized)
% Change
in Energy
Charge
Portion of
Customer
Bill from
2024 to
2030
Energy Charge
Portion of
Customer Bill
in 2045
($/single
family
residential
customer,
annualized)
% Change in
Energy Charge
Portion of
Customer Bill
from 2024 to
2045
1 $2.728 $836.12 $1,354.52 62% $1,584.78 90%
2 $3.453 $836.12 $1,806.02 116% $1,824.08 118%
3 $3.378 $836.12 $1,722.41 106% $1,774.08 112%
4 $2.127 $836.12 $1,220.74 46% $1,196.32 43%
5 $3.057 $836.12 $1,722.41 106% $1,205.69 44%
Given that the costs in the IRP are higher than what is currently in the Light & Power Fund Financial Plan, customer retail rates will need to increase to meet the additional revenue requirements. Figures 196 and 197 represent the Energy Charge, just one component of the rates that customers pay for electricity. Other components recover costs for
transmission of power to the PWP service area, distribution inside of the service area, customer service, administration, and other factors. All facets of the enterprise require revenue increases to address cost factors such as inflation, high demand, limited supply, supply chain issues, and a competitive job market.
While a full cost‐
of‐service analysis will give more certainty on the exact rate impact, it is possible that bill amounts may double. The current rate is in the 20 ¢ per kWh range and doubling would result in 40 ¢+ in the planning time horizon. By looking at just the Energy Charg e in this report, customer will likely see bill in increases in the double digits. Looking to other utilities, who have done full cost analyses and have less ambitious plans and longer lead times, doubling retail rates may also be on the lower end of the spectrum.
21. Greenhouse Gas Emissions
PWP can express its carbon impacts across multiple dimensions, as follows:
Cap‐and‐Trade
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Carbon Emissions Netting Market Interactions at CAISO Average Carbon Content RPS (SB 100, SB 1020)
Renewable and Zero‐Carbon (SB 1020)
Carbon‐Free (City of Pasadena Resolution 9977)
Greenhouse gas Emissions Accounting Table (GEAT)
The CEC requirements reference how PUC Section 9621 require POUs to adopt IRPs that ensure the utility achieves specific goals and targe
ts by 2030, including meeting CARB and RPS requirements. PWP exceeds its obligations under both programs as shown in its IRP modeling. PWP seeks to procure renewable energy in excess of requirements to meet its goals for Resolution 9977. There are various factors that may enable or preve nt excess renewable energy procurement, including, but not limited to, the following:
Resource cost and type
Resource location and transmission congestion considerations Competition on supply or demand side
Resource timing and implications for rates
21.1. Cap‐and‐Trade Program
This IRP ensures that the utility meets, by 2030, the GHG emissions reduction targets established under the Cap‐ and‐Trade Program, which is regulated through CARB. Post 2030, the carbon‐free scenarios have no fossil emissions. See Figure 199. The model optimizes for PWP to operate under its allowance cap and is an assumption included in all scenarios.
Figure 199: Cumulative Emissions Under Cap‐and‐Trade Program Scenario
1 2 3 4 5 Carbon Cap
Cumulative Million Metric Tons Emitted (2030 – 2049) ‐ ‐ ‐ 1.00 0.12 2.30 Emissions co
vered under the Cap‐and‐Trade Program include the emissions from Glenarm, Magnolia, and IPP.
21.2. Carbon Emissions Netting Market Interactions at CAISO Average Carbon Content Cap‐and‐Trade Program allowances are used to cover emissions for the Glenarm, IPP, and Magnolia resources.
PWP’s portfolio also includes two other sources of carbon that are not a part of the Cap‐and‐Trade Program modeling, specifically, two landfill gas contracts, which will expire in 2030, and spot market purchases.
There are different ways to think about PWP’s total
carbon emissions, inclusive of other factors like landfill gas or market purchases that are not covered in the Cap‐and‐Trade Program. If PWP considers emissions from landfill gas and credits the net of market purchases and sales at the emission intensity of the CAISO market (previously
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provided in Figure 91), then total emissions could look like Figure 200. Sales (particularly for Scenario 5) create this effect.
Figure 200: Cumulative Portfolio Emissions Netting CAISO Purchases and Sales 2030‐2049
Million Metric
Tons Emitted
from Portfolio
Net Generation
(GWh) in
Portfolio
Purchases (GWh) Sales (GWh)
Scenario 1 (Island) 0.00 27,989 0 0
Scenario 1 (Energy Market Access) 0.25 25,403 11,532 8,946 Scenario 2 (Island) 0.00 27,989 0 0
Scenario 2 (Energy Market Access) 0.46 38,022 9,410 19,443 Scenario 3 (Island) 0.00 27,989 0 0
Scenario 3 (Energy Market Access) 0.18 35,170 10,091 17,271 Scenario 4 1.11 29,580 8,188 9,779
Scenario 5 0.15 43,346 6,495 21,852
If PWP
sells the RECs, it may not be able to claim the carbon reduction or renewable energy attributes. Claims must be cautiously made in accordance with regulations and best practices.
Scenario 4 has the lowest cost, with emissions forecasted to be 90% below 1990 thresholds by 2030. PWP can calculate the price for carbon avoided abov e the carbon reductions found in Scenario 4. The carbon avoided could refer to the carbon avoided under the Cap‐and‐Trade Program or at the carbon avoided if net market interactions were credited at CAISO’s average emission rate. PWP pays between $503/metric ton and $1,616/metric ton to avoid carbon. See Figure 201.
Figure 201: Cost of Avoided Carbon
2030 $/Metric
Ton of Carbon
(2030 – 2040)
Scenario 1
(Island)
Scenario 1
(Energy
Market
Access)
Scenario 2
(Island)
Scenario 2
(Energy
Market
Access)
Scenario 3
(Island)
Scenario 3
(Energy
Market
Access)
Scenario 5
Using Cap‐
and‐Trade
Incremental
Avoided
Carbon
$835 $503 $1,477 $1,050 $1,351 $972 $669
Netting
Market
Purchases at
CAISO
Emission Rate
$756 $592 $1,338 $1,616 $1,223 $1,053 $618
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2030 $/Metric
Ton of Carbon
(2030 – 2040)
Scenario 1
(Island)
Scenario 1
(Energy
Market
Access)
Scenario 2
(Island)
Scenario 2
(Energy
Market
Access)
Scenario 3
(Island)
Scenario 3
(Energy
Market
Access)
Scenario 5
Incremental
Avoided
Carbon
21.3. RPS (SB 100)
Examining the load, sales, and storage charging on the CAISO level (which is the level of modeling in the 2023 IRP) that are met with renewable resources, PWP exceeds 100% clean energy across all scenarios by 2030. See Figure 202.
Figure 202: Renewable Traits
Label
#14 on the RPS Procurement Table (RPT) shows the over/under procurement for compliance periods 4. PWP acquires RECs in excess of its obligations under these scenarios. PWP would need purchases prior to 2025, which is the first year that new resources can be installed in the model. See Figure 203.
Figure 203: Over/under procurement for compliance period (MWh) Over/Under Procurement for Compliance Period (MWh)
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2021‐2024 (121,488) (121,488) (121,488) (121,488) (121,972) 2025‐2027 1,921,321 1,272,450 1,119,924 1,761,458 5,075,959 2028‐2030 2,244,856 2,286,662 2,022,649 2,054,884 5,302,369 0%
50%
100%
150%
200%
250%
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
% of CAISO Load, Storage Charging, and Sales
Covered by Annual Renewables
Renewable Traits
Scenario 1 (Island) Scenario 1 (Energy Market Access)
Scenario 2 (Energy Market Access) Scenario 2 (Island)
Scenario 3 (Energy Market Access) Scenario 3
Scenario 4 Scenario 5
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21.4. Renewable and Zero‐Carbon (SB 1020)
Examining the load, sales, and storage charging on the CAISO level (the level of modeling in the 2023 IRP) that are met with renewable and zero‐carbon resources, PWP exceeds 100% clean energy across all scenarios by 2045. See Figure 204).
Figure 204: Renewable and Zero‐Carbon Traits
21.5. Carbon‐Free Hourly (Resolution 9977)
Scenarios 1, 2, and 3 achieve zero‐carbon on an hourly basis without offsets under normal operating conditions by the end of 2030, while Scenario 4 and Scenario 5 exceed 100% clean energy and achieve 62% and 81% of hours in a year with carbon‐free energy, respectively. See Figure 205.
Figure 205: Hourly‐Carbon‐Free Achievements
Percent Zero‐Carbon (Hourly) (%)
Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2023 17% 17% 16% 17% 21%
2024 16% 16% 16% 16% 20%
2025 34% 36% 39% 40% 64%
2026 32% 34% 37% 38% 62%
2027 49% 51% 52% 55% 76%
0%
50%
100%
150%
200%
250%
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
Percent of CAISO Load, Storage Charging and
Sales Covered by Annual Renewables and
Zero‐Carbon Resources
Renewable and Zero‐Carbon Traits
Scenario 1 (Island) Scenario 1 (Energy Market Access)
Scenario 2 (Energy Market Access) Scenario 2 (Island)
Scenario 3 (Energy Market Access) Scenario 3
Scenario 4 Scenario 5
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2028 53% 55% 56% 59% 80%
2029 54% 55% 57% 60% 80%
2030 96% 97% 97% 60% 78%
2031 100% 100% 100% 62% 81%
21.6. GEAT
Labeled as #12 on the GEAT, adjusted portfolio emissions in million metric tons of CO2e is shown in Figure 206. The GEAT credits storage charging and market purchases at the emissions intensity of 0.428 Mt CO2e/MWh, which is the value CARB uses for unspecified power imported from out of state.
Procurement in excess of requirements could le ad to emissions reductions for the grid as a whole.
Figure 206: Adjusted Portfolio emissions
Adjusted Portfolio Emissions (million metric tons of CO2e) Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2023 0.51 0.51 0.52 0.51 0.40
2024 0.53 0.53 0.54 0.53 0.41
2025 0.13 0.21 0.24 0.14 (0.40)
2026 0.07 0.18 0.20 0.11 (0.43)
2027 (0.05) 0.05 0.08 (0.02) (0.57)
2028 (0.01) 0.09 0.12 0.05 (0.52)
2029 (0.01) 0.10 0.12 0.05 (0.53)
2030 0.17 0.18 0.21 0.08 (0.49)
2031 0.20 0.17 0.20 0.11 (0.45)
2032 0.21 0.16 0.15 0.10 (0.47)
2033 0.22 0.16 0.16 0.12 (0.44)
2034 0.22 0.13 0.15 0.12 (0.45)
2035 0.22 0.12 0.14 0.11 (0.44)
2036 0.20 0.07 0.10 0.10 (0.44)
2037 0.18 0.04 0.07 0.09 (0.45)
2038 0.18 0.05 0.08 0.09 (0.44)
2039 0.19 0.06 0.09 0.10 (0.44)
2040 0.19 0.05 0.07 0.10 (0.43)
2041 0.18 0.03 0.05 0.10 (0.43)
2042 0.26 0.08 0.16 0.10 (0.25)
2043 0.26 0.09 0.17 0.12 (0.23)
2044 0.27 0.09 0.17 0.11 (0.22)
2045 0.33 0.14 0.16 0.10 0.10
2046 0.32 0.13 0.16 0.09 0.11
2047 0.37 0.13 0.19 0.09 0.10
2048 0.40 0.17 0.23 0.10 0.10
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Adjusted Portfolio Emissions (million metric tons of CO2e) Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2049 0.40 0.17 0.23 0.11 0.11
2050 0.39 0.21 0.29 0.11 0.11
Total 6.50 4.09 5.06 3.50 (7.09)
22. Implementation Steps – Carbon‐Free Pathways
In any future resource portfolio, PWP will be required to fill the gap between its current resources and the forecasted quantitative performance requirement associated with each resource attribute (specifically, energy supply, RA, and renewable carbon‐free energy content). PWP’s challenge will be to augment its portfolio with additional procured and owned resources of various technologies that will fill all three gaps simultaneously, yet cost‐effectively.
The 2023 IRP provides the technical objectives, data, information, and pathways needed to achieve 100% carbon‐ free energy supply by 2030. Furthermore, this IRP identifies optimized renewable portfolio configurations and their associated power supply costs. It also validates and reinforces the understandi ng that power supply decarbonization will require flexibility in negotiation of renewable contracts as well as employment of all approaches and carbon‐free resource types identified in the Scenarios.
The 2023 IRP continues PWP’s long‐standing goal of reducing carbon from its portfolio in a flexible way so that the current risks and challenges can be carefully ad
dressed. Proactive planning is critical to ensure ongoing safe and reliable electric service while minimizing cost impacts to ratepayers and the environment. Resource planning is a complex process, especially where extreme external volatility exists in the cost and availability of renewable generation resources. Ongoing assessment will be required to ensure that PWP responds to changi ng conditions
while addressing its programmatic priorities and providing rate payer protections.
As with past IRPs, PWP will continue to evaluate the IRP results in consideration of new and changing laws, regulations, resource availability and market conditions, providing updates and performance reporting when needed. The 2023 IRP was developed with a forward‐thinking and flexible approach, along with a determination to meet and exceed to California’s increasingly aggressive clean energy targets as quickly as possible.
Besides the actual acquisition and development of individual energy and storage resources, the following are some of the additional actions that PWP
is considering that would support the overall carbon reduction goals of the IRP:
o Explore expansion of DERs.
o Support mass transit and electric vehicle fleet development and vehicle‐to‐grid distributed storage opportunities.
o Continue to study the reliability of PWP’s evolving resource portfolio. o Perform a co
st‐of‐service study to identify projected resource portfolio capital expenditures over the next 20 years.
o Evaluate possible changes to customer incentives or subsidies, including low‐income assistance. o Expand Demand‐Side Management, expand Energy Efficiency programs, implement Advanced Metering Infrastructure, and explore connection in centives.
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o Monitor the actual influence of the City’s Building Electrification Ordinance, which becomes effective in 2025.
o Continue to monitor developments in emerging technologies and funding opportunities.
As noted earlier, of the five modeled scenarios, Scenario 2 installs the largest number of new resources and is the most ambitious of the Carbon‐Free resource portfolios. Th is determined approach provides the bes t planning opportunity for achieving carbon‐free electricity by 2030. The resource procurement and development for such a plan will require a level of resource acquisition by the defined 2028 Waypoint, in addition to various actions that support ongoing efforts.
Waypoint 2028 – Scenario 2 Carbon‐Free resource additions:
o 180 MW of new utility‐scale solar
o 5 MW of utility/community solar within Pasadena
o 30 MW of new utility‐scale wind
o 85 MW of new utility scale storage
The 2028 Waypoint procurement plan is defined by the Scenario 2 modeling results, whereby progress in the evaluation of the maturation of new and em ergent carbon‐free technologies will be periodically assessed and assessed again at the 2028 Waypoint. The next steps in the Implementation Plan will be formally incorporated into the 2028 IRP, as the Waypoint was strategically selected to align with CEC IRP processes.
The 2028 Waypoint Implementation Plan continues to preserve a pathway to 100% carbon‐free elec tricity by 2030 and leverages existing CEC processes so that updates can be included in the next (2028) IRP. Additionally, the 2028 Waypoint Implementation Plan is in addition to the existing contracted procurements of solar, storage, and geothermal resources prior to, and after 2028; where PWP has previously executed proactive and timely carbon‐ free resource acquisitions.
Figure 207 pr
ovides exact detail of the modeling results for Scenario 2 through the 2028 Waypoint and presents the framework for the detailed implementation plan.
Figure 207 Incremental Installation of Resource Under Scenario 2 2023 2024 2025 2026 2027 2028
New Utility
Scale Solar ‐ ‐ 180 MW ‐ 39 MW
(Sapphire) ‐
Community
Solar (Inside
Pasadena)
‐ ‐ 5 MW ‐ ‐ ‐
New Utility‐
scale Wind ‐ ‐ 30 MW ‐ ‐ ‐
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New Utility‐
scale
Storage
‐ ‐ 85 MW ‐ 20 MW
(Sapphire) ‐
New
Geothermal ‐ ‐ ‐ ‐ 35 (Coso +
Geysers) ‐
Waypoint Fr
amework Development:
The Waypoint framework was informed through a thorough examination of the IRP data, analysis, and scenario results. In the most general terms, the IRP Waypoint can be indirectly attributed to a critical path analysis, within a project plan.
The policy goal of the City Resolution 9977 is a primary determinate in both the evaluation and selection of the appropriate Waypoint. To the de
gree practical, the selection criteria of the Waypoint is strategically designed to align and optimize across the following considerations:
1. The Waypoint will be in alignment with the policy goal of the City of Pasadena Resolution 9977
2. The Waypoint identifi cation will be in alignment with CEC and other regulatory requirements and guidelines including electric system reliability, minimization of impacts to ratepayers, and reduction of GHG emissions.
3. The Waypoint will continue the aggressive trajectory of decarbonization, as affirmed by historical PWP performance.
4. The Waypoint attributes and/or characteristics will generally align with the modeling results of carbon‐ free scenarios, from a plan
ning and/or implementation plan perspective.
5. The Waypoint identification, from a planning perspective, will ideally provide limited opportunity cost to achieving the policy goal of Resolution 9977 as defined in the scenario modeling results.
6. The Waypoint will have an Implementation Plan that should be def ined or informed by the IRP scenario modeling results.
7. The Waypoint should align, support previous or historical decarbonization guidance and directives of the City Council.
8. The Waypoint must provide a reevaluation point to allow for reassessment, specifically related to the maturation of new and emerging technologies. It is widely accepted that such technologies will be required for
a full decarbonization transition.
9. The Waypoint aligns with support for energy procurement that is technology‐flexible and in line with energy needs, as defined in Pasadena’s City Council‐approved State Legislative Platform.
22.1. PWP’s Proactive Carbon‐Free Procurement Actions
PWP anticipates continued load growth, driven primarily by EV adoption and building electrification. This trend, in turn, will increase PWP’s need for all three major attributes of a resource portfolio: energy supply, RA, and renewable/zero‐carbon /carbon‐free energy content. Accordingly, PWP proactively began building its future resource portfolio in 2022 and 2023 with the information outlined in the following paragraphs.
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22.1.1. Utility‐Scale Photovoltaic Solar + Battery
PWP has contracted for a portion of the Sapphire Project, a hybrid PV solar and battery energy storage facility to be built in Riverside County, California. During the contract delivery period (December 31, 2026, through December 31, 2046) PWP would receive a 39 MW share of the project’s solar capability, plus a 19.67 MW share of its battery energy storage system. The contract requires that most of the en ergy charging the BESS comes from the solar field.
This feature would benefit PWP because the presence of the BESS would convert the solar field (by itself, a variable energy resource) to a limited dispatchable resource, thus en abling PWP to store the project’s renewable energy until PWP needs it to serve system load.
22.1.2. Geothermal
PWP has secured a 25 MW share of the Geysers, an existing geothermal energy resource comprised of multiple generating facilities in Sonoma County and Lake County, California. PWP plans to use its share of Geysers as a baseload renewable energy resource, meaning it would receive its 25 MW allotment on a full‐time basis during the contractual delivery period (January 1, 2027, throug
h December 31, 2041).
22.1.3. Additional Battery (Local)
Foreseeing the need for energy storage resources electrically within Pasadena, PWP has issued a solicitation to install design and to build a 25 MW, 4‐hour battery at the Glenarm Power Plant complex. This facility, slated to commence service sometime in 2026 or 2027, could give PWP the ability to store renewable and carbon‐ free energy generated within the PWP system. PWP will leverage the experience it derives from this pilot project, since a BESS’ modular design would enable PWP to adjust its MW throughput capability, and its hours of storage capability, to meet future needs as they arise.
22.2. Resource Procurement Guided by the Results of this IRP PWP’s challenge will be to acquire a diverse collection of procured and owned resources of various technologies that simultaneously, yet cost effectively, fulfills its needs for energy supply, Resource Adequacy, and renewable/carbon‐free energy content. The composition of this new resource portfolio, and how quickly PWP needs to assemble it, will depend upon many factors, including, but not limi ted to, the following:
The results of this IRP
PWP’s policy directives
The deliverability of external resource energy to the PWP system The commercial availability of resources by type, size, and offered contract duration Reliability considerations
Regulatory requirements
Rate impac
ts
Since the IRP study period exceeds most typical contract durations, PWP will likely create its new resource portfolio in pieces over the years, allowing for flexibility, while leveraging all resource types and configurations identified in the Scenarios, while leaving breath to accommodate new technologies as they develop and mature in the fut ure.
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Figure 208 below shows the extended study period modeling results, by scenario, of how much cumulative nameplate capacity of wind, solar, storage, and fuel cells are added by 2031. Scenarios 1‐3, which all meet 100% carbon‐free by the end of 2030, require 700 – 1,300 MW of new installed capacity over the next eight years.
Compared to PWP’s current resource portfolio of about 400 MW, this represents an extraordinary expansion of
resource procurement and capacity additions.
Figure 208: Cumulative New Resource Installed Capacity Through 2031 (MW) Solar Wind Battery
Storage
Fuel Cell Geothermal Scenario
Total
Scenario 1 300 285 115 700
Scenario 2 615 30 665 35 10 1,355
Scenario 3 480 60 598 35 20 1,193
Scenario 4 5 250 130 385
Scenario 5 5 610 60 675
All
of the suggested resource portfolios for Scenarios 1 through 5 include some utility‐scale PV solar and some utility‐scale battery storage. Before 2030, the smallest amount of utility‐scale solar among the carbon‐free by 2030 scenarios (Scenarios 1‐3) is 300 MW; this is in addition to the Sapphire Solar contract. Utili ty‐scale storage varies among the scenario findings, but a minimum of 60 MW of 4‐hour storage prior to 2031 appears across all of the results. This includes the 25‐MW, 4‐hour facility that PWP is currently soliciting, because the associated contract has not yet materialized.
Note, that these represent potential minimu
m procurements up to the year 2030; the larger potential procurement strategy is described in the Procurement Plan located in Appendix 28 of this IRP.
22.3. Supplemental Near‐Term Actions
In addition to resource acquisition, PWP can take additional measures to support the goals of this IRP, as outlined in the following sub‐sections.
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22.3.1. Explore DER Expansion and Refine Planning for Internal Resource Sizes and Placement; Revisit the PDMP
The 2023 IRP describes a “Doubled Distributed Solar and Storage” Scenario that envisions over 200 MW of customer‐installed photovoltaic solar generation capacity in Pasadena by 2050. Compared to PWP’s Load Forecast, this degree of Distributed Energy Resource (DER) growth exceeds what PWP expects to occur naturally. If the City of Pasadena decides to promote such expansion, PWP will need to consider how to achieve this outcome – presumably through some combination of customer outreach/education, equipment rebates, and/or rate incentives. Even considering merely the expected, “normal” growth of DERs in Pasadena (to over 100 MW by 2050), PWP would need to increase its utility‐side energy storage ca pacity to accommodate generation from these resources. This could take the form of expanded BESS facilities at PWP’s Glenarm/Broadway complex, plus additional BESS installations at other City‐owned locations that PWP would need to identify and to coordinate with the associated City Department(s). Any of these changes could significant ly change the topographic loading pattern within PWP’s subtransmission and distribution networks, especially in the connected MW of load and internal generation that these networks would face in the future. As PWP develops these internal resources, it will need to update its Power Delivery Master Plan (PDMP) accordingly.
22.3.2. Support Mass Transit and Electric Vehicle Fleet Development, Focusing on Electric Buses (City and School); Pursue Vehicle‐to‐Grid Charging Opportunities PWP and other City Departments (Public Works, Police, Transportation, etc.) are at various stages of converting their vehicle fleets to electric vehicles. These fleets encompass both light‐duty vehicles (such as sedans) and medium/heavy‐duty vehicles (such as transit buses). PWP has supported, and will continue to support, charging facilities in its service area to accommod ate this growing number of EVs. This also presents potential opportunities to partner with other City organizations for a symbiotic use of batteries aboard City vehicles and equipment, as they could charge from PWP’s distribution system and discharge energy back to the system in times of need. Using central charging facili
ties at municipal bus yards in a vehicle‐to‐grid (V2G) mode presents a promising opportunity for symbiotic use of batteries aboard electric buses, as they could charge from PWP’s distribution system and discharge energy back to the system in times of need.
22.3.3. Perform a More Extensive Study on the Future of Glenarm The 2023 IRP study as well as past IRPs, raised awareness of the need to examine the future of PWP’s natural gas‐ fired Glenarm Power Plant, which could take either of two main trajectories:
Maintain its current operational status.
Replace, convert, or make adaptations with carbon‐free alternative energy and long‐term storage resources such as carbon capture and sequestration, green hydrogen, biofue l, or other future technologies
that may develop
At 197 MW, Glenarm plays a crucial role in PWP’s current resource portfolio. It constitutes PWP’s single largest source of RA and contributes to frequency regulation and reliability needs in a transmission‐constrained topology.
To deliver 100% carbon‐fr
ee electricity on an hourly basis, as required by the Carbon‐Free Scenarios (1 through 3), while maintaining reliability and RA requirements, will require replacing, converting, or making adaptations to Glenarm to an alternative energy and storage resource as described in 22.3.1.2. Since these technologies are still being developed and not yet available
at scale, they were not studied as part of the IRP process. However, they do
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represent emergent technologies that PWP could consider in order to achieve 100% carbon‐free electricity while also meeting reliability requirements. Further studies of the feasibility, cost, and provisional timeline of these options must be performed to better understand what role they might play in Glenarm’s future.
22.3.4. Prepare for a Significant Increase in Expenditures Over the Next 20 Years Once PWP has defined a specific resource procurement/development program and has secured any alternative funding mechanisms, PWP can then incorporate this information into the power supply portion of future power system budgets. PWP routinely seeks authorization from its City Council before securing any renewable/carbon‐ free based resource procurement.
22.3.5. Perform a Cost‐of‐Service Study, Rate Impact Study, and Rate Ordinance Proposal Several internal PWP financial studies would directly follow from this IRP and the resource procurement that it suggests. PWP’s power supply costs include operations and maintenance expenses, as well as capital development costs. To the extent that PWP expects to fund these fiscal requirements through retail revenues, a rate impact study would show how cust omer rates could change. This process would culminate in a rate ordinance proposal by which PWP requests the Pasadena City Council’s approval of changes to its rate structure and/or rates.
22.3.6. Investigate Rate Structure: Time‐of‐Use Rates, the Next Net Energy Metering Program, Electric Vehicle Charging Rates, Low‐Income Assistance, Any Changes to Customer Incentives or Subsidies, Etc.
This IRP envisions an evolution occurring within PWP’s connected load, including growth in distributed generation and distributed storage, additional adoption of EVs, and further strides in energy efficiency. Encouraging these developments and accommodating them in an equitable manner may require PWP to consider adjustments to its rate structure. PWP could explore a new TOU rate, a successor to PWP’s curr ent NEM program, or EV charging rates. As some of these programs may overlap with existing or proposed customer incentive and subsidy programs, PWP may need to re‐evaluate existing programs in the context of other proposed changes. Any resulting rate proposal would need to consider the needs of PWP’s low‐ income customers, incorporating rate equity in the proposal so that PWP’s electric service remains affordable to all of its customers.
22.3.7. Expand Demand‐Side Management; Explore Advanced Metering Infrastructure Connection Incentives
Section 6.4 of the IRP discusses PWP’s current demand‐side management efforts to adjust customer load in response to, or in anticipation of, power system contingencies. PWP’s AMI network, slated for inauguration as early as 2027, will enable PWP not only to monitor individual customer loads in real time but also, potentially, to control some of those loads with the customers’ permission.
22.3.8. Determine the Future of PWP’s Green Power Program As PWP overhauls its resource portfolio, its portfolio content may eventually reach 100% renewable/carbon‐free.
Before this occurs, PWP would need to re‐evaluate the need and future of its existing GPP, which currently places a surcharge on participating customer bills to accomplish this same goal.
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22.3.9. Monitor the Influence of the Building Electrification Ordinance After It Becomes Effective in 2025
The 2023 IRP estimates the future impact of Pasadena’s Building Electrification Ordinance, which may modify load growth within PWP’s service territory. In cooperation with Pasadena’s Building & Safety Department, PWP may monitor how its load grows in the future and potentially estimate how much of this load growth is attributable to the ordinance. This field data would help
PWP refine AAFS/Building Electrification assumptions for future utility planning, including future IRPs.
22.3.10. Update the Pasadena Utility Code, Electrical Code, and Fire Code (for Batteries, Hydrogen Fuel Cells, etc.)
Emerging technologies may prompt revisions to Codes and Standards (C&S) – for example, PWP’s restrictions on types of customer‐installed generation, electrical code requirements (which Pasadena’s Building and Safety Department administers), and the Pasadena Fire Code (particularly with respect to customer‐installed battery systems within enclosed spaces such as garages). Keeping Pasadena’s C&S up to date would promote the safe application of these technologies while tapping into their full pote ntial.
22.3.11. Continue to Monitor Emerging Technology Developments Chapters 15 and 17 describe this IRP’s Emerging Technologies Scenario. PWP staff continues to identify and to track such developments. As these technologies mature to the point of commercial applicability, PWP could assess if, how, and when to incorporate them into its evolving resource portfolio. This concept is central to the 2028 Waypoint fram
ework.
Each of the above activities will have its own timeline, which will become clear as PWP addresses them individually.
Additionally, PWP would present each resulting program to the City Council in a timely manner so that PWP could proceed with appropriate guidance and policy directives. In any event, PWP would likely need to accomplish these activities within five to seven years after issuing this IRP.
22.4. Timeline The Longer‐Range Outlook
Transitioning to a more renewable and carbon‐free resource mix would require PWP to ramp up its current long‐ term contract origination and contract administration activities, with a commensurate increase in its work with SCPPA, which supports PWP in these activities. Conversely, PWP foresees increasing participation in markets for RECs and RA to support interim portfolio balancing durin g the first five to seven years following this IRP.
The timeline in Figure 209, is a general high‐level representation of activities inherent to the 2028 Waypoint framework. While standard utility practices encompass many of the below concepts, other considerations are not included such as energy risk manage ment and mitigation, PPA contract negotiations to capture favorable terms intended to protect rate payer interests, while also strategically sourcing procurements that are less likely to be negatively impacted by inherent CAISO transmission constraints, among other things.
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Figure 209: 2023 IRP Implementation Timeline
Figure 210: 100% Carbon – Free Trajectory to Waypoint in 2028
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23. Appendix ‐ Required Tables
The required tables are filed separately.
23.1. Capacity Resource Accounting Table
Additional information regarding how the load is calculated in the CRAT is provided in Figure 21111.
Figure 211: Capacity Resource Accounting Table Load
Peak Load C 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 1 Forecast Total
Peak‐Hour 1‐in‐2
Demand (7a + 5 –
4)
326 330 343 347 352 356 356 363 364 369 372 376 378 380 383 384 386 388 390 392 394 396 398 399 398 400 399 401 2 [Customer‐side
solar: nameplate
capacity]
30 32 34 37 39 42 44 47 50 53 56 59 62 65 68 71 74 78 81 84 88 91 95 98 102 105 108 112 2a
[Customer‐side
solar: peak hour
output]
20 8 18 12 11 28 4 12 16 15 37 40 40 42 44 46 48 50 52 55 57 59 61 63 9 9 0 0 3 [Peak load
reduction due to
thermal energy
storage]
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4 [Light Duty PEV
consumption in
peak hour]
4 5 6 8 7 10 15 16 18 20 29 31 31 32 34 34 35 36 36 37 37 38 38 38 32 32 31 31 4a
[Medium/Heavy
Duty PEV
consumption in
peak hour]
0 0 0 1 1 1 1 2 2 2 4 5 5 6 7 8 9 10 11 12 13 15 16 18 14 15 17 18 4d
[TOU rates
generation in peak
hour]
0 0 0 0 0 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 4e
[Distributed
storage generation
in peak hour]
0 1 0 1 1 0 3 2 2 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 16 17 3 3 4f
[AAFS
consumption in
peak hour]
0 1 1 1 1 1 1 2 2 3 2 3 3 3 3 3 3 3 4 4 4 4 4 4 4 4 5 5 4g
[Climate change
consumption in
peak hour]
0 0 0 0 1 1 1 1 1 2 2 2 2 2 2 3 3 3 3 3 3 3 3 3 2 2 3 3 4h
[Native load
consumption in
peak hour]
352 343 354 350 354 370 345 356 360 361 373 376 377 379 381 383 385 387 389 392 394 396 399 401 373 375 348 349 4i
[Distributed
natural gas
generator in peak
hour]
10 10 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 Additional
Achievable Energy
Efficiency Savings
on Peak
6 8 8 9 11 13 10 14 13 15 16 17 17 17 17 17 18 17 17 17 17 17 17 17 14 14 12 12 6 Demand
Response / 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
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Peak Load C 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 Interruptible
Programs on Peak
7 Peak Demand
(accounting for
demand response
and AAEE) (1‐5‐6)
320 323 335 338 341 343 346 348 351 354 356 359 362 363 365 367 369 371 373 374 376 378 380 382 384 386 388 390 7a
[Metered peak
demand in peak
hour]
330 333 335 338 341 343 346 348 351 354 356 359 362 363 365 367 369 371 373 374 376 378 380 382 384 386 388 390 8 Planning Reserve
Margin 48 48 59 59 60 60 61 61 61 62 62 63 63 64 64 64 65 65 65 66 66 66 67 67 67 68 68 68 8b Reserve Margin
(%) 15% 15% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 9 Firm Sales
Obligations ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 10 Total Peak
Procurement
Requirement
(7+8+9)
368 371 394 397 400 403 406 409 412 416 419 422 425 427 429 431 433 436 438 440 442 444 447 449 451 453 456 458
23.2. Energy Balance Table (Scenario 4 Example)
Additional information regarding how load is calculated in the EBT is in Figure 21212.
Figure 212: Energy Balance Table (Scenario 4) Load
Net Energy for Load
Calculations 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 1 Retail sales to end‐use
customers (1a + 4a –
1b) *.96
1,047,923 1,059,784 1,156,277 1,173,515 1,192,802 1,215,253 1,239,018 1,265,082 1,291,633 1,315,006 1,338,073 1,358,607 1,371,814 1,384,239 1,395,351 1,405,369 1,414,512 1,422,988 1,430,986 1,438,674 1,446,195 1,453,669 1,461,195 1,468,851 1,476,698 1,484,777 1,493,119 1,501,739 1a Metered Load 1,156,320 1,162,535 1,173,224 1,185,899 1,201,519 1,220,842 1,241,853 1,265,577 1,290,067 1,312,076 1,333,660 1,352,810 1,364,639 1,375,921 1,386,185 1,396,148 1,405,362 1,414,327 1,422,855 1,430,863 1,438,698 1,446,483 1,454,323 1,462,298 1,470,471 1,478,887 1,487,577 1,496,556 1b Distributed Generation 84,240 84,480 240 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2 Other loads ‐ ‐ 105,325 117,752 153,124 241,384 246,479 245,473 243,882 242,986 238,602 233,086 228,095 205,042 198,862 193,939 198,942 194,942 190,373 202,111 237,876 235,070 256,827 247,512 257,543 284,078 283,324 285,431 2a [Storage pumping
load] ‐ ‐ ‐ ‐ 22,845 26,475 28,199 27,839 26,429 23,543 22,129 20,338 18,485 12,748 10,648 10,578 11,407 10,907 10,471 9,858 10,032 9,976 9,655 9,553 ‐ ‐ ‐ ‐ 2b [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2,519 2,500 2,389 2c [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2,447 2,515 2,612 2,572 2,453 2d [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2e [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2f [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2g [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2h [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2i [Storage pumping
load] ‐ ‐ 105,325 117,752 130,279 214,909 218,279 217,634 217,452 219,444 216,473 212,749 209,610 192,293 188,214 183,361 187,534 184,034 179,902 192,253 225,114 219,763 242,022 230,601 250,360 273,733 273,056 275,344
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Net Energy for Load
Calculations 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2j [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2k [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 2,730 5,331 5,150 4,912 4,668 5,215 5,195 5,246 2l [Storage pumping
load] ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 3 Net energy for load
(1a + 4a – 1b +2) 1,091,586 1,103,941 1,309,781 1,340,163 1,395,626 1,507,272 1,537,123 1,563,267 1,589,333 1,612,784 1,632,428 1,648,302 1,657,067 1,646,957 1,652,353 1,657,865 1,672,392 1,677,221 1,680,984 1,700,730 1,744,329 1,749,309 1,778,906 1,777,566 1,795,770 1,830,721 1,838,656 1,849,743 4 Retail sales to end‐use
customers (accounting
for AAEE impacts) ((1a
– 1b)*.96)
1,029,197 1,034,933 1,126,064 1,138,463 1,153,458 1,172,009 1,192,179 1,214,954 1,238,464 1,259,593 1,280,313 1,298,697 1,310,054 1,320,884 1,330,738 1,340,302 1,349,147 1,357,754 1,365,941 1,373,629 1,381,150 1,388,624 1,396,150 1,403,806 1,411,652 1,419,732 1,428,074 1,436,694 4a [AAEE generation] 19,506.21 25,886.41 31,471.95 36,512.71 40,983.11 45,045.88 48,790.91 52,216.66 55,384.83 57,721.15 60,166.46 62,405.96 64,333.16 65,994.23 67,305.27 67,777.88 68,088.44 67,952.51 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 67,755.48 5 Net energy for load
(accounting for AAEE
impacts) (1a – 1b +2)
1,072,080 1,078,055 1,278,309 1,303,651 1,354,642 1,462,226 1,488,332 1,511,050 1,533,948 1,555,063 1,572,261 1,585,896 1,592,734 1,580,963 1,585,048 1,590,087 1,604,303 1,609,269 1,613,229 1,632,974 1,676,574 1,681,554 1,711,150 1,709,810 1,728,014 1,762,966 1,770,900 1,781,987 6 Firm Sales Obligations ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 7 Total net energy for
load (accounting for
AAEE & AAFS impacts)
(5+6)
1,072,080 1,078,055 1,278,309 1,303,651 1,354,642 1,462,226 1,488,332 1,511,050 1,533,948 1,555,063 1,572,261 1,585,896 1,592,734 1,580,963 1,585,048 1,590,087 1,604,303 1,609,269 1,613,229 1,632,974 1,676,574 1,681,554 1,711,150 1,709,810 1,728,014 1,762,966 1,770,900 1,781,987 8 [Customer‐side solar
generation] 57,838 62,350 66,608 71,103 75,793 80,665 85,714 90,950 96,366 101,93 4 107,61
7 113,37
4 119,17
0 125,15
2 131,23
7 137,41
9 143,68
8 150,03
9 156,46
3 162,95
2 169,49
8 176,09
4 182,73
3 189,40
6 196,10
6 202,82
6 209,55
8 216,29
7 9
[Total Annual Light
Duty PEV electricity
consumption/procure
ment requirement]
39,428 50,945 64,260 79,439 96,970 115,25
1 135,43
6 157,14
4 179,72
6 196,48
1 211,38
9 224,44
2 235,73
7 245,42
4 253,68
0 260,68
5 266,61
1 271,61
4 275,83
3 279,38
8 282,38
4 284,90
8 287,03
5 288,82
9 290,34
2 291,62
0 292,69
9 293,61
0 10
[Total Annual
Medium/Heavy Duty
electricity
consumption/procure
ment requirement]
242 423 2,827 4,605 6,952 9,777 12,777 15,881 19,789 23,677 30,058 35,906 41,939 48,054 54,511 61,340 68,580 76,269 84,445 93,138 102,37 4 112,16
7 122,52
7 133,45
4 144,93
9 156,96
8 169,51
7 182,55
9 11
[Total Annual AAFS
consumption/procure
ment requirement]
2,914 4,798 6,833 8,430 10,124 11,932 13,820 15,790 17,832 19,924 21,927 23,779 25,448 26,856 28,109 29,215 30,186 31,032 31,765 32,399 32,944 33,412 33,812 34,154 34,445 34,693 34,903 35,082 12 [Total Annual TOU
rates generation
requirement]
‐ ‐ ‐ ‐ ‐ ‐ ‐ 12 12 13 12 12 12 13 13 13 13 14 14 14 14 14 15 15 15 15 15 15 13 [Total Annual climate
change
consumption/procure
ment requirement]
658 994 1,333 1,677 2,028 2,379 2,736 3,096 3,458 3,822 4,189 4,559 4,931 5,221 5,484 5,720 5,932 6,120 6,287 6,433 6,562 6,674 6,773 6,858 6,932 6,996 7,052 7,100 14 [Total Annual
distributed storage
consumption/procure
ment requirement]
407 501 591 694 799 914 1,032 1,166 1,319 1,473 1,642 1,812 1,997 2,184 2,377 2,576 2,780 2,990 3,207 3,430 3,659 3,895 4,138 4,388 4,646 4,912 5,185 5,467 15 [Total Annual native
load
consumption/procure
ment requirement]
1,190,0
16 1,193,1
11 1,195,4
61 1,198,6
69 1,201,4
23 1,206,2
99 1,210,5
57 1,215,6
79 1,219,7
07 1,226,3
67 1,232,2
49 1,238,1
03 1,238,1
03 1,239,3
41 1,240,5
80 1,241,8
21 1,243,0
63 1,244,3
06 1,245,5
50 1,246,7
96 1,248,0
43 1,249,2
91 1,250,5
40 1,251,7
90 1,253,0
42 1,254,2
95 1,255,5
50 1,256,8
05 Surplus/Shor
tfall (21‐22) (MWh), labeled as #23 on the EBT, is plus or minus 10 MWh.
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24. Appendix – Integrated Resource Plan Contract and Resource Roles Figure 213: IRP Contacts and Roles
Company Roles Contract Details Representatives
PWP Represent the utility and best
interests of stakeholders
N/A Sidney Jackson –
General Manager of PWP
Kelly Nguyen –
Assistant General Manager of
Power Supply
Evaluate, communicate,
engage, and analyze options
for meeting load requirements
in compliance with regulations
and stakeholder priorities
Robert Castro –
Power Resource Planning
Manager
File an IRP to the CEC by
December 31, 2023, in
compliance with California
regulatory requirements
John Hormozi –
Principal Power Resource
Planner
Jason Tarasi –
Power Resource Planner II
Christina Schieber –
Power Resource Planner I
Mark Webster –
Power Resource Planner I
Jessica Velazquez ‐ Intern
ACES
Provide consulting services to
help PWP meet IRP
development and filing
requirements in accordance
with Publicly Owned Utility
Integrated Resource Plan
Submission and Review
Guidelines – Revised Second
Edition
Formal solicitation process,
entered December 2022;
$277,200 for 2023 IRP
modeling and consulting
services with optional
$150,000 in hourly consulting
services to be conducted, if
needed, in the post‐IRP
submission phase; total value
of contract not to exceed
$427,000
Nette Brocks –
Manager of Resource Planning
Patrick Maguire –
Executive Director of Resource
Planning
Todd White –
Executive Director of Business
Development
Michael Bloom – Consultant
EE‐3 Validate the assumptions data
and results.
Informal solicitation, $70,560 Nick Schlag –
Partner at E3
Nathan Lee –
Managing Consultant
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Company Roles Contract Details Representatives
Charlie Duff –
Managing Consultant
Melissa Rodas –
Consultant
25. Appendix – Opportunities for Future Studies and Analysis Figure 214: Opportunities for Future Studies and Analysis What the 2023 IRP Did Opportunities for Future Study
Planning Horizon The IRP guidelines only require
present year through 2045, but the
2023 IRP modeled for a Study Period
of 2023 through 2050.
Scenarios and Sensitivity Analysis
“IRP Filings and IRP Filing updates
must meet the requirements of PUC
Section 9621. POUs are encouraged to
also evaluate other scenarios and
sensitivity analyses to consider the
feasibility and cost‐effectiveness (and
rate impacts) of alternative resource
options. Although not required, POUs
are encouraged to submit analyses of
alternatives” – 2018 Guidelines
While only one scenario is required
by the CEC, the 2023 IRP modeled
five scenarios, one emerging
technology study, and four
sensitivities.156
Consider additional or different
scenarios and sensitivity tests to
evaluate other potential risks
and opportunities in future IRPs.
Supporting Information
“Supporting Information for an IRP
Filing refers to (1) analyses, studies,
data, and work papers, or other
material that the POU used or relied
upon (including inputs and
assumptions) in creating the IRP (such
as, but not limited to, market
conditions current at the time of the
The IRP represented PWP’s existing
fleet of 20 existing
resources/contacts and 4 imminent
contracts.
The IRP created low, medium, and
high‐cost estimates for 16 different
technologies using publicly available
sources.157
The IRP disclosed power prices
(while normally subject to a
Further consider the impacts of
transmission congestion on
energy value for existing and
new resources external to
Pasadena.
Green hydrogen and biogas price
forecasts could consider impacts
from the IRA.
156 34 unique results packages.
157 48 unique estimates of resource costs.
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What the 2023 IRP Did Opportunities for Future Study
analyses, energy infrastructure, state
policies and laws, and needs of the
Filing POU) but are not included in the
IRP itself; and (2) additional
information required by these
guidelines.” – 2018 Guidelines
nondisclosure agreement), courtesy
of Horizons Energy
The IRP disclosed gas prices (while
normally subject to a nondisclosure
agreement), courtesy of Horizons
Energy.
The IRP created forecasts for green
hydrogen and biogas based on
public sources of data.
Demand Forecast
“The Energy Commission recommends
using the California Energy Demand
Forecast developed annually as part of
the IEPR.” – 2018 Guidelines
The IRP created hourly load
forecasts from 2023 through 2050
for the various components of
demand, based upon the IEPR.
Hourly forecasts included the
following:
o Native load
o Additional achievable energy
efficiency
o Additional achievable fuel
substitution
o Distributed (residential and
nonresidential) storage
o Distributed solar
o Time of use rates
o Light‐duty electric vehicles
(EVs)
o Medium/heavy duty electric
vehicles
o Climate change
Consider an econometric load
forecast in future IRPs.
Consider additional studies
regarding distributed resources,
EVs, or other components.
Resource Procurement Plan
Diversified Procurement
Portfolio
RPS Planning Requirements
Energy Storage and Demand
Response Resources
Energy Storage
Transportation Electrification
The IRP studied three pathways to
achieve 100% hourly carbon‐free
by 2030 without offsets, and one
additional decarbonization
portfolio looking at the SCC, and
compared these results to a
reference case that meets state
regulatory targets. The results
showed a range of resources that
could meet environmental goals
Update internal practices
regarding contract size, contract
duration, and resource diversity
as market conditions change.
Continue to monitor the
potential for long‐duration or
novel storage technologies
applicable to the PWP system.
Study the feasibility of rate
mechanisms to incentivize
transportation electrification and
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What the 2023 IRP Did Opportunities for Future Study
and requirements reliably and cost‐
effectively given constraints.
The IRP documented procedures in
place to achieve compliance with
State goals.
Energy storage was included as a
selectable resource choice; it helps
avoid the use of fossil peakers by
storing excess renewable energy
for later dispatch.
Demand response and energy
efficiency were further evaluated in
the emerging technology scenario.
The load forecast also included
impacts.
PWP incorporated light, medium,
and heavy‐duty transportation
electrification into its load forecast.
to avoid the need for additional
resources.
System and Local Reliability PWP’s transmission constrained topology was incorporated into IRP
modeling.
PWP considered the impact of
Glenarm and Goodrich on reliable
operations.
Conduct further, detailed
reliability studies of these two
facilities under various load and
resource conditions.
Study the distribution system’s
existing or potential hosting
capacity for distributed resources
under different conditions in the
context of a future PDMP.
Consider operational alternatives
at Glenarm (carbon capture,
hydrogen, etc.).
GHG Emissions The IRP documents CARB
compliance.
PWP models carbon emissions
from its fossil fleet, landfill/biogas
contracts, and net market
purchases.
Retail Rates The IRP quantifies the incremental
revenue requirement associated
with various scenarios and
sensitivities.
Conduct a cost of service study
in preparation for its next Rate
Ordinance proposal.
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What the 2023 IRP Did Opportunities for Future Study
The IRP conducts a rate
examination.
Further investigate the
feasibility of applying AMI to
support increased distributed
resources and demand
response.
Investigate alternative rate
structures.
Transmission and Distribution Systems PWP explains operations and areas of risk and opportunities on PWP’s
system.
Consider further studies to
explore decarbonization
potential with more of a
reliability focus.
Localized Air Pollutants and
Disadvantaged Communities
PWP identifies various areas of
concern and pathways for
mitigation.
Further research ways to
provide tangible benefits
targeted to disadvantaged
communities.
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26. Appendix ‐ Model Parameters and Additional Reliability Metrics The following constraints are applied when conducting capacity expansion:
1,000 MW of new resources can be built each year
2,000 MW of new resources can be online at once
Resources are usually in 10 MW increments, but could be in the following increments:
Hybrids are in 15 MW increments (10 MW of solar or wind with 5 MW of 4‐hou r battery) 5 MW of internal fuel cells in a 5 MW increment
5 MW of community solar in 1 MW increments
Distributed resources in 1 MW increments
The capacity expansion was run from 2023 through 2050 to optimize for reliabili ty using capacity derations. A typical day of the week was optimized with 24 intervals in a day over 20 years, with a 10‐year expansion period. There was no commitment and mixed integer programming (MIP) stop basis of 200.
Scenario 2 was optimized under an on/off‐peak day due to problem size and solve time.
Hourly dispa
tch runs were run with no maintenance shifts and new outages with convergence. All calendar days with 24 daily intervals over a 7‐day optimization period, with a 1‐day extension period. Twelve split months were run under full commitment with a MIP
stop basis of 25 and a MIP maximum solve time of 120 seconds.
The capacity expansion is optimized with a $2,000/MWh penalty for unserved energy, and a $32.95/kW‐month (in 2023, escalating at inflation) penalty for unserved capacity. The energy penalty is based on the soft energy cap for energy at CAISO. The capaci
ty penalty is based on the penalty price for investor‐owned utilities. The capacity market can trade at this level.
Scenario 1, 2, and 3 required additional internal resources to meet load with carbon‐free resources. Resources are added iteratively, after the initial optimization, to help cover load, as follows:
Scenario 1: Minimum of 110 MW of fuel cells in 2030 (compared to 20 MW) and 220 MW of fuel cells in 2050 (compared to 120 MW)
Scenario 2: Minimum of 400 MW of commercial storage and of commercial solar (compared to none) in 2030 and 2050 (compared to 3 MW of commerc
ial storage and 8 MW of commercial solar)
Scenario 3: Minimum of 350 MW of commercial storage and of commercial solar (compared to 14 MW of commercial storage and 31 MW of commercial solar) in 2030 and 2050 (compared to 31 MW of commercial storage and 67 MW of com
mercial solar)
Scenario 4: None
Scenario 5: None
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Additional energy needs were likely due to the difference between a typical week in the capital optimization, and standard hourly day in the dispatch. The energy needs for the capital optimization are shown in Figure 21515, the resulting hourly dispatch is shown in Figure 2166, and the adjusted dispatch with additional resources are shown in Figure 2177.
Figure 215: Reliability Metrics for First Round Scenario Modeling (Capital Expansion) Capacity Expansion: Additional Energy Needs (MW)
Year Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2023 0 0 0 0 0
2024 0 0 0 0 0
2025 0 0 0 0 0
2026 0 0 0 0 0
2027 0 0 0 0 0
2028 0 0 0 0 0
2029 0 0 0 0 0
2030 224 149 0 0 0
2031 735 2,199 0 0 0
2032 0 0 0 0 0
2033 311 1,488 0 0 0
2034 1,135 1,079 0 0 0
2035 1,433 1,246 0 0 0
2036 195 1,743 0 0 0
2037 0 0 0 0 0
2038 0 0 0 0 0
2039 0 0 0 0 0
2040 606 0 0 0 0
2041 1,575 1,502 0 0 0
2042 4,431 318 1,000 0 0
2043 73 0 0 0 0
2044 32 419 0 0 0
2045 0 0 1,031 0 0
2046 0 0 0 0 0
2047 0 0 0 0 0
2048 0 0 0 0 0
2049 0 0 89 0 0
2050 0 0 0 0 0
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Figure 216: Reliability Metrics for First Round Scenario Modeling (Hourly Dispatch) Hourly Dispatch: Additional Energy Needs (MW)
Year Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 2023 0 0 0 0 0
2024 0 0 0 0 2
2025 0 0 0 0 5
2026 0 0 0 0 14
2027 0 0 0 0 4
2028 0 0 0 0 6
2029 0 0 0 0 12
2030 10,960 5,043 6,209 0 2
2031 15,462 9,111 7,167 0 4
2032 9,663 5,740 1,342 0 1
2033 9,890 9,051 3,642 0 0
2034 9,136 10,627 5,562 0 1
2035 12,330 13,582 7,295 0 0
2036 12,814 16,147 10,010 0 3
2037 5,735 7,284 3,673 0 3
2038 7,408 8,037 4,141 0 0
2039 8,781 10,326 4,151 0 2
2040 11,833 14,332 6,899 0 2
2041 15,601 15,837 7,715 0 0
2042 21,173 6,722 11,832 0 1
2043 19,013 4,569 11,002 0 2
2044 20,397 4,963 11,047 0 1
2045 11,656 4,951 13,725 0 1
2046 7,011 5,140 8,456 0 0
2047 6,625 568 7,054 0 0
2048 7,532 557 7,028 0 0
2049 7,052 1,298 10,173 0 0
2050 560 208 587 0 0
Figure 217: Reliability Metrics for Second Round Scenario Modeling (Hourly Dispatch) Hourly Dispatch: Additional Energy Needs (MWh) Revamped Year Scenario 1 Scenario 2 Scenario 3
2023 0 0 0
2024 0 0 0
2025 0 0 0
2026 0 0 0
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Hourly Dispatch: Additional Energy Needs (MWh) Revamped Year Scenario 1 Scenario 2 Scenario 3
2027 0 0 0
2028 0 0 0
2029 0 0 0
2030 0 0 0
2031 0 0 0
2032 0 0 0
2033 0 0 0
2034 0 0 0
2035 0 0 0
2036 0 0 0
2037 0 0 0
2038 0 0 0
2039 0 0 0
2040 0 0 0
2041 0 0 0
2042 0 0 0
2043 0 0 0
2044 0 0 1
2045 1 0 7
2046 1 0 1
2047 2 0 2
2048 2 0 1
2049 2 0 2
2050 0 1 4
Scenario 1 i
nformation regarding additions and reliability metrics is described in Figure 112. Scenario 2 information is described in Figure 218. The scenario needs a minimum of 400 MW of commercial storage and 400 MW of commercial solar (compared to none) in 2030 and 2050 (compared to 3 MW of commercial storage and 8 MW of commercial solar).
This ensures load is served every hour with carbon‐
free electricity. The 400 MW of commercial solar and 400 MW of commercial storage helps meet additional energy needs under normal operating conditions.
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Figure 218: Scenario 2: Consecutive Model Runs
Additional Energy Needs (MWh) Additional Energy Needs (% of Total Load) Year Energy
(MWh)
With 400 MW Minimum of
Commercial Storage and 400 MW
Minimum of Commercial Solar
Without
With 400 MW Minimum of
Commercial Storage and 400 MW
Minimum of Commercial Solar
Without
2023 1,156,000 0 0 0.0% 0.0%
2024 1,163,000 0 0 0.0% 0.0%
2025 1,173,000 0 0 0.0% 0.0%
2026 1,186,000 0 0 0.0% 0.0%
2027 1,202,000 0 0 0.0% 0.0%
2028 1,221,000 0 0 0.0% 0.0%
2029 1,242,000 0 0 0.0% 0.0%
2030 1,266,000 0 5,043 0.0% 0.4%
2031 1,290,000 0 9,111 0.0% 0.7%
2032 1,312,000 0 5,740 0.0% 0.4%
2033 1,334,000 0 9,051 0.0% 0.7%
2034 1,353,000 0 10,627 0.0% 0.8%
2035 1,365,000 0 13,582 0.0% 1.0%
2036 1,376,000 0 16,147 0.0% 1.2%
2037 1,386,000 0 7,284 0.0% 0.5%
2038 1,396,000 0 8,037 0.0% 0.6%
2039 1,405,000 0 10,326 0.0% 0.7%
2040 1,414,000 0 14,332 0.0% 1.0%
2041 1,423,000 0 15,837 0.0% 1.1%
2042 1,431,000 0 6,722 0.0% 0.5%
2043 1,439,000 0 4,569 0.0% 0.3%
2044 1,446,000 0 4,963 0.0% 0.3%
2045 1,454,000 0 4,951 0.0% 0.3%
2046 1,462,000 0 5,140 0.0% 0.4%
2047 1,470,000 0 568 0.0% 0.0%
2048 1,479,000 0 557 0.0% 0.0%
2049 1,488,000 0 1,298 0.0% 0.1%
2050 1,497,000 1 208 0.0% 0.0%
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All scenarios were optimized under the capital expansion with a heat rate of 2,047.2 Btu/kWh for fuel cells. E3 identified this in review. The hourly dispatch was re‐optimized with a corrected heat rate of 6,469 Btu/kWh.158 Fuel cell capacity is in Figure 219. Given the size and importance of fuel cells in meeting reliability, and time constraints, the capital expansion was not repeated. Since the heat wave and Goodrich sensitivities were focused on reliability, they were kept. The Emerging Technology Sensitivity was also kept because the emphasis was on comparative differences.
Figure 219: Installed Capacity of Fuel Cells
Year Scenario 1 Scenario 2 Scenario 3
2030 110 35 35
2031 115 35 35
2032 120 35 35
2033 125 35 35
2034 130 35 35
2035 130 35 35
2036 130 35 35
2037 130 35 35
2038 130 35 35
2039 130 35 35
2040 130 35 35
2041 130 35 35
2042 150 65 65
2043 150 65 65
2044 150 65 65
2045 165 75 65
2046 175 75 75
2047 185 95 85
2048 185 95 85
2049 190 95 85
2050 220 135 115
Once the mo
del runs are complete, resources in PWP’s portfolio are assigned to load in the order shown in Figure 22020.
Resources on the top are assigned to load first. Preference is given to dispatchable and internal resources. Assigning resources to load rather than the market helps identify how PWP’s carbon‐free resources are meeting load. 158 https://www.eia.gov/outlooks/aeo/assumptions/pdf/table_8.2.pdf
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Figure 220: Resources Toward Load
Resources Toward Load
BTM NG Generator
GT ‐ 1
GT ‐ 2
GT ‐ 3
GT ‐ 4
GT ‐ 5
GT ‐ 1 Biogas
GT ‐ 2 Biogas
GT ‐ 3 Biogas
GT ‐ 4 Biogas
GT ‐ 5 Biogas
New 2‐Hour Residential Storage
New 4‐Hour Commercial Storage
New 4‐Hour Storage (Internal Solar Paired)
New 4‐Hour Internal Storage
New 6‐Hour Internal Storage
New 8‐Hour Internal Storage
New 10‐Hour Internal Storage
New Internal Fuel Cells
Intermountain Coal
Intermountain Repower NG
Magnolia
Palo Verde Nuclear
Hoover Hydro
Calpine Geysers
Coso Geothermal
Puente Hills Landfill
Chiquita Landfill
EDF Sapphire Storage
Milford Wind
PPM (Avangrid) Wind
Antelope Solar
Columbia Two Solar
Kingbird Solar
Summer Solar
Windsor Reservoir Solar
EDF Sapphire Solar
New 4‐Hour Storage (External Solar Paired)
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Resources Toward Load
New 4‐Hour Storage (Land‐Based External Wind Paired)
New 4‐Hour External Storage
New 6‐Hour External Storage
New 8‐Hour External Storage
New 10‐Hour External Storage
New External Fuel Cells
New External Geothermal
New Land‐Based External Wind (Storage Paired)
New Land‐Based External Wind
New Offshore Wind
New Residential Solar
New Commercial Solar
New Community Solar
New Internal Solar (Storage Paired)
New Internal Solar
New External Solar (Storage Paired)
New External Solar
Curtailments are reported in
EnCompass if the price received for generation dips below $100/MWh. This price is a model default that allows for uncertainty. Curtailments across scenarios are shown in Figure 22121. Scenario 2 has the greatest amount of curtailment.
Figure 221: Economic Curtailments Across Scenarios (MWh) Year Scenario 1
(Island)
Scenario 1
(Energy
Market
Access)
Scenario 2
(Island)
Scenario 2
(Energy
Market
Access)
Scenario 3
(Island)
Scenario 3
(Energy
Market
Access)
Scenario
4 Scenario 5
2023 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
2024 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
2025 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
2026 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
2027 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
2028 52,437 52,437 41,131 41,131 38,311 38,311 39,383 72,148 2029 20,675 20,675 15,932 15,932 14,559 14,559 12,761 21,592 2030 187,478 46,734 579,156 50,661 411,034 44,209 34,816 59,833 2031 140,075 28,953 581,054 34,654 401,022 30,358 32,134 61,223 2032 118,726 339 564,742 646 500,999 1,105 2,398 5,265 2033 108,595 13,554 563,308 16,429 488,579 16,391 16,060 31,065 2034 104,325 2,994 601,788 3,552 475,829 2,851 1,339 1,817 2035 99,791 ‐ 583,053 ‐ 467,824 ‐ ‐ ‐
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Year Scenario 1
(Island)
Scenario 1
(Energy
Market
Access)
Scenario 2
(Island)
Scenario 2
(Energy
Market
Access)
Scenario 3
(Island)
Scenario 3
(Energy
Market
Access)
Scenario
4 Scenario 5
2036 99,746 ‐ 575,057 ‐ 460,519 ‐ ‐ ‐
2037 97,002 ‐ 595,679 ‐ 478,079 0 ‐ ‐
2038 91,938 ‐ 579,007 ‐ 464,031 ‐ ‐ ‐
2039 87,286 ‐ 570,236 1 454,676 ‐ ‐ ‐
2040 85,993 ‐ 565,901 ‐ 454,923 ‐ ‐ ‐
2041 83,004 ‐ 582,338 1 476,094 ‐ ‐ ‐
2042 67,652 ‐ 463,746 ‐ 286,794 0 ‐ ‐
2043 66,744 ‐ 461,955 0 281,494 1 ‐ ‐
2044 63,019 ‐ 454,459 0 280,020 1 ‐ ‐
2045 16,538 ‐ 334,621 ‐ 271,617 0 ‐ ‐
2046 20,121 ‐ 335,611 0 243,978 0 ‐ ‐
2047 4,438 ‐ 337,080 0 194,630 ‐ ‐ ‐
2048 3,239 ‐ 318,606 0 171,392 ‐ ‐ ‐
2049 4,394 ‐ 316,677 0 184,534 1 ‐ ‐
2050 10,398 ‐ 251,968 0 113,390 ‐ ‐ ‐
Scenarios 1,
2, and 3 select new resources as if PWP operates like an island (i.e., has no market interactions with CAISO).
The results of these studies have the “island” label. This is done so that carbon‐free resources meet load in each hour.
These results provide an upper bound of costs (excluding the separately studied impacts of new resource cost variations) because excess renewable energy is not sold.
However, given that PWP operates within CAISO, Scenarios 1, 2, and 3 are run again with access to CAISO’s energy market.
This shows a lower bound of cost estimates (again, excluding the separately studied impac ts of new resource cost variations), as excess renewable energy is sold. These results may also predict greater CO2 emissions because PWP has access to CAISO markets. This pertains to the results with the “energy market access” label.
27. Appendix – Cost of New Resources
27.1. Utility‐Scale Solar
Figure 222: Utility‐Scale Solar Nominal Costs
Figure 223: Utili ty‐Scale Solar Real Costs
$0
$10
$20
$30
$40
$50
$60
Utility‐Scale Solar (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High PWP Signed Solar
PPA (Sapphire)
$0
$10
$20
$30
$40
$50
$60
Utility‐Scale Solar (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High PWP Signed Solar
PPA (Sapphire)
DRAFT
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27.2. Commercial Solar
Figure 224: Commercial Solar Nominal Costs
Figure 225: Commercial Solar Re al Costs
$0
$20
$40
$60
$80
$100
$120
Commercial Solar (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$20
$40
$60
$80
$100
$120
Commercial Solar (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
DRAFT
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27.3. Residential Solar
Figure 226: Residential Solar Nominal Costs
Figure 227: Residential Solar Re al Costs
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
Residential Solar (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$20
$40
$60
$80
$100
$120
$140
$160
$180
Residential Solar (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
DRAFT
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27.4. Utility‐Scale 4‐Hour Storage
Figure 228: Utility‐Scale 4‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 229: Utili ty‐Scale 4‐Hour Lithium‐Ion Battery Storage Real Costs $0
$5
$10
$15
$20
$25
4‐Hour Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High PWP Signed Solar
PPA (Sapphire)
$0
$5
$10
$15
$20
$25
4‐Hour Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High PWP Signed Solar
PPA (Sapphire)
DRAFT
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27.5. Utility‐Scale 6‐Hour Storage
Figure 230: Utility‐Scale 6‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 231: Utili ty‐Scale 6‐Hour Lithium‐Ion Battery Storage Real Costs $0
$5
$10
$15
$20
$25
$30
$35
6‐Hour Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$5
$10
$15
$20
$25
$30
$35
6‐Hour Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
DRAFT
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27.6. Utility‐Scale 8‐Hour Storage
Figure 232: Utility‐Scale 8‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 233: Utili ty‐Scale 8‐Hour Lithium‐Ion Battery Storage Real Costs $0
$5
$10
$15
$20
$25
$30
$35
$40
$45
8‐Hour Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$5
$10
$15
$20
$25
$30
$35
$40
$45
8‐Hour Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.7. Utility‐Scale 10‐Hour Storage
Figure 234: Utility‐Scale 10‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 235: Utili ty‐Scale 10‐Hour Lithium‐Ion Battery Storage Real Costs $0
$10
$20
$30
$40
$50
$60
10‐Hour Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$10
$20
$30
$40
$50
$60
10‐Hour Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.8. Commercial 4‐Hour Storage
Figure 236: Commercial 4‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 237: Commercial 4 ‐Hour Lithium‐Ion Battery Storage Real Costs $0
$5
$10
$15
$20
$25
$30
Commercial Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$5
$10
$15
$20
$25
$30
Commercial Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.9. Residential 2.5‐Hour Storage
Figure 238: Residential 2.5‐Hour Lithium‐Ion Battery Storage Nominal Costs Figure 239: Residential 2.5 ‐Hour Lithium‐Ion Battery Storage Real Costs $0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Residential Battery Storage (Nominal $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Residential Battery Storage (Real 2023 $/kW‐mo)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.10. Fuel Cells
Figure 240: Fuel Cells Nominal Costs
Figure 241: Fuel Ce lls Real Costs
$0
$10
$20
$30
$40
$50
$60
$70
Fuel Cells (Nominal $/kW‐mo)
EIA 2023 AEO IRP ‐ Base IRP ‐ Low IRP ‐ High
$0
$10
$20
$30
$40
$50
$60
Fuel Cells (Real 2023 $/kW‐mo)
EIA 2023 AEO IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.11. Land‐Based Wind
Figure 242: Land‐Based Wind Nominal Costs
Figure 243: Land‐Base d Wind Real Costs
$0
$10
$20
$30
$40
$50
$60
$70
$80
Land‐Based Wind (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High Indicative Wind Bid
$58/MWh
±20% range: $46‐
70/MWh
$0
$10
$20
$30
$40
$50
$60
$70
Land‐Based Wind (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High Indicative Wind Bid
$55/MWh (Real 2023$)
±20% range: $44‐66/MWh (Real
2023$)
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27.12. Offshore Wind
Figure 244: Offshore Wind Nominal Costs
Figure 245: Offs hore Wind Real Costs
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
Offshore Wind (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High $0
$20
$40
$60
$80
$100
$120
$140
$160
$180
Offshore Wind (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High
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27.13. Geothermal
Figure 246: Geothermal Nominal Costs
Figure 247: Geot hermal Real Costs
$0
$20
$40
$60
$80
$100
$120
$140
Geothermal (Nominal $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High Indicative Geothermal Bid
$90/MWh
±20% range: $72‐108/MWh
$0
$20
$40
$60
$80
$100
$120
Geothermal (Real 2023 $/MWh)
NREL High‐Low Range NREL Moderate IRP ‐ Base IRP ‐ Low IRP ‐ High Indicative Geothermal Bid
$81/MWh (Real 2023$)
±20% range: $65‐$98/MWh (Real
2023$)
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Renewable Portfolio
Standard
Procurement Plan
Still Under Development and Review
Appendix 28
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Table of Contents
1. Executive Summary 265
2. Disclaimer 266
3. Portfolio Content Category Requirements 266
4. Renewable Portfolio Standard Procurement Plan 268
4.1. Supply vs. Load .............................................................................................................................................................. 268
5. Compliance Strategy 269
6. Balanced Portfolio 270
7. PWP’s Renewable Portfolio Standard a nd Carbon-Free Strategy 270
8. PWP’s Renewable Portfolio Standard Procurement Process 271
8.1. Quantitative Analysis .................................................................................................................................................. 272
8.2. Qualitative Analysis..................................................................................................................................................... 272
9. Summary of Renewable Portfolio Standa rd Procurement Plan 273
10. Renewable Portfolio Standard Procurement Plan Limitations and Relief 277
11. Version History 277
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Table of Figures
Figure 1: Renewable Resource Categories and State Renewable Portfolio Standard Requirements ................................ 267 Figure 2: 2023 Integrated Resource Plan Updated Load Projection ................................................................................... 269 Figure 3: PWP SB 100 Procurement Plan from 2023 IRP .................................................................................................. 2741 Figure 4: PWP SB 100 Procurement Plan from 2023 IRP ……………………………………………………………………………………………….274
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1. Executive Summary
In late 2018, Pasadena City Council (City Council) approved Pasadena Water and Power’s (PWP) Renewable Portfolio Standard (RPS) Procurement Plan to comply with Senate Bill 100 (SB 100). SB 100 mandates a 60% RPS by 2030 and sets a planning target of 100% zero carbon resources by 2045. 159 The City Council also approved the Pasadena Climate Action Plan in 2018, which strives for a 52% reduction (compared to 1990) in citywide greenhouse gas (GHG) emissions associated with energy, transportation, water, and solid waste by 2035. In 2022, SB 1020 expanded the 100% zero‐carbon by 2045 goal of SB 100 by adding interi m targets to accelerate the adoption timeline. On January 30, 2023, the City Council adopted Resolution 9977, which declares a climate emergency in Pasadena and sets a policy goal to source 100% of Pasadena’s electricity from carbon‐free sources by 2030. This target is more ambitious than California and directs the City Manager to utilize the 2023 Inte
grated Resource Plan (IRP) process to plan multiple approaches to transition to the goal in a way that optimizes affordability, rate equity, stability, and reliability of electricity while achieving the goal.
This procurement plan a guide to ensure compliance with SB 100, SB 1020, and other state requirem ents. PWP will endeavor to investigate and pursue achievement of Resolution 9977’s goals in accordance with best utility practices as described below in Section 7, PWP’s Renewable Portfolio Standard and Carbon‐Free Strategy. The following are the primary changes in this revised RPS Procurement Plan:
Annual renewable ene
rgy targets will reflect reasonable progress in the intervening years between RPS milestones and will be set at the greater of (i) the City of Pasadena’s RPS goal or (ii) the State of California RPS goal of SB 100. Pursuant to SB 350 and the City of Pasadena’s RPS Enforcement Program, PWP will incorporate the most recen t RPS Procurement Plan into future iterations of the IRP. The following changes in Pasadena’s contracted RPS resources are reflected in this RPS Procurement Plan:
Update to potential contracts, as presented in the 2023 IRP. Given the number of variables and unce rtainties related to actual resource performance and net retail load, it is difficult to precisely match the amount of renewable energy procured for each year to the RPS requirements. PWP’s RPS portfolio optimization strategy to achieve the target RPS at the lowest cost to Pasadena customers includes the following:
To the extent available and consistent with Pasadena City Council goals, maximizing the use of lower cost cate
gories (e.g., Portfolio Content Category (PCC) 2 and PCC 3), within resource balancing requirements, to meet the target RPS goals.
Limiting the amount of renewable energy and renewable energy credits (REC) that are actually retired in each PCC
each year to the targeted amount. Any surplus is carried over to the following year(s) as long as the RECs can be retired within 36 months of generation. 159 60% of retail sales as explained below.
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2. Disclaimer
This RPS Procurement Plan describes the intended strategy of PWP to comply with the RPS requirements of California SB X1‐2, SB 350, SB 100, and the RPS Enforcement Program adopted by the Pasadena City Council on December 5, 2023. The RPS Enforcement Program and this RPS Procurement Plan incorporate the regulations established by the California Energy Commission (CEC) regarding Publi
c Utilities Code Section 399.30 (l), as such interpretations of the law are codified in the California Code of Regulations, Title 20, Division 2, Chapter 13, Sections 3200 through 3208, and in Title 20, Division 2, Chapter 2, Article 4, Section 1240. This RPS Procurement Plan addresses not only California’s state‐ wide RPS requirements but also the City of Pasadena’s RPS goal, as affirmed in the 2015 IRP Update.
3. Portfolio Content Category Requirements
The CEC developed Enforcement Procedures for the RPS for local publicly‐owned utilities (POU), which specify rules and procedures for compliance with the provisions of the California Public Utilities Code as modified by SB X1‐2, SB 350, SB 100, and SB 1020. This Procurement Plan is consistent with the latest version of the CEC Enforcement Procedures and the City of Pasadena’s RPS Enfo
rcement Program. 160
The following categories of renewable resources may be used to meet statutory RPS procurement targets (these categories are defined in the City of Pasadena RPS Enforcement Program and CEC Enforcement Procedures):
Portfolio Content Category (PCC) 0
Resources procured prior to June 1, 2010
PCC 1
Eligible renewable energy resource e lectricity that meets the requirement of in‐state or out‐of‐state resources scheduling power directly to a California balancing authority in accordance with Public Utilities Code section 399.16(b)(1)
PCC 2
Resources located outside a California balancing authority that may be delivered at times or locations other than when the ener
gy is actually produced, in accordance with Public Utilities Code Section 399.16(b)(2) PCC 3
Eligible renewable energy resource electricity products or any fraction of the electricity generated, including unbundled RECs that do not qualify under the criteria of PCC 1 or PCC 2, in accordance with Public Utilities Code Section 399.16(b)(3)
160 CEC: “Enforcement Procedures For The Renewables Portfolio Standard For Local Publicly Owned Electric Utilities,” Amended Regulations, Title 20, Division 2, Chapter 13, Sections 3200 – 3208, Title 20, Division 2, Chapter 2, Article 4, Section 1240; Effective April 2016 ‐ CEC‐300‐2016‐002‐CMF; and Pre‐Rulemaking Amendments to the Enforcement Procedures for the Renewables Portfolio Standard for Lo
cal Publicly Owned Electric Utility (Sections 3200 through 3208)
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The Ne
t Procurement Requirement is the total RPS requirement minus the grandfathered PCC 0 resources, which count in full. PWP assigns eligible renewable energy resource electricity products to the appropriate PCC consistent with Section A.3 of the City of Pasadena RPS Enforcement Program and the CEC Enforcement Procedures, Section 3203.
Under the CEC’s Enforcement Procedures, all local POUs must show an increas ing annual renewable energy procurement to demonstrate reasonable progress toward reaching the mandated 60% by calendar year 2030. PWP must procure a minimum quantity of electricity products from eligible renewable energy resources, including RECs, as a specified percentage of retail sales. Retail sales are defined in the RPS Enforceme nt Program as sales of electricity by a POU to end‐ use customers and their tenants, measured in MWh minus energy consumption by a POU, electricity used by a POU for water pumping, or electricity produced for onsite consumption (self‐generation). Annually, PWP uses approximately 16 GWh (or about 1.6% of tota
l load) of electricity for water pumping. 161 SB 350 further clarifies that retail sales may exclude sales to customers taking service under the optional Green Power Option or any shared renewable generation program to achieve the following RPS targets.
Figure 1 summarizes the renewable energy procurement requirements under the CEC Enforcement Procedures, Pasadena’s RPS Enforcement Program, and the potential requirements under SB 100 (the SB 100 requirements are estimates, as the CEC Enforcement Procedures have not been updated for SB 100 compliance).
Figure 1: Renewable Resource Categories and State Renewable Portfolio Standard Requirements PWP CEC‐Compliant RPS Procurement Plan Requirements by Calendar Year Requirement Compliance
Period 3
Compliance
Period 4
Compliance
Period 5
Compliance
Period 6
Compliance
Period 7
California RPS
Mandatory
Procurement
Requirement (% of
Net Retail Sales)162, 163
Year %
44% by
December 31,
2024
52% by
December 31,
2027
60% by
December 31,
2030
2031+
(3 year blocks)
60%
2017 27%
2018 29%
2019 31%
2020 33%
PCC 1 Minimum ≥75% of Net Procurement Requirement
PCC 2 Maximum164 ≤15% of Net Procurement Requirement
PCC 3 Maximum ≤10% of Net Procurement Requirement
Long‐Term Contracts
(at least 10 years
duration)
N/A At least 65% of contracts must be long‐term contracts (at least 10 years in duration)
161 1 GWh = one Gigawatt hour = one million kilowatt hours. 162 As specified in the CEC Guidebook and CEC Enforcement Procedures. 163 Net Retail Sales is defined as Total Retail Sales minus Department usage including Water Department pumping load. 164 The PCC 2 constraint is not specified by law but is derived logically as the maximum residual given the PCC 1 and PCC 3 constraints.
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For
a customer participating in the Green Power Option or any shared renewable generation project, the RECs associated with electricity credited to such customer under the program will not be used by PWP for compliance with state mandated RPS procurement requirements. The RECs will be retired on behalf of the participating customer and may not be fu rther sold, transferred, or otherwise monetized for any purpose. Under these programs, PWP will seek to procure generation from eligible renewable energy resources that are located in reasonable proximity to participants to the extent possible.165 Details of the above requirements can be found in the CEC’s Enforcement Procedures for Local Publicly Owned Utilities and Pre‐Rulemaking Amendments to the Enforcement Procedures.
4. Renewable Portfolio Standard Procurement Plan
4.1. Supply vs. Load
This Procurement Plan is consistent with the renewable energy procurement guidelines recommended by the 2023 IRP.
The PWP 2023 IRP was designed to strike a balance between environmental regulatory compliance and system reliability while maintaining stable and affordable retail electric rates. It also complies with the requirements of SB 350, SB 100, and SB 1020. The 2023 IRP projects that PWP’s reta
il sales will increase due to increased electrification efforts. The gap between the gross and net forecast is due to demand response, energy efficiency and distributed generation. This trend is shown in Figure 2.
165 PUC Section 399.30(c)(4)
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Figure 2: 2023 Integrated Resource Plan Updated Load Projection Though the SB 100
mandates require POUs to procure 60% of their retail needs through renewable power by 2030, PWP must strike a balance of meeting this need while being mindful of its cost, reliability, and sustainability obligations and priorities. Over or under procuring renewable energy in comparison to requirements come with risks and opportunitie s.
Private use restrictions on generation projects financed with municipal bonds, and on the sale of power from the federally‐ owned and operated Hoover power project, generally require that these projects be dedicated to serving PWP’s load and not resold. IPP is expected to be repowered with a smaller natural gas‐fired project in 2025. Much of the shortfall in capacity and energy after that date is pl
anned to be fulfilled with renewable or zero‐carbon energy resources. To mitigate a variety of risks, PWP will seek to ensure an appropriate mix of various RPS and other products as part of a diversified power supply portfolio.
5. Compliance Strategy
PWP starts with a projected load forecast based on actual historical loads, assuming load growth for planned projects and electrification, offset by expected distributed generation, demand side‐management and projected energy efficiency savings. PWP’s RPS procurement requirement is calculated by multiplying the load forecast for each year (in GWh) by the required annual RPS percentage for that year to co
me up with the amount of renewable energy (in GWh) required by year (the annual RPS Total Procurement Requirement). 166
166 1 GWh = one Gigawatt hour = one million kilowatt hour (kWh) ‐
500,000
1,000,000
1,500,000
2,000,000
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
2042
2044
2046
2048
2050
Retail Sales (MWh)
Retail Sales
Retail Sales (Historical)
Retail Sales (Future)
Retail Sales (Future) With Energy Efficiency & Distributed Solar Removed Energy efficiency and
distributed solar reduce load
Electrification increases load
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Next, PWP
subtracts the amount of energy that is expected to be delivered from the existing resources. First, the existing, grandfathered contracts in PCC 0 are subtracted from load. The resulting number is the RPS Net Procurement Requirement. Next, PWP subtracts the amount of energy that is expected to be delivered from the exist ing resources procured by PWP by PCC and Compliance Period.
In meeting the RPS procurement requirements identified in this RPS Procurement Plan, PWP is required to meet the long‐ term contract requirements per Public Resources Code § 399.13(b). Beginning January 1, 2021, a minimum of 65% of PWP’s RPS resource procurement shall be from its contracts that have terms of 10 years or more or in its ownership or ownership agreements for eligible renewable energy resources.
6. Balanced Portfolio
After determining the amount of energy already procured in each year, each PCC, and each Compliance Period, PWP must determine the amount of RPS procurement still required. This requires a calculation of the RPS procurement constraints and a comparison of annual energy procurement against these constraints to determine if future compliance targets (or obligations) will require additional purchases of PCCs. The final ca lculation is the net short evaluation. If the sum of existing contracts is less than the total required RPS Net Procurement Requirement energy for the year, the difference is the amount that must be procured, and allocated to the PCCs according to the constraints. Any surplus renewable energ y and/or credits in a year may be carried over into the following year, and the RPS Net Procurement Requirement adjusted accordingly.
In addition to balancing between PCCs and compliance periods, PWP must consider the right mix of resources to fit PWP’s portfolio and load as it evaluates RPS proposals. PWP evaluates its existing RPS portfolio and re maining future needs to develop a diverse portfolio of different technology types (e.g., wind, solar, geothermal). Further, PWP evaluates the right mix of contract durations to meet the long‐term contract requirements and balancing ongoing needs with short term opportunities. Additionally, PWP
expects to contract with a diversified set of counterparties, which in the procurement process are evaluated for deliverability and performance risk to mitigate risk of delays and project failure. PWP also factors in aspects of geographic diversity to further mitigate deliverability risk.
7. PWP’s Renewable Portfolio Standard and Carbon‐Free Strategy Above and beyond the mandatory RPS procurement requirements under SB 350 and SB 100, PWP’s target of 100% carbon‐ free resources by 2030, a policy goal set by City Council, requires the additional procurement of carbon‐free resources.
Additional procurement will occur as PWP is able to secure resources beyond meeting regulatory requirements and replacing In
termountain Power Plant with carbon‐free resources by 2027, while balancing cost and other considerations.
In all scenarios, a significant amount of wind, solar, storage, and fuel cells are added by 2031. Scenarios 1‐3, which all meet 100% carbon‐free by the end of 2030, require 700 – 1,300 MW of new installed capaci ty over the next eight years (see Figure 3). Compared to PWP’s current resources of around 400 MW, this is a transformational amount of resources. In case a particular resource type is unobtainable according to the timeline, and in the quantity specified below, PWP could exercise alternative resources to make up the shortfall. Througho ut this initial period through 2031, PWP will carefully monitor the procurement progress and recommend adjustments as new information or technology emerges.
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Successfully procuring thi
s level of new capacity will require a coordinated effort in order to source projects, conduct due diligence, perform evaluations, negotiate contracts, secure approval, sign contracts, and ultimately see projects through to their commercial operations date. There will be continual Requests for Proposals for the carbon‐free resources that will help shape the optimal mix of resources
in PWP’s Power Supply at best fit and least cost portfolio.
Figure 3: Cumulative New Resource Installed Capacity Through 2031 (MW) Solar Wind
Battery
Storage Fuel Cell Geothermal
Scenario
Total
Scenario 1 300 285 115 700
Scenario 2 615 30 665 35 10 1,355
Scenario 3 480 60 598 35 20 1,193
Scenario 4 5 250 130 385
Scenario 5 5 610 60 675
8. PWP’s Renewable Portfolio Standard Procurement Process Because PWP is a relatively small municipal utility, it solicits most of its long‐term renewable resources through open requests for proposals (RFP) conducted by its joint powers authority SCPPA (Southern California Public Power Authority).167 This allows PWP and other SCPPA members to purchase the output of portions of multiple diverse projects and gain economies of scale, rather than limit the projects that they would be capable of participating in due to the comparatively small demand of most of the individual utilities. PWP anticipates dividing its outstanding RPS procurement betwee
n different resource technologies and seeking some long‐term and mid‐term contract terms. In this case, PWP defines long‐term as ten years or longer, and mid‐term as five to ten years. PWP may procure some RECs and/or PCC 2 products with shorter tenures. PWP will also seek products with ener gy pricing tied to electricity market indices as well as fixed priced.
The SCPPA RFPs are considered an open and “rolling” solicitation, generally issued in January, with responses accepted through December each year. The SCPPA RFP solicits proposals for power purchase agreements with and without ownership options and also invites energy storage and innovative proposals. PWP initially s creens prospective renewable resource proposals received through SCPPA and through direct contact with renewable project developers based on the levelized offer price ($/MWh or $/kW‐month) for resources with a project size and proposed delivery period that matches PWP’s procurement targets. For larger projec ts, joint participation with other SCPPA members may be desirable to obtain the best project economics and contract terms.
167 SCPPA = Southern California Public Power Authority, which includes the cities of Anaheim, Azusa, Banning, Burbank, Cerritos, Colton, Glendale, Los Angeles Dept. of Water & Power, Pasadena, Riverside, Vernon, and the Imperial Irrigation District.
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8.1. Quantitative Analysis
From the short‐list of projects that pass the initial screening, PWP evaluates and compares proposals to identify the “least cost/best fit” opportunities. Best fit analysis considers PWP’s projected needs in light of its existing portfolio of generating resources and contracts. For example, considerations include: RPS targets and other regulatory requirements, grid and local area reliability needs, projected lo
ad and generation profiles, the estimated commercial operation or contract start date, and proposed contract term (duration). Variables can include the following:
Generation cost
Risk analysis of time‐of‐delivery value under various market price scenarios Capacity value
Congestion hedge value at the point of delivery
Ancillary service value 168
Value
of environmental attributes by PCC
Costs of integrating variable generation technologies Incremental transmission costs excluding current CAISO load‐ based transmission access and grid management charges
Costs and deliverability status associated with CAISO load‐ based transmission access and grid management charges
8.2. Qualitative Analysis
In addition to the quantitative evaluation, PWP performs a qualitative evaluation using a process similar to that employed by California investor‐owned utilities to rate project viability. Project viability can refer to the following:
Project owner/development team experience developing, owning, operating and/or maintaining similar projects and technical feasibility
The proposed resource must be a commerciali zed technology in use at other operating facilities of similar or larger capacity
Must meet the California Emission Performance Standard Must be pre‐certified by the CEC as an eligible renewable resource The proposal must include high quality resource production profile estimates There should not be any known or anticipated manuf acturing supply chain constraints Identified available water source and minimal water consumption 168 Ancillary Services are required to support the transmission of energy from generation resources to loads while maintaining reliable operation of the electric grid in accordance with regional reliability standards and good utility practice. Ancillary Services include Regulation, Spinning Reserve, Non‐Spinning Reserve, Voltage Support and Black Start, each as defined in the CAISO Tariff.
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Development milestones
Site control
Permitti
ng
Status of and ability to obtain financing
Interconnection progress
Transmission system and deliverability upgrade requirements/schedule Reasonableness of proposed commercial operation or contract start date In addition to project viability, PWP’s qualitative evaluation also considers the following factors:
Risk exposure diversificati on
Counterparty creditworthiness and willingness to post collateral Resource flexibility and optionality
California’s Energy Action Plan preferred loading order Preference for previously disturbed and brownfield sites, or locations in designated Renewable Energy Zones Local and certified small or micro business preference
9. Summary of Renewable Portfolio Standard Procurement Plan PWP’s 2023 RPS Procurement Plan for meeting the RPS goals is outlined in, with the appropriate PCC and RPS targets required under the CEC Enforcement Procedures. To optimize the portfolio and minimize costs, this Procurement Plan assumes PWP retires only the amount of RECs required in each PCC in any particular year and carries over the remainder into future periods. The pendi
ng contracts listed in Figure 4 refer to planned future contracts to meet compliance requirements. The 2023 RPS Procurement Plan is an estimate only to show PWP’s intent to comply with SB 100.
When reviewing the 2023 RPS Procurement Plan, it is important to note the following:
CP refers to Compliance Period
CP 4,
CP 5, and CP 6 are based on PWP estimates
TBD is to be determined based on contract negotiations and the 2018 IRP Update Planned refers to projects that are under negotiation, or plan to be under negotiation in that CP
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Figure 4: PWP SB 100 Procurement Plan from 2023 IRP
2023 – 2024 (Partial Compliance Period
4)169 Compliance Period 5 Compliance Period 6
Calendar Year (CY) 2021 ‐ 2024 2025 ‐ 2027 2028 ‐ 2030 Estimated PWP Adjusted
Projected Retail Sales
(MWh)
2,064,129 3,417,985 3,579,142
Estimated Requirement
Procurement for CP (MWh) 879,914 1,687,019 2,053,186 Grandfathered Projects
Resource Resource
Type Location Online
Year PCC Partial Compliance
Period 4 (GWh)
Compliance Period 5
(GWh)
Compliance Period
6 (GWh)
Biofuels: Chiquita Landfill Biofuels CA 2010 PCC0 75,002 106,606 97,569 Wind: PPM (Avangrid) Wind Wind CA 2003 PCC0 5,648 ‐ ‐ Wind: Milford Wind Wind UT 2009 PCC0 19,055 28,754 17,996 Total Grandfathered Owned or Contracted Projects 99,705 135,360 115,566 Non‐Grandfathered Owned or Contracted Projects
Resource Resource
Type Location Online
Year PCC Partial Compliance
Period 4 (GWh)
Compliance Period 5
(GWh)
Compliance Period
6 (GWh)
Biofuels: Puente Hills
Landfill Biofuels CA 2014 PCC1 59,790 89,527 89,142 Solar PV: Antelope Solar Solar PV CA 2012 PCC1 30,823 46,116 44,725 Solar PV: Kingbird Solar Solar PV CA 2013 PCC1 114,972 172,485 167,340 Solar PV: Columbia Two
Solar Solar PV CA 2013 PCC1 14,672 21,991 21,320 Solar PV: Summer Solar Solar PV CA 2012 PCC1 30,825 46,119 44,727 169 Compliance shown for 2023 – 2024.
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Solar PV: Windsor Reservoir
Solar Solar PV CA 2010 PCC1 2,639 3,962 3,828
Geothermal: Coso
Geothermal Geothermal CA 2027 PCC1 ‐ 72,375 214,730 Geothermal: Calpine
Geysers Geothermal CA 2027 PCC1 ‐ 194,910 578,280 Solar PV: EDF Sapphire Solar Solar PV CA 2027 PCC1 0 110743 321581 Total Non‐Grandfathered Owned or Contracted Projects 253,722 758,228 1,485,675 Non‐Grandfathered Generic Projects (Scenario 4)
Resource Resource
Type Location Online
Year PCC Compliance Period 4
(GWh)
Compliance Period 5
(GWh)
Compliance Period
6 (GWh)
Wind: New Land‐Based
External Wind Wind WECC
Region
TBD (250
MW in
2025)
PCC1 ‐ 2,302,196 2,255,532
Wind: New Land‐Based
External Wind (Storage
Paired)
Wind WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New External Solar Solar PV WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New External Solar
(Storage Paired) Solar PV WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New Internal Solar Solar PV WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New Community
Solar Solar PV WECC
Region
TBD (5
MW in
2025)
PCC1 ‐ 42,692 41,298
Solar PV: New Internal Solar
(Storage Paired) Solar PV WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New Commercial
Solar Solar PV WECC
Region PCC1 ‐ ‐ ‐
Solar PV: New Residential
Solar Solar PV WECC
Region PCC1 ‐ ‐ ‐
Geothermal: New External
Geothermal Geothermal WECC
Region PCC1 ‐ ‐ ‐