2023 Integrated
Resource Plan
IRP filing for submission to the
California Energy Commission
Pasadena Water and Power
Still Under Development and Review
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TABLE OF CONTENTS
1. Acronyms Used in PWP’s IRP 15
2. Disclaimer 18
3. Executive Summary 18
4. Introduction 20
4.1. Introduction .............................................................................................................................................. 20
4.2. Pasadena Water and Power Department .................................................................................................... 22
4.2.1. Pasadena Executive Management and Governing Bodies .............................................................................................. 25
4.2.2. Regulatory Agencies........................................................................................................................................................ 26
4.3. Statutory Mandate for Integrated Resource Plans ....................................................................................... 27
4.4. Community Outreach ................................................................................................................................. 28
4.5. Integrated Resource Plan Objectives .......................................................................................................... 29
4.6. Integrated Resource Plan Process and Timeline .......................................................................................... 30
4.7. 2023 Integrated Resource Plan Timeline ..................................................................................................... 30
5. Previous Integrated Resource Plans 31
6. Existing Policies and Programs 32
6.1. Distributed Solar ........................................................................................................................................ 33
6.1.1. Current Programs ............................................................................................................................................................ 33
6.1.2. Net Energy Metering ....................................................................................................................................................... 33
6.1.3. Community Solar ............................................................................................................................................................ 34
6.2. Electric Vehicles ......................................................................................................................................... 34
6.2.1. Current Electric Vehicle Incentives ................................................................................................................................. 35
6.2.2. Current Electric Vehicle Outreach................................................................................................................................... 35
6.2.3. Current Electric Vehicle Fleet .......................................................................................................................................... 35
6.2.4. EV Charging Stations ....................................................................................................................................................... 38
6.2.5. Pasadena’s Department of Transportation Initiatives .................................................................................................... 39
6.2.6. Vehicle-to-Grid Charging ................................................................................................................................................. 39
6.3. Energy Efficiency ........................................................................................................................................ 40
6.3.1. Current Program Incentives ............................................................................................................................................ 40
6.3.2. Residential Programs ...................................................................................................................................................... 41
6.3.3. Energy Efficiency Regulations ......................................................................................................................................... 42
6.3.4. Energy Efficiency Forecast and Goals ............................................................................................................................. 44
6.4. Demand Response ..................................................................................................................................... 45
6.4.1. Current Demand Response Programs ............................................................................................................................. 45
6.4.2. Future Demand Response Programs .............................................................................................................................. 46
6.5. Green Power Program ................................................................................................................................ 46 DRAFT
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6.5.1. Residential Green Power Program .................................................................................................................................. 46
6.5.2. Commercial Green Power Program ................................................................................................................................ 46
6.6. Low-Income Assistance Programs ............................................................................................................... 46
6.6.1. Income-Qualified Programs ............................................................................................................................................ 47
6.6.2. General Bill Assistance .................................................................................................................................................... 48
7. Public Participation 48
7.1. Stakeholder Technical Advisory Group........................................................................................................ 50
7.2. STAG Meetings .......................................................................................................................................... 50
7.3. Community Meetings ................................................................................................................................. 51
7.4. Public Outreach ......................................................................................................................................... 51
7.5. Municipal Service Committee and Environmental Advisory Commission Meetings ...................................... 51
8. Environmental Regulations and Priorities 51
8.1. PWP’s Environmental Priorities .................................................................................................................. 51
8.2. Renewable Portfolio Standard and Zero-Carbon Regulations....................................................................... 52
8.2.1. State Compliance ............................................................................................................................................................ 53
8.3. Cap-and-Trade Regulation .......................................................................................................................... 56
8.4. Other Environmental Points of Note ........................................................................................................... 57
8.4.1. Power Source Disclosure Program .................................................................................................................................. 57
8.4.2. The Cost Impacts of 100% by 2045 ................................................................................................................................. 57
8.4.3. Social Cost of Carbon ...................................................................................................................................................... 58
9. Resource Adequacy 58
9.1. System Resource Adequacy and Reserve Margin......................................................................................... 59
9.2. Local Resource Adequacy Capacity ............................................................................................................. 60
9.3. Flexible Resource Adequacy Capacity ......................................................................................................... 61
9.4. Slice of Day Proposal .................................................................................................................................. 62
9.4.1. Reliability Must-Run Resources ...................................................................................................................................... 62
10. Model Assumptions 64
10.1. Planning Horizon (POUs) ............................................................................................................................ 64
10.2. Model ........................................................................................................................................................ 64
10.3. Model Topology ......................................................................................................................................... 66
10.4. Power and Fuel Prices ................................................................................................................................ 67
10.4.1. More About Horizons Energy, LLC’s Forecasting Method .............................................................................................. 69
10.5. Transmission and Congestion ..................................................................................................................... 70 DRAFT
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10.6. Load vs. Resources ..................................................................................................................................... 71
11. Resources 73
11.1. Existing Resources...................................................................................................................................... 73
11.1.1. Coal ................................................................................................................................................................................. 75
11.1.2. Natural Gas ..................................................................................................................................................................... 75
11.1.3. Wind ................................................................................................................................................................................ 76
11.1.4. Landfill Gas ...................................................................................................................................................................... 76
11.1.5. Solar ................................................................................................................................................................................ 76
11.1.6. Hydro .............................................................................................................................................................................. 76
11.1.7. Nuclear ............................................................................................................................................................................ 76
11.1.8. Geothermal ..................................................................................................................................................................... 76
11.2. New Resources .......................................................................................................................................... 76
11.2.1. New Resource Options ................................................................................................................................................... 76
11.2.2. New Resource Parameters .............................................................................................................................................. 77
11.2.3. Availability of New Resources ......................................................................................................................................... 80
11.2.4. Inflation Reduction Act and Tax Credits .......................................................................................................................... 81
11.2.5. Contract vs. Ownership and Tax Credits ......................................................................................................................... 84
11.2.6. Cost of New Resources: The General Market ................................................................................................................. 85
11.2.7. Pasadena in the Market .................................................................................................................................................. 86
11.2.8. Spotlight Technologies .................................................................................................................................................... 90
11.2.9. How Electricity Products Are Priced ............................................................................................................................... 93
11.2.10. Cost vs. Value .................................................................................................................................................................. 95
11.2.11. Transmission Access Charge ........................................................................................................................................... 95
11.2.12. Exclusions and Other Notes ............................................................................................................................................ 96
11.3. Diversified Procurement Portfolio .............................................................................................................. 96
12. Load Forecast 97
12.1. Requirements ............................................................................................................................................ 97
12.2. Integrated Energy Policy Report and California Energy Demand Forecast..................................................... 98
12.3. Integrated Resource Plan Method ............................................................................................................ 100
12.3.1. Additional Achievable Energy Efficiency ....................................................................................................................... 102
12.3.2. Additional Achievable Fuel Substitution ....................................................................................................................... 105
12.3.3. Distributed Solar ........................................................................................................................................................... 106
12.3.4. Distributed Storage ....................................................................................................................................................... 107
12.3.5. Time-of-Use Rates ......................................................................................................................................................... 108
12.3.6. Vehicle Electrification ................................................................................................................................................... 110
12.3.7. Climate Change ............................................................................................................................................................. 114
12.3.8. Native Load ................................................................................................................................................................... 114
12.3.9. CAISO Metered Load ..................................................................................................................................................... 115
13. Transmission and Distribution 121
13.1. Bulk Transmission System ........................................................................................................................ 121 DRAFT
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13.2. Bulk Transmission Planning ...................................................................................................................... 121
13.3. Distribution System Planning ................................................................................................................... 121
14. Localized Pollutants and Disadvantaged Communities 123
14.1. Emissions Reduction ................................................................................................................................ 124
14.2. Expanding Transportation Electrification in Pasadena’s DAC ..................................................................... 125
14.2.1. EV Rebates and Incentives ............................................................................................................................................ 125
14.2.2. Efficiency and Assistance Programs .............................................................................................................................. 126
14.3. Supporting Underserved Communities in the Future ................................................................................. 127
15. Defining Scenarios 127
15.1. Scenarios vs. Sensitivities ......................................................................................................................... 127
15.2. Important Definitions for Scenarios .......................................................................................................... 128
15.3. Scenario 1: 100% Carbon-Free by 2030 with No Limit on Internal Resources .............................................. 132
15.4. Scenario 2: 100% Carbon-Free by 2030 with a Limit on Internal Resources ................................................. 132
15.5. Scenario 3: 100% Carbon-Free by 2030 with a Limit on Internal Resources and Doubled Distributed Resources …………………………………………………………………………………………………………………………………………………………………………….133
15.6. Scenario 4: Reference Case (SB 1020) ....................................................................................................... 134
15.7. Scenario 5: Reference Case + Social Cost of Carbon (SB 1020 + SCC) ........................................................... 134
15.8. Scenario 6: Emerging Technology Study .................................................................................................... 136
15.8.1. Scenario 6: Energy Efficiency Proxy .............................................................................................................................. 137
15.8.2. Scenario 6: Demand Response Proxy ............................................................................................................................ 137
15.9. Modeling a Carbon-Free Resource Scenario .............................................................................................. 137
15.10. PWP’s Starting Position ............................................................................................................................ 139
16. Defining Sensitivities 143
16.1. Sensitivity 1: Heat Wave .......................................................................................................................... 144
16.1.1. Sensitivity 1: Heat Wave: Data Scraping and Cleaning ................................................................................................. 145
16.1.2. Sensitivity 1: Heat Wave: Normal Data Creation .......................................................................................................... 145
16.1.3. Sensitivity 1: Heat Wave: Training Datasets Creation ................................................................................................... 145
16.1.4. Sensitivity 1: Heat Wave: Prediction Data Creation...................................................................................................... 146
16.1.5. Sensitivity 1: Heat Wave: Model Creation and Prediction ............................................................................................ 146
16.2. Sensitivity 2: Goodrich Transfer Contingency ............................................................................................ 149
16.2.1. Sensitivity 2: Goodrich in 2030 Under Forecasted Normal Operating Conditions ....................................................... 149
16.2.2. Sensitivity 3: High Technology Costs ............................................................................................................................. 150
16.2.3. Sensitivity 4: Low Technology Costs ............................................................................................................................. 150
17. Scenarios and Sensitivities Results 150
17.1. Scenario 1: 100% Carbon-Free by 2030 (No Limit on Internal Resources) ................................................... 150 DRAFT
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17.2. Scenario 2: 100% Carbon-Free by 2030 – Maximum Limit on Internal Resources ........................................ 160
17.3. Scenario 3: 100% Carbon-Free by 2030 (Maximum Limit on Internal Resources and Doubled Distributed Resources) ......................................................................................................................................................... 165
17.4. Scenario 4: Reference Case (SB 1020) ....................................................................................................... 170
17.5. Scenario 5: Reference Case Plus Social Cost of Carbon ............................................................................... 176
17.6. Scenario 6: Emerging Technologies Study Scenario.................................................................................... 182
17.6.1. Scenario 6: Energy Efficiency Proxy .............................................................................................................................. 182
17.6.2. Scenario 6: Demand Response Proxy ............................................................................................................................ 183
17.7. Scenario Comparisons .............................................................................................................................. 183
17.8. Sensitivity 1: Heat Wave .......................................................................................................................... 190
17.9. Sensitivity 2: Goodrich Transfer Contingency ............................................................................................ 195
18. Battery Storage 197
18.1. Storage in the IRP .................................................................................................................................... 197
18.2. Storage: Over-Generation and Evening Ramps .......................................................................................... 198
18.3. Addressing Net Demand in Peak Hours ..................................................................................................... 201
19. Financial Impacts 202
19.1. Present Value Revenue Requirements ...................................................................................................... 202
19.2. Scenario 3 and Distributed Resources ....................................................................................................... 207
19.3. Scenario 5 and the Carbon Tax ................................................................................................................. 208
19.4. Scenarios and Cap-and-Trade Interactions ................................................................................................ 209
20. Retail Rates 210
21. Greenhouse Gas Emissions 215
21.1. Cap-and-Trade Program ........................................................................................................................... 216
21.2. Carbon Emissions Netting Market Interactions at CAISO Average Carbon Content ..................................... 216
21.3. RPS (SB 100) ............................................................................................................................................ 218
21.4. Renewable and Zero-Carbon (SB 1020) ..................................................................................................... 219
21.5. Carbon-Free Hourly (Resolution 9977) ...................................................................................................... 219
21.6. GEAT ....................................................................................................................................................... 220
22. Implementation Steps – Carbon-Free Pathways 221
22.1. PWP’s Preemptive Actions ....................................................................................................................... 222
22.1.1. Utility-Scale Photovoltaic Solar + Battery ..................................................................................................................... 222
22.1.2. Geothermal ................................................................................................................................................................... 222 DRAFT
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22.1.3. Additional Battery (Local) ............................................................................................................................................. 222
22.2. Resource Procurement Guided by the Results of this IRP .......................................................................... 222
22.3. Supplemental Near-Term Actions ............................................................................................................. 224
22.3.1. Explore DER Expansion and Refine Planning for Internal Resource Sizes and Placement; Revisit the PDMP .............. 224
22.3.2. Perform a More Extensive Study on the Future of Glenarm ........................................................................................ 225
22.3.3. Prepare for a Significant Increase in Expenditures Over the Next 20 Years ................................................................. 225
22.3.4. Perform a Cost-of-Service Study, Rate Impact Study, and Rate Ordinance Proposal ................................................... 225
22.3.5. 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. .............................................................. 225
22.3.6. Expand Demand-Side Management; Explore Advanced Metering Infrastructure Connection Incentives ................... 226
22.3.7. Determine the Future of PWP’s Green Power Program ............................................................................................... 226
22.3.8. Monitor the Influence of the Building Electrification Ordinance After It Becomes Effective in 2025 .......................... 226
22.3.9. Update the Pasadena Utility Code, Electrical Code, and Fire Code (for Batteries, Hydrogen Fuel Cells, etc.) ............. 226
22.3.10. Continue to Monitor Emerging Technology Developments ......................................................................................... 226
22.4. The Longer-Range Outlook ....................................................................................................................... 227
23. Appendix - Required Tables 228
23.1. Capacity Resource Accounting Table ......................................................................................................... 228
23.2. Energy Balance Table (Scenario 4 Example)............................................................................................... 229
24. Appendix – Integrated Resource Plan Contract and Resource Roles 231
25. Appendix – Opportunities for Future Studies and Analysis 232
26. Appendix – Model Parameters and Additional Reliability Metrics 236
27. Appendix – Cost of New Resources 245
27.1. Utility-Scale Solar ..................................................................................................................................... 245
27.2. Commercial Solar ..................................................................................................................................... 246
27.3. Residential Solar ...................................................................................................................................... 247
27.4. Utility-Scale 4-Hour Storage ..................................................................................................................... 248
27.5. Utility-Scale 6-Hour Storage ..................................................................................................................... 249
27.6. Utility-Scale 8-Hour Storage ..................................................................................................................... 250
27.7. Utility-Scale 10-Hour Storage ................................................................................................................... 251
27.8. Commercial 4-Hour Storage ..................................................................................................................... 252
27.9. Residential 2.5-Hour Storage .................................................................................................................... 253
27.10. Fuel Cells ................................................................................................................................................. 254
27.11. Land-Based Wind ..................................................................................................................................... 255
27.12. Offshore Wind ......................................................................................................................................... 256 DRAFT
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27.13. Geothermal ............................................................................................................................................. 257
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Table of Figures
Figure 1: Acronyms ............................................................................................................................................................... 15 Figure 2: California Energy Commission Guidelines and Location ........................................................................................ 20 Figure 3: Comparison of System Average Interruption Frequency Index and System Average Interruption Duration Index .............................................................................................................................................................................................. 23 Figure 4: Average Residential Bills, Measured at 750 kWh/Month ...................................................................................... 24 Figure 5: Average Commercial Bills, Measured at 3,500 kWh/Month (May 2023) .............................................................. 25 Figure 6: California Energy Commission Requirements ........................................................................................................ 28 Figure 7: PWP's 2023 Integrated Resource Plan Timeline .................................................................................................... 31 Figure 8: 2018 Integrated Resource Plan Progress ............................................................................................................... 31 Figure 9: 2021 Integrated Resource Plan Update Progress .................................................................................................. 32 Figure 10: Total Light-Duty Electric Vehicles on Grid ............................................................................................................ 37 Figure 11: Annual Sales of Light-Duty Electric Vehicles ........................................................................................................ 37 Figure 12: Map of Electric Vehicle Chargers in PWP’s Territory ........................................................................................... 39 Figure 13: PWP's Actual Cumulative Energy Efficiency Savings ............................................................................................ 42 Figure 14: Past Public Benefit Charge Budgets ..................................................................................................................... 43 Figure 15: Estimated Greenhouse Gas Emissions from Existing Homes and Businesses ..................................................... 43 Figure 16: Incremental Energy Efficiency Savings (MWh) .................................................................................................... 44 Figure 17: Incremental Energy Efficiency Savings (MW) ...................................................................................................... 45 Figure 18: Impact of Energy Efficiency and Customer-Owned Generation on Electric Sales ............................................... 45 Figure 19: Low-Income (Electric Utility Assistance Program) ............................................................................................... 47 Figure 20: California Alternate Rates for Energy (Age or Disability Qualification) ............................................................... 47 Figure 21: California Alternate Rates for Energy Plus (Age or Disability Qualification) ........................................................ 47 Figure 22: Comparison of the Composition of the 2018 STAG and the 2023 STAG ............................................................. 50 Figure 23: Renewable Portfolio Standard: Key Legislative Actions in California .................................................................. 52 Figure 24: Senate Bill 100 and Senate Bill 1020 Requirements ............................................................................................ 53 Figure 25: Portfolio Content Categories ............................................................................................................................... 54 Figure 26: RPS and Zero-Carbon Modeled Requirements .................................................................................................... 55 Figure 27: Solar Resource Adequacy Accreditation .............................................................................................................. 60 Figure 28: EnCompass Power Planning Software ................................................................................................................. 65 Figure 29: PWP Integrated Resource Plan Critical Model Constraints ................................................................................. 66 Figure 30: Model Topology ................................................................................................................................................... 66 Figure 31: SP15 7x24 Power Prices ....................................................................................................................................... 68 Figure 32: Fuel Prices ............................................................................................................................................................ 68 Figure 33: Fuel Pricing Assumed in PWP’s 2023 Integrated Resource Plan ......................................................................... 69 Figure 34: Transmission Access Charge Forecast .................................................................................................................. 71 Figure 35: Resources by Location ......................................................................................................................................... 72 Figure 36: Resource Category by Size ................................................................................................................................... 72 Figure 37: Owned and Contracted Resources ...................................................................................................................... 73 Figure 38: Contracts for Renewable Energy ......................................................................................................................... 74 Figure 39: New Resource Parameters ................................................................................................................................... 77 DRAFT
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Figure 40: Resource Adequacy Accreditation for New Resources ........................................................................................ 79 Figure 41: Bonus Tax Credits for Renewable Resources ....................................................................................................... 82 Figure 42: IRA Tax Credits for Projects in Service After December 2024 ............................................................................. 83 Figure 43: PWP 2023 Integrated Resource Plan Tax Credit Assumptions ............................................................................ 83 Figure 44: Domestic Content Requirements ......................................................................................................................... 85 Figure 45: Reference Market Prices ...................................................................................................................................... 86 Figure 46: Utility-Scale Solar Nominal Pricing ....................................................................................................................... 87 Figure 47: Utility-Scale Solar Pricing in Real 2023 $ .............................................................................................................. 88 Figure 48: Real vs. Nominal Values ....................................................................................................................................... 89 Figure 49: Real vs. Nominal Levelized Cost of Energy ........................................................................................................... 89 Figure 50: Different Components of Electricity .................................................................................................................... 93 Figure 51: Different Components of Electricity by Resource Type ....................................................................................... 94 Figure 52: Cost of New Energy Resources ............................................................................................................................ 94 Figure 53: Cost of New Capacity Resources .......................................................................................................................... 95 Figure 54: Transmission Access Charge ................................................................................................................................ 96 Figure 55: Diversity in Load Consumption and Resource Generation .................................................................................. 97 Figure 56: California Energy Demand Forecast Components ............................................................................................... 98 Figure 57: PWP Peak Demand ............................................................................................................................................. 101 Figure 58: PWP Energy ........................................................................................................................................................ 102 Figure 59: Technical, Economic, and Market Potential for Energy Efficiency .................................................................... 104 Figure 60: Additional Achievable Energy Efficiency in PWP’s 2023 Integrated Resource Plan .......................................... 105 Figure 61: Additional Achievable Energy Efficiency Percent Reduction in Load ................................................................ 105 Figure 62: AAFS in PWP’s 2023 IRP ..................................................................................................................................... 106 Figure 63: Distributed Solar in PWP’s 2023 IRP .................................................................................................................. 107 Figure 64: Distributed Storage in 2023 IRP ......................................................................................................................... 108 Figure 65: Time-of-Use Rates in PWP’s 2023 Integrated Resource Plan ............................................................................ 109 Figure 66: Average Hourly Impact of Time-of-Use Rates in PWP’s 2023 Integrated Resource Plan .................................. 109 Figure 67: Transportation Electrification in PWP’s 2023 Integrated Resource Plan .......................................................... 111 Figure 68: Light-Duty Electric Vehicle Penetration in PWP’s 2023 Integrated Resource Plan ........................................... 111 Figure 69: Average Hourly Shape for Light-Duty Electric Vehicles ..................................................................................... 112 Figure 70: Average Hourly Shape for Medium/Heavy-Duty Electric Vehicles .................................................................... 112 Figure 71: Average Hourly Load Profile .............................................................................................................................. 113 Figure 72: PWP’s Historical Load ........................................................................................................................................ 114 Figure 73: Percent of PWP Peak During Southern California Edison’s Peak ....................................................................... 115 Figure 74: Load Forecast ..................................................................................................................................................... 116 Figure 75: CAISO Metered Load by Component ................................................................................................................. 117 Figure 76: Hour of CAISO Peak Metered Load .................................................................................................................... 117 Figure 77: PWP Load Comparison ....................................................................................................................................... 119 Figure 78: Average Hourly Load .......................................................................................................................................... 119 Figure 79: Load Duration Curve .......................................................................................................................................... 120 Figure 80: Load Duration Curve Inflection Points ............................................................................................................... 120 Figure 81. Simplified Diagram of PWP's Sub-Transmission System .................................................................................... 122 DRAFT
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Figure 82: PWP’s CalEnvironScreen 4.0 Identified Disadvantaged Area Communities ...................................................... 124 Figure 83: Scenario vs. Emerging Technology Scenario vs. Sensitivity ............................................................................... 128 Figure 84: Internal vs. External ........................................................................................................................................... 129 Figure 85: Utility-Scale or Distributed? ............................................................................................................................... 130 Figure 86: Renewable vs. Zero-Carbon vs. Carbon-Free ..................................................................................................... 131 Figure 87: Scenarios ............................................................................................................................................................ 132 Figure 88: Distributed Resources in Load Forecast ............................................................................................................. 133 Figure 89: Social Cost of Carbon ......................................................................................................................................... 135 Figure 90: Carbon Intensity of CAISO .................................................................................................................................. 136 Figure 91: Potential Emerging Technologies....................................................................................................................... 136 Figure 92: Island vs. Market Access .................................................................................................................................... 138 Figure 93: PWP’s Existing Cumulative Installed Capacity ................................................................................................... 139 Figure 94: PWP’s Firm Capacity Position without Resource Additions ............................................................................... 140 Figure 95: PWP’s Firm Capacity Position without Resource Additions ............................................................................... 141 Figure 96: Energy Position without Resource Additions ..................................................................................................... 142 Figure 97: Renewable Position without Resource Additions .............................................................................................. 143 Figure 98: Sensitivities ........................................................................................................................................................ 143 Figure 99: Sensitivity Metrics .............................................................................................................................................. 144 Figure 100: Peak Load in 2030 ............................................................................................................................................ 144 Figure 101: Heat Wave Data Creation ................................................................................................................................ 147 Figure 102: Simulated Temperatures Under a Heat Wave ................................................................................................. 148 Figure 103: Wind and Solar Profiles Under Heat Wave ...................................................................................................... 148 Figure 104: Heat Wave Prices ............................................................................................................................................. 149 Figure 105: Demand vs. Goodrich in 2030 .......................................................................................................................... 150 Figure 106: Scenario 1: New Cumulative Installed Capacity ............................................................................................... 150 Figure 107: Scenario 1: Cumulative Installed Capacity by Location ................................................................................... 151 Figure 108: Scenario 1: Summer Resource Adequacy ........................................................................................................ 153 Figure 109: Scenario 1: Winter Resource Adequacy ........................................................................................................... 153 Figure 110: Scenario 1: Resource Adequacy Position ......................................................................................................... 154 Figure 111: Scenario 1: Consecutive Model Runs ............................................................................................................... 155 Figure 112: Summer vs. Winter Peaks ................................................................................................................................ 156 Figure 113: Scenario 1: Island – Resources That Load, Storage Charging, and Market Sales are Served By...................... 156 Figure 114: Scenario 1: Energy Market Access – Energy Position ...................................................................................... 157 Figure 115: CAISO Excess: What is it Worth? ...................................................................................................................... 158 Figure 116: Scenario 1: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served By ............................................................................................................................................................................................ 158 Figure 117: Scenario 2: New Cumulative Installed Capacity ............................................................................................... 160 Figure 118: Scenario 2: Cumulative Installed Capacity by Location .................................................................................. 160 Figure 119: Scenario 2: Summer Resource Adequacy ........................................................................................................ 162 Figure 120: Scenario 2 Resource Adequacy Position .......................................................................................................... 162 Figure 121: Scenario 2: Island – Resources That Load, Storage Charging, and Market Sales are Served By...................... 163 DRAFT
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Figure 122: Scenario 2: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served B y ............................................................................................................................................................................................ 164 Figure 123: Scenario 2: Energy Market Access – Energy Position ...................................................................................... 164 Figure 124: Scenario 3: New Cumulative Installed Capacity ............................................................................................... 165 Figure 125: Scenario 3: Cumulative Installed Capacity by Location ................................................................................... 167 Figure 126: Scenario 3: Summer Resource Adequacy ........................................................................................................ 168 Figure 127: Scenario 3: Resource Adequacy Position ......................................................................................................... 168 Figure 128: Scenario 3: Island – Resources That Load, Storage Charging, and Market Sales are Served By...................... 169 Figure 129: Scenario 3: Energy Market Access – Resources That Load, Storage Charging, and Market Sales are Served By ............................................................................................................................................................................................ 169 Figure 130: Scenario 3: Energy Market Access – Energy Position ...................................................................................... 170 Figure 131: Scenario 4: New Cumulative Installed Capacity ............................................................................................... 170 Figure 132: Scenario 4: Cumulative Installed Capacity by Location ................................................................................... 171 Figure 133: Scenario 4: Summer Resource Adequacy ........................................................................................................ 173 Figure 134: Scenario 4: Resource Adequacy Position ......................................................................................................... 173 Figure 135: Scenario 4: Summer Qualifying Capacity ......................................................................................................... 174 Figure 136: Scenario 4: Resources That Load, Storage Charging, and Market Sales are Served By ................................... 174 Figure 137: Scenario 4: Energy Position .............................................................................................................................. 175 Figure 138: Wind and Solar vs. Alternative Fuels ............................................................................................................... 176 Figure 139: Scenario 5: Installed Capacity .......................................................................................................................... 176 Figure 140: Scenario 5: Cumulative Installed Capacity by Location ................................................................................... 177 Figure 141: Scenario 5: Summer Resource Adequacy ........................................................................................................ 178 Figure 142: Scenario 5: Resource Adequacy Position ......................................................................................................... 178 Figure 143: Average Resource Costs with Carbon Tax (SCC) .............................................................................................. 179 Figure 144: Scenario 5: Resources That Load, Storage Charging, and Market Sales are Served By ................................... 180 Figure 145: Scenario 5: Energy Position .............................................................................................................................. 181 Figure 146: Total Carbon Emissions Under Cap-and-Trade (Scenarios 1 through 5) ......................................................... 181 Figure 147: Total Portfolio Carbon Emissions (Netting Market Purchases and Sales) ....................................................... 182 Figure 148: Scenario 6: Energy Efficiency Proxy – Results .................................................................................................. 183 Figure 149: Scenario 6: Demand Response Proxy: Results ................................................................................................. 183 Figure 150: Installed Capacity of Scenarios ........................................................................................................................ 184 Figure 151: Installed Capacity of Scenarios by Type in 2031 .............................................................................................. 184 Figure 152: Qualifying Capacity of Scenarios in 2031 ......................................................................................................... 185 Figure 153: Internal vs. External Installed Capacity in 2031 ............................................................................................... 185 Figure 154: Installed Capacity Distributed Resources per Scenario – in Addition to Load Forecast .................................. 186 Figure 155: Net Generation of Scenarios in 2031 ............................................................................................................... 187 Figure 156: Renewable Compliance Across Scenarios ........................................................................................................ 188 Figure 157: Renewable Compliance Across Scenarios by Type in 2031 ............................................................................. 188 Figure 158: Annual Zero-Carbon Requirements by Scenarios ............................................................................................ 189 Figure 159: Zero-Carbon Across Scenarios by Type in 2045 ............................................................................................... 189 Figure 160: Carbon-Free Across Scenarios ......................................................................................................................... 190 Figure 161: Heat Wave Sensitivity Results .......................................................................................................................... 190 DRAFT
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Figure 162: Scenario 1: Heat Wave ..................................................................................................................................... 192 Figure 163: Scenario 1: Heat Wave with Goodrich Maximized .......................................................................................... 192 Figure 164: Scenario 2: Heat Wave with Goodrich Maximized .......................................................................................... 193 Figure 165: Scenario 3: Heat Wave Top 10 Additional Energy Need Hours (September 2030) ......................................... 193 Figure 166: Internal Installed Capacity in 2030 for Scenarios 2 and 3 ................................................................................ 194 Figure 167: Scenario 4: Heat Wave ..................................................................................................................................... 195 Figure 168: Goodrich Transfer Contingency Results ........................................................................................................... 195 Figure 169: Internal Installed Capacity in 2030 Across Scenarios ....................................................................................... 196 Figure 170: Scenarios 4 and 5: Additional Energy Needs Under Heat Wave ...................................................................... 196 Figure 171: Illustration of Degradation Strategies for Battery Storage .............................................................................. 198 Figure 172: Installed Storage Capacity in 2031 ................................................................................................................... 199 Figure 173: Net Renewable Generation vs. Load in 2031 ................................................................................................... 200 Figure 174: California Eligible Renewable and Carbon-Free Resources That Do Not Go Toward Hourly .......................... 200 Figure 175: PWP is Selling or Curtailing X% of Load in Renewable/Zero-Carbon Resources ............................................. 201 Figure 176: Percent of Hours with Negative Net Load in September 2031 ........................................................................ 201 Figure 177: Hourly Load versus Net Load Across Scenarios for Three Days in September 2031 ....................................... 202 Figure 178: Components of PVRR ....................................................................................................................................... 202 Figure 179: Scenario 1: PVRR .............................................................................................................................................. 203 Figure 180: Scenario 2: PVRR .............................................................................................................................................. 204 Figure 181: Scenario 3: PVRR .............................................................................................................................................. 204 Figure 182: Scenario 4: PVRR .............................................................................................................................................. 205 Figure 183: Scenario 5: PVRR .............................................................................................................................................. 205 Figure 184: PVRR By Category Across Scenarios (Mid Costs) ............................................................................................. 206 Figure 185: PVRRs for Mid, High, Low Costs of New Resources ......................................................................................... 206 Figure 186: Percent Costs are Higher in 20 Years Compared to Scenario 4 (Reference Costs) .......................................... 207 Figure 187: 2030 $/kWh Costs in Addition to Scenario 4 ................................................................................................... 207 Figure 188: Costs of Forced Distributed Energy Resources in Scenario 3 .......................................................................... 207 Figure 189: Costs of Carbon Tax in Scenario 5 .................................................................................................................... 208 Figure 190: Present Value Revenue Requirement if Carbon Tax Returned ........................................................................ 209 Figure 191: Carbon Allowance Sale Prices .......................................................................................................................... 210 Figure 192: PVRR with Cap-and-Trade Allowance Sales ..................................................................................................... 210 Figure 193: PWP Historical and Budgeted Retail Rates (Nominal Dollars per kWh) .......................................................... 211 Figure 194: PWP Retail Rate Components as Percent of Total ........................................................................................... 212 Figure 195: Costs Included and Excluded from IRP Modeling ............................................................................................ 212 Figure 196: Cumulative Emissions Under Cap-and-Trade Program .................................................................................... 216 Figure 197: Cumulative Portfolio Emissions Netting CAISO Purchases and Sales .............................................................. 217 Figure 198: Cost of Avoided Carbon ................................................................................................................................... 217 Figure 199: Renewable Traits.............................................................................................................................................. 218 Figure 200: Over/Under Procurement for Compliance Period (MWh) .............................................................................. 218 Figure 201: Renewable and Zero-Carbon Traits ................................................................................................................. 219 Figure 202: Hourly-Carbon Free Achievements .................................................................................................................. 219 Figure 203: Adjusted Portfolio Emissions ........................................................................................................................... 220 DRAFT
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Figure 204: Cumulative New Resource Installed Capacity Through 2031 (MW) ................................................................ 223 Figure 205: Capacity Resource Accounting Table Load ...................................................................................................... 228 Figure 206: Energy Balance Table (Scenario 4) Load .......................................................................................................... 229 Figure 207: IRP Contacts and Roles..................................................................................................................................... 231 Figure 208: Opportunities for Future Studies and Analysis ................................................................................................ 232 Figure 209: Reliability Metrics for First Round Scenario Modeling (Capital Expansion) .................................................... 237 Figure 210: Reliability Metrics for First Round Scenario Modeling (Hourly Dispatch) ....................................................... 238 Figure 211: Reliability Metrics for Second Round Scenario Modeling (Hourly Dispatch)................................................... 238 Figure 212: Scenario 2: Consecutive Model Runs ............................................................................................................... 240 Figure 213: Installed Capacity of Fuel Cells ......................................................................................................................... 241 Figure 214: Resources Toward Load ................................................................................................................................... 242 Figure 215: Economic Curtailments Across Scenarios (MWh) ............................................................................................ 243 Figure 216: Utility-Scale Solar Nominal Costs ..................................................................................................................... 245 Figure 217: Utility-Scale Solar Real Costs ............................................................................................................................ 245 Figure 218: Commercial Solar Nominal Costs ..................................................................................................................... 246 Figure 219: Commercial Solar Real Costs ............................................................................................................................ 246 Figure 220: Residential Solar Nominal Costs ...................................................................................................................... 247 Figure 221: Residential Solar Real Costs ............................................................................................................................. 247 Figure 222: Utility-Scale 4-Hour Lithium-Ion Battery Storage Nominal Costs .................................................................... 248 Figure 223: Utility-Scale 4-Hour Lithium-Ion Battery Storage Real Costs ........................................................................... 248 Figure 224: Utility-Scale 6-Hour Lithium-Ion Battery Storage Nominal Costs .................................................................... 249 Figure 225: Utility-Scale 6-Hour Lithium-Ion Battery Storage Real Costs ........................................................................... 249 Figure 226: Utility-Scale 8-Hour Lithium-Ion Battery Storage Nominal Costs .................................................................... 250 Figure 227: Utility-Scale 8-Hour Lithium-Ion Battery Storage Real Costs ........................................................................... 250 Figure 228: Utility-Scale 10-Hour Lithium-Ion Battery Storage Nominal Costs .................................................................. 251 Figure 229: Utility-Scale 10-Hour Lithium-Ion Battery Storage Real Costs ......................................................................... 251 Figure 230: Commercial 4-Hour Lithium-Ion Battery Storage Nominal Costs .................................................................... 252 Figure 231: Commercial 4-Hour Lithium-Ion Battery Storage Real Costs ........................................................................... 252 Figure 232: Residential 2.5-Hour Lithium-Ion Battery Storage Nominal Costs................................................................... 253 Figure 233: Residential 2.5-Hour Lithium-Ion Battery Storage Real Costs ......................................................................... 253 Figure 234: Fuel Cells Nominal Costs .................................................................................................................................. 254 Figure 235: Fuel Cells Real Costs ......................................................................................................................................... 254 Figure 236: Land-Based Wind Nominal Costs ..................................................................................................................... 255 Figure 237: Land-Based Wind Real Costs ............................................................................................................................ 255 Figure 238: Offshore Wind Nominal Costs .......................................................................................................................... 256 Figure 239: Offshore Wind Real Costs ................................................................................................................................ 256 Figure 240: Geothermal Nominal Costs .............................................................................................................................. 257 Figure 241: Geothermal Real Costs ..................................................................................................................................... 257
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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 approaches to transition to this goal and to opti mize 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 Resource 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 aff ordability, rate equity, stability , and reliability of electricity, 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 C ity Manager to utilize the 2023 IRP process to plan multiple approaches to transition and 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 spen t 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 resources 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 types 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 m ultitude 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 designed 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 modifications, 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.
Resolution 9977 is one of the world’s leading decarbonization targets. The 2023 IRP identified potential resource needs, reliability implications, cost, and equity considerations involved in a transition. PWP looks forward to continuing to build on its directive to provide carbon-free electricity.
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4. Introduction
4.1. Introduction
The 2023 P WP 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) commitment 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 electricity 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 community 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 t argets 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 re quirements 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 regulations.
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 DRAFT
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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 environmentally 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, DRAFT
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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 the 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 efficiency. 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 protecting 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 public 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.
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.
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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 C ouncil 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. Th e City Council determines how PWP provides services in the community, including 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
• Assistant General Manager – Finance and Administration
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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 recommendation. 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 ag ency 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 certifies 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 energy 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 reductio n 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 reducing 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 CEC 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 generation 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 Excel 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 and 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 comments 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 a nd 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 each 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 meeting 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 2022 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 score 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 diff erent 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 collecting 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 them 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 DRAFT
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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 regulations.
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 implementation 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 i ncentivizes 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 generation. 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 requirement 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, wires, 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. While 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 energy a t 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 difference 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 should 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 achieved, utilities could transition to a replacement program. At this time, PWP still provides DRAFT
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benefits to its customers under the NEM 1.0 con struct, 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 produces 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 into 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 Green 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 DC fast chargers, the rebate ranges up to $6,000 per charger, if installed near a school, as part of income - qualifying housing, or in a disadvantaged community. Total incentives are limited to $50,000 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 Residential 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. PWP income-qualified customers 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 customers $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 DRAFT
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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: Annual 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%
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10%
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0 500
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2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Percent of Total Light-Duty Vehicles Sold
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BEV >= 200 Miles BEV < 200 Miles PHEV ZEVs (%)
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Medium- and heavy-duty vehicles, by definition 14, 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 convert 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 charged. 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 stations is shown in Figure 12. PWP’s website also provides details on where chargers are located. 18 14 Website with definition of heavy duty versus light duty 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 departments 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 inf rastructure 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 charger • 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 support 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 acc ount, 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/ DRAFT
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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, there 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 installation of devices such as LED light bulbs, advanced power strips, attic insulation, or tune-up of central AC. 24 • HERs provide customers with 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 collaboration 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 2021 (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 adopted 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 $0.00685/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 2035.
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 energy 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 advocacy.
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 costs – 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 p rogram 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 electricity 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 DRAFT
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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 6 1 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 residential 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 pandemic. 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 te nts, 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 information 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 en sure that stakeholder and community input were included. PWP provided periodic updates 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/
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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:
TABLE XX
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 supply 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 included residential customers, small and large businesses, low income/disadvantaged/senior communities, environmental advoc acy 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 22.
Figure 22: 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 1 0 STAG meetings that were hel d 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 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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The use of modeling in IRP analysis including scenario development and sensitivity analysis, and resource options and costs
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 February 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 recommendations.
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 analysis 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 anticipate d 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 DRAFT
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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 increase d 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 qualifying resources.
SB 100 also stated that 100% should be met with renewable and zero -carbon resource s 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 Report: 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 23 illustrates key policies driving California’s environmental efforts.
Figure 23: 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 DRAFT
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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 electricity (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 targets in the interim years.
RPS compliance requirements are included in Figure 24 and are reflected in the IRP models.
Figure 24: 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 DRAFT
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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 25.
Figure 25: 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 balance 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 percentage of load that must be met with renewable and zero-carbon sources prior to the 2035 goal. These interim goals are shown in Figure 26. Values in black bold text indicate the requirements, while values in grey italics represent the modeled interim values.
Figure 26: 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 1990 levels by 2030, as SB 32 (2016) requires. Covering more than 80% of the state’s GHG an d 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 ot her 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 allowances 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 h elp 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 emissions 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 easy-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 hydroelectric, 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 that 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
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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 resources 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 authority 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 types 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 overload. 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 high er 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 during 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 information 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 deliver 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 ; DRAFT
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Figure 27 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 min us renewable resources) occurs. As a result, the hour of operational concern shifts to later in the day when solar is less available.
Figure 27: 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 t ariff 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 responsibility, 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, Puente 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 DRAFT
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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 tim e. Local RA capacity is currently a scarce product in the market with high prices and less liquidity than System RA capacity. This trend 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 each 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 minimum 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 le ss 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 capable 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 (Super-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 DRAFT
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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 dispatches 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 gene rally 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 Flexible RA and System RA t o 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 economics, 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 deficiencies. 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 constrained on- line to meet NERC and WECC reliability criteria for interconnected systems operation; ii) Generation needed to meet Load demand in constrained areas;
71 https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M488/K540/488540633.PDF DRAFT
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and iii) Generation needed to be operated to provide voltage or security support of the CAISO or a local area."
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 circumstances 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 transmission 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 clearinghouse; 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 reliability 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 manipulation 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 DRAFT
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10. Model Assumptions
10.1. Planning Horizon (POUs)
In accordance with CEC guidelin es, 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% renewable 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 useful 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 municipal 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 28 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/ DRAFT
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Figure 28: EnCompass Power Planning Software
EnCompass minimizes total costs and maximize s 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 calendar years. The three critical model constraints used for PWP’s IRP are shown in Figure 29.
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Figure 29: 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 39.
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 30. This setup mimics the system on a transmission level.
Figure 30: 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 described
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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 trade 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 executable pricing as possible, with later years mimicking the long-term fundamental price forecast. Power and natural gas pricing are included in Figure 31 and Figure 32, 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 projections, estimates, or analyses, or that such work products will be accepted by any legal, financial, or regulatory body.
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Figure 31: SP15 7x24 Power Prices
Source: Horizons Energy Fall 2022 Advisory
Figure 32: Fuel Prices
Source for Natural Gas: Horizons Energy Fall 2022 Advisory
Figure 33 includes 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 33: 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, incorporating 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 DRAFT
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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 based 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 distinct 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 34 shows a forecast of TAC fees.
84 http://www.caiso.com/Pages/DocumentsByGroup.aspx?GroupID=7A2CFF1E -E340-4D46-8F39-33398E100AE7 DRAFT
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Figure 34: Transmission Access Charge Forecast
Electric 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, el ectricity 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 locatio n, 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 e xternally (located outside PWP’s service territory (i.e. , “the grid.”)). Figure 35 lists the internal and external resources used in the model, as well as the distrib uted 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 36 classifies resource size.
$0
$5
$10
$15
$20
$25
$30
$35
Nominal $/MWh
TAC Forecast
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Figure 35: 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 36: 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 DRAFT
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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 summary of resources is provided in Figure 37.
Figure 37: 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 DRAFT
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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 energy in Figure 38 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 38: 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/ DRAFT
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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 information 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. The 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 and 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 percentages 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 tr ansfer 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 t hat 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 3 7 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 M W 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 DRAFT
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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 model 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 includes 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 distributed 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 39. All resources, except possibly stand-alone batteries, provide renewable and carbon-free energy.
Figure 39: 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 DRAFT
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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 40. PWP assumed the accreditation for solar was consistent across size. PWP also assumed 100% accreditation for storage Figure 40: 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 39 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 m odel are larger than what PWP may be willing to pursue. This currently prevents the model 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 resources (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 cred it 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 been in place for decades in the U.S. and have helped encourage develop ment 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 technology-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 assessmen t. The 2023 IRP assumes 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 ITC.
The Federal Government revamped the ITC and PTC to support U.S. labor and supply chains. G enerally, 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 41. 96 Figure 42 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 criteria.
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 DRAFT
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Figure 41: Bonus Tax Credits for Renewable Resources
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Figure 42: IRA Tax Credits for Projects in Service After December 2024
Figure 43 summarizes the IRA tax credits applied to new resources in the 2023 PWP IRP study and modeling process.
Figure 43: 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 captur e, 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 44.98 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 DRAFT
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Figure 44: 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 pandemic 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 regulatio n has reduced U.S. domestic supplies from China. According to a Utility Dive article, “Extreme market conditions 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 exacerbated 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 connect 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 DRAFT
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60% expansion of the nation’s tr ansmission 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 Power s 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 additional 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 Figure 45.
Figure 45: 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 estimates. 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 performance, 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
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 DRAFT
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storage system configurations and installation practices. Bottom-up costs are based on national averages and do not necessarily represent typical costs in all local markets.
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 dr iving installed prices and where there are opportunities for price reductions. The benchmarks are also used to project future system prices, provide transparency, and facilitate engagement 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 purposes.”
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 46 and Figure 47 show a detailed example of solar pricing. The pricing is provided in nominal dollars and in real 2023 dollars.
Figure 46: Utility-Scale Solar Nominal Pricing
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Figure 47: Utility-Scale Solar Pricing in Real 2023 $
Evaluating nominal versus real values can often lead to confusion. See Figure 48 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 inflation. 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 prices 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 48: 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 49.
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 benchmarks 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 identified, PWP re-evaluated the costs of new resources using sensitivity tests to quantify potential cost variation.
Figure 49: 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 $940.01
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Real vs. Nominal LCOEs (2030)
Solar (Utility Scale, Single Axis Tracking) Real LCOE Nominal LCOE Fixed O&M ($/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 impacts 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 E xcel files with raw data, citations, and the blending methodology to th e 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 sensitivit y 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 DRAFT
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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 electrochemic ally 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 grow ing 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 DRAFT
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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/MWh and $120/MWh (in 2021 dollars) by 2030.119 NREL produced cost projections specific to fiv e 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 DRAFT
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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 with 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 unknown 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 50 for examples on the different components of electricity (definitions in the table are simplified).
Figure 50: 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 51 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 52 and Figure 53 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 51: 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 52: Cost of New Energy Resources
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Figure 53: 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 54 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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Figure 54: 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 limitations • 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 considered 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 55 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 example, 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 55: 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, renewa ble 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 regulations, 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
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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 p lanning 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 203 5. These components are shown in Figure 56.
Figure 56: 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 Num ber:
CEC-100-2022001-CMD.
130 https://efiling.energy.ca.gov/GetDocument.aspx?tn=247951&DocumentContentId=82234 DRAFT
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CED Update, 2022 - 2035 Description
Treatment in
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Modeling
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to
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from
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Modified in
PWP’s 2023
IRP?
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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 DRAFT
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CED Update, 2022 - 2035 Description
Treatment in
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Modeling
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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 S CE’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 subcategories that comprise the net electricity demand, this metho d 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 57 and Figure 58. These values are metered at PWP’s interface with CAISO, so they include the impact of distribution system losses. PWP considers distribution losses at around 4%.
Figure 57: 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 58: PWP Energy
Year
Potential Energy
(GWh) Imported into
CAISO
Behind-the-Meter
Generation (GWh)
Retail Sales (GWh) to
End-Users
Retail Sales to End-
Users (Accounting for
AAEE Impacts)
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 DRAFT
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identified. Details of current PWP e nergy 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 demand 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 quantified the following three types of potential penetration of energy efficiency :
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• Technical (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. Figure 59 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 59: Technical, Economic, and Market Potential for Energy Efficiency
Energy efficiency 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 go al is based on incremental net savings , which are approximately 96% of gross market potential savings.
The 2023 IRP uses PWP’s energy 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 60 shows the IRP forecast of AAEE. The negative values on the Y axis indicate energy saved.
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Figure 60: Additional Achievable Energy Efficiency in PWP’s 2023 Integrated Resource Plan
The percent reduction in load is shown in in Figure 61.
Figure 61: 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. The 2023 IRP assumes the allocation of AA FS from the (160)
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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 62 shows an AAFS projection for PWP.
Figure 62: 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 point. Extrapolating forward, approximately 12% of households wou ld 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 63 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 63: 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 estimated, and it produced an estimate more in line with expectations. See Figure 64.
140 https://www.nrel.gov/docs/fy21osti/79444-4.pdf
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Figure 64: 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 65 and Figure 66.
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Figure 65: Time-of-Use Rates in PWP’s 2023 Integrated Resource Plan
Figure 66: Average 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 co nstitute 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 the 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 U pdate), 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 2 023 and the forecast moved up accordingly. Approximately 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 energy in 2030 and 28% in 2045, as shown in Figure 67 and Figure 68.
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 DRAFT
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Figure 67: Transportation Electrification in PWP’s 2023 Integrated Resource Plan
Figure 68: 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 69 and Figure 70. 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 charg ing 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 69: Average Hourly Shape for Light-Duty Electric Vehicles
Figure 70: Average Hourly Shape for Medium/Heavy-Duty Electric Vehicles
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The average contribution of EV charging to average hourly load in 2030 is shown in Figure 71. 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 when market prices are high.
Figure 71: 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 aligning 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% o f 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 forecas ts 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 climate 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 72 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, n ative 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 increased 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 72: 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.
M
etered load is calculated according to the following equation:
𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝐿𝐿𝐿𝐿𝐿𝐿
𝑀𝑀 = (𝑁𝑁𝐿𝐿𝑀𝑀𝑁𝑁
𝑁𝑁𝑀𝑀 𝐿𝐿
𝐿𝐿𝐿𝐿
𝑀𝑀 + 𝐿𝐿𝑁𝑁
𝐿𝐿ℎ𝑀𝑀 𝐷𝐷
𝐷𝐷𝑀𝑀𝐷𝐷 𝐸𝐸𝐸𝐸
𝐸𝐸 + 𝑀𝑀𝑀𝑀𝑀𝑀𝑁𝑁
𝐷𝐷𝑀𝑀 𝐿𝐿
𝑎𝑎𝑀𝑀 𝐻𝐻
𝑀𝑀𝐿𝐿𝑁𝑁𝐷𝐷 𝐷𝐷
𝐷𝐷𝑀𝑀𝐷𝐷 𝐸𝐸𝐸𝐸
𝐸𝐸 + 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴
+ 𝐷𝐷𝑁𝑁
𝐸𝐸𝑀𝑀𝑀𝑀𝑁𝑁𝐷𝐷
𝐷𝐷𝑀𝑀
𝑀𝑀𝑀𝑀 𝐴𝐴
𝑀𝑀𝐿𝐿𝑀𝑀𝐿𝐿𝐿𝐿𝑀𝑀 ) + (𝑇𝑇
𝑇𝑇𝑇𝑇 𝑅𝑅𝐿𝐿𝑀𝑀
𝑀𝑀𝐸𝐸 + 𝐴𝐴𝐴𝐴
𝐸𝐸𝐸𝐸 + 𝐷𝐷𝑁𝑁
𝐸𝐸𝑀𝑀𝑀𝑀𝑁𝑁𝐷𝐷
𝐷𝐷𝑀𝑀
𝑀𝑀𝑀𝑀 𝐴𝐴
𝐿𝐿𝑆𝑆𝐿𝐿𝑀𝑀)
Fi
gure 73 shows a comparison between PWP’s forecast and SCE’s forecast from the CED.
Figure 73: Percent of PWP Peak During Southern California Edison’s Peak Percent of PWP Peak During SCE's Peak
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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 74 shows PWP’s annual energy and peak forecast. Positive values for energy refer to consumption and negative values refer to avoided energy consumption. Figure 75 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 what 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 74: Load Forecast
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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 75: CAISO Metered Load by Component
CAISO’s metered peak load occurs on the dates and hours shown in Figure 76.
Figure 76: 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
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2030
2031
2032
2033
2034
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2038
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2043
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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 77. 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 77: PWP Load Comparison
PWP’s average hourly load shape for 2023 through 2050 is shown in Figure 78. 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 78: 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
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2023
2024
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2026
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2028
2029
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2032
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2038
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Energy (GWh)
CAISO Metered Load
2023 IRP 2019 IRP 2021 IRP Update Historic
0 50
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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 79 and Figure 80.
Figure 79: Load Duration Curve
Figure 80: Load Duration Curve Inflection Points
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
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1 238
475
712
949
1186
1423
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2134
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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 CAISO 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 interconnection 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 S tate 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 1 12 MVA power transformers that step the voltage down from 220kV to 34.5kV. PWP also has a 40 MW, 34.5kV interconnection between 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 connection to the CAISO grid. Its use is limited to emergencies or CAISO-mandated load curtailment requirements. See Figure 81.
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Figure 81. 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 34.5 kV circuits that form the cro ss-town backbone of the sub -transmission system and connect directly from Goodrich through 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 enhance 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 t o 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 improved 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 transformers 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 electrically 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 renewabl e energy projects , such as community solar, within the PWP system. Precise locations, types, sizes and installation dates of new generation and storage projects connected to PWP ’s distribution system have yet to be determined and will require the PDMP be r evised 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 neighbor – 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 DACs based on geographic, socioeconomic, public health, and environmental hazard criteria. CalEPA’s CalEnvironScreen uses U.S. Census data and 21 indicators to identify communities 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 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 on e DAC. This location, shown Figure 82 , encompasses 0.6 square miles in northwest Pasadena and includes a population of more than 6,000 people.
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Figure 82: 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 emissi ons 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 define multiple paths to this goal in a way that optimizes stability, service reliability, affordability, and rate equity.
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Following its core mission, PWP constructs, operates, and maintains its power system facilities to provide stabile and reliable electric service to all its customers, regardless of their respective locations. By also actively promoting rate equity, PWP provides a benefit of special importance to its DAC area.
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 credits 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 s ervices that directly benefit qualified DACs and/or low -income customers. In accordance with the LCFS regulation, PWP allocated 30% of LCFS 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, including 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 encourage 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 ZEVs by 2024. This requirement increases to 100% effective 2027 and will contribute significantly toward overall emissions reduction in the DAC and its surrounding neighborhoods.
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 doubl e rebates in the previous year.
Income-qualified customers are eligible for additional re bates to help improve the affordability of an EV investment.
Likewise, commercial 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.
In 2023, PWP launched an e-Bike rebate, which will further incentivize adoption of affordable clean transportation options.
The program was fully subscribed in fall 2023. Looking forward, the City will evaluate pilot program results, benefits and challenges for future discussion.
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14.2.2. Efficiency and Assistance Programs
PWP offers numerous programs supporting both the DAC and income -qualified customers throughout the community.
Existing Policies and Programs of the IRP outlines these programs. The descriptions in the following subsections highlight several key programs available to these 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 APPLE 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 f ederal 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 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 eligible income-qualified customers.
The Refrigerator/Freezer Recycling Program is a no -cost recycling service that encourages the purchase of newer, more energy efficient food cooling appliances. The program also provides eligible income -qualified customers with a new replacement refrigerator at no cost.
14.2.2.3. Whole House Services
PWP offers variou s 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 guidance 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, broken window replacements, and solar energy system installations 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 consu mption 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 free 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 must produce a scenario to file 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 built over time that aim to optimally meet energy, capacity, and environmental goals. Sensitivities stress scenarios to see how they would perform under different conditions.
PWP must file one scenario to the CEC. However, in the 2023 IRP, PWP studied five scenarios and one emerging technology scenario. PWP also elected to model the five scenarios under four sensitivities. See Figure 83 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 83: 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 resolution, 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 statute 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 one of the most ambitious deca rbonization 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 States plans 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 to work toward and achieve such a goal will require intensive and concent rated 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 demonstrated decarbonation 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 84.
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Figure 84: 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 85 for a brief description of each category. Additional informat ion on NREL’s 2022 ATB, as referenced in the f igure, is available online.148
148 https://atb.nrel.gov/
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Figure 85: 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 86. 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 86: 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 analysis 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 o ne scenario (Scenario 4 ) follows state requirements. Scenario 5 studies the impact of a carbon tax. Figure 87 includes the list of scenarios.
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Figure 87: Scenarios
Each scenario generated 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 storage 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 elect to install up to those amounts of resources internally. If those limits bind (i.e., if the results maximize any one of those limits), th e 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 88. 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 trends. 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 88: 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 89149. 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 DRAFT
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Figure 89: 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 90.150
150 https://scenarioviewer.nrel.gov/
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$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 90: Carbon Intensity of CAISO
Scenario 5 allows the capacity 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 91 shows examples of potential emerging technologies.
Figure 91: Potential Emerging Technologies
Emerging 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. -
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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 suppor t 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 resources 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 reduc tion goals cost effectively, the following are two performance traits of particular interest 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 answers 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 questions, 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 scenario, which results in a higher bound of financial value to PWP for an emerg ing 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 during 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 purchases 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 90. • 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 Glenarm 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 requir e 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 dispatchable alternatives such as carbon capture, green hydrogen, biofuel s 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 exit. 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 perspective, 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 92.
Figure 92: 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 93.
Figure 93: 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 94 shows PWP’s existing RA position without any resource additions.
Figure 94: 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 95 shows the firm capacity of these resources in greater detail.
Figure 95: 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 Geysers, 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 96 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 96: Energy Position without Resource Additions
Capacity shortages also result in increasing renewable energy needs over time, as shown in Figure 97. As it stands, PWP needs more renewable energy to fulfill its state requirement of 60% renewables by 2030.
0 500
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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 97: 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 98.
Figure 98: Sensitivities
The sensitivities seek to answer fundamental questions . S ee Figure 99. Sensitivities 1 and 2 focus on reliability, and Sensitivities 3 and 4 focus on cost.
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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 99: 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 times occur in late August through early September. See Figure 100. 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 100: 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
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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 removing 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 ma ximum 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 historical 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 were converte d 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 data (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 no t 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 curv e for a given latitude 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 normal 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 trained 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 capacity 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 predicted bin was taken as the single predicted capacity factor and used to re scale 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 model 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 101: 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
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Overall, assumed temperatures average 104°F, as shown in Figure 102.
Figure 102: Simulated Temperatures Under a Heat Wave
During a heat wave, renewable output changes. Solar increases by 3.6% and wind is 12% of its normal output. See Figure 103 for details.
Figure 103: Wind and Solar Profiles Under Heat Wave
Load increases to approximately 1.5 times its typical amount during a heat wave due to air conditioning demand. 80 85
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Wind and Solar Profiles Under Heat Wave: September 2030 Wind (Reference) Solar (Reference) Wind (Heat) Solar (Heat) DRAFT
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Power and natural gas prices also increase during a heat wave, with natural g as prices averag ing $35/MMBtu. In September 2030, the reference forecasted price was $5.50/MMBtu. Figure 104 shows the pricing assumed in the IRP.
Power prices average d $447/MWh for this sensitivity . For September 2030, the reference case forecasted price was $69/MWh. These prices are in nominal dollars.
Figure 104: Heat Wave Prices
16.2. Sensitivity 2: Goodrich Transfer Contingency
Under normal operating conditions, Goodrich can import up to 280 MW until July 2032 . It is anticipated that planned upgrades will allow up to 336 MW thereafter. For purposes of this sensitivity, Goodrich’s import capability is reduced by one-half to 140 MW in 2030 to reflect a single transmission line outage into the station for one week during the summer.
There are different circumstances such as planned system maintenance or unplanned (forced) outages that could cause such an event. These could originate at Goodrich, or on the lines feeding into Goodrich. This sensitivity would help PWP compare the value of internal versus external resources.
16.2.1. Sensitivity 2: Goodrich in 2030 Under Forecasted Normal Operating Conditions The model ran the week of September 8, 2030, through September 14, 2030, when peak loads in 2030 are likely to occur.
Figure 105 shows how demand compares to Goodrich’s capability.
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Power and Gas Prices Under A Heat Wave
Gas Price ($Nominal/MMBtu) Power Price ($Nominal/MWh)
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Figure 105: 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 cos ts. 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 106.
Figure 106: 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
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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 107: 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. This 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 108, Figure 109, and Figure 110. 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 108: Scenario 1: Summer Resource Adequacy
Figure 109: Scenario 1: Winter Resource Adequacy
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Existing Renewable Existing Demand Response New Storage New Renewable* New Distributed Resources Load Requirements Load
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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 110: 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 S cenario 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 111 Fuel cells were added to the first round of modeling results because Scenario 1 allowed for unlimited internal resources. Fuel cells are dispatchable, carbon -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 111: 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 calibration 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 det ails for the carbon -free scenarios are provided in Appendix - 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 112, 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 112: Summer vs. Winter Peaks
Scenario 1 does 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 113, load 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 113: 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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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 114.
Figure 114: 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 115. Market value is uncertain. Financial studies are explored in Financial Impacts of the IRP. There are also carbon implications of continued market interactions.
See Section 21 of this IRP.
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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 115: 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 bound ary 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 “energy market access”.
Figure 116 shows how PWP would meet load if it interacts with the markets . This is different from Figure 113 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 capt ure, 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 116: 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?
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•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 117 are installed under Scenario 2. By 2030, PWP has 4.3 times its peak in installed capacity.
Figure 117: 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 118: 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 Scenario 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 (com pared to 3 MW of commercial storage and 8 MW of commercial solar). This ensures load is DRAFT
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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 replace 212 MW of natural gas. The resulting summer capacity position is shown in Figure 119. Details are quantified in Figure 120.
Figure 119: Scenario 2: Summer Resource Adequacy
Figure 120: Scenario 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
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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 registered as a Proxy Demand Response resource. CAISO’s tariff sets the rules for how this work s. 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 tariff 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 mar kets 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 121). Figure 122 shows how PWP meets is energy obligations if market 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 ad apted 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 121: 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%
151 http://www.caiso.com/Documents/Jun17-2022-OrderPartialAccepting-RequestingComplianceFiling-FERCOrderNo2222-ER21- 2455.pdf
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Resource Type 2023 2030 2031 2040 2050
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 122: 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%
The energy position, assuming energy market access, is shown in Figure 123.
Figure 123: Scenario 2: Energy Market Access – Energy Position DRAFT
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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 124. 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.
Figure 124: Scenario 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
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Scenario 2: 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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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 125: 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 shows 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 126.
Figure 126: Scenario 3: Summer Resource Adequacy
Overall RA is shown in Figure 127.
Figure 127: 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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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 128 and Figure 129 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 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, or prior to 2030. Until such future technologies become available at scale, the availability of the Glenarm facility will be required across all Scenarios.
Figure 128: 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 129: 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 130.
Figure 130: Scenario 3: Energy Market Access – Energy Position
17.4. Scenario 4: Reference Case (SB 1020)
Scenario 4 meets state environmental requirements and serves as the basis for comparison for the other scenarios.
Installed capacity under this scenario is shown in Figure 131. By 2030, installed capacity is 2.2 times PWP’s peak load.
Figure 131: 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
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Scenario 3: 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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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050
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 132: 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
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
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2025 2026 2027 2028 2029 2030 2035 2040 2045 2050
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 online 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 already signed contracts 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 sto rage installed to assist with the natural gas contract expiration. Then, through the 2030s, retirements and additions are smaller (+/- 15 MW). The resulting capacity position is shown in Figure 133 and Figure 134.
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Figure 133: Scenario 4: Summer Resource Adequacy
Figure 134: Scenario 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 135, wind receives 14% of its nameplate capacity in qualifying capacity in August. In 2025, solar receives 10% of its nameplate capacity in qualifying capacity in August. This IRP forecasts the qualifying capacity for solar to decrease to 8% by 2031.
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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 135: Scenario 4: Summer Qualifying Capacity
There is significant 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 136 and Figure 137 show the resources that PWP’s load, storage, and market sales are met by under Scenario 4.
Figure 136: 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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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 137: Scenario 4: Energy Position
Scenario 4 elects 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 138 includes an estimate of costs from hydrogen assuming a 6,469 B tu/kWh heat rate and from biofuel assuming a 10,500 Btu/kWh heat rate.
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Figure 138: 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 139. 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 139: 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 140: 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 DRAFT
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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 installed capacity under Scenario 5 creates the RA position in Figure 141 and Figure 142.
Figure 141: Scenario 5: Summer Resource Adequacy
Figure 142: Scenario 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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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 social 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 $2,000/MWh penalty charge rather than turning on the Glenarm units (Figure 143).
Figure 143: Average Resource Costs with Carbon Tax (SCC) Average Cost of Energy ($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 145 and Figure 146.
Figure 144: Scenario 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 145: Scenario 5: Energy Position
Scenario 5 produces 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 146).
Figure 146: Total Carbon Emissions Under Cap-and-Trade (Scenarios 1 through 5)
Another method 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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Load Storage Charging Market Sales
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characteristics if the energy is sold. As shown in Figure 147, by that calculation, because of PWP’s sales, PWP could offset emissions elsewhere on the grid.
Figure 147: 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 year by 30 MW, how much would ratepayers save?
The savi ngs 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 efficiency 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
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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 148. Figure 148 also contains the average costs for the entirety of the 1%, 2%, or 3% avoided.
Figure 148: 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 willing 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 peaks each year does not avoid a new resource build during this time under this model run. See Figure 149.
Figure 149: 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 Scenario 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 150 and Figure 151. 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 2031, PWP needs between 80 MW (Scenario 5) and 685 MW (Scenario 2) of batteries.
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Figure 150: Installed Capacity of Scenarios
Figure 151: Installed 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.
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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 152.
Figure 152: 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 h elp serve load reliably given that PWP is a transmission -constrained system. See Figure 153 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 153: 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
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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 154).
Figure 154: 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 155). 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 155: Net Generation of Scenarios in 2031
This generation 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 156.
0 50
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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 156: Renewable Compliance Across Scenarios
This renewable resource requirement 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 157.
Figure 157: Renewable Compliance across Scenarios by Type in 2031
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Renewable Resources (GWh)
Annual CA Renewable Requirements
RPS Requirements Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 -
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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 158).
Figure 158: Annual Zero-Carbon Requirements by Scenarios
Those requirements are met by resources like solar (Figure 159).
Figure 159: Zero-Carbon across Scenarios by Type in 2045
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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 160).
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 Scenario 5 above 80%.
Figure 160: 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 information in Figure 160 represents single model runs conducted under normal operating conditions. Sensitivit y 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 161 show the amount of resources that would have to be installed internally and externally.
Figure 161: 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 162.
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Figure 162: 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 163. When Goodrich increases from 280 MW to 336 MW, this capacity could be external.
Figure 163: Scenario 1: Heat Wave with Goodrich Maximized
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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 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)
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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 import s additional carbon-free power up to its maximum potential, PWP co uld need an additional 240 MW in a given hour to help serve load (Figure 164).
Figure 164: Scenario 2: Heat Wave with Goodrich Maximized
Based on the top 10 hours of additional energy needs 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 165.
Figure 165: 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 166). In 2030, Scenario 2 has 1,001 MW installed internally, while Scenario 3 has 93 7 MW (64 MW less than Scenario 2 ). Furthermore, the breakdown of technology types and amounts is different between the two scenarios. Different technology mixes interact differently during a heat wave.
Figure 166: 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 also shows additional energy needs; however, there is availability on the Glenarm units. See Figure 167. 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 167: 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 energy 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 168, under a single week of highest demand under normal operating conditions outside the Goodrich contingency, all scenarios can operate reliably.
Figure 168: 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 169.
Figure 169: 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 February. The monthly needs for Scenarios 4 and 5 are shown in Figure 170.
Figure 170: Scenario 4 and 5: Additional Energy Needs Under Heat Wave Scenario 4 Scenario 5
Month
(2030)
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Energy Needs
(Hours)
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(Days)
Additional
Energy Needs
(MWh)
Additional
Energy Needs
(Hours)
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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 determined 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 example, 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. The 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 cycles 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, utility-scale batteries can lose energy over time with use.
Developers and utilities have several ways to account for this:
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Assume the battery project will just degrade and that is factored into the cost and forec asted 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 171: 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 capacity. See Figure 172 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 cos t-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 10 11 12 13 14 15
Years
MWh
Desired
Oversizing
Augmentation
No Augmentation
Illustrative Only
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Figure 172: Installed 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, the ability of resources to meet peak-hour capacity needs. Storage helps meet PWP’s RA requirements.
As shown in Figure 173, 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 con ditions, 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 173: 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 given in Figure 214. See Figure 174 for results.
Figure 174: California Eligible Renewable and Carbon-Free Resources That Do Not Go Toward Hourly
(500)
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2,000
2,500
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Annual Net Renewable Generation vs. Load in 2031
Geothermal Solar PV Wind Battery Load
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The IRP selected the amount of storage necessary to meet obligations, but PWP is still generating excess. See Figure 175.
Figure 175: 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 P OU 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 optimizes 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 words, hours when wind, solar, and geothermal energy are greater than hourl y load). See Figure 176. Figure 177 shows a graphical representation.
Figure 176: 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 177: Hourly Load versus Net Load Across Scenarios for Three Days in September 2031
Excess 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 178.
Figure 178: 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 DRAFT
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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, under mid, low, and high technology costs, are shown in Figure 179 through Figure 183. Scenarios 1, 2, and 3 have costs associated with an island system and with energy market access.
Figure 179: Scenario 1: PVRR
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Figure 180: Scenario 2: PVRR
Figure 181: Scenario 3: PVRR
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Figure 182: Scenario 4: PVRR
Figure 183: Scenario 5: PVRR
Figure 184 shows the breakdown of costs by type across scenarios. $0
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Figure 184: 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 PVRR values (in 2030 dollars) are shown in Figure 185.
Figure 185: 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
Scenario 3 (Island System) 2,512 3,162 3,722
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20-Year PVRR
(2030 $ in Millions, 2030-2049) Low Costs Mid Costs High Costs 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 186 shows the percent increase in costs compared to Scenario 4. Costs increase in t he carbon -free scenarios between 28% and 82%.
Figure 186: 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 187.
Figure 187: 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 188. From 2030 through 2049, there is almost $1.4 billion (in 2030 dollars) in costs for these resources.
Figure 188: 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 DRAFT
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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 distributed 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 CAISO, 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 further 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 considered 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 189.
Figure 189: 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
2031 $10.7 $180.5 $169.8
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Nominal Millions Carbon Tax Scenario 5 Scenario 5 (Carbon Tax Returned) 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
Resulting comparisons are in Figure 190.
Figure 190: 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 Figure 191, scenarios could generate additional savings shown in Figure 192.
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Figure 191: Carbon Allowance Sale Prices
Figure 192: PVRR 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, Scenario 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, 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 fina ncial $0
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impact of the IRP will be fully evaluated after adoption and incorporated 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 maintenance, 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 Distribution 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 193 depicts PWP’s historical and budgeted rates from 2003 through 2024. Figure 194 shows the breakdown of the rates by percent of total.
Figure 193: PWP Historical and Budgeted Retail Rates (Nominal Dollars per kWh)
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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 194: PWP Retail Rate Components as Percent of Total
Figure 195 shows the various rate components that are included and excluded in the IRP modeling.
Figure 195: 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 lower than projected.
• Congestion costs
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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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 needed.
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 investments tot aling $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 includes 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 distribution system support of battery storage infrastructure.
CAISO, as the primary infrastructure planner for the state has a pr oactive approach to meet California’s long-term clean energy goals that calls for investments of $7.3 Billion in the approved 2022 -2023 Investment Plan155. These investments will have an additive impact to customer rates. • Other costs
Other operating co st to be considered are the finance, administration, information technology and customer service components of expenses.
Cost of future debt financing and credit risk.
The tables below show estimated impacts and are intended to provide a sense of the financial implications to the utility and customers based on each scenario. The amounts shown are provided for illustrative purposes only and represent “just in time” rates that would be needed for the different “moderate” and “high” costs in order to recover costs. Varying rate structures, capital financing plans, and rate offsets ( such as grant funding) will all be actively pursued but cannot confidently be projected and as such are not included in this analysis.
The Energy Charge p rojections are based on single -family residential customers on an annual basis . The projections assume usage of 500 kWh per month (6,000 kWh annually). Rates will accelerate during the first seven years of the plan
155 https://www.caiso.com/Documents/caiso-2022-2023-transmission-plan-approved.pdf DRAFT
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due to cost recovery associated with the compressed timeline and will remain elevated after 2030 to support the portfolio costs.
Table X: Annual Bill Impacts for Single-Family Residential Customers (Moderate Cost Estimates)
Scenario
Power
Supply
NPV
Moderate
Cost ($ 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 $632.33 million. All Scenarios studied in the 2023 IRP have included an embedded D istributed Energy Resource (“DER”) growth rate built into the load forecast. Scenario 3 takes this natural growth rate and doubles to study the value of DERs. The IRP modeling captures the estimated costs as they are an additional cost, regardless of the funding source.
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Table X: Annual Bill Impacts for Single-Family Residential Customers (High-Cost Estimates)
Scenario
Power Supply
NPV High Cost
($ 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. Tables 8 and 9 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 possib le 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 Charge in this report, customer will likely see bill in increases in the double d igits. 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:
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• Cap-and-Trade
• 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 target s 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 prevent 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 196.
The model optimizes for PWP to operate under its allowance cap and is an assumption included in all scenarios.
Figure 196: 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 covered 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 DRAFT
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the net of market purchases and sales at the emission intensity of the CAISO market (previously provided in Figure 90), then total emissions could look like
Figure 197. Sales (particularly for Scenario 5) create this effect.
Figure 197: 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 REC s, 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 above 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 interac tions were credited at CAISO’s average emission rate. PWP pays between $503/metric ton and $1,616/metric ton to avoid carbon. See Figure 198.
Figure 198: 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
$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
Emission Rate
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 199.
Figure 199: 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 200.
Figure 200: 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 201).
Figure 201: 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 202.
Figure 202: 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%
2028 53% 55% 56% 59% 80%
2029 54% 55% 57% 60% 80%
2030 96% 97% 97% 60% 78%
2031 100% 100% 100% 62% 81%
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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21.6. GEAT
Labeled as #12 on the GEAT, adjusted portfolio emissions in million metric tons of CO2e is shown in Figure 203. 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 lead to emissions reductions for the grid as a whole.
Figure 203: 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
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)
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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 al so validates and reinforces the understanding 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 addressed. Proactive planning is critical to ensure ongoing safe and reliable electric service while mini mizing 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 ensu re that PWP responds to changing 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 cost-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, and any follow-on Net Energy Metering programs, and creation of a community solar programs. o Expand Demand-Side Management, expand Energy Efficiency programs, implement Advanced Metering Infrastructure, and explore connection incentives.
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.
Each of these activities is discussed in further depth later in the chapter. Any resulting programs or actions will be presented to the City Council for approval and/or other guidance or policy directives.
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22.1. PWP’s Preemptive 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. Wi th this in mind, PWP has already begun building its future resource portfolio in 2023 with the information outlined in the following paragraphs.
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 energy 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 dispatchable resource, thus enabling 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, through 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 c ould also use the BESS to receive renewable and carbon -free energy from its electrically external resources – again, to serve system load as needed. Additionally, PWP could offer some or all of this BESS to the California Independent System Operator (CAISO) as a CAISO-dispatchable grid resource, in partial fulfillment of PWP’s RA obligation to the CAISO. As PWP’s first BESS, this project would serve as a pilot for future BESS facilities within Pasadena. PWP could make good use of the experience it derives f rom 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 technologie s 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 limited to, the following:
• The results of this IRP
• PWP’s policy directives
• The deliverability of external resource energy to the PWP system DRAFT
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• The commercial availability of resources by type, size, and offered contract duration • Reliability considerations
• Regulatory requirements
• Rate impacts
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 future.
PWP’s general strategy calls for a resource portfolio build plan incorporating solar PV, geothermal, wind, renewable H2 fuel cells, and battery storage. Utility-scale generation or storage resources will most likely come in the form of long-term PPAs and/or utility owned resources that could be sited in Pasadena. PWP would probably install as much utility-owned BESS as it could construct inside Pasadena. To manage the output of variable energy resources, i t is advisable to have energy storage resources available totaling at least 50% of the combined nameplate MW value of solar and wind energy resources, beginning with 4 -hour storage and incrementally increasing this to 8 -hour or 10 -hour storage as PWP’s load curve flattens over the coming years.
As PWP fills its resource gaps year by year, it will obtain more accurate indications of how many MW of which types of resources to pursue, and over how many years. This knowledge base would also establish the basis of PWP’s “Procurement Plan” (included within the Appendix of this IRP) –schedule of procurement/project development goals that PWP can use as benchmarks to monitor how well it remains on track to fulfill its evolving portfolio requirements. PWP will continue to update these goals, and hence its Procurement Plan, in future iterations of the IRP.
Figure 1 below shows, by scenario, 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 is a monumental capacity expansion.
Figure 204: 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
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All of the suggested resource portfolios for Scenarios 1 through 5 include some utility-scale PV solar and some utility-scale battery storag e. 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. Utility-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.
Therefore, PWP could procure 300 MW of utility-scale photovoltaic solar and 60 MW of utility-scale battery storage by the end of 2030 and remain able to transition to any new policy direction, change in resource market availability, or emerging technology. Successfully procuring this level of new capacity would require a coordinated effort to source projects, to conduct due diligence, to perform evaluations, to negotiate contracts, to secure approvals, to sign contracts, and ultimately to see projects through to their commercial operation dates.
Note that these represent potential minimum 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.
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 re bates, 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 capacity to accommodate overgeneration 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 significantly 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 C ity 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 accommodate this growing number of EVs. This also presents potential opportunities to partner with other City organizations for a symbiotic use of batteries ab oard 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 facilities at municipal DRAFT
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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 wel l 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, biofuel, 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-free 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 ye t available at scale, they were not studied as part of the IRP process. However, they do 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 authori zation 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 customer 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 N ext Net Energy Metering Pr ogram, E lectric 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 distribu ted 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 current 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 DRAFT
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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.
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 potential.
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.
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.
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22.4. 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. Executing this transition may lead to dwindling energy procurement in spot markets.
Conversely, PWP foresees increasing participation in markets for RECs and RA to support interim portfolio balancing during the first five to seven years following this IRP.
Changes may occur relatively simultaneously, which would pose organizational challenges for PWP. But the PWP team, having been trained to embrace change, is well-equipped to address these challenges.
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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 205.
Figure 205: 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 206.
Figure 206: 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/Shortfall (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 207: 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 208: 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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• 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-hour 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 reliability 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 dispatch 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 capacity 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 commercial 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 commercial 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 op timization are shown in Figure 209, the resulting hourly dispatch is shown in Figure 210, and the adjusted dispatch with additional resources are shown in Figure 211.
Figure 209: 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 210: 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 211: 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 information regarding additions and reliability metrics is described in Figure 123. Scenario 2 information is described in Figure 212. 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 212: 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 213. 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 213: 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 model runs are complete, resources in PWP’s portfolio are assigned to load in the order shown in Figure 214.
Resources on the top are assigned to load first. Preference is given to dispatchable and internal resources. A ssigning 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 214: 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 215. Scenario 2 has the greatest amount of curtailment.
Figure 215: 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 impacts of new resource cost variations), as excess renewable energy is sold. These results may also predict greater CO 2 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 216: Utility-Scale Solar Nominal Costs
Figure 217: Utility-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)
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27.2. Commercial Solar
Figure 218: Commercial Solar Nominal Costs
Figure 219: Commercial Solar Real 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)
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27.3. Residential Solar
Figure 220: Residential Solar Nominal Costs
Figure 221: Residential Solar Real 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)
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27.4. Utility-Scale 4-Hour Storage
Figure 222: Utility-Scale 4-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 223: Utility-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)
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27.5. Utility-Scale 6-Hour Storage
Figure 224: Utility-Scale 6-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 225: Utility-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)
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27.6. Utility-Scale 8-Hour Storage
Figure 226: Utility-Scale 8-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 227: Utility-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)
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27.7. Utility-Scale 10-Hour Storage
Figure 228: Utility-Scale 10-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 229: Utility-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)
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27.8. Commercial 4-Hour Storage
Figure 230: Commercial 4-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 231: 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)
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27.9. Residential 2.5-Hour Storage
Figure 232: Residential 2.5-Hour Lithium-Ion Battery Storage Nominal Costs
Figure 233: 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)
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27.10. Fuel Cells
Figure 234: Fuel Cells Nominal Costs
Figure 235: Fuel Cells 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 236: Land-Based Wind Nominal Costs
Figure 237: Land-Based 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 238: Offshore Wind Nominal Costs
Figure 239: Offshore 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)
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27.13. Geothermal
Figure 240: Geothermal Nominal Costs
Figure 241: Geothermal 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
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Table of Contents
1. Executive Summary 261
2. Disclaimer 262
3. Portfolio Content Category Requirements 262
4. Renewable Portfolio Standard Procurement Plan 264
4.1. Supply vs. Load ........................................................................................................................................ 264
5. Compliance Strategy 265
6. Balanced Portfolio 266
7. PWP’s Renewable Portfolio Standard and Carbon-Free Strategy 266
8. PWP’s Renewable Portfolio Standard Procurement Process 267
8.1. Quantitative Analysis ............................................................................................................................... 268
8.2. Qualitative Analysis ................................................................................................................................. 268
9. Summary of Renewable Portfolio Standard Procurement Plan 269
10. Renewable Portfolio Standard Procurement Plan Limitations and Relief 273
11. Version History 273
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Table of Figures
Figure 1: Renewable Resource Categories and State Renewable Portfolio Standard Requirements ................................ 263 Figure 2: 2023 Integrated Resource Plan Updated Load Projection ................................................................................... 265 Figure 3: PWP SB 100 Procurement Plan from 2023 IRP .................................................................................................... 270
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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 interim 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 Integrated 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 requirements. 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 Stand ard and Carbon -Free Strategy . The following are the primary changes in this revised RPS Procurement Plan:
• Annual renewable energy 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 recent 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 uncertainties 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 categories (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 [INSERT DATE], 2023.
The RPS Enforcement Program and this RPS Procurement Plan incorporate the regulations established by the California Energy Commission (CEC) regarding Public 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. Th is RPS Procurement Plan addresses not only California’s s tate-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 Enforcement Program. 160
The following categories of renewable resources may be used to meet statutory RPS procurement targets (th ese 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 electricity that meets the requ irement 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 energy 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 Local Publicly Owned Electric Utility (Sections 3200 through 3208) DRAFT
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The Net 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 increasing 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 Enforcement Program as sales of electricity by a POU to end- use customers and their tenants, measured in MWh minus energy consumption by a POU, elect ricity 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 total 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 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 further 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 retail 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 opportunities.
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 planned 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 dist ributed 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 come 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 existing 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 reflected in Figure and a comparison of annual energy procurement against these constraints to determine if future compliance targets (or obligations) will require add itional purchases of PCCs. The final calculation 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 energy 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 remaining 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 c ounterparties, 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 p rocurement will occur as PWP is able to secure resources beyond meeting regulatory requirements and replacing Intermountain 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 capacity over the next eight years (see table below for details). 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. Throughout 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 this 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.
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 between 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 energy 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 screens 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 projects, 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 load 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 commercialized 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 manufacturing 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
Permitting
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 diversification
• 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 pending 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 3: 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 - - -
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Biofuels: New External Fuel
Cells Biofuels WECC
Region
PCC1 - - -
Biofuels: New Internal Fuel
Cells Biofuels WECC
Region
PCC1 - - -
Wind: New Offshore Wind Wind WECC
Region
PCC1 - - -
Total Non-Grandfathered Owned or Contracted Projects - 2,344,889 2,296,829 DRAFT
10. Renewable Portfolio Standard Procurement Plan Limitations and Relief Section E of the City’s RPS Enforcement Program notes that PWP will use its best efforts to procure adequate supplies of renewable energy as set forth in this RPS Procurement Plan; however, PWP will at all times maintain system reliability and average procurement costs for retail electric sales in accordance with the approved budget and retail electric rates approved by the City Council. California law recognizes that adverse situations beyond PWP’s control may arise and prevent PWP from fulfilling the RPS Procurement Targets in a timely manner and consistent with such limitations.
In the event PWP discovers that such conditions, as specified in the City of Pasadena’s RPS Enforcement Program, may potentially prevent PWP from meeting the RPS Procurement Targets set forth in the RPS Enforcement Program, PWP will notify the City Council of the adverse conditions and apply to the CEC for relief. If appropriate, PWP may submit a revised RPS Procurement Plan for discussion, approval, and implementation.
The CEC may reduce a procurement requirement to the extent PWP demonstrates that it cannot comply because of conditions beyond its control.
170 However, the CEC may not, under any circumstance, reduce the procurement obligation of PCC 1 below 65%for any compliance period obligation after December 31, 2016. PWP expects to fully comply with the City of Pasadena’s and the State of California’s mandatory RPS requirements. PWP does not recommend taking advantage of this provision or other optional compliance measures detailed in the City of Pasadena’s RPS Enforcement Program at this time.
11. Version History
• Version 1: Initially adopted July 22, 2013
New mandate to comply with SBX1 2
• Version 2: Amended June 1, 2015
Include updates on contracts and other processes
• Version 3: Amended January 29, 2018
Show compliance with SB 350
Include updates on contracts and other processes
• Version 4: Amended December 10, 2018
Show compliance with SB 100
Include updates on contracts and other processes, as recommended by the 2018 IRP • Version 5: Amended September XXX, 2023
Show compliance with SB 100
Include updates on contracts and other processes, as recommended by the 2023 IRP
170 PUC Section 399.15(5)
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CONFIDENTIAL
100 Garfield Avenue, Room N 106
Pasadena, California 91101
626.744.4005
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CONFIDENTIAL
Renewable Portfolio
Standard
Enforcement Plan
Still Under Development and Review
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CONFIDENTIAL
Table of Contents
1. Purpose 278
2. RPS PROCUREMENT PLAN GUIDELINES 278
2.1. Compliance Periods ................................................................................................................................. 278
2.2. State RPS Procurement Targets ................................................................................................................ 278
2.3. PCC Definition and Balance Requirements ................................................................................................ 280
2.4. Long-Term Contracts ................................................................................................................................ 283
2.5. Additional Requirements ......................................................................................................................... 283
2.6. City Council Discretion ............................................................................................................................. 284
2.7. Review of the RPS Procurement Plan ........................................................................................................ 284
3. Public Notice for RPS Procurement Plan 284
4. Excess Procurement 285
5. Renewable Energy Procurement in Excess of Statutory Procurement Targets 286
6. PRS Procurement Plan Limitations and Relief 286
7. Reporting 289
8. Enforcement 290
9. Version History 291
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Table of Figures
Figure 1: Compliance Targets .............................................................................................................................................. 279 Figure 2: Portfolio Content Categories ............................................................................................................................... 280
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28. Purpose
The purpose of this revised Renewable Portfolio Standard (RPS) Enforcement Program 171 for the Pasadena Water and Power Department (PWP) is to comply with the California RPS pursuant to California Public Utilities Code (PUC) Section 399.30. Each calendar year, PWP will target California state mandated targets (e.g., 60% by 2030), with reasonable progress towards these goals in the intervening years. Pasadena also has its own carbon-free policy goal, which is not subject to State compliance requirements.
29. Renewable Portfolio Standard Procurement Plan Guidelines PWP has developed a RPS Procurement Plan for the City Council to consider for adoption. Going forward, no later than January 1, 2024, PWP will incorporate the RPS Procurement Plan into its broader Integrated Resource Plan (IRP) developed and adopted pursuant to PUC Section 9621(b). The RPS Procurement Plan will at minimum include the elements described in the following sections.
29.1. Compliance Periods
Procurement targets in Section 2.2 reflect the minimum quantity of eligible renewable energy resources to be procured by PWP in each of the following RPS Compliance Periods (CP):
• CP 4: January 1, 2021, to December 31, 2024, inclusive • CP 5: January 1, 2025, to December 31, 2027, inclusive • CP 6: January 1, 2028, to December 31, 2030, inclusive • CPs three years in length beginning January 1 and ending December 31, beginning and after January 1, 2031
29.2. State RPS Procurement Targets172
PWP will procure a minimum quantity of electricity products from eligible renewable energy resources, including renewable energy certificates/credits (REC), as a specified percentage of total retail sales to achieve the targets outlined in Figure 1. In each of the intervening years, PWP must show reasonable progress towards the next goal.
171 Pursuant to California Public Utilities Code Section 399.30 as enacted by California Senate Bill (SB) X1 -2 in 2011 (“The California Renewable Energy Resources Act”) and subsequently revised by Assembly Bill (AB) 2227 in 2012, and in 2015 by SB 350 (“The Clean Energy and Pollution Reduction Act of 2015”), and as implemented through the Pre- Rulemaking Amendments to the Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric Utilities, California Energy Commission Amended Regulations Effective April 12, 2016, CEC- 300-2016-002-CMF; the Pre -Rulemaking Amendments to the Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric Utility (Sections 3200 through 3208), and the California Energy Commission Draft Guidebook, Renewables Portfolio Standard Eligibility, Ninth Edition, July 2016, CEC-300-2016- 006-ED9-SD. 172 PUC Section 399.30(c)(2)
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The requirements shown in Figure reference the California PUC Section 399.30 and SB 100 requirements, not PWP’s goal of 100% carbon-free by 2030.
Figure 1: Compliance Targets
CP Dates Minimum % of RPS
1 [complete] By December 31, 2013 Average of 20% retail sales by 2013 2 [complete] By December 31, 2016 25% of 2016 retail sales 3 [complete] By December 31, 2020 The sum of: 27% of 2017 retail sales, 29% of 2018 retail sales, 31% of 2019 retail sales, and 33% of 2020 retail sales
4 By December 31, 2024 44% of 2024 retail sales
5 By December 31, 2027 52% of 2027 retail sales
6 By December 31, 2030 60% of 2030 retail sales
7+ Post 2030
Not less than a 60% of retail sales, post 2030; the California Energy Commission (CEC) will establish appropriate multi-year
compliance periods at a later time
For the purpose of this RPS Enforcement Program, r etail sales shall be defined as the total volume of energy sold, in Megawatt hours, to all retail end-use customers taking service under Pasadena Municipal Code (PMC) Sections 13.04.040 to 13.04.090173, and 13.04.177 (Net Energy Metering), inclusive. Retail sales may exclude sales to customers taking service under the optional Green Power Option (P MC 13.04.179) or any shared renewable generation program. Sales to retail customers taking Direct Access Service under PMC 13.04.095, energy consumption by PWP, electricity used by PWP for water pumping, and electricity produced for onsite consumption under PMC 13.04.178 (self-generation) that was not sold to the customer by PWP shall not be included in this definition of retail sales.
For a customer participating in the Green Power Option or any shared renewable generation project, if the renewable energy is excluded from the calculation of retail sales, the Portfolio Content Category (PCC) 1 RECs associated with the 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 further sold, transferred, or otherwise monetized for any purpose. To the extent possible, the electricity products excluded from retail sales will be procured by PWP from eligible renewable energy resources that are located in the PWP service territory and in reasonable proximity to program participants
174.
173 PMC Sections 13.04.040 – Residential single-family service, 13.04.045 – Residential multi-family service, 13.04.050 – Small commercial and industrial service, 13.04.060 – Medium commercial and industrial service – Secondary,13.04.064 – Medium Commercial and Industrial Service – Primary, 13.04.067 – Large commercial and industrial service – Secondary, 13.04.070 – Large commercial and industrial service – Primary,
13.04.071 – Special load management and conservation service, 13.04.075 – Long-term contracts, 13.04.080 – Standby Service, 13.04.85 – Unmetered rates – Non-demand, 13.04.087 – Unmetered rates – Demand, 13.04.090 Street lighting and traffic signal service. 174 PUC Section 399.30(c)(4)
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29.3. Portfolio Content Category Definition and Balance Requirements The categories of renewable resources outlined in
Figure will be used to meet the statutory RPS procurement targets.175
Figure 2: Portfolio Content Categories
PCC PCC Description PCC % Balance Requirements
PCC 0: (“Grandfathered” or
“Count-in-Full” resources and
contracts):176
• PCC 0 refers to electricity products
procured pursuant to a contract or
ownership agreement executed
before June 1, 2010, and associated
with generation from an eligible
renewable energy resource that met
the CEC eligibility requirements in
effect when the original procurement
contract or ownership agreement
was executed will be classified as PCC
0. • PCC 0 products will count in full
toward state mandated RPS
procurement requirements177.
“Count-in-full” means that such
renewable electricity products
procured prior to June 1, 2010, will
be applied toward (deducted from)
the state RPS procurement target for
each compliance period prior to
determining the portfolio balance
requirement, subject to the
following:
The associated REC must be
retired within 36 months of the
date the electricity product is
generated.
• No minimum or maximum
requirements; the PCC 0
amount is subtracted from the
RPS needs and any shortage
must comply with the PCC1,
PCC 2, or PCC 3 balance
requirements
• PCC 0 does not have portfolio
balancing requirements
175 PUC Sections 399.30(c)(3) and 399.16, and California Energy Commission Enforcement Procedures Section 3203 176 CPUC 399.16(d) and (e)
177 California Energy Commission Enforcement Procedures Section 3202 DRAFT
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PCC PCC Description PCC % Balance Requirements
The PCC 0 products will not
count toward the portfolio
balancing requirements
The PCC 0 electricity projects
associated with contracts of less
than 10 years will not be
subtracted when calculating
excess procurement (See
Section 4)
PCC 1
• PCC 1 are products procured as a
bundle with associated energy from
the eligible renewable resource.
• To be classified as PCC 1, eligible
renewable energy resource electricity
products must meet the requirement
of either of the following:
Having a first point of
interconnection with a California
balancing authority (BA), having
a first point of interconnection
with distribution facilities used
to serve end users within a
California BA area, or scheduled
from the eligible renewable
energy resource into a California
BA without substituting
electricity from another source
other than to provide real-time
ancillary services required to
maintain an hourly or sub-hourly
import schedule into a California
BA. Only the fraction of the
schedule actually generated by
the eligible renewable energy
resource shall count toward this
PCC.178
• CP2: Minimum of 65%
• CP 3 and thereafter: Minimum
of 75%
178 A balancing authority is the entity responsible for integrating resource plans ahead of time, maintaining balance between loa ds, energy imports/exports, and generation within its balancing authority area, and supporting interconnection frequency in real -time. California balancing authorities include: the California Independent System Operator (CAISO), the Los Angeles Department of Water & Power (LADWP), the Imperial DRAFT
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PCC PCC Description PCC % Balance Requirements
Having an agreement between
the BA in which the eligible
renewable energy resource is
located and a California BA to
dynamically transfer electricity
from the renewable energy
resource to the California BA.179
PCC 2
• PCC 2 refers to electricity products
that must be generated by an eligible
renewable energy resource and be
procured as a bundle (matched) with
incremental energy scheduled into a
California BA from a substitute
resource.180
• The first point of interconnection to
the transmission grid for the eligible
renewable energy resource and the
resource providing the incremental
electricity must be located within the
WECC181 service territory but outside
the metered boundaries of a
California BA area.
• The contract for the incremental
electricity must be executed at the
same time or after the contract for
the renewable electricity product.
• CP 3 and thereafter: Maximum
of 15%
PCC 3
• PCC 3 products may be procured
separately from the energy produced
by the renewable resource
(unbundled).
• Eligible renewable energy resource
electricity products or any fraction of
• CP 3 and thereafter: Maximum
of 10%
Irrigation District (IID), the Balancing Authority of Northern California (BANC), PacifiCorp West, Sierra Pacific Power (SPP), Turlock Irrigation District (TID) and the Western Area Lower Colorado Region (WALC). PWP is in the CAISO balancing authority area. 179 PUC section 399.16(b)(1)
180 PUC Section 399.16(b)(2)
181 Western Electricity Coordinating Council, the non- profit regional electric reliability entity in the western interconnection, which includes 14 Western US states, 2 Canadian provinces, and Northern Baja Mexico.
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PCC PCC Description PCC % Balance Requirements
the electricity generated, including
unbundled RECs that do not qualify
under the criteria of PCC 1 or PCC 2,
fall within PCC 3.182
29.4. Long-Term Contracts
PWP may enter into a combination of long -term and short-term contracts for electricity and associated RECs. Beginning January 1, 2021, at least 65% of the procurement PWP counts toward the California RPS requirement in each compliance period will be from contracts of 10 years or longer in duration, or PWP ownership or ownership agreements, for eligible renewable energy resources. An electricity product classified as PCC 2 will count toward the long -term procurement requirement of this subdivision if the electricity product is procured under a contract of at least 10 years in duration or an ownership agreement, even if the matching incremental electricity is not associated with a contract of at least 10 years in duration or an ownership agreement.
183
29.5. Additional Requirements
• RPS procurement requirement deficits incurred by PWP in any compliance period will not be added to the RPS procurement requirements of a future compliance period. • PWP must retire RECs to meet its RPS procurement requirements within 36 months from the initial month of the generation of the associated energy.
• In general, publicly -owned utilities (POU) may not use RECs for purposes of the California RPS for any given compliance period if that compliance period begins after the date of REC retirement; however, CEC Resolution No. 16-0309-04a (adopted by the CEC March 9, 2016) establishes a process to allow PWP to request that surplus RECs retired and reported to the CEC for a specified RPS CP (surplus retired RECs) be withdrawn and used for the following RPS CP.
• PWP may not procure or retire a REC to meet its RPS procurement requirements for a compliance period that precedes the date of generation of electricity associated with that REC, or the date the REC was procured by PWP. For example, PWP may not procure or retire a REC generated in April 2021 to meet its state RPS procurement requirements for the 2017 to 2020 CP, nor retire a REC generated in November 2020 to meet its procurement requirements for the 2017 to 2020 CP if PWP did not procure the REC until February 2021.
182 PUC Section 399.16(b)(3)
183 PUC Section 399.13(b)
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29.6. City Council Discretion
The City Council will have the discretion to approve, reject, or modify PWP’s recommendations with respect to the following:
• The mix of eligible renewable energy resources procured by PWP pursuant to the RPS Procurement Plan for meeting the greater of the City’s carbon-free policy goal • Those additional generation resources procured by PWP for purposes of ensuring resource adequacy and reliability
• The reasonable costs to be incurred by PWP for any eligible renewable energy resources that may be procured or owned by the utility
29.7. Review of the Renewable Portfolio Standard Procurement Plan PWP shall provide progress and assessments and/or updates of the approved RPS Procurement Plan for the City Council’s consideration when re gulatory mandates modify the RPS requirements and/or significant changes occur to the RPS Procurement Plan as a result of RPS procurement. Going forward, updates to the RPS Procurement Plan will be brought to the City Council on an as needed basis. The RPS Procurement Plan update is included as part of PWP’s 2023 IRP.
30. Public Notice for the Renewable Portfolio Standard Procurement Plan PWP will adhere to the following guidelines related to public notice associated with the RPS Procurement Plan184:
• Post public notice pursuant to the Ralph M. Brown Act 185 when the City Council will deliberate in public on the RPS Procurement Plan
• Contemporaneously notify the CEC of the date, time, and location of the meeting and provide an electronic copy of the RPS Procurement Plan and other documents for posting on CEC’s website This requirement will be satisfied if PWP provides the Uniform Resource Locator (URL) that links to this information
• Upon distribution of information related to its renewable energy resources procurement status and future plans to the City Council for consideration at a noticed public meeting, PWP will make that information available to the public and provide the CEC with an electronic copy of the documents for posting on the CEC's web site This requirement will be satisfied if PWP provides the URL that links to the documents or information regarding other manners of access to the documents
184 PUC Sections 399.30(f)
185 Chapter 9 (commencing with Section 54950) of Part 1 of Division 2 of Title 5 of the Government Code DRAFT
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31. Excess Procurement186
PWP may apply excess procurement in one CP to any future CP, including compliance year s following 2020.187 However, there will be no carryover of deficits between compliance periods. Other provisions include:
• PCC 3 products may not be counted as excess procurement • PCC 0 products that would otherwise be classified as PCC 3 and that exceed the 10% maximum limit for PCC 3 must be subtracted from the calculation of excess procurement • Prior to January 1, 2021, electricity products procured under contracts of less than 10 years in duration will be subtracted from the calculation of excess procurement, unless grandfathered (PCC 0) If procurement is under a contract that has been amended to extend the term, the duration of the amended contract will be calculated from the original contract execution date to the amended contract end date If procurement is under a contract that has been amended to a total term of at least 10 years in duration, the electricity products generated as of the month and year in which the contract amendment occurs will be eligible to qualify as excess procurement
• The numerical express of the excess procurement permitted for the CP ending December 31, 2021, and each annual CP thereafter is as follows:
Excess Procurement = (EP
X) – (RPSX+S2X+ S3X)
EPX = Electricity products retired and applied toward the RPS procurement target for the compliance period X
RPSX = The RPS procurement target calculated for compliance period X S2X = Retired PCC 2 RECs that meet the criteria of Section 3202 (a)(1) or 3202 (a)(3) and that were not applied to the procurement target
S3X = Retired PCC 3 RECs that meet the criteria of section 3202 (a)(1) in excess of the 10% maximum for compliance period X
• For PCC 1 products, contracts of any duration may count as excess procurement • PCC 2 or PCC 3 products shall not be counted as excess procurement • Contracts of any duration for PCC 2 or PCC 3 products that are credited toward a CP shall not be deducted from a retail seller's procurement for purposes of calculating excess procurement
186 Pre-Rulemaking Amendments to the Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric Utilities, California Energy Commission Amended Regulations Effective April 12, 2016; CEC- 300-2016-002-CMF; Section 3206 – Optional Compliance Measures, Subsection (a)(1) – Excess Procurement 187 Pre-Rulemaking Amendments to the Enforcement Procedures for the Renewables Portfolio Standard for Local Publicly Owned Electric Utilities, California Energy Commission Amended Regulations Effective April 12, 2016; CEC- 300-2016-002-CMF; Section 3206 – Optional Compliance Measures, Subsection (a)(1) – Excess Procurement DRAFT
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32. Renewable Energy Procurement in Excess of Statutory Procurement Targets If the City Council establishes RPS goals for PWP higher than the California Procurement Targets, or procures energy to serve PWP Green Power Option customers taking service under PMC 13.04.179 or a shared renewables program, the eligible renewable resources procured in excess of the statutory minimum shall be deemed voluntary and not subject to 188
the following:
• Any mandatory enforcement provisions under California rules or regulations • Any restriction from carry over or banking provisions to subsequent CPs, such as sale, purchase, exchange, or any other use
• Any requirements for or restrictions on portfolio content categorization189 • Any reporting or public notice required by the CEC
33. Renewable Portfolio Standard Enforcement Plan Limitations and Relief PWP will use its best efforts to procure adequate supplies of renewable energy as set forth in this RPS Enforcement Plan and the RPS Procurement Plan; however, PWP will always maintain system reliability and maintain average procurement costs for retail electric sales in accordance with the approved budget and retail electric rates approved by the City Council.
California law recognizes that adverse situations beyond PWP’s control may arise and prevent PWP from fulfilling the RPS Procurement Targets in a timely manner and consistent with such limitations.
In the event PWP discovers that such conditions may potentially prevent it from meeting the RPS Procurement Targets set forth in this RPS Enforcement Plan, PWP will notify the City Council of the adverse conditions and apply to the CEC for relief. If appropriate, PWP may submit a revised RPS Procurement Plan for discussion, approval, and implementation.
The CEC may reduce a procurement requirement to the extent PWP demon strates that it cannot comply because of conditions beyond its control.
190 However, the CEC may not, under any circumstance, reduce the procurement obligation of PCC 1 below 65% for any compliance period obligation after December 31, 2016.
The below applies:
• Delay of timely compliance
188 As defined in PUC Section 399.30(c)
189 PUC Section 399.30(c)(3)
190 PUC Section 399.15(5)
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The City Council may make a finding that conditions exist that are beyond PWP’s control to delay the timely compliance with RPS procurement requirements as defined in Section 3204 of the CEC’s Enforcement Procedures, including achieving procurement targets and balancing requirements for each CP. Such a finding shall be limited to one or more of the following causes for delay and shall demonstrate that PWP would have met its RPS procurement requirements but for the cause of the delay:
There is inadequate transmission capacity to allow sufficient electricity to be delivered from eligible renewable energy resources, or proposed eligible renewable energy resource projects, to the extent applicable, using CAISO’s current operational protocols. The City Council may find that:
PWP has undertaken all reasonable measures under its control and consistent with its obligation under local, state, and federal laws and regulations to develop and construct new transmission lines or upgrades to existing lines intended to transmit electricity generated by eligible renewable energy resources, considering its expectation for cost recovery. PWP has taken all reasonable operational measures to maximize cost -effective purchases of electricity from eligible renewable energy resources in advance of transmission availability. Permitting, interconnection, or other circumstances have delayed procured eligible renewable energy resource projects, or there is an insufficient supply of eligib le renewable energy resources available to PWP:
The City Council must also find that PWP prudently managed portfolio risks, including, but not limited to, holding solicitations for RPS -eligible resources with outreach to market participants and relying on a sufficient number of viable projects to achieve RPS procurement requirements.
PWP sought to develop either its own eligible renewable energy resources, transmission to interconnect to eligible renewable energy resources, or energy storage used to integra te eligible renewable energy resources.
PWP procured an appropriate minimum margin of procurement above the level necessary to comply with the RPS to compensate for foreseeable delays or insufficient supply. PWP had taken reasonable measures to procure cost-effective distributed generation and allowable unbundled RECs.
Unanticipated curtailment of eligible renewable energy resources was necessary to address the needs of CAISO or other BA, if the delay of timely compliance would not result in an increase in greenhouse gases (GHG) emissions.
Unanticipated increase in retail sales due to electrification. For purposes of this paragraph, electrification refers to electrifying sectors that were either supplied by natural gas or other means.