1. 2023 Integrated Resource Plan — Anaheim City Council, May 16, 2023 (part 1 of 2)

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Table of Contents ............................................................................................................................................................... 1 Table of Graphs .................................................................................................................................................................. 4 Table of Tables .................................................................................................................................................................... 7 I. Executive Summary ........................................................................................................................................................ 8 II. APU Fact Sheet............................................................................................................................................................ 26 III. Planning Goals ........................................................................................................................................................... 27 A. Sustainable Resources ............................................................................................................................................. 27 B. High Reliability ......................................................................................................................................................... 28 C. Affordable Rates ....................................................................................................................................................... 30 IV. Key Policy Drivers Affecting the Utility ................................................................................................................ 31 A. Reducing Greenhouse Gas (GHG) Emissions ................................................................................................... 33 B. Increasing Procurement from Renewable Resources ......................................................................................... 34 C. Transformation of the Regional Grid ................................................................................................................... 35 V. Renewable Energy Procurement Plan and Enforcement Program ..................................................................... 36 A. Elements of the RPS Program ............................................................................................................................... 36 B. Planning and Procurement ..................................................................................................................................... 38 C. Status of APU’s RPS Portfolio .............................................................................................................................. 39 D. Potential Compliance Delays ................................................................................................................................. 40 E. Cost Limitation ......................................................................................................................................................... 41 F. Enforcement Program ............................................................................................................................................. 42 VI. Energy Demand and Peak Forecasts ...................................................................................................................... 44 A. Energy Demand Forecast - Methodology & Assumptions .............................................................................. 45 B. Peak Forecast - Methodology & Assumptions .................................................................................................... 58 VII. Resource Portfolio Evaluation ............................................................................................................................... 66 A. Portfolio Considerations and Performance Measures ....................................................................................... 67 B. Resource Options ..................................................................................................................................................... 75 C. Model Analysis – Production Cost Model ........................................................................................................... 79 D. Model Analysis – Input Assumptions .................................................................................................................. 82 E. Model Analysis – Output Evaluation ................................................................................................................... 85 F. Stress Testing ............................................................................................................................................................ 97 G. Optimum Portfolio Selection .............................................................................................................................. 103 2023 Integrated Resource Plan
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H. Rate Impact ............................................................................................................................................................ 110 Standard Base Electric Rates ........................................................................................................................................ 110 Optional Base Electric Rates ...................................................................................................................................... 110 VIII. Reliability & Electric System Overview ............................................................................................................ 114 A. APU Electric System Overview ........................................................................................................................... 115 B. Generation and Transmission Resources ........................................................................................................... 116 C. CAISO Resource Adequacy Requirements ....................................................................................................... 123 D. Distribution System Overview ................................................................................................................................ 127 IX. Greenhouse Gas Emission Reduction ................................................................................................................. 136 X. Transportation Electrification ................................................................................................................................. 141 A. Quantification, Characterization, and Location ............................................................................. .............. 141 B. Transportation Electrification Programs .................................................................................... ................... 145 C. Prioritization and Funding Leverage ........................................................................................ ....................... 150 D. Education and Outreach Plans ............................................................................................... ......................... 151 E. Alignment with State Policy and Local Needs ................................................................................ ............. 153 XI. Distributed Generation and Storage ..................................................................................................................... 161 A. Customer Owned Solar PV .................................................................................................... ........................... 161 B. Solar for Schools .......................................................................................................... ........................................ 163 C. Anaheim Solar Energy Plant at the Convention Center ........................................................................ .... 164 D. Non-Solar Distributed Generation ........................................................................................... ...................... 165 E. Energy Storage ............................................................................................................. ......................................... 166 XII. Energy Efficiency and Demand Response Programs ...................................................................................... 167 A. Program History ............................................................................................................ ....................................... 167 B. Target Setting ............................................................................................................. ........................................... 168 C. Program Highlights.......................................................................................................... .................................... 170 D. Existing Programs .......................................................................................................... ..................................... 172 E. COVID-19 Assistance Programs ............................................................................................... ...................... 176 F. Challenges and Future Program Development .................................................................................. ........... 177 G. Demand Response Programs .............................................................................................................................. 178 XIII. Programs for Low Income and Disadvantaged Communities ...................................................................... 181 A. Definition of Low Income and Disadvantaged Communities ....................................................................... 181 B. Interdepartmental Strategies ................................................................................................................................. 182 C. APU Strategies ........................................................................................................................................................ 186 Appendix A – Renewable Procurement Plan ............................................................................................................. 189 2023 Integrated Resource Plan
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Appendix B – Public Engagement ............................................................................................................................... 190 A. Customer Survey Summary .................................................................................................................................. 190 B. Customer Survey Types ........................................................................................................................................ 190 C. Survey Topics and Summary Results .................................................................................................................. 191 Appendix C – Acronyms and Definitions .................................................................................................................. 200

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TABLE OF GRAPHS

Graph 1: APU GHG Reduction Targets ...................................................................................................................... 34 Graph 2: Cumulative Adjustments to Base Energy Demand Forecast .................................................................... 45 Graph 3: Anaheim Actual Energy Demand 2007 - 2022 ........................................................................................... 46 Graph 4: Historical and Base Energy Demand Forecast by Month ......................................................................... 48 Graph 5: Estimated Electric Vehicle Energy Demand Growth ............................................................................... 50 Graph 6: Estimated Behind-the-Meter Solar Impact to Energy Demand .............................................................. 51 Graph 7: Adjusted Base Energy Demand Forecast .................................................................................................... 55 Graph 8: APU vs. IEPR Energy Demand Forecast .................................................................................................... 56 Graph 9: Cal-Adapt vs APU Maximum Temperature Forecast ................................................................................ 57 Graph 10: Forecasted Energy Demand with Extreme Temperatures ..................................................................... 58 Graph 11: APU Historical Peak Demand ..................................................................................................................... 59 Graph 12: Estimated Cumulative Distributed (Behind‐the‐Meter) Solar PV Capacity ........................................ 60 Graph 13: Average Hourly Solar Profile by Month: Anaheim Convention Center ............................................... 61 Graph 14: Estimated Distributed (Behind‐the‐Meter) Solar PV Impact to Energy Demand ............................. 62 Graph 15: Peak Day Demand Profile ............................................................................................................................ 62 Graph 16: Renewables Serving Peak Demand – Day with High Renewables & Low Energy Demand ............ 63 Graph 17: Renewables Serving Peak Demand – Day with Low Renewables & High Energy Demand ............ 64 Graph 18: Forecasted Peak demand with Extreme Temperatures ........................................................................... 65 Graph 19: Selection Process for the Optimum Resource Portfolio ......................................................................... 67 Graph 20: APU Resource Stack in 2012 ....................................................................................................................... 68 Graph 21: APU Resource Stack in 2022 ....................................................................................................................... 68 Graph 22: Banked and Existing Long-Term Renewable Energy Credits (RECs) ............................................ 70 Graph 23: Planned Emission Reduction ....................................................................................................................... 71 Graph 24: Available Resource Adequacy (RA) System Capacity .............................................................................. 72 Graph 25: Options for the Natural Gas Power Plants ........................................................................................... 75 Graph 26: Simulated RPS Compliance Requirement .................................................................................................. 78 Graph 27: System Diagram (Partial) .............................................................................................................................. 81 Graph 28: Average Annual SP-15 Energy Price .......................................................................................................... 82 Graph 29: Candidate Portfolio Results: RPS Compliance ......................................................................................... 86 Graph 30: Candidate Portfolio Results: Forecasted GHG Reduction ..................................................................... 86 Graph 31: Candidate Portfolio Results: System Capacity .......................................................................................... 88 Graph 32: Local Capacity Resources and LCR Requirement – Reliability and RNG Portfolios ................. 89 Graph 33: Local Capacity Resources and LCR Requirement – Zero Emissions Portfolio ........................... 89 Graph 34: CAISO Flexible Capacity Requirement – Reliability and RNG Portfolios .................................... 90 Graph 35: CAISO Flexible Capacity Requirement – Zero-Emissions Portfolio ............................................. 90 Graph 36: New Resource Builds: Reliability Portfolio ............................................................................................ 91 Graph 37: New Resource Builds: RNG Portfolio ................................................................................................... 92 Graph 38: New Resource Builds: Zero-Emissions Portfolio ................................................................................ 92 Graph 39: New Resource Builds: Zero-Emissions Portfolio ................................................................................ 93 Graph 40: Candidate Portfolio Results: Net Power Supply Cost ............................................................................. 94 Graph 41: Candidate Portfolio Results: NPV: Net Portfolio Cost........................................................................... 94 Graph 42: Candidate Portfolio Results: Wholesale Energy Purchase as a % of Total Energy Portfolio ... 95 2023 Integrated Resource Plan
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Graph 43: Stressed Gas Prices (Partial) ......................................................................................................................... 97 Graph 44: Stressed System Load Growth or Reduction (GWh)(Partial) ................................................................ 99 Graph 45: Stress Test Results: Extreme High Costs vs. Extreme Low Costs ...................................................... 101 Graph 46: Stress Test Results: Portfolio Comparison - Extreme High Costs vs. Extreme Low Costs ........... 101 Graph 47: Stress Test Results: Extreme High Demand vs. Extreme Low Demand ........................................... 102 Graph 48: Stress Test Results: Portfolio Comparison - Extreme High Demand vs. Extreme Low Demand 103 Graph 49: Reliability Portfolio Meets or Exceeds Environmental Goals ............................................................. 104 Graph 50: Reliability Portfolio Forecasted Resource Adequacy ............................................................................. 105 Graph 51: Resource Mix for Retail Energy Demand: 2025, 2030, 2035, 2040 ..................................................... 106 Graph 52: Reliability Portfolio Power Supply Cost Structure ................................................................................. 107 Graph 53: Monthly Avg Residential Electric Bills ..................................................................................................... 111 Graph 54: Residential Electric Bill as % of Median Household Income ............................................................. 111 Graph 55: System Average Rate ................................................................................................................................... 112 Graph 56: Average Cost of Power (cents per kWh) ................................................................................................. 113 Graph 57: Customer Class Data ................................................................................................................................... 115 Graph 58: Reliability Portfolio Forecasted Resource Adequacy ............................................................................. 123 Graph 59: CAISO Local Capacity Requirement – Reliability and RNG Portfolios ............................................ 124 Graph 60: CAISO Flexible Capacity Requirement – Reliability and RNG Portfolios ........................................ 126 Graph 61: Anaheim’s Reliability Performance in Terms of SAIDI, SAIFI, and CAIDI Since 1990 ............... 131 Graph 62: APU at the Top Quartile of Utilities Nationwide for Reliability ......................................................... 132 Graph 63: Basic Characteristics of Smart Grid .......................................................................................................... 134 Graph 64: Advanced Metering Infrastructure ............................................................................................................ 135 Graph 65: APU GHG Reduction Targets .................................................................................................................. 137 Graph 66: APU GHG Emission for System Energy Demand ............................................................................... 140 Graph 67: Estimated Electric Vehicle Energy Demand Growth ........................................................................... 141 Graph 68: Estimated GHG Emission Reduction Summary ................................................................................... 142 Graph 69: EV Charging Stations within APU Service Territory ............................................................................ 143 Graph 70: Cumulative Solar Capacity Installed - Customer Owned Solar Systems ............................................ 161 Graph 71: Location of Customer Owned Solar in Anaheim ................................................................................... 162 Graph 72: Annual kWh Savings Targets ..................................................................................................................... 167 Graph 73: Cumulative Energy Efficiency Saving Goals with CEC Adjustments ................................................ 168 Graph 74: FY 21/22 Residential Program Energy Savings ..................................................................................... 174 Graph 75: FY 21/22 Commercial Program Energy Savings ................................................................................... 175 Graph 76: Map of Anaheim’s Priority Populations as defined by CalEnviroScreen4.0 ...................................... 182 Graph 77: Map of FY21/22 Home Utility Check-Up Program Participation, Layered with CalEnviroScreen

4.0 Census Tract Score ................................................................................................................................................... 186 Graph 78: Map of FY21/22 Dusk-to-Dawn Program Participation, Layered with CalEnviroScreen 4.0 Census Tract Score ....................................................................................................................................................................... 187 Graph 79: Map of FY21/22 Weatherization Program Participation, Layered with CalEnviroScreen 4.0 Census Tract Score ....................................................................................................................................................................... 187 Graph 80: Residential Customer Satisfaction Rating: APU vs. CMUA ................................................................. 192 Graph 81: Customer Survey - Importance of Water Sustainability Initiatives ...................................................... 192 Graph 82: Customer Survey - Measures for Reducing Indoor Water Use ............................................................ 193 Graph 83: Customer Survey - Measures for Reducing Outdoor Water Use ......................................................... 194 Graph 84: Customer Survey – Importance of Solar Energy Initiatives ................................................................. 195 2023 Integrated Resource Plan
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Graph 85: Customer Survey – Support for the Pace of California’s Clean Energy Goals ................................. 196 Graph 86: Customer Survey – Customers Willing to Pay More to Accelerate Clean Energy Goals ................ 197 Graph 87: Customer Survey – Local Air Quality Ratings ........................................................................................ 197 Graph 88: Customer Survey – Customer Opinions on Common EV Statements .............................................. 198 Graph 89: Customer Survey – Sustainability Program Rebates and Satisfaction Rating .................................... 199

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TABLE OF TABLES

Table 1: Temperature Summary ..................................................................................................................................... 47 Table 2: APU Energy Efficiency Targets including Codes & Standards (GDS Associates, Inc.) ....................... 52 Table 3: Historical Load Factors .................................................................................................................................... 60 Table 4: Anaheim EVs and Emission Savings per Vehicle ...................................................................................... 138 2023 Integrated Resource Plan
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I. EXECUTIVE SUMMARY
Introduction
Anaheim Public Utilities (APU) operates a municipally-
owned, vertically-integrated electric utility, which has the privilege and obligation to reliably serve electricity and water to the approximately 350,000 residents and 15,000 businesses within its fifty square mile service territory. As the only municipal full-service electric utility in Orange County, APU is responsible for planning adequate power generation
resources to reliably meet customer demand for electricity after adjusting for customer energy efficiency savings, added energy demand from electric vehicles (EV) and building
electrification, and reductions from customer-owned power generation (e.g., roof-top sola r), all while incorporating sustainability policy goals which call for significant reductions in greenhouse gas (GHG) emissions. In addition to reliability and sustainability, APU seeks to mitigate the impact of legislative mandates on resource additions that increase customer rates.

The 2023 Integrated Resource Plan (IRP ) serves as a long-ter m comprehensive roadm ap to continue APU’s long-standing focus on customers by balancing the demand and supply-side factors of the electric utility. The IRP provides a framework showing how APU will transition away from carbon-inten sive resources such as coal, to clean renewable resources such as wind, geothermal, biogas, small hydro and solar. This aligns with APU’s GHG emission reduction targets and is in accordance with the State’s policy goals required by Senate Bills (SB) 350 and SB 100, including the requirement to update the IRP no less than once every five years. The IRP includes the results of data modeling of customer energy demands balanced against reliability, sustainability, and affordability goals to develop an optimum portfolio of resources to meet the needs of Anaheim residents and businesses over the next 20 years. The following graphic shows how APU balances adjustments to customer energy demand and the gradual reduction of carbon-intensive resources to develop its IRP. The power supply mix will change dramatically over time, with a major milestone projected in 2025, when APU will no longer have coal in its power supply portfolio resulting in a significant reduction in GHG emissions.

APU is responsible for planning adequate
power generation resources to reliably
meet customer demand for electricity
after adjusting for customer energy
efficiency savings, added energy demand
from electric vehicles (EV), and
reductions from customer-owned power
generation (e.g., roof-top solar), all while
considering sustainability policy goals
which call for further reductions in
greenhouse gas (GHG) emissions.

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APU’s 2023 IRP process commenced in mid-2022 with cu stomer outreach efforts which indicated broad support for APU’s responsible transition away from carbon intensive energy resources, strong interest in APU’s sustainability initiatives, and support for procurement of renewable energy resources supplemented by cleaner resources.

The California Energy Commission (CEC) has the authority through the passage of SB 350 to implement IRP guidelines for publicly owned utilities and did so in 2018 by requiring the planning horizon for the initial IRP submissions to extend out to the year 2030. The CEC is proposing amendments to their IRP Guidelines which will extend the IRP planning horizon ou t to the year 2045. As of the wr iting of the 2023 IRP, the proposed changes to the existing IRP Guidelines are not yet formally adopted by the CEC; nonetheless, for the 2023 IRP cycle APU extended its IRP planning horizon out to 2042. Extending the analyses beyond 2042 presented challenges and abnormal results due to the limits within the long-term capacity expansion database that APU utilized, which provides forecasted additions and retirements only through 2042, or a 20-year planning horizon.

Assessment of Customer Energy Demand
APU uses a statistical model to forecast long-term baseli ne customer energy demand, which is adjusted up or down based on planned customer additions, expected transportation and building electrification, estimated customer-owned rooftop solar installations, and expect ed customer energy efficiency reductions. The results of this same modeling in APU’s 2018 IRP projected a cumulative reduction in customer energy demand of 0.86 percent between 2018 and 2030, effectiv ely a zero-growth energy demand forecast. For the 2023 IRP, the adjusted load forecast projects a total load growth of 1.41% be tween 2024 and 2035, effectively a low-growth energy demand forecast, which indicates that the expect ed customer expansion and electrification growth is being mostly offset by customer solar installation and energy efficiency reductions, in both retrofit applications and new developments.

Load forecast beyond 2036 assumes a 0.25% annual load increase. The growth factor is consistent with average load growth between 2027 and 2036 and is applied due to th e lack of information in these outer years for all demand variables.

Base Energy Demand Forecast
+ Energy Demand Addition
• System Expansion
• Electrification
- Energy Demand Reduction
• Solar Installation
• Energy Efficiency
= Adjusted Energy Demand
Forecast
(300)
(200)
(100)
0 100
200
300GWh
Cumulative Adjustments to Base Energy
Demand Forecast 2023 - 2035
Energy Efficiency
Solar PV
Electrification
Planned Expansion
Cumulative Impact on Energy Demand
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Transition to Clean Energy Resources
In planning to serve the customer energy demand foreca st established above, APU must consider its existing power generation resource mix and plan for the reso urce changes necessary to meet its reliability and sustainability goals outlined in the IRP. Although APU’s current resource mix is adequate to reliably serve the low-growth energy demand forecast, up until 2025 it st ill includes a significant amount of coal energy. APU recognizes the importance of having reliable, sustainable, and cost-effective electricity supplies to drive the regional economy, support residents, businesse s, schools, and visitors, all the while protecting the local environment. Carbon dioxide is the primary GHG associated with electricity generation, and APU has been steadily transforming its electric power supply portfolio since 2003 through increased procurement of renewable resources and accelerating the exit of coal ownership agreements and other contractual obligations. As an example, APU completed divestiture of its ownership share of the San Juan Generation Station, a coal resource in 2017 that demonstrated to customers that APU is responsibly transitioning towards decarbonization.

Upon the Intermountain Power Project (IPP) conversi on to natural gas, which is scheduled for mid-2025, APU’s power supply portfolio will be 100 percent free of coal resources. APU will completely end its contractually obligated participation in IPP in 2027. Transitioning away from coal resources and replacing them with renewable and/or carbon-free energy resources was the optimum resource portfolio identified in the 2018 IRP to meet the State’s clean energy and climate goals while maintaining affordability and reliability. The 2023 Statewide Goal
20% Below 1990
GHG Emission Levels
Statewide Goal
40% Below 1990
GHG Emission Levels
SB 100 Zero‐Carbon
Obligation
APU Achieves
20% Below
1990 GHG Levels
Divestiture of San Juan
Generating Station
IPP Conversion
to Natural Gas
0 250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
MTCO2e (x 1,000)
Resource Portfolio GHG Emission Reductions
(1990 Emission Level ~2.3M MTCO2e)
Statewide GHG Reduction Targets 2022 Scoping Plan Target Share Actual Emissions Forecasted Portfolio GHG Emissions
APU GHG Emission Target Range
386,000 ‐ 305,000 MTCo2e
The divestiture from coal
energy, along with the
support for accelerating
transportation electrification,
will reduce APU’s GHG
emissions by more than 80%
below 1990 emission levels by
the year 2030.
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IRP reaffirms that the optimum pathway to decarbonization requires continuing to divest from coal and invest in new clean energy resources and storage technologies. These clean energy resource additions, along with APU’s support for accelerating transportation and building electrification, is expected to reduce APU’s GHG emissions by more than 80% below 1990 emission levels by the year 2030, significantly exceeding the State’s current overall target of 40% below 1990 emission levels by 20301.

Renewable Energy Resource Procurement Plan
On May 15, 2018, Anaheim’s City Council approved APU’s 2018 IRP, which expanded the procurement of renewable energy resources to serve Anaheim electric customers from 33% to 50% renewable energy by 2030, consistent with the mandates of SB 350. SB 350 also required that utilit ies incorporate existing renewable energy resource procurement plans into IRPs going forward. The 2023 IRP includes APU’s most recent update to its renewable energy resource procurement plan, which is in accordance with the 60% renewable energy by 2030 target established in late 2018 through the passage of SB 100. SB 100 also established a state policy goal for utilities to serve 100% of customer retail sales from carbon-free resources by 2045.

The 2023 IRP evaluated and modeled th ree power supply procurement plans and the follow ing pie charts display the changing resource mix over time under the optimal Reliability Portfolio. The new resources are recommended by the optimization model runs, which reflect RPS requirements and constraints, planning reserve margin requirements, and seeks to meet en vironmental goals and reliability requirements, while managing cost pressures. Under the Reliability Portfolio, the renewable perc entages continue to increase over the years, consistent with State mandates. As existing contractual obligations end over time and new resources are added to the portfolio, APU plans to add cost-effective resources includ ing utility-scale solar plus battery storage, solar and wind while gradually decreasing fossil-fuel generation to maintain grid reliability.

1 AB 9 (Muratsuchi) & SB 12 (Stern) introduced this legislative session seek to increase the 2030 goal to 55% below 1990 levels.

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Optimum Resource Portfolio
APU’s renewable portion of its current overall power resource mix consists mainly of baseload renewables such as geothermal, landfill gas and biofuels. These baseloa d resources operate continuo usly around-the-clock and are not dependent on favorable weather conditions unlike intermittent resources such as wind or solar power generation. To supplement these baseload renewables and to cover the capacity and generation from the divestiture of IPP in 2027, APU modeled three power supply portfolios. As shown in the bar chart, the Net Present Value (NPV) identified the Reliability Portfolio as optimal from a cost perspective, and still requires an investment of nearly $4.6 billion over 20 years. The Reliability Portfolio not only is the most affordable, it also maintains high reliability, achieves APU’s sustainability goals, and complies with State mandates. Power supply modeling includes the replacement of the divested coal
resource and considerations for the gradual decrease of natural gas resources, and includes qualitative performance measures and production cost modeling.

Production cost modeling analysis was used to compare the overall power supply cost of APU’s existing resources plus any new resources considered for each portfolio. In addition to the expected cost of each portfolio scenario, the following five factors were also considered in determining the optimum portfolio: Compliance, Regulatory Risk, Resource Adequacy, Portfolio Diversification, and Market Exposure. The
Reliability Portfolio outper formed the other portfolios under both ex pected conditions and stress tested conditions, such as extreme heat, extreme carbon pricing, extreme fuel price volatility, and extreme high or low energy efficiency, behind-the-meter solar penetration, and proliferation of transportation and building electrification.

Under the Reliability Portfolio, APU
plans to achieve a diverse and low-
emission resource portfolio that meets
the RPS and GHG reduction goals,
achieves resource adequacy and local
reliability, and maintains affordable
electric rates. The following graphic
shows that the Reliability Portfolio
causes the lowest overall increase in
power supply costs, compared to the
two other scenarios: the Renewable
Natural Gas (RNG) Portfolio that
considers investments in biofuels to
replace natural gas, and the Zero
Emissions Portfolio that considers
elimination of natural gas resources . The additional costs for these alternatives are $326M and $461M, respectively.

APU’s resource portfolio will be coal-free by mid-2025 and, at a minimum, 60% of APU’s electricity deliveries will come from renewable energy resources. Based on current law and regulations, APU’s optimum resource portfolio under the 2023 IRP will achieve the upper bound of the proposed GHG reduction target range (i.e., Under the Reliability Portfolio, APU
will achieve a diverse and low-emission
resource portfolio that meets RPS and
GHG reduction goals, achieves
Resource Adequacy and local
reliability, and maintains affordable
electric rates.
$4,400
$4,500
$4,600
$4,700
$4,800
$4,900
$5,000
Reliability Portfolio RNG Portfolio Zero Emissions
Portfolio
Millions
Net Present Value: Portfolio Cost
(2023 - 2042)
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83% GHG reduction); however, the lower bound of the range (i.e., 87% GHG reduction) will not be achieved without cost impacts. This is not an isolated issue fa cing APU and is outlined in the Joint Agency SB 100 report2, published in 2021, which outlined the viability and challenges in serving California demand with 100% zero-carbon resources. This report id entified that achieving a 100% zero-carbon by 2045 was achievable but would require significant costs and unprecedented renewable resource build rates. Fulfilling the more stringent 87% GHG reduction target could cause a significant rate impact to APU customers as it would require the shutdown, fuel conversion, or “stranding,” of a reliabl e and efficient baseload natu ral gas resource Magnolia Power Plant, which has 20-years of unavoidable debt service costs that would still need to be paid by APU customers in addition to replacement renewable resources. The gradual reduction of the reliance of natural gas and the corresponding contractual and bond financing obligations would help maintain reliability and ease the cost burdens on APU customers who will already need to invest heavily in clean energy resources. APU is closely following relevant regulatory proceedings and will work with the California Air Resources Board (CARB) and California Energy Commission (CEC) to recommend methodologies to reduce APU carbon emissions, such as accounting for the effect of electric vehicle (EV) penetration and building electrification on emission reduction, without compromising reliability especially as hot summers require an all-resources approach to meet peak demands.

2 https://www.energy.ca.gov/publications/2021/2021-sb-100-joint-agency-report-achieving-100-percent-clean-electricity APU GHG Emission Target Range
386,000 ‐ 305,000 MTCo2e
(83% ‐ 87% lower than 1990 levels)
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Projected Impacts on Customer Rates
APU strives to find resources that are cost-effective and minimize rate impacts on customer utility bills, while still meeting its compliance obligations for increased renewables and lower GHG emissions. By responsibly di vesting of its coal assets and utilizing its peaking resources to integrate more renewable purchases, APU has been able to maintain affordable electric rates. The following graphic shows the expected net power supply cost forecast from 2023 through 2042 based on the Reliability Portfolio and the expected consumption case. The net cost to supply power, presented in the graphic below, is estimated to be $126 million higher in 2042 compared to 2023, or a 2.97% average annual increase over the next 20 years.

The increase is mainly driven by procurement costs for the resources necessary to meet the State’s carbon-free energy goals and GHG emissions reduct ions (carbon neutrality by 2045), as well as an increase in scheduling service fees for participation in the CAISO markets. This analysis does not take into account future legislation or regulatory requirements or other cost pressures such as inflation, supply chain, fleet replacement, and grid modernization that may subject customers to additional rate increases.

Power Supply Cost Structure – Reliability Portfolio

APU performed cost impact analyses under high, medium, and low load growth scenarios to determine the potential cost impact of various changes in re gulatory requirements and resulting impacts on power supply costs. The results of this study principally su ggest how the projected cost impact to customers is By responsibly divesting of its coal
assets and utilizing its peaking
resources to integrate more
renewable purchases, APU has been
able to maintain affordable and
competitive electric rates.

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relatively modest, even under the low consumption scenario where the average cost of power peaks at approximately 14 cents per kWh in FY 2027; under th is scenario, the average cost of power increases modestly at a compound annual rate3 of 2.37% over five years to reach this hypothetical peak. As shown in the chart, the average cost of power is forecast to dip thereafter, as Anaheim will exit from IPP and no longer be subject to the associated cost obligations.

This analysis was based on forward-
looking assumptions and is subject to
change due to commodity price
fluctuations, policy changes,
technological developments, and/or
changing customer behavior. APU will
continue to update its long-term plan
as expectations change in order to
maintain accurate forecasts. While the
model used for the 2023 IRP analysis
was based on information available at a
single point in time, it is not
uncommon for assumptions to change
over time as additional information is
made available.

Customer Cost Protections
The acceleration of procurement for renewable and carbon-free resources to replace IPP and meet the State’s escalating goals for clean energy resources is one key driver for upward pressure on customer rates going forward. It is important that State programs mandating certain types of procurement from utilities include provisions that protect customers from disproportionate rate impacts. APU’s renewable energy resource procurement plan includes a cost limitation
methodology that can be used to prevent a
disproportionate impact on customer
electric rates caused by a significant increase
in costs associated with the procurement of
renewable energy resources. The State’s
RPS law permits the local governing board
of each publicly owned utility (POU), such
as APU, to implement a cost limitation for
its RPS activities for the protection of APU
customers. As part of the 2023 IRP, APU is
updating its cost limitations policy to
consider the expanded 60% RPS.

These cost limitation rules are intended to
protect APU customers from experiencing

3 This is calculated using the geometric mean or compound annual growth rate over five years. ¢
2¢
4¢
6¢
8¢
10¢
12¢
14¢
16¢
2024 2025 2026 2027 2028 2029 2030
Average Cost of Power (¢/kWh)
High Consumption Scenario Expected Consumption Scenario Low Consumption Scenario
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significant and disproportionate rate impacts resulting from procurement expenditures used to comply with RPS procurement requirements. More detailed information can be found in Section V. Renewable Energy Procurement Plan and Enforcement Policy.

Local Reliability and Air Quality
Of APU’s approximate 640 MWs of generation capacity, 200 MWs are lo cated within the City. The Canyon Power Plant provides flexible power generation capability that counts towards resource adequacy capacity near the Anaheim load center, including lo cal black-start capability, which enha nces local and statewide reliability.

The power plant uses natural gas fuel, including air emission controls to meet stringent air quality permit conditions, has much lower GHG emissions than coal resources, and operates as flexible peaking units to support the morning and evening ramping needs of the pow er grid and backup fluctuations in solar and wind output due to weather.

According to APU’s 2022 residential customer survey, ju st over 77% of the respon dents indicated that they have acceptable to excellent air quality near their home, and approximately 63% of the respondents indicate the air quality has improved or stayed the same over the past few years.

To improve local air quality and support sustainabilit y goals, APU facilitates and promotes transportation electrification through electric vehicle time-of-use rates, rebate incentives for public access and private use charging stations, and the electrification of utilities field services vehicles. APU also supports and facilitates the installation of fast-charging infrastructure to be used by visitors and residents without home charging facilities, which helps to remove fossil fueled vehicles from the road and improves local air quality.

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In addition, APU supported customer-owned
solar distributed generation by fully
implementing the SB 1 solar initiative rebates.

Over the past two decades, APU’s commercial
and residential customers have installed over 47
MW of solar capacity. APU continues to expand
clean local distributed generation through
utility-owned solar projects. For example, APU
installed and maintains 2.4 MW of solar on the
roof of the Anaheim Convention Center and

1.5 MW solar carports and lunch shelters at nine
public schools throughout Anaheim through its
Solar for Schools program.

Programs for the Low Income and Disadvantaged Communities APU has a tradition of helping low income customers use energy efficiently to reduce their electric bills, and APU has historically provided rate discounts to income-qualified seniors, military veterans and disabled customers, and
directly applies bill credits to qualifying residential customers through the federally-funded Low Income
Home Energy Assistan ce Program (LIHEAP).

Additionally, the energy from the Solar for Schools
program is administered as a solar discount for income
qualified residents who may not be able to procure solar as multi-family development tenants or financial limitations on obtaining solar themselves. APU also offers Home
Utility Check-ups that provide indoor and outdoor energy assessments along with LED light bulb replacements and other measures that reduce the customer’s energy usage and educ ate them on making smart energy decisions.

APU has incorporated programs that assist “disadvantaged comm unities (DAC),” as defined by SB 535 and the most current version of CalEPA’s California Communities Environmental Health Screening Tool (“CalEnviroScreen”), which includes low income communities and households known as “priority populations “that are especially vulnerable to the impacts of climate change. The CalEnviroScreen considers area pollution exposure levels in addition to income and unemployment levels to determine which areas are disadvantaged.

However, APU programs serve expanded DAC areas, which include low income areas defined by the Department of Housing and Urban Development as Community Development Block Grant (CDBG) areas.

The following map illustrates this expanded DAC area served by APU DAC programs:

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City of Anaheim CalEnviroScreen 4.0 Score by Census Tract

To ensure energy efficiency, transportation electrification and renewable energy is accessible to the low income and disadvantaged communities (LI-DACs), APU offers program incentives and works closely with other City departments including Planning and Building, Public Works, Community Services, and Housing and Community Development to service LI-DAC customers. Below are some examples of interdepartmental collaboration to ensure that investments are made in the City’s most vulnerable communities.  Partnering with other departments to host community outreach events, sustainability fairs, mobile family resource clinics, neighborhood popup meetings, and EV ride and drive events.  Providing no-interest loans to other City departments to improve efficiency at parks and libraries in LI-DACs.
 Offering rebates for enhanced energy
efficiency and publicly accessible EV
charging stations located at schools and
Affordable Housing Developments. The
public access EV rebate program is
funded by proceeds from the California
Low Carbon Fuel Standard (LCFS)
program.
 Actively seeking grant opportunities to
support EV charging stations and shade
trees for qualifying commercial, industrial,
and residential projects, and multi-family
developments near freeways and within
LI-DACs.

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 Transitioning to LED streetlights and partnering with the Southern California Gas Company to offer no-cost weatherization services that are frequently located within LI-DACs.  Providing EV charging stations at city sites within LI-DACs through grant funding opportunities.  Offering an EV ride-share program at affordable housing developments to residents for local commuting needs.

Data analytics is used to maximize LI-DAC residents’ participation in efficiency programs. As an example, a significant majority of the customers who participate in the Home Utility Checkup Program are within LI- DACs, as illustrated in the following map below. APU’s weatherization program is therefore enhanced through the Home Utility Checkup Program. Eligible customer s applying for the Home Utility Checkup are also pre- qualified for free weatherization installations. The graph below shows CalEnviroScreen 4.0 layered maps detailing APU’s Home Utility Check-Up Program, Dusk- to-Dawn Lighting Program, and income-qualified Weatherization Program participation for Fiscal Year 2021/22, considering CalEnviroScreen census tract data and associated score.

CalEnviroScreen 4.0 Score and APU’s Home Utility Check-Up Program Participation as of December 7, 2022

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CalEnviroScreen 4.0 Score and APU’s Dusk-to-Dawn Program Participation as of December 7, 2022

CalEnviroScreen 4.0 Score and APU’s Weatherization Program Participation as of December 7, 2022

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Customer Satisfaction and Outreach
In 2018, APU actively solicited inpu t from customers and received responses from residents and businesses through online surveys, phone interviews, and outreach events. For the 2023 IRP, APU again commissioned a residential satisfaction survey to compare with, and build upon, the feedback received from the 2018 IRP customer survey. The primary goals of this research study were to assess the effectiveness of APU’s ability to serve its customers, identify areas for
improvement, and isolate areas that may increase
engagement.

The 918 survey results show high satisfaction with
the APU’s overall services, with high marks for
reliability, safety, and value, consistent with the
2018 survey. Customers al so expressed support
and satisfaction with APU’s sustainability
programs and initiatives, with mixed support for
the State’s pace for renewable and carbon-free
energy goals. In line with the 2018 IRP customer
responses, customers re main concerned with
potential cost increases related to increased renewable and carbon-free energy goals.

The California Municipal Utilities Association (CMUA) conducted a statewide customer satisfaction survey in 2016
4 that reached nearly 1,400 reside ntial customers. In comparison to the CMUA municipal customers surveyed, APU customers once again expressed a significan tly higher overall customer satisfaction with APU services.

Importance of Environmental Sustainability Measures
As a utility that provides both water and electric services to its customers, APU solicited input on a series of questions pertaining to water and electricity sustainability initiatives, considering that water and energy systems are interdependent. Over 95% of APU’s residential customers indicated that they have taken one or more

4 The 2016 CMUA customer survey is the latest available as of the writing of the 2023 IRP, another survey is expected within the next 2 years.

86.3%

55.0%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
%
Overall Satisfaction with Electric Services
2016 CMUA Statewide 2022 APU Residential

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measures to reduce indoor water use, and approximately 68% indicated they have taken one or more measures to reduce outdoor water use.

APU customers were also asked about their thoughts on solar energy initiatives and their importance. Nearly four-fifths (79.9%) of customers resp onded that the “more solar at local homes and businesses with battery systems” initiative is an important sustainability initiative. Similarly, APU customers indicated that “more large- scale solar with batteries in remote areas that transmit into APU” as important. Nearly three-quarters of APU’s customers believe that initiatives that provide compensation for customers that voluntarily reduce energy usage during peak times or allow APU to control customer equipment (such as air conditioners) are important to them. Only 51.7% of APU’s customers feel that requiring time-of-use rates to reduce energy demand during peak times is an important initiative.

Expansion of California’s Clean Energy Goals
In its 2018 IRP, APU outlined its plan s to increase renewable power to 50% by 2030, reduce coal power to zero as contracts expire, and do this over a 10-year pe riod to keep the impact on electric rates to a minimum.

Customers were asked to rate how strongly they support or oppose this approach, and approximately 65% of APU’s residential customers supported that plan. For the 2023 IRP, customers were asked for their thoughts on the timing of California’s 60% RPS and the additional goal to provide 100% carbon-free energy to all retail customers by the year 2045. Customer responses indicate moderate support for the timing of the State’s clean energy goals with 42.9% of customers indicating the timing is “just right” while 26.9% indicate they are “too slow”.

Since the last APU IRP in 2018, the passage of SB 100 expanded California’s RPS to 60% by 2030 and added the carbon-free policy goal by 2045. For the 2023 IRP, APU asked customer s if they would be willing to pay more to reach higher clean energy percentages faster than state law requires. Customer responses to this IRP survey are consistent with the customer responses from the 2018 IRP.

79.9% 78.0% 74.0% 71.9% 69.8% 51.7%
0%
20%
40%
60%
80%
100%
More solar and
local homes and
businesses
w/battery systems
More large scale
battery systems
with solar in
remote areas that
transmit to APU
Paying customers
to voluntarily
reduce energy use
during peak
demand times
Paying customers
for controlling
their equipment
(e.g., thermostats)
More stand-alone
battery systems
Requiring
customers to
change to time-of-
use rates to reduce
energy during
peak demand
times
Importance of Solar Energy Initiatives
% of Customers Scoring Initiative as "Important" (Scores 7-10 on a scale of 1-10) 2023 Integrated Resource Plan
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The survey results indicate that a noticeable percentage of customers (46.3%) are hesitant or unwilling to incur additional rate increases due to increased or accelerated clean energy goals.

1.4% 2.7% 4.0% 18.8% 26.7%

46.3%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
Other Amount $30-$40 More $20- $30 More $10-$20 More Less than $10 Not Willing to Pay More
Customers Willing to Pay More to Reach Clean Energy
Goals Faster
% Customers Willing to Pay More to Reach Clean Energy Goals Faster 2023 Integrated Resource Plan
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Executive Oversight and Governing Board Approval
Executive Oversight
IRP development and subsequent updates are guided by an Executive Oversight group consisting of the following members:
o General Manager
o Assistant General Manager – Administrative & Risk Services o Assistant General Manager – Electric Services
o Assistant General Manager – Finance and Energy Resources o Assistant General Manager – Water Services
Staff receives direction and support from the Executive Oversight group on all aspects of the IRP, particularly the cross-departmental efforts such as transportation and building electrification and programs and resources focused on the low income and disadvantaged communities.

Board and Council Approval
The 2023 IRP and future updates will be made available to the public for re view as part of two meetings; the first opportunity will be at a Public Utilities Board (Board) meeting. The Board is comprised of seven Anaheim residents who are appointed to staggered four-year terms by members of the Anaheim City Council. Their role, as defined in the City Charter, is to make recommendations to the Anaheim City Council on utility matters, including:
o Annual capital and operating budgets
o Water and electric rates, rules and regulations
o Operation of the water and electric utilities
o Financial matters including issuing bonds
o Reliability improvements
Upon the Board's recommendation for approval, the IRP is presented to the Anaheim City Council at a subsequent meeting allowing for public comment. The Anaheim City Council will then consider the 2023 IRP for approval and adoption.

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II. APU FACT SHEET

Dukku Lee
Utilities General
Manager
Brian Beelner
Assistant General Manager
Finance & Energy Services
Janet Lonneker
Assistant General Manager
Electric Services
Janis Lehman
Assistant General Manager
Administration & Risk Services
Craig Parker
Assistant General Manager
Water Services
Local Ownership & Control
Anaheim Public Utilities is a city-owned, not-for-profit electri c and water utility that offers quality electric and water services to residents and businesses in Anaheim at rates among the lowest in California.

Anaheim citizens are more than utilities customers: they are owners of their utilities. They ha ve input to the decision process both directly and through a City Council appointed Public Utilities Board. With final authority vested in Anaheim's elected City Council, decisions are made in the best interest of our citizens, quality of life, and local economy.

As a municipal, not-for-profit utilities, our rates are based on our costs of providing water and electricity. 1 One resource within Anaheim Service Area
2 Conversion to natural gas in 2025
3 Ten resources within Anaheim Service Area
Electric Services Facts
Anaheim Public Utilities (APU) operates the only
municipal electric utility in Orange County,
delivering more than 3.7 million megawatt-hours
to Anaheim’s 350,000 residents and more than
15,000 businesses, including multimillion- dollar
tourism, sports, and manufacturing customers.

APU’s generates approximately $350 million in
retail sales annually, with total assets of $1.7
billion.

Power Use
Residential customers make up ~85% of APU’s
total customer meter base; however, nearly 75% of
total load is consumed by commercial and
industrial customers.

Resource Adequacy
APU has 640 megawatts (MW) of generation
capacity from various types of resources. The
record peak customer demand of 593 megawatts
was reached on July 14, 2006.

Power Resources
2 natural gas (in-state1)
1 coal (out-of-state2)
1 large hydroelectric (out-of-state)
4 small hydroelectric (in-state)
12 solar photovoltaic (in-state3)
1 geothermal (out-of-state)
3 wind (1 out-of-state)
2 landfill gas (in-state)

Distribution Infrastructure
Transmission, 220kV
 1.2 circuit miles
Sub-Transmission, 69kV
 29.3 circuit miles of overhead
 59.7 circuit miles of underground
Distribution, 12kV and lower, circuit miles
 Overhead – 389 primary, 1,153 secondary
 Underground – 769 primary, 979 secondary
Transformer Capacity, KVA
 220kV to 69kV – 1,808,000
 69kV to 12kV – 1,325,800
 12kV to customer – 1,911,248

14 Substations
22,305 Streetlights
11,866 Distribution Transformers
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III. PLANNING GOALS
APU’s mission is to be an agile, customer‐focused, water and power utility operating in an ever‐changing world providing reliable, high quality, environmentally sustainable, and competitively priced water and power and delivering the maximum value to our customer ‐owners in order to preserve Anaheim’s health and prosperity.

The 2023 IRP supports this mission by establishing resource planning goals for sustainable resources, high reliability, and affordable rates, including the following sub-goals:

A. SUSTAINABLE RESOURCES
For more than two decades APU has been a leader in helping its customers use energy wisely and efficiently and
transitioning to sustainable power resources such as wind, geothermal, biogas, small hydro, and solar. These efforts, in combination with the transition away from carbon intensive resources will ensure APU is on track to achieve compliance with key California policy goals.

In 2006, Assembly Bill (AB) 32 established a statewide GHG emissions reduction target of 20% below 1990 levels by
2020. This goal was expanded by the passage of SB 32, which established a statewide GHG emissions reduction
target of 40% below 1990 levels by 2030. To help achieve the State's GHG reduction goals, Governor Brown signed
SB 350 in 2015, which establis hed targets for all California electric utilities, including APU, to increase the use of renewable resources to serve customer load to 50% by 2030. SB 350 also sets a goal to double electricity and natural gas energy efficiency savings statewide by 2030. In 2019, the passage of SB 100 increased the SB 350 renewable energy requirement of 50% by 2030 to 60% by 2030 and established a state policy to serve 100% of all customer load from renewable energy resources and zero-carbon resources by 2045.

The 2023 IRP lays out a plan for APU’s resource portfolio to achieve Anaheim’s sustainability goals and comply with all of California’s legislative and regulatory requirements, including the following:

Sustainable
Resources
•R P S G o a l
• Emmission
Reduction Goal
• Regulatory Risk
High
Reliability
• Resource Adequacy
• Portfolio
Diversification
Affordable
Rates
• Expected Cost
• Market Exposure
Key California Policy Goals
60% renewable resources by 2030
GHG reduction of 40% below
1990 levels by 2030
Cumulative doubling of energy
efficiency savings by 2030
Phase-out of coal, 100% carbon
free energy goal by 2045

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 Meet or exceed the following Renewables Portfolio
Standard (RPS) targets, as a percentage of retail load:
 50% by December 31, 2026; and
 60% by December 31, 2030, and each year
thereafter.
 Meet or exceed the GHG emissions reduction targets
established by the California Air Resources Board (CARB) for electric utilities, which co ntribute toward a statewide GHG emissions reduction goal of 40% below 1990 levels
by 2030. The GHG reduction targets established by CARB
for POUs are currently 77% to 87% below 1990 levels by
2030. These targets are expected to be revised to align with CARB’s 2022 Final Scoping Plan for Achieving Carbon
Neutrality resulting in POU emission reduction targets of 83% to 87% below 1990 levels.  Meet or exceed the energy efficiency targets es tablished by the Anaheim City Council for APU electricity customers, which contri bute toward a statewide cumulative doubling of energy efficiency savings in the electricity and natural gas sector fina l end uses by 2030. The energy efficiency target established for APU by the Anaheim City Council is currently a 1.1% reduction in electricity sales per year.
 Phase-out of all APU coal resources by 2025.

These sustainability goals and reasonab le Regulatory Risk were considered in the development of the power supply scenarios evaluated under the 2023 IRP. Regulatory Risk measures the ability to remain compliant with current and anticipated future legislative or regulatory changes. The recommended optimum portfolio is expected to achieve all these goals and be resilient to future regulatory risk.

B. HIGH RELIABILITY
High overall electric service reliability is a key APU goal considered in the development of the 2023 IRP. Overall electric service reliability is comprised of 1) high power supply reliability and 2) high electric distribution system reliability.

High power supply reliability is measured by two qua ntitative portfolio performance measures: Resource Adequacy and Portfolio Diversification.

1. Resource Adequacy is measured by the ability to achieve an additional 15% capacity over the forecasted system peak demand, and to meet local and flexible capacity requirements.

2. Portfolio Diversification is measured by the differ ent types of resources, fuel and contract lengths within the portfolio, which increases flexibility, re liability, and operational performance of the overall portfolio.

Sustainable Resources
60% RPS is measured by percent of renewable energy
delivered to serve retail load.
40% GHG Reduction is measured by percent of
GHG reduction of the total generation portfolio.

Regulatory Risk measures the ability to remain
compliant with current and anticipated future legislative or regulatory changes.
2023 Integrated Resource Plan
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While the power supply portfolio scenarios evaluated
under the 2023 IRP primarily considered power supply
reliability (versus distribu tion system reliability), the addition of customer-owned distributed energy
resources (DER), such as rooftop solar, fuel cells, and batteries, the proliferation of electric vehicle charging infrastructure, and increased energy efficiency
measures will have an effect on electric distribution
system and the need to inve st in enhancing reliability; as such, they were also considered and addressed under
various sections of the 2023 IRP. The recommended
portfolio maintains high power supply reliability
through 2030 and beyond, and the expected effect of the aforementioned demand-side factors were determined to have no adverse impact on APU’s high electric distribution reliability going forward.

More specifically regarding power supply reliability, APU operates within the balancing area of the California Independent System Operator (CAISO), and the CAISO is within the Western Interconnection of the United States, known as the electric “Grid.” The electric Grid interconnects thousands of power generation plants across the 14 western states and parts of Canada and Mexico using a high voltage power transmission system, and all of these generators collectively serve customer electric demands. By participating in this interconnected Grid system, APU operates with extremely high power supply reliability because the loss of any single generator does not affect the delivery of electricity to APU customers, who pay for this level of service through their retail rates. Additionally, APU is able to offer resources to enhance Grid reliability, especially during extreme weather events.

In addition to maintaining Resource Adequacy to maintain adequate power generation capacity beyond that required to serve its own customers and cover any unexpected losses of power generation, the CAISO and the other balancing authorities operating the Grid also adhere to reliability and cyber security standards established and monitored by the North American Reliability Corporation (NERC) under the auspices of the Federal Energy Regulatory Commission (FERC). APU is in fu ll compliance with NERC reliability standards and manages a comprehensive NERC compliance program, which includes annual self-certification, internal audits and formal program reviews.

APU adheres to the CAISO tariffs an d Business Process Manuals pertaini ng to the Grid-level reliability requirements. The reliability requirements and Resource Adequacy programs provide performance and deliverability criteria for generation resources require d for each load serving entity. APU’s resources fully comply with the system-wide, local, and flexible Resource Adequacy requirements established by the CAISO, and the recommended portfolio is expected to maintain this reliability as APU phases out coal resources and adds renewable resources to achieve a 60% RPS. Also, to improve system resiliency, a diversified and flexible portfolio is considered to minimize risks of unplanned facility outages accomp anied with acquisition of resources with complementary generation profiles.

High Reliability
Resource Adequacy is measured by the ability to
achieve 15 percent above system peak forecast, and to
meet forecasted local and flexible capacity requirements.

Portfolio Diversification is measured by the
different types and length of resource investment within the portfolio.
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C. AFFORDABLE RATES
As a municipally-owned utility, maintaining affordable electric rates is a key APU goal considered in the development of the 2023 IRP. APU customers consistently express the need for afford ability in their electric rates, given their housing and other cost pressures. APU has consistently maintained electric rates that are lower than adjacent investor-o wned utilities, and the
recommended portfolio is expected to help maintain
affordable rates throughout the planning period.

Sections 205 and Section 206 of the Federal Power Act
stipulate that “all rules and regulations affecting or
pertaining to such [public utility] rates or charges shall be just and reasonable.” State statute also requires that the integrated resource plan “enable each electrical
corporation to fulfill its obligati on to serve its customers at just and reasonable rates.” In addition, Article XIII C of the California Constitution requires that electric rates do not exceed APU’s reasonable cost to provide electricity to its customers. This is also c
onsistent with Section 1221 of the Anah eim City Charter which requires that electric rates be based on the cost-of-service requirements for each customer class.5 The Reliability Portfolio consists of a balanced mix of renewable resources and ensures high reliability, meets statutory compliance requirements, while at the same time maintains affordable rates. APU’s IRP process includes comprehensive production cost modeling to ensure the resource portfolio serving APU’s customer load is met at the lowest possible cost.

The long-term resource planning process introduces many assumptions and each of them may deviate from the original assumptions. A modeling “stress test” is in troduced to ensure the op timal portfolio outperforms the alternatives under all scenarios. In addition, the portfolio financial exposure is calculated to evaluate mitigating factors.

Achieving affordable rates is measured by two quantitative portfolio performance measures: Expected Cost and Market Exposure. Lowest Expected Cost is measured by th e total cost to supply power, while Market Exposure is measured by percentage of energy purchased from the wholesale market, and the portfolio’s ability to withstand market price volatility.

5 Anaheim City Charter, https://codelibrary.amlegal.com/codes/anaheim/latest/anaheim_ca/0-0-0-51756 Affordable Rates
Expected Cost is measured by the total cost to
supply power.

Market Exposure is measured by the percentage
of energy purchased from the wholesale market, and
the portfolio’s ability to withstand market price
volatility.
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IV. KEY POLICY DRIVERS AFFECTING THE UTILITY
California is considered a le ader in its many efforts to combat the ef fects of climate change. The overarching goal of the State’s climate change strategy is to drastically reduce statewide GHG emissions over the next two decades. To reach this goal, the State has put forward several key legislative actions over the past several years that have a direct effect on how APU plans for and manages its resource portfolio now and into the future.

APU is committed to reducing GHG emissions by implementing not only the letter of state laws and regulations, but also their spirit, which supports Anaheim’s goal of a more sustainable environment for future generations. In doing so, APU’s long-term strategies focus on striking a balance amongst numerous legislative and regulatory issues and challenges while maintaining affordable rates and reliable service for its customers.

At the time of the development of the 2023 IRP, several climate-related bills were introduced and successfully passed through the State’s legislative process and were signed by Governor Newsom in September 2022. These newly adopted bills have the potentia l for significant operational and cost implications for APU that depend on how the responsible state agencies implement the re quirements of the legislation. To the extent the requirements of these bills could be assessed and included in the 2023 IRP’s resource modeling and associated analyses, they were included. Two of these key bills , SB 1020 (Laird) and AB 1279 (Muratsuchi) are likely to be most impactful because each call for the acceleration of procurement from carbon-free energy resources and deeper GHG emission reductions.

The following table is a summary of the California la ws passed since 2006 requiring electric utilities to reduce GHG emissions and increase the proportion of renewable energy in their power supply portfolios:

Date Legislation Description
September 16,
2022
Senate Bill 1020 (Laird, Chapter 361,
Statutes of 2022)
Clean Energy, Jobs, and Affordability Act of 2022
Builds upon SB 100 (below) and establishes a state policy goal to achieve net zero carbon emissions as soon as possible, but no later than 2045. Also accelerates the goal of reaching 100% carbon-free energy deliveries to all California retail customers by the year 2045.

Sets interim policy targets for carbon-free energy deliveries of 90% by 2035 and 95% by 2040, respectively.

September 16,
2022
Assembly Bill 1279 (Muratsuchi,
Chapter 337, Statutes of 2022)
The California Climate Crisis Act
Establishes a statewide goal for ac hieving carbon neutrality no later than 2045, and thereafter. Sets statewide policy goal that ensures that GHG emissions are reduced at least 85% below 1990 levels by 2045.

September 10,
2018
Senate Bill 100 (De Leon, Chapter 312,
Statutes of 2018)
The 100 Percent Clean Energy Act of 2018
Accelerates the state’s renewable portfolio standard (RPS) to 60% by 2030 and establishes a state policy to ensure 100% of all electricity delivered to retail customers be derived from zero-carbon sources of electricity by 2045.

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September 10,
2018
State of California. Executive Order B-
55-18
Achieve Carbon Neutrality
An Executive Order signed by Governor Brown in 2018 that directs the California Air Resources Board to work with all relevant state agencies to ensure policies and pr ograms are undertaken to achieve carbon neutrality by the year 2045.

July 25, 2017 Assembly Bill 398 (Garcia, Chapter 135,
Statutes of 2017)
Cap-and-Trade Extension
Extends and improves the Cap-and-Trade Program, which will enable the State to meet its 2030 emission reduction goals in the most cost- effective manner. Furthermore, extending the Cap-and-Trade Program will provide billions of dollars in auction proceeds to invest in communities across California.

September 8, 2016 Assembly Bill 197 (Garcia, Chapter 250, Statutes of 2016)
California Global Warming Solutions Act of 2006 – Direct Emissions
Directs the CARB to prioritize direct emission reductions from larg e stationary sources and mobile sources when adopting rules an d regulations pursuant to the Act.

September 8, 2016 Senate Bill 32 (Pavley, Chapter 249,
Statutes of 2016)
California Global Warming Solutions Act of 2006 – 2030
Emissions Limit
Establishes a statewide greenhouse gas (GHG) emission reduction target of 40 percent below 1990 levels by 2030.

October 7, 2015
Senate Bill 350 (De León, Chapter 547,
Statutes of 2015)
Clean Energy and Pollution Reduction Act of 2015
Establishes targets to increase reta il sales of renewable electricity to 50 percent by 2030 and double the energy efficiency savings in electricity and natural gas end uses by 2030. Amended by SB 100 (2018)
April 12, 2011 Senate Bill X1-2 (Simitian, Chapter 1,
Statutes of 2011)
California Renewable Energy Resources Act
Governor Edmund G. Brown, Jr. signed Senate Bill X1-2 into law to codify the ambitious 33 percent by 2020 goal. SBX1-2 directs California Public Utilities Commission's Renewable Energy Resources Program to increase the amount of electricity generated from eligible renewable energy resources per year to an amount that equals at least 20% of the total electricity sold to retail customers in California per year by December 31, 2013, 25% by December 31, 2016, and 33% by December 31, 2020. The new RPS goals apply to all electricity retailers in the stat e including publicly owned utilities (POUs), investor-owned utilities, electricity service providers, and community choice aggregators. This new RPS preempts the California 2023 Integrated Resource Plan
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Air Resources Board’s 33 percent Renewable Electricity Standard.

Amended by SB 350 (2015).

September 27,
2006
Assembly Bill 32 (Núñez, Chapter 488,
Statutes of 2006)
California Global Warming Solutions Act of 2006
This bill requires Air Resources Board (ARB) to adopt a statewide greenhouse gas emissions limit equivalent to the statewide greenhouse gas emissions levels in 1990 to be achieved by 2020. ARB shall adopt regulations to require the reporting and verification of statewide greenhouse gas emissions and to monitor and enforce compliance with this program. AB 32 directs Climate Action Team established by the Governor to coordinate the efforts set forth under Executive Order S-3-05 to continue its role in coordinating overall climate policy. See more information on AB 32 at ARB.

Source: leginfo.legislature.ca.gov and gov.ca.gov

A. REDUCING GREENHOUSE GAS (GHG) EMISSIONS
To meet the AB 32 and SB 32 goals, APU began reducing its reliance on generation resources that produce GHG emissions by transitioning from fossil fuel-fired generating resources to renewable resources. The most significant contribution that APU can make in reducing GHG is the reduction of energy resources that produce GHG emissions from its power supply. In addition to GHG emission reductions from APU’s power supply, further GHG reductions will come from complementary efforts
including continued energy efficiency measures, local solar, energy storage, electrification of homes from natural gas, and electrification of the transportation sector.

In May 2020, APU published it s follow-up utility-specific Greenhouse Gas Reduction Plan
6 with the purpose of continuing
its commitment to a clear and comprehensive long-term strategic framework to reduce GHG emissions. The Plan reviews how it doubled its 2020 goal to redu ce GHG emissions by 20% below 1990 levels by 2020, as well as identifying goals for a minimum of 40% below 1990 levels by 2030 and zero-carbon by 2045. It is important to note that the 40% reduction below 1990 levels is a statewide goal; however, California utilities will likely be called upon to do more. This includes serving all retail load with zero-carbon resources by 2045 as prescribed in SB 100 passed in 2018.

6 https://www.anaheim.net/5507/Greenhouse-Gas-Reduction

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to the divesture of the San Juan Generating Station in 2017. Upon the conversion of the Intermountain Power Project to natural gas in 2025, APU’s overall GHG emissions from its power supply portfolio are expected to decrease to at least 70% below its 1990 emissions. In or der to continue a downward emissions trajectory to meet increased GHG reduction targets beyond 2025, APU will need to procure additional renewable energy to account for forecasted growth of transportation and building electrification demand. Procurement and/or development of bulk energy storage systems is another method that APU is actively pursuing to shift renewable over-generation from mid-day hours to evening dema nd periods where the CASIO grid managers currently depend on natural gas, and other high emitting resources, to meet peak demand. This has a direct impact on reducing system wide emissions but may not necessarily reduce APU’s natural gas baseload or Canyon Power Plant Project
7 resources. Significant emission reductions are observed in each of the portfolio scenarios analyzed and discussed in Section VII. Resource Portfolio Evaluation.

Graph 1: APU GHG Reduction Targets

B. INCREASING PROCUREMENT FROM RENEWABLE RESOURCES
APU has steadily been increasing th e renewable energy component of it s resource portfolio since 2003. In response to SB 1078, the Anaheim City Council adopted a renewable portfolio objective in July 2003 requiring APU to provide 15% of retail energy requirements with energy from renewable resources by 2017. That objective was revised by Council Resolution No. 2006-187 in August 2006 to achieve a target of 20% by 2015 as a result of Assembly Bill 1362, which accelerated th e statewide target to 20% by 2010. The passage of SB X1-2 in 2011 increased the State’s renewables target to 33% by 2020 and was further expanded to 50% by 2030

7 https://www.anaheim.net/DocumentCenter/View/21469/Canyon-Power-Project Statewide Goal
20% Below 1990
GHG Emission Levels
Statewide Goal
40% Below 1990
GHG Emission Levels
SB 100 Zero‐Carbon
Obligation
APU Achieves
20% Below
1990 GHG Levels
Divestiture of San Juan
Generating Station
IPP Conversion
to Natural Gas
0 250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
MTCO2e (x 1,000)
Resource Portfolio GHG Emission Reductions
(1990 Emission Level ~2.3M MTCO2e)
Statewide GHG Reduction Targets 2022 Scoping Plan Target Share Actual Emissions Forecasted Portfolio GHG Emissions
APU GHG Emission Target Range
386,000 ‐ 305,000 MTCo2e
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in late 2015 through the passage of SB 350. Shortly afterward, the pa ssage of SB 100 in 2018 expanded the RPS target to 60% by 2030 and established a state policy to ensure 100% of retail energy sales to customers are derived from carbon-free energy resources by the year 2045.

In late 2022, two additional legislative bills passed through California’s legislature that intensify and escalate the state’s environmental policy goals. The requirements of these bills will be established by California energy agencies through new regulations, or amendments to existing regulations. SB 1020 builds upon SB 100 and establishes a statewide policy goal to achieve net zero carbon emissions as soon as possible, but no later than 2045. The bill also accelerates the goal of reaching 100% carbon-free energy deliveries to all California retail customers by the year 2045 and sets in terim policy targets for carbon-free re tail energy deliveries of 90% by 2035 and 95% by 2040, respectively. AB 1279 establishes a st atewide goal for achievin g carbon neutrality no later than 2045, and each year thereafter. Additionally, it establishes a statewide policy goal that ensures that GHG emissions are reduced to at least 85% below 1990 levels by 2045.

The Renewable Portfolio Standard (RPS) is a key elem ent of California’s strategy to reduce statewide GHG emissions. By the end of 2023, APU will be delivering nearly 40% of its retail electricity sales to customers from renewable resources. APU is a fully resourced utility , meaning APU’s resource po rtfolio has sufficient generation capacity to serve customer energy demand and meet Resource Adequacy capacity requirements.

The State’s increasing renewable energy procurement requirements and carbon-free energy policies create a challenge in balancing the costs associated with the curre nt resource portfolio with the added costs of further increasing the renewable energy/carbon-free components of the overall resource mix. Section VII further discusses the effect of an accelerated RPS, along with APU’s strategies to minimize costs, risk and maintain affordable rates for the customers.

C. TRANSFORMATION OF THE REGIONAL GRID
APU is a market participant within the CAISO, which manages approximately 80 percent of California’s electric grid and operates a competitive whol esale market. The CAISO is also responsible for Grid reliability and efficiency. While California’s RPS is one of the more effective ways of lowering emissions of GHGs, integrating a significant amount of variable renewable energy resources, such as wind and solar, into the physical electric power grid presents various challenges for Grid reliability and the st ability of energy markets. As the State’s share of variable renewable energy generation increase s, the need for resources to respond to intermittent generation becomes critical for grid operators especially when this is occurring on a minute-by-minute basis, with changes in hourly, daily, and seasonal patterns of variable generation.

As a consequence of the State’s RPS, including solar generation installed by residents and businesses, the CAISO is dealing with an over-supply of daytime electrici ty produced by solar generation. When there is less demand for electricity than there is supply, the result is a drop in wholesale electricity prices, which in turn forces generation to shut down (or curtail) until the demand for electricity increases later in the day. During times of extreme energy oversupply, the CAISO may need to send market signals through negative energy pricing, resulting in generators paying other entities to take the energy. This will le ad to additional costs if market participants own generation that cannot be ra mped down due to technology constraints such as non- dispatchable renewables or a minimum capacity requirement. 2023 Integrated Resource Plan
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V. RENEWABLE ENERGY PROCUREMENT PLAN AND ENFORCEMENT

PROGRAM
A. ELEMENTS OF THE RPS PROGRAM

A.1. PROCUREMENT TARGETS
Public Utilities Code Section 399.30(n) , as amended from time to time, directs the CEC to establish POU enforcement rules and procedures for the RPS. Unless ot herwise provided herein, all section references will refer to the California Code of Regulations, Title 20, Division 2, Chapter 13, Sections 3200-3208 (Regulation).

Section 3204 of the Regulation requires APU to procure specific quantities of electricity products from eligible renewable energy resources for each Compliance Period (CP), including Renewable Energy Credits (RECs).

The CEC, through formal rulemaking processes, ad opted multi-year Compliance Periods and procurement targets for each calendar year (CY) through the year 2030. Compliance Periods beginning on and after January 1, 2031, shall be three years in length starting on Ja nuary 1 and ending on December 31, and must meet an average of 60% over each three-year compliance period. The current Compliance Periods and procurement targets are outlined below:

The passage of SB 350 established a long-term procurement requirement (LTR) beginning January 1, 2021.

This provision requires that at least 65 percent of the procurement APU counts toward the RPS requirement of each Compliance Period must be from its contracts of 10 years or more in duration, or in its ownership or ownership agreements for eligible renewable energy resources.

Compliance Period Procurement Targets

CP 3
(CY 2017-CY 2020)
Total renewable procurement of CP 3 must be equal to or greater than the sum of:
[(27% of 2017 retail sales)+(29% of 2018 retail sales)+(31% of 2019 retail sales)+(33% of 2020 retail sales)].

CP 4
(CY 2021-CY 2024)
Total renewable procurement of CP 4 must be equal to or greater than the sum of:
[(35.75% of 2021 retail sales)+(38.50% of 2022 retail sales)+(41.25% of 2023 retail sales)+(44% of 2024 retail sales)].

CP 5
(CY 2025-CY 2027)
Total renewable procurement of CP 5 must be equal to or greater than the sum of:
[(46.00% of 2025 retail sales)+(50.0% of 2026 retail sales)+(52% of 2027 retail sales)].

CP 6
(CY 2028-CY 2030)
Total renewable procurement of CP 6 must be equal to or greater than the sum of:
[(54.67% of 2028 retail sales)+(57.33% of 2029 retail sales)+(60% of 2030 retail sales)].

Post-2030
Compliance periods beginning on and after January 1, 2031, shall be three (3) years in length. Total renewable procurement in each three-year compliance period must meet an average of 60% over each compliance period.
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A.2. PORTFOLIO CONTENT CATEGORY REQUIREMENTS
Per Section 3203, any renewable contra cts executed after June 1, 2010, will be categorized into one of three Portfolio Content Categories (PCCs). The table below describes the types of resources that are subject to the PCC limitations, and the minimums and maximums a llowed for each Compliance Period. Any renewable contracts executed prior to June 1, 2010, are not subject to the following PCC limitations:

Portfolio Content Categories (PCCs)

Percentage Requirements
(Post-June 1, 2010 Procurement)
PCC 1:

Energy or RECs from eligible resources interconnected to a transmission network within the Western Electricity Coordinating Council (WECC) that:

1. Has its first point of interc onnection within the metered boundaries of a California (CA) balancing authority area; or

2. Has its first point of interconnection to an electricity distribution system used to serve end users within the metered boundaries of a CA balancing authority area; or

3. Is scheduled into a CA balancing authority without substituting electricity from another source. If another source provides real- time ancillary services to maintain an hourly import schedule into CA, only the fraction of the schedule actually generated by the renewable resource will count; or

4. Has an agreement to dynamically transfer electricity to a CA balancing authority area.

Compliance Period 3 (CP 3), and
thereafter: Minimum of 75%
PCC 2:

Energy or RECs from eligible resources interconnected to a transmission network within the WECC that must be matched with incremental energy that is schedu led into a CA balancing authority area.

CP 3, and thereafter: Maximum of
25%
PCC 3:

Energy or RECs from eligible resources that do not meet the requirements of PCC 1 or PCC 2, including unbundled RECs.

CP 3, and thereafter: Maximum of
10%

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B. PLANNING AND PROCUREMENT
B.1. PLANNING ACTIVITIES
APU’s Integrated Resources (IR) division is responsible for managing APU’s energy resource portfolio (both conventional and renewable). To effectively manage the overall resource portfolio, IR develops a Power Supply Forecast on an annual basis. When developing this forecast, IR considers several factors including, but not limited to, an assessment of the resource supply portfolio and a projection of customer energy and peak demand requirements. This annual review results in a twenty (20) year projection that includes all contracted projects, potential projects, and other viable technologies to fill resource needs that are required to meet California Independent System Operator (CAISO) reliability requirements, as well as legislative mandates. IR determines its expected renewable procurement needs by comparing its forecasted RPS procurement quantity targets to its forecasted energy deliveries from its renewable energy resource portfolio, all of which are key components of the Power Supply Forecast.

IR takes the RPS program’s regulatory framework into account when planning for renewable procurement and meets to discuss its RPS requirements and progress on a regular basis. This process includes a thorough analysis of project performance, as well as short-term and long-term RPS needs. Other factors taken into consideration while conducting this analysis include, but are not limited to: renewable integration costs, the risk of delay or failure associated with renewable resources contracted or under consideration, transmission availability, developer experience, financial considerations (includi ng the ability of the develo per to secure funding), technology (i.e., new technology versus proven technology), and any other factors that can potentially delay or indefinitely postpone a project. APU also offers a voluntary Green Power Program (GPP) that allows residents and businesses to support more renewable energy above APU’s state-mandated target to meet clean energy goals. Under this program APU purchases additional clean green power on behalf of GPP customers up to 60% or 100% of electric usage. This program is considered during overall procurement to ensure APU procures enough incremental renewable purchases for a successful program while ensuring APU’s compliance with the RPS Program.

IR’s objective is to competitively procure renewable projects that are viable and cost-effective, enhance APU’s resource portfolio, and opti mize each PCC to minimize overall costs. In doing so, APU determines whether resources are procured jointly, are financed, are owned or purchased, and these determinations are made in the best interests of APU customers. However, long-term investments to manage expenses result in financial obligations that may conflict with aggressive State policies.

State law requires APU to develop an Integrated Resources Plan (IRP) no less than once every five years. This comprehensive plan outlines APU’s activities to meet a 60% RPS by 2030 and greenhouse gas (GHG) emission reduction targets. It also addresses impacts on customer rates, energy efficiency, system reliability and the integration of various distributed energy resources within the APU service area. The IRP describes APU’s strategy for effectively managing its overall energy resource portfolio into the future.

B.2 PROCUREMENT (ORIGINATION)
APU intends to demonstrate its progress in reaching its RPS targets in compliance with the State’s established RPS goals; however, it is important to note that APU is fully resourced and additional resources will exceed the retail sales needs. Per PUC §399.15(a) “… in order to fulfill unmet long-term resource needs, the commission shall establish a renewable portfolio standard…” (emphasis added). APU has sufficient long-term resources to 2023 Integrated Resource Plan
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meet anticipated customer demand. Future resource procurement plans will be based upon load forecasts, any new power supplies required, if any, to cover unmet needs, and divestiture of existing coal resources.

Additionally, as a member of the CAISO, APU is required to procure resources to meet 115 percent (115%) of its forecasted peak demand for each month to ensure that more than sufficient resources are available to meet customer loads per the FERC-approved CAISO tariff.

In the third Compliance Period, IR executed eight (8) renewable energy contracts, which included a long-term contract for 36 MW of solar energy sourced within California and one SB 859 compliant biomass contract. To date, APU has executed four (4) short-term contracts in Compliance Period four (CP 4) and is actively negotiating a term extension to an existing long-term contract. APU’s procurement strategy incorporates both near and long-term renewable power purchase agreements to meet the complex requirements of the RPS Regulation.

APU routinely reviews its procurement strategy each mont h, not only for meeting its RPS goals, but to also ensure the reliability of its distribution system. In a ddition, APU evaluates the vi ability of energy storage, demand response, and distributed generation resources to maintain grid reliability and meet the State’s overall energy policy goals.

C. STATUS OF APU’S RPS PORTFOLIO
C.1. PROGRESS TOWARD MEETING TARGETS
APU has successfully met all the RPS requirements for Compliance Periods 1 and 2. At the time of the writing of the 2023 IRP, APU is awaiting the final verification from the CEC of its Compliance Period 3 compliance filing. Planning activities undertaken in 2021-2022 while developing the IRP incorporated a variety of renewable resources as a way to ensure continued diversification of the portfolio while progressing toward an aggressive goal of 60% renewables by 2030.

C.2. RENEWABLE RESOURCE PROCUREMENT PLAN
Appendix A – Renewable Procurement Plan provides a detailed summary of APU’s Renewable Resource Energy Procurement Plan. The table includes all gran dfathered and contracted resources, as well as any contracts being actively negotiated. This chart also provides expected RPS compliance percentages and expenditures. The data is based on actual data for past years and forecasted data for all future years. Appendix A may be revised, with the approval of the General Manager, without further approval by the Anaheim City Council to reflect updated Renewable Resource Procurement Plan information or data.

C.3. BANKING OF EXCESS PROCUREMENT
Due to the inconsistent nature of renewables develo pment and energy production, there may be years when the APU exceeds its projected RPS targets. To preserve the investment our customers have made, and will continue to make, in the development of these resources, the legislature and State agencies recognized that the ability to use any excess procurement fo r future compliance is essential. Pursuant to Section 3206, the City Council may permit APU to accumulate excess procurement of eligible renewable resources in one Compliance 2023 Integrated Resource Plan
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Period to be applied to any subsequent Compliance Period. APU intends to continue banking any excess procurement, as appropriate, and will use any surplus to help satisfy its future RPS compliance targets in the most cost-effective manner.

C.4. REPORTING REQUIREMENTS
APU is required to provide the CEC with documentation and reports, pursuant to Section 3207. Compliance reports are due by July 1 after every Compliance Period; however, similar reports are required annually for the CEC to track each publicly owned utility’s progress toward meeting RPS targets. APU has demonstrated full compliance for the years 2011-2017 in it s compliance filings to the CEC. Th e third Compliance Period filing covering the years 2017-2020 was filed ahead of the July 1, 2017 deadline, and is awaiting final verification from the CEC.

D. POTENTIAL COMPLIANCE DELAYS
D.1 COMPLIANCE PERIOD EVENTS
As discussed in Section B.1. above, in planning its renewable procurement position and needs, APU accounts for and attempts to anticipate potential issues that could delay RPS compliance in future Compliance Periods.

As global supply chains and economies adjust to post-COVID conditions, circumstances may be encountered that have the potential to encumb er APU’s ability to comply with RPS requirements. Achieving renewable energy goals is dependent on a multitude of factors successfully occurring at relatively the same time. Some of these necessary factors include, but are not limited to, the availability of critical components, dependence on developers to achieve commercial operation, and influences from continually changing regulatory requirements.

For example, it is recognized that worldwide supply ch ain issues have resulted in a significant shortage of microchips, transformers, and other components vital to any electrical system which can result in significant delays to the development and deployment of renewable facilities and the transmission necessary for energy delivery to the bulk electric system. Completing construction milestones, achieving commercial operation, and completing CEC RPS Certification in a timely manner are all contractual re quirements for renewable developers, and the supply chain issues are additional factors affecting the performance of renewable developers in meeting contractual obligations.

APU has experienced delays associated with two renewable resource contracts that were previously mentioned in APU’s 2018 IRP. One contract delay was caused by the developer’s inability to secure contract compliant fuel, which subsequently forced the developer into Ch apter 7 Bankruptcy. The second contract delay was similarly the result of the developer’s inability to secure organic waste feedstock needed to produce RPS eligible renewable biomethane. The continued delay resulted in the failure of this project, but APU considered this potential in its renewable planning processes. These de lays and/or project failure are not expected to affect APU’s compliance moving forward.

Finally, APU actively monitors and participates in potential legislative and regulatory changes that influence renewable procurement. These changes impact APU’s planning process by potentially increasing the quantity of renewables that are required to be procured (i.e., SB 350 and, subsequently, SB 100) and/or result in market changes that make renewable energy supply scarcer and thus procurement incrementally more challenging. 2023 Integrated Resource Plan
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Going forward into the next Compliance Periods, APU will continue to consider all factors in the planning process that may have an effect on its renewables portfolio and potentially delay timely compliance with the RPS.

E. COST LIMITATION
E.1. BACKGROUND
California Energy Commission (CEC) RPS Regulations permits the local governing board of each POU to implement, at its sole discretion, ru les for a cost limitation on the procurement expenditures used to comply with its RPS requirements. Through the approval and adoption of the 2023 IRP, the Anaheim City Council is implementing a cost limitation. Pursuant to Section 3206(a)(3) of the Re gulation, the City Council, in the manner set forth in this and previous versions of the IRP, has adopted rules for a cost limitation for the protection of its customers and continues to review its methodology in coordination with updates to the IRP.

The 2018 IRP included rules for a cost limitation based on a goal of 50% renewables by 2030. APU is revising the cost limitation methodology to account for costs rel ated to the increased State goal of a 60% RPS by the year 2030.

E.2. RULES ON COST LIMITATIONS
The following cost limitation rules are intended to pr otect APU customers from experiencing significant and disproportionate rate impacts resulting from procurement expenditures used to comply with RPS procurement requirements.

1. APU may not make any major financial commitment to procure eligible renewable energy resources prior to evaluating any potential rate impact it ma y have on customers. Such an evaluation should account for local and regional economic conditions indicative of an average residential customer’s ability to afford produced or procured energy products. The ev aluation should also account for any resulting rate disparities where comparable, neighboring utilities gain a rate advantage (lower average system rate) over APU.

2. The costs of all procurement cred ited toward achieving the state mandated RPS requirement shall be considered as part of the rate impact on customers.

3. Procurement expenditures will not include any indirect expenses such as, but not limited to, imbalance energy charges, sale of excess energy, decreased generation from existing resources and costs to upgrade transmission facilities.

E.3. IMPLEMENTATION OF RULES
The Anaheim City Council has the authority to implement a cost limitation which may result in the temporary suspension of RPS compliance activi ties. Through the approval and adop tion of the 2023 IRP, the Anaheim City Council is implementing rules for cost limitation that relies on the following:
 The most recent RPS Procurement Plan (which is contained herein); and 2023 Integrated Resource Plan
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 Procurement expenditures that approximate the expe cted cost of building, owning or operating eligible renewable resources, which does not incl ude indirect expenses as described in Section 3206(a)(3)(A-D); and
 The potential that some planned resource additions may be delayed or cancelled.

APU continuously monitors its expenditure levels and will advise the Public Utilities Board and City Council of its RPS activities, including its procurement expenditur es. If the cost limitation, as determined by City Council, is insufficient to support the projected costs of meeting the renewables portfolio standard procurement requirements, APU may refrain from entering into new contracts or constructing facilities beyond the quantity that can be procured within the limitation, unless eligible renewable energy resources can be procured in a manner consistent with the 2023 IRP.

F. ENFORCEMENT PROGRAM

WAIVER FOR NONCOMPLIANCE
APU monitors its progress in reaching its RPS targets on a monthly basis, as well as through the APU’s annual budgeting process, subject to the approval of budgeted expenditures by the City Council as recommended by the Public Utilities Board. The Ci ty Council is responsible for enforcing the RPS Policy through the Enforcement Program and will consider any recommendation by the Public Utilities Board.

Current law authorizes the City Council to waive APU’s compliance requirements, consistent with PUC §399.15(b)(5) and Section 3206(a)(2) of the Regulation, if APU can demonstrate any of the following conditions are beyond the control of the utility and will prevent timely compliance. The conditions for waiver or delaying compliance include, but are not limited to the following (which may delay or indefinitely postpone a project):

1. Inadequate transmission capacity: [Section 3206(a)(2)(A)(1)]. There is inadequate transmission capacity to allow for sufficient electricity to be delivered from proposed eligible renewable energy resource projects using the current operational protocols of the California Independent System Operator (CAISO). City Council interprets this to mean the inability to bring eligible renewable resources into the CAISO due to transmission limitations. This includes instances where transmission outages may prevent renewable energy from entering the CA ISO market. This may cause APU to be out of compliance for a Compliance Period. The City Counc il has the authority to waive APU’s compliance for this instance.

2. Permitting, interconnection, or other circumstances that delay procured renewable energy resource projects or insufficient supply of eligible renewable energy reso urces: [Section 3206(a)(2)(A)(2)].

Examples include, but are not limited to, the following:
 Development (i.e., permitting, financing, etc.): City Council interprets this to include a renewable resource developer's inability to obtain financing, permits, interconnection, or the rights to build the project. This may cause APU to be short of compliance for a Compliance Period. The City Council has th e authority to waive APU’s compliance for this instance.

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 Operation (i.e., fires, accidents, outages, etc.): City Council interprets this to include any unforeseen circumstances preventing the renewable resource from being developed or delaying its output. This includes outages at the renewable energy facility. For example, if there is a wildfire, transmission outage, or fa cility outage that prev ents resources from delivering energy into the CAISO may cause APU to be short of compliance for a Compliance Period. The City Council has th e authority to waive APU’s compliance for this instance.

 Regulatory Delays: City Council interprets th is to include instances where State agencies delay timely requests by APU for registerin g renewable resources, certifying renewable resources, and accepting renewable resources into its renewable portfolio. In addition, these also include changes to State mandates, which may lead to a delay in compliance.

The City Council has the authority to waive APU’s compliance for this instance.

3. Unanticipated curtailment to address needs of a balancing authority: [Sectio n 3206(a)(2)(A)(3)]. City Council interprets this section to include the CAISO directing a renewable resource to modify their energy obligations, due to the needs of the balancin g authority. This may cause APU to be short of compliance for a Compliance Period. The City Council has the authority to waive APU’s compliance for this instance.

To date, APU has not sought a waiver of compliance. APU will monitor its progress in reaching its RPS targets; however, as listed above, there may be circumstances that prevent APU from procuring renewable resources to meet its RPS targets. In such an instance, APU will request City Council authority to approve a waiver of compliance, consistent with Section 3206(a)(2).

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VI. ENERGY DEMAND AND PEAK FORECASTS
Integrated resource planning is the process in whic h APU evaluates a multitude of supply-side and demand- side resources to meet customer energy needs in an effi cient, cost effective, and reliable manner. Traditionally this integrated resource planning activity was primarily to ensure that all cost-effective demand side resources were deployed prior to commitment to new supply-side resources such as power plants. Supply-side resources usually involved long lead times to develop, and increased the use of fossil fuel causing the depletion of a limited resource and adverse effects on the environment. The passage of SB 350 requires integrated resource planning to consider and address the following elements in addition to traditional demand-side and supply-side resources:
 Actively involve stakeholders. APU proactively solicited additional feedback from residential customers to build upon information obtained through the 2018 IRP Customer Survey process.  Include energy efficiency and demand side management activities.  Incorporate more robust analysis of more aspects of utility activities.  Explicitly account for commodity price volatility and other risks to quantify the risk/reward tradeoff.  Reflect a set of goals that are broader than just meeting energy demand, such as meeting RPS goals and GHG goals.
 Accommodate the load increases and decreases caused by transportation electrification and distributed energy resources such as rooftop solar.

The energy demand forecast, and peak forecast are both developed as a first step to evaluate APU’s future energy needs. APU’s forecasting methodology and different components of the forecasts are detailed below.

Pursuant to the 2023 IRP, APU performed a long‐term statistical forecast of its expected load growth and then adjusted this base load forecast for the factors described above. This adjusted load forecast projects a total load growth of 1.41% between 2024 and 2035, effectively a low growth energy demand forecast, which indicates

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that the expected customer expansion and EV growth is being offset by customer solar installation and energy efficiency reductions. Load forecast beyond 2036 assumes a 0.25% annual l oad increase. The growth factor is consistent with average load growth between 2027 and 2036 and is applied due to th e lack of information on all demand variables.

Graph 2: Cumulative Adjustments to Base Energy Demand Forecast

In determining APU’s energy demand forecast, staff considered historical energy demand and customer growth trends as the basis for statistical modeling and econometric forecasting techniques to develop a “base energy demand forecast.” Once developed, the base forecast wa s further adjusted (referred to as the adjusted energy demand forecast) by planned system expansion, expected EV energy demand, estimated customer ‐side solar installations, and the effect of demand side management and energy efficiency. While system expansion and EV growth in crease the energy demand, solar installation and energy efficiency programs reduce the energy demand.

The adjusted energy demand forecast was then used as the basis for the development of power supply expansion portfolio scenarios, which were analyzed to determine the recommended supply (resource) portfolio.

A. ENERGY DEMAND FORECAST - METHODOLOGY & ASSUMPTIONS

The energy demand forecast is determined in two steps:

The first step establishes the base energy demand forecast. It relies on traditional econometric forecasting techniques to develop relational equations that reflect historic consumption trends. The base forecast for energy demand is developed using a 5‐year running average of historical temperature.

The second step adjusts the base energy demand forecast by taking into consideration residential and commercial projects within the City of Anaheim (City) that may affect energy demand. Information related to these projects is collected through collaboration with the City’s Planning Department, APU Electric System Planning, and Community & Sustainability Progra ms. Examples of such projects include City ‐wide development and expansion plans, customer‐specific capacity additions and/or energy reduction plans, and the Base Energy Demand
Forecast
+ Energy Demand Addition
• System Expansion
• Electrification
- Energy Demand Reduction
• Solar Installation
• Energy Efficiency
= Adjusted Energy Demand
Forecast
(300)
(100)
100
300GWh
2023 - 2035
Energy Efficiency
Solar PV
Electrification
Planned Expansion
Cumulative Impact on Energy Demand
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installation of commercial‐scale solar installations and other behind‐the‐meter distributed generation resources.

Project timelines are evaluated and incorporated into adjustments that either increase or decrease the “base” forecast.

A.1. BASE ENERGY DEMAND FORECAST

HISTORICAL ENERGY DEMAND
Prior to the economic recession in 2008, APU’s average energy demand was between 2,500 and 2,700 GWh.

From 2008 to 2011, a decline in energy demand growth was observed due to economic conditions impacting demand. The economy began to stab ilize in 2011 and continued to im prove through 2015. However, the corresponding demand growth was offset by behind ‐the‐meter distributed generation, such as fuel cell and solar installations, as well as by energy efficiency in both the commercial and residential sectors. From 2017 to 2019, energy efficiency and solar penetration continued to reduce sy stem demand. The COVID pandemic lowered system demand in 2020 through 2021. By 2022, a slight bounce back in energy demand occurred after statewide reopening.

Graph 3: Anaheim Actual Energy Demand 2007 - 2022

ECONOMETRIC MODELING
Econometric modeling is the application of mathematical and statistical methods to forecast future values and understand the relationship between variables. APU develops its forecast of total system energy consumption using econometric modeling. Hourly energy demand is estimated using least squares estimation and variables for expected temperature, calendar (weekday versus holiday), season and time effects (which capture specific hours as well as the cumulative impact of prolonged heat waves). Five years of historical hourly data are used to estimate the following econometric equation:

Total Energyt = α + 1 Temperaturet + D1 Holidayt + Vt + Mt + εt Where:
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Temperaturet = Temperature at hour t
Holidayt = Dummy variable to identify weekend and NERC holidays Vt = Vector of dummy variables for the hours
Mt = Vector of dummy variables for the months
εt = Error term

VARIABLES INCLUDED: TE MPERATURE FORECAST
APU owns calibrated equipment at the Linda ‐Vista Reservoir that records hourly temperature in the Supervisory Control and Data Acquisition (SCADA) system. The IRP energy demand forecast assumes normal weather conditions and uses average hourly temperatures from the past five years (summer 2017 – summer 2022). The forecasted monthly temperatures in degrees Fahrenheit are summarized below in Table 1. Compared to data from the 2018 IRP, the total average and maximum temperature did not change; however, the minimum temperature increased by 13%. The monthly average temperature was higher in June – August and October – December, and lower in February, March, and September. The monthly minimum was higher in 10 out of 12 months of the year.

Table 1: Temperature Summary
Month Average Minimum Maximum
January 60 38 92
February 59 36 93
March 61 42 94
April 65 48 104
May 67 51 96
June 72 56 100
July 76 61 105
August 77 60 105
September 75 55 105
October 71 52 105
November 65 41 99
December 59 40 86

VARIABLES EXCLUDED: ECONOMIC AND DEMOGRAPHIC FORECAST
Anaheim is a fully developed Orange County city with historically cons istent growth and median income level and employment rate. A series of modeling tests determined that the inclusion of economic and demographic variables leads to increased variability, an d results in overly optimi stic demand growth. The hourly demand estimation excluding these variables proved to be more accurate.

Although economic and demographic variables are excluded from the base model, planned expansions and energy reductions are included as adjustments after the econometric regression modeling is complete.

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MODEL VALIDATION
The base econometric model is validated by comparing modeling results to historical energy demand data.

Essentially, the model is used to develop energy demand forecasts for 5 historical years (summer 2017 through summer 2022). The forecast results are compared to historical actual values and analyzed for reasonableness.

The base model was proven to produce efficient estimation results averaging 0.28% variance from the testing period. Had the model been proven inefficient, alternative variables would have been introduced and a new model established to go through the validation process again.

Note that backcasts for selected historical months showed greater variance due to the pandemic impact.

Therefore, two other models were introduced to remove the pandemic impact. However, upon review and comparison, the 5-year historical data regression model still yielded the most reasonable overall forecast. The regression model is accepted as the base forecast model. In addition, the energy demand forecast is subject to stress testing of a wide range of high and low demand forecasts to capture any deviations from the base forecast.

FORECAST RESULTS
After validating the model, the base forecast for future years is generated and compared to historical energy demand. As seen in Graph 4, the energy demand forecast profile is comparable to historical energy demand.

Overall, annual energy demand shape remains fairly constant, while peak demand appears to be lower than that of recent years. This is mostly due to the assumption of normal weather conditions rather than the incorporation of heat shocks in the base model.

Graph 4: Historical and Base Energy Demand Forecast by Month

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A.2. ADJUSTMENTS
Planned energy growth and reductions are included as adjustments to the base economic model. Adjustments include planned new development, electric vehicle growth, behind-the-meter distributed generation, and energy efficiency targets.

This section focuses on the energy demand impact. The
design, funding and details of these programs can be found in the following sections:

X. Transportation Electrification
XI. Solar and Other Distributed Generation
XII. Energy Efficiency and Demand Response Programs
XIII. Programs for the Low Income and Disadvantaged Communities

SYSTEM EXPANSION
Most of the buildable open land in Anaheim is fu lly developed. While new building developments may contribute to energy demand increase, a corresponding decrease also incurs from the demolition of existing buildings and infrastructure. As such, it is not appropriate to apply a growth rate based on historical trends.

Rather, new development data is gathered from City permits and from APU’s Electric System Planning, and these net impacts to energy demand are applied to the base model.

Anaheim’s most recent development projects are expected to cumulatively contribute an additional 34 MW capacity to Anaheim’s distribution infrastructure through 2035. When estimating the impact to load, staff took into consideration both the distribution system expansio n and the varying levels of capacity factors for each customer sector.

System expansions related to transportation electrification is accounted for separately under the section below.

EV PENETRATION & TRANSPORTATION ELECTRIFICATION
APU’s incremental EV load is exp ected to average 17 GWh annually, fr om 2023 to 2035. This results in a cumulative EV load of 134 GWh in 2030, which is more than double the 2018 IRP forecast of 63 GWh in 2030. By 2035, the estimated cumulative EV load reaches 217 GWh, or 9.7% of the total system load. The CEC no longer provides the “Transportation Electrification Common Assumptions” workbook 8 made available during the 2018 IRP process. The forecast is deri ved from the CPUC 2022 Unified RA and IRP Modeling

8 APU relied on the “Transportation Electrification Common Assumptions 3.0” workbook for the 2018 IRP EV Energy Demand forecast. It included utility-specific forecast on EV growth, energy demand increase per EV, and GHG emission savings per EV. + Energy Demand Additions
• System Expansion
• Electrification
- Energy Demand Reductions
• Solar Installation
• Energy Efficiency & Demand Response

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Datasets9 with data comparison again the CEC IEPR Demand Forecast10. Note that the statewide CPUC’s 38 MMT Portfolio is used to approximate EV energy dema nd in APU territory. This is consistent with the California Air Resources Board (CARB) 2022 Scoping Plan11 approach for the electricity sector.

Graph 5: Estimated Electric Vehicle Energy Demand Growth -
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FUEL SUBSTITUTION (BUILDING ELECTRIFICATION)
Additional achievable fuel substitution (AAFS) was introduced as a new load modifier in the CEC’s 2021 IEPR.

As explained in the 2021 IEPR, “Fuel substitution refers to substitution of one end use fuel type for another, such as changing out gas appliances in buildings for cleaner more efficient electric end uses.”12 AAFS is also a component of the CPUC’s IRP demand forecast. APU’s AAFS may be derived from the CPUC’s IRP demand forecast, as a percentage of the Southern California Edison region’s overall AAFS energy demand.

This method captured a minimal cumu lative energy demand increase of 2% by 2035. However, Anaheim is a

9 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 “study_10_2023_Renewables_Output_Profiles”, “study_10_2024_Renewables_Output_Profiles”, “study_10_2026_Renewables_Output_Profiles”, “study_10_2030_Renewables_Output_Profiles” and “study_10_2035_Renewables_Output_Profiles” 10 https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report/2021-integrated-energy-policy-report/2021-1 “TN241221_20220119T103905_CED 2021 Baseline Forecast - SCE Mid Demand Case”

11 Pg. 201 of the 2022 Scoping Plan Update: https://ww2.arb.ca.gov/sites/default/files/2022-12/2022-sp.pdf 12 Page 3, https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report/2021-integrated-energy-policy-report and https://efiling.energy.ca.gov/GetDocument.aspx?tn=241581 2023 Integrated Resource Plan
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fully developed Orange County city, with half of the utilities service area within low income and disadvantaged communities. APU’s AAFS impact may be at a rate that is different from the overall SCE region.

Due to the lack of internal data for AAFS analysis and the minimal impact derived from the CPUC dataset, AAFS is not introduced as a separa te demand adjustor into the 2023 IRP demand forecast. However, APU’s adjusted base energy demand forecast is compared wi th the CEC’s demand forecast inclusive of the AAFS considerations, to ensure APU’s forecast is comparable to the CEC’s forecast.

As more information becomes available, APU may include AAFS as a separate demand adjustor.

SOLAR INSTALLATION & OTHER DISTRIBUTED GENERATION
Behind‐the‐meter distributed generation information is obtained from SB 1 and City permit applications. This includes micro turbine, fuel cell, solar and battery storage installations.

The Inflation Reduction Act of 2022 extended the 30% tax credit for solar installations through 2032. Behind- the-meter solar installation is estimated with recent year annual installation totals, and with specific project plans from commercial customers. APU estimates to have 51.5 MW of new solar installations within the next decade, including solar plus battery storage projects. To estimate solar generation, a proxy capacity factor of 18% is applied to the solar capacity forecast. Detailed solar capacity calculation and peak impact analysis may be found in the “Peak Shift Analysis” section.

In 2022, behind‐the‐meter solar distributed generation is estimated to account for 3.4% of APU’s total energy demand and is expected to grow by 0.25% or greater annually, depending on when larger planned commercial installations take place. Graph 6 shows the estimated annual impact of behind ‐the‐meter solar installation growth.

Graph 6: Estimated Behind-the-Meter Solar Impact to Energy Demand -
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Planned distributed generation projects other than solar are forecasted only in the short term, with system size estimates obtained from Electric System Planning.

ENERGY EFFICIENCY
In accordance with AB 2021, APU is required to establ ish specific annual energy saving goals as a percentage of total annual retail electric consumption. SB 350 also mandated that the CEC develop utility-specific energy efficiency saving targets to help achieve doubling statew ide energy efficiency savings in electricity and natural gas end uses by 2030.

APU, in conjunction with other members within CMUA, co ntracted with GDS Associates, Inc. to identify all potentially achievable cost ‐effective electricity efficiency savings and establish annual targets for energy efficiency savings for 2022‐2031. The final report “Energy Efficiency in California’s Public Power Sector”13 was published and submitted to the CEC in 2021.

APU’s energy saving goal, along with its impact to Energy Demand, are summarized in Table 2.

Table 2: APU Energy Efficiency Targets including Codes & Standards (GDS Associates, Inc.) 10 Year Energy Goals (Incremental Gross MWh)

ALL Sectors (MWh) 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Total Market
Potential 17,825 17,277 15,621 11,732 7,636 7,346 7,363 7,435 7,222 7,264 Res Market Potential 3,710 3,340 2,603 2,506 2,582 2,721 2,792 2,991 3,226 3,411 Non‐Res Market
Potential 14,115 13,936 13,018 9,226 5,054 4,624 4,571 4,445 3,996 3,853

Total Potential as a
% of Total Sales 0.82% 0.79% 0.72% 0.54% 0.36% 0.34% 0.34% 0.35% 0.33% 0.34% Res Potential as a %
of Res Sales 0.62% 0.56% 0.44% 0.43% 0.44% 0.47% 0.48% 0.51% 0.55% 0.58% Non‐Res Potential as
a % of Non‐Res Sales 0.90% 0.87% 0.82% 0.59% 0.32% 0.30% 0.29% 0.28% 0.25% 0.24%

13 https://www.anaheim.net/DocumentCenter/View/11240
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10 Year Energy Goals (Incremental Gross MWh)

ALL Sectors (MWh) 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Base Market
Potential 17,825 17,277 15,621 11,732 7,636 7,346 7,363 7,435 7,222 7,264 Codes & Standards
Advocacy 18,026 18,589 17,879 17,374 16,350 15,347 13,929 12,092 10,349 8,901

APU’s voluntary demand response programs are only called upon under extreme conditions, and therefore is not included in the energy demand adjustments under normal weather conditions. In summer 2022, the residential demand response program generated 6 MWh savings, while the commercial voluntary load reduction program reduced 120 MWh. Currently, only voluntary demand response pr ograms are in place. Estimated adjustments for demand response reductions will be considered for extreme weather conditions when dispatchable demand response programs are in place.

APU is planning to launch several dispatchable demand response programs in the upcoming years. By summer 2023, APU will implement an electric vehicle charging s tation and demand response program, titled “Drive Green Anaheim”. The program aims to increase the proliferation of EVs in underserved locations by installing, operating, and maintaining charging stations and providing no-cost charging to local users. Through the program, commercial properties and multifamily dwellings in low income and disadvantaged communities will have the opportunity to become a publ ic EV charger station host site and receive a turn-key EV charger program inclusive of design, procurement, installation, operation and maintenance. With growing EV demands on the local grid, EV charging stations will be equipped with demand response capabilities to be able to curtail EV charging during peak hours (between 4-9 PM) or during grid emergencies.

In 2024, APU will launch an expanded demand response program that provides customers with energy saving tools, incentives, and a user-friendly notification system that prompts participating customers to curtail usage during times of high demand, or when APU calls for a load curtailment event. As part of the expanded demand response program, new software management technology will be implemented that provides a one-stop-shop of services including customer enrollment tracking , customer participation in curtailing load, device registration, load impact, dispatch notifications, optimization with CAISO alerts, incentive processing, and behavioral analysis. A variety of energy saving tools and incentives will be available to customers, including smart thermostats, heat pumps, HVAC, pool pumps, small business equipment, commercial equipment, industrial equipment, energy management systems, electric vehicle supply equipment, electric school buses, and batteries for storing energy.

A.3. ADJUSTED BASE ENERGY DEMAND FORECAST
In total, APU expects a 1.41% net energy demand gr owth between 2023 and 2035, wh ich is essentially a low growth forecast. Load forecast be yond 2036 assumes a 0.25% annual load increase. The gr owth factor is consistent with average load grow th between 2026 and 2035 and is applied due to the lack of information on 2023 Integrated Resource Plan
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all demand variables. The net energy demand forecast is used in Section VII. Resource Portfolio Evaluation to determine the recommended resource portfolio to meet APU’s future energy needs.

Graph 2 displays the estimated cumulative impacts to the Base Energy Demand Forecast. The energy demand additions are estimated to increase by 234 GWh cumulatively due to planned expansion projects and electric vehicle growth. During the same period, solar PV and energy efficiency are estimated to reduce the energy demand by approximat ely 208 GWh cumulatively. The overall cumu lative net energy demand growth is estimated to be approximately 26 GWh as indicated by the blue line in the graph below.

Cumulative Adjustments to Base Energy Demand Forecast

Graph 7 below depicts the Adjusted Energy Demand Forecast. The sum of all three bars is the anticipated Base Energy Demand Forecast, assuming no growth or reduction. Additions such as planned expansion projects and electric vehicles are displayed by the light green ba r. The total reductions are displayed by the white bars.

The Adjusted Energy Demand is the sum of the dark green and light green bars. The remaining white bar is the estimated net energy demand reduction per year. Load reduction in earlier years is mainly due to planned solar plus storage projects by commercial customers. Load increases in the later years are mainly due to EV penetration.

Base Energy Demand
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= Adjusted Energy Demand
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Graph 7: Adjusted Base Energy Demand Forecast

APU’s energy demand forecast was completed in 2022. The CEC released its energy demand forecast for the 2021 Integrated Energy Policy Report (IEPR) in February 202214. Staff compared APU’s adjusted (or expected) energy demand against the IEPR 2021-2035 demand fo recast: Medium Baseline Demand with Medium Additional Achievable Energy Efficiency (AAEE) Scenario 3 and Additional Achievable Fuel Substitution (AAFS) Scenario 3

15. Scenario 3 represents full compliance with all regulations, including CARB’s Advanced Clean Fleets Regulation. APU’s forecast is very close to the CEC’s forecast in the beginning years, with a 4% variance observed in 2035.

It is noted that the CEC assumes a distribution loss factor of 6.37%. Or, it requires 106.37 MWh of total system energy in order to serve the retail customer consumption of 100 MWh. APU’s historical distribution loss factor is typically around 3.5%. When the CE C’s forecast is adjusted down with the lower distribution loss factor, it becomes lower than the APU forecast by roughly 6% in 2035. The difference is considered acceptable for long- term planning purposes. In addition, a range of high and low energy demand will be tested under Resource Portfolio Evaluation – Stress Testing.

14 https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report/2021-integrated-energy-policy-report and https://efiling.energy.ca.gov/GetDocument.aspx?tn=241581

15 https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report/2021-integrated-energy-policy-report/2021-1 and https://efiling.energy.ca.gov/GetDocument.aspx?tn=241382 2,000
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Graph 8: APU vs. IEPR Energy Demand Forecast

A.4. OTHER CONSIDERATIO NS - EXTREME WEATHER
It is important to analyze the impact of weather extremes on energy demand due to its sensitivity related to temperature changes. Extreme temperature forecasts under high and low emission scenarios are available through Cal‐Adapt, a climate change resource database developed by the Geospatial Innovation Facility at the University of California, Berkeley with funding and advisory oversight by the California Energy Commission.

The daily extreme temperature forecast data for the Anaheim area was obtained through Cal‐Adapt16 and then compared to APU’s internal temperature forecast, which was developed using five ‐year minimum and maximum temperatures. APU’s forecast consistently produces higher extremes compared to the Cal ‐Adapt forecast. The deviations between the forecasts are shown in Graph 9, which displays the high and low emissions Cal‐Adapt high temperature forecast compared to APU high temperature forecast from July 2023 to June 2024.

As the APU forecast produces higher extremes, it was selected to be the preferred temperature forecast to conduct the extreme weather analysis on energy demand.

16 https://cal-adapt.org/
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Graph 9: Cal-Adapt vs APU Maximum Temperature Forecast

The econometric model described in VI.A.1. estimates a coefficient of 2.19 MWh for the temperature variable.

This is interpreted as an increase in energy demand of 2.19 MWh for every degree Fahrenheit increase. For example, an increase in temperature of 20 degrees Fahrenheit results in a corresponding increase in demand for that hour of 43.8 MWh. Applying the extreme temperature forecast to the economic model produces a bandwidth of expected energy demand under high and low temperature extremes.

Graph 10 below displays the estimated deviations from expected energy demand due to extreme weather impacts. The high weather extreme results in an increase from expected energy demand of 180 GWh annually, with the highest monthly impact in the month of January of 18 GWh. The low weather extreme results in a decrease from expected energy demand of 75 GWh annua lly, with the largest decrease being in the month of February of 9 GWh.

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Graph 10: Forecasted Energy Demand with Extreme Temperatures

The energy demand variation due to extreme weather impacts will be used to stress test the resource portfolio in VII. F. Stress Testing.

B. PEAK FORECAST - METHODOLOGY & ASSUMPTIONS
The peak forecast is also developed along with the energy demand forecast for use in consideration of the reliability aspects of power supply Resource Adequacy and electric distribution system planning:
 Peak forecast is used to determine the Reso urce Adequacy capacity need ed to meet reliability requirements.
 Hour-by-hour peak and energy profile analysis is used to determine which resource’s generation portfolio provides the best match. It also assists APU’s effort to explore possibilities in using clean energy to meet the peak demand.
 APU’s Electric System Planning relies on the long-term peak forecast to plan for necessary distribution system expansion.

B.1. CONSIDERATION OF THE HISTORICAL SYSTEM PEAK
Although APU’s total energy demand declined from 2017 to 2022, the total system peak has fluctuated over the past several years between 487 and 566 MW. Anaheim sa w the lowest peak in 2021 as a result of lower- than-average temperatures of 96 degrees. In 2022, the peak increased sharply compared to 2021, which was 150
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due to temperatures increasing back to the normal average. APU’s annual system peak is typically observed in the months of August or September when temperatures average 76 degrees and reach up to 105 degrees.

Graph 11 illustrates the temperature impact on the peak energy demand. Temperature data since 2017 are used for the 2023 IRP forecast and represented in solid red. Peak hour te mperature data from earlier years are not used for this forecast and represented in shaded red. The peak energy demand patterns were different in the earlier years due to the differences in the avai lability of rooftop solar, energy efficiency programs, demand response tools and time-of-use rates.

Graph 11: APU Historical Peak Demand

B.2. DEVELOPING THE PEAK FORECAST
When developing the peak demand forecast, APU considers historical load factors.

APU’s load factor is calculated by taking the total energy demand for each month and dividing it by the peak demand for the same month. Historical average load factors are calculated for each month for the most recent five years. The load factors are applied to the adjusted monthly energy demand forecast to develop the peak demand forecast.

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Table 3: Historical Load Factors

Month 2017 2018 2019 2020 2021 2022 AVERAGE January 73% 79% 81% 75% 79% 77%
February 74% 81% 79% 79% 69% 76%
March 79% 80% 73% 75% 71% 76%
April 66% 70% 57% 64% 53% 62%
May 71% 78% 60% 67% 66% 68%
June 67% 59% 58% 61% 60% 61%
July 68% 62% 60% 60% 66% 64%
August 60% 66% 68% 55% 65% 63%
September 54% 66% 59% 55% 59% 59%
October 53% 61% 60% 53% 66% 59%
November 67% 68% 68% 70% 60% 67%
December 76% 76% 80% 78% 78% 78%

The peak demand forecast is validated by comparing the model’s “backcast” output to the previous five year’s actual data. The average peak forecast’s accuracy to predict monthly peak is between -2.4% and 1.1%. The average annual peak forecast accuracy was in the range of ‐3.3% to 5.5% and within the acceptable confidence level.

B.3. OTHER CONSIDERATIONS
Peak Shift
APU estimates to have 51.5 MW of new solar within the next decade. Graph 12 details the estimated cumulative installed solar capacity for APU’s service territory. The initial increase in 2024 and in 2025 is due to planned large commercial solar projects. Solar installation is estimated to remain stable through 2035. Under stress testing, a high demand scenario and a low demand scenario assumes extra low solar installation and extra high solar installation, respectively. More information can be found under Chapter VII. Resource Portfolio Evaluation, TEST 2: EXTREME HIGH DEMAND VS. EXTREME LOW DEMAND.

Graph 12: Estimated Cumulative Distributed (Behind‐the‐Meter) Solar PV Capacity

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To develop an estimation methodology for customer‐owned, behind‐the‐meter solar generation, APU studied the solar generation from the city ‐owned Anaheim Convention Center so lar system. The system generates approximately 3,400 MWh of solar energy per year (as recorded in 2022) and has a capacity factor of 18%.

In 2022, April produced the highest generation, with 12.5 MWh per day. The mont h of December produces the least amount of generation per year, on average with 4.7 MWh per day. Graph 13 details each month’s average hourly solar profile, as derived from the generation of the Anaheim Convention Center solar system.

Peak solar generation is at noon October through February and at Hour 13 (1 PM) for the remainder of the year.

Graph 13: Average Hourly Solar Profile by Month: Anaheim Convention Center

Although production varies from system to system, the calculated capacity factor from the Anaheim Convention Center serves as a strong proxy to estimate production from installed private solar capacity within the City. This is especially true because the Convention Center is located in the center of Anaheim and is capable of capturing City specific weather effects.

To calculate total distributed solar generation, the 18% capacity factor is applied to solar capacity data collected from SB 1 applications and City permits. Graph 14 details the estimated monthly distributed solar generation in 2022, and its effect on APU energy demand. The total estimated effect on energy demand using the proposed methodology for 2022 was 76,849 MWh, or a 3% reduction of Anaheim’s total energy demand.

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Graph 14: Estimated Distributed (Behind‐the‐Meter) Solar PV Impact to Energy Demand

While the Anaheim Convention Center’s solar production meter data is still an effective tool for estimating the total behind-the-meter solar generation, there is not a direct relationship between solar production and peak shift or peak reduction. Although distributed solar has grown as expected from 2015-2022; the peak has not shifted from HE16 to later in the day, as previously expected in the 2018 IRP. Some of the reasons for the unchanged peak hour may include the introduction of time-of-use (TOU) rate s, successful voluntary demand response programs, and the proliferation of EVs and battery storage.

Graph 15: Peak Day Demand Profile

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Clean Peak Analysis
Aligning renewable generation with peak demand is a current industry challenge.

In an effort to meet peak demand with renewable or other clean energy resources, APU takes into consideration its existing renewable generation portfolio, efficiency of Grid operations, energy storage options and forecasts, distributed energy resources, and ener gy reduction measures such as energy efficiency and demand response programs. This comprehensive consideration ensures APU meets energy and reliability needs during its peak, while reducing the need for new/additional electric generation, distribution, and transmission resources.

During certain times of the year, system peak can be served with a higher percentage of renewable energy. As an example, in April 2022, the Intermountain Power Plant (IPP) 17 underwent a scheduled maintenance outage
for most of the month, which caused a significant reduction in generation capacity. On April 17, 2022, APU’s 232 MW peak was served by 36% or 84 MW of large hydro and renewables.

Graph 16: Renewables Serving Peak Demand – Day with High Renewables & Low Energy Demand

During other times of the year, serving the peak with renewable energy faces its challenges. This is generally due to a higher peak demand, renewable resource availability, and CAISO dispatch signals. APU deployed eight voluntary residential demand respon se events in summer 2022 to reduce energy demand; however, additional energy was still needed during the hot and humid summer days.

On September 8, 2022, APU reached a system peak of 566 MW; more than double the system peak in the previous example. During the peak hour, only 17% or 96 MW of large hydro and renewable energy was available

17 Details of the power plant may be found in Section VIII.B. Generation and Transmission Resources -
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to meet the demand, even though APU has greater renewable contract capacity. This is due to various reasons, which include:
 De‐rated landfill and geothermal generating units due to extreme heat,  Minimal small hydro energy output due to drought conditions; and  Wind energy output at 60% of April level.

Also, during the peak day, the CAISO dispatched APU’s fossil fuel units to meet not only the APU peak, but also the system demand of other California load serving entities. The light blue bars in Graph 17 indicate the thermal (non‐renewable) energy APU sold into CAISO market, per market dispatch signals.

Graph 17: Renewables Serving Peak Demand – Day with Low Renewables & High Energy Demand

Other than reducing peak demand through efficiency measures and demand response programs, APU takes into consideration how renewables or other zero emission resources may provide more clean energy during the peak hour. APU recently contracted for a solar plus stor age project and is actively working on the evaluation and negotiations of three energy storage projects. In addition, the location and generation profile of new renewable projects are also considered. The goal is to acquire renewable projects with generation profiles most aligned with APU’s energy demand profile.

Extreme Weather Impacts
Peak demand estimates are obtained for the extreme weat her analysis using the load factor methodology, as described in VI.B.2. DEVELOPING THE PEAK FORECAST. Graph 18 displays the impact of extreme temperatures on peak demand. On average, peak demand is estimated to be 34 MW higher with extremely high -
100
200
300
400
500
600
700MWh
Axis Title
Low Renewables/High Energy Demand
September 8, 2022
Renewable | Retail Thermal | Retail Purchase | Retail CAISO Market Renewable | Wholesale Thermal | Wholesale Utility Customer Load 2023 Integrated Resource Plan
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temperatures, with the highest impact of 42 MW in October. Similarly, peak demand is estimated to be 10 MW lower with extremely low temperatures, with the highest impact of 14 MW in October.

Graph 18: Forecasted Peak demand with Extreme Temperatures

250
300
350
400
450
500
550
600
Jan Feb Mar Apr May Jun July Aug Sept Oct Nov Dec
MW
High Temp Expected Temp Low Temp
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VII. RESOURCE PORTFOLIO EVALUATION
After forecasting the energy and peak demand, the supply side analysis is detailed in this section to answer one question: What is the optimal resource mix to supply the forecasted energy and peak demand given APU’s planning goals of sustainable resources, high reliability, and affordable rates?

This section starts with basic considerations, such as how to transition from fossil fuels to clean, renewable energy and determining the performance measures to evaluate available supply-side options.

Candidate portfolio scenarios were developed based on commercially available technology and market intelligence regarding the availability of resources. These supply-side options were screened to filter out non- viable scenarios which do not meet APU’s planning goals, and the remaining scenarios were analyzed using extensive quantitative production cost modeling analysis. The model outputs were scored and stress tested prior to a final portfolio selection. Graph 19 summarizes the selection process used to choose the optimum resource additions needed to satisfy customer demand, reliabili ty, and sustainability goals. Graph 19 below summarize the selection process used to choose the optimum resource additions needed to satisfy customer demand, and reliability, and sustainability goals:

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Graph 19: Selection Process for the Optimum Resource Portfolio

A. PORTFOLIO CONSIDERATIONS AND PERFORMANCE MEASURES

A.1. COAL-TO-CLEAN ENERGY TRANSITION
Prior to the heightened awareness regarding the effect of carbon intensive fuels on the environment, APU was fully resourced to meet local energy demand with long- term, low-cost, baseload coal-fired power plants. Coal-fired power plants were historically a nationally preferred resource due to the abundance of coal as a fuel, it’s low-cost, and the reliable coal generation technologies available to produce electricity.

Also, in the 1980s, nuclear energy fell out of favor due to issues surrounding where to house nuclear waste and the associated capital risk. During that same time, Congress banned the use of natural gas for power generation due to its scarcity and higher value as a space heating fuel. For these reasons, APU invested in two coal facilities that served APU customers for several decades, and approximately two- thirds of APU’s energy needs were met by these two coal-fired power plants.

APU has actively transitioned from a carbon intensive resource mix to clean renewable energy since the early 2000’s, as demonstrated by the introduction of A. Portfolio
Considerations &
Performance
Measures
• Optimize Existing
Resources
• Renewables and
GHG Emission
Goals
• Regulatory
Compliance
• Reliability;
Diversification
• Expected Cost;
Market Exposure
B. Resource
Options
• Natural Gas
Resources
•M a r k e t P u r c h a s e s
• Renewable
Resources
• Energy Storage
• Hybrid Resources
C. D. & E.

Model Analysis
•Input Assumptions
•Long-Term
Capacity
Expansion
•Output Evaluation
• Renewables and
GHG Emission
Goals, Reliability,
Production Cost
F. Stress Testing
•Market Volatility
• High/Low Fuel &
Energy
•Customer Demand
Variation
•H i g h / L o w
Temperature, Solar,
EV, Energy
Efficiency
G. Optimum
Portfolio
Selection
A. Portfolio
Considerations &
Performance
Measures
• Optimize Existing
Resources
• Renewables and GHG
Emissions Goals
• Regulatory Compliance
• Reliability;
Diversification
• Expected Cost; Market
Exposure

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renewable resources to the power portfolio and its early exit of the San Juan Coal Power Plant.

APU has continued to increase the amount of energy delivered to customers from renewable energy resources since the early 2000’s, while reducing coal power from 43% to 23%18 for the years 2012 through 2022. Today, APU’s overall resource stack for retail customers and the wholesale market is very different from the historical view, with a much greater percentage of retail energy demand met by sustainable energy. The following graphs show the change in APU’s power supply resource stack over the past decade for years 2012 through 2022.

Graph 20: APU Resource Stack in 2012

Note: Generation above the retail energy demand was sold into the CAISO wholesale energy market.

Graph 21: APU Resource Stack in 2022

Note: Generation above the retail energy demand represents energy sold into the CAISO wholesale energy market.

18 The 23% coal calculation assumes the same Power Content Label (PCL) calculation methodology is used in 2022. The PCL calculation methodology was updated in 2019 and assumes all coal generation is used to serve the retail energy demand. Previously, it was assumed that a portion of the coal generation served the wholesale market.

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Roughly one quarter of APU’s 2022 en ergy supply came from the Interm ountain Power Project (IPP) coal plant. APU has taken action to allo w the IPP contract to expire effect ive 2027. The IPP coal plant will be converted into a natural gas power plant in 2025, at which time APU will have divested itself of coal resources.

After the IPP contract expiration in 2027, APU will no longer receive generation from this natural gas resource.

The capacity and generation from IPP will need to be replaced prior to 2027 to maintain high reliability, achieve APU’s sustainability goals, comply with State mandates, and mitigate market price risk. To select the optimum resource portfolio, which includes the replacement of the divested coal resources and the gradual reduction in natural gas resources, APU used quantitative performance measures and production cost modeling to evaluate the portfolio scenarios pursuant to its planning goals, as mentioned in Section III. Planning Goals

A.2. PORTFOLIO PERFORMANCE MEASURES
APU’s mission is to be an agile, customer focused, water and power utility operating in an ever-changing energy landscape, while continuing to provide reliable, high quality, environmentally sustainable, and competitively priced water and power, delivering the maximum value to our customers.

The integrated resource planning process maintains three main planning goals to achieve the organizational mission: Sustainable Resources, High Reliability, and Affordable Rates.

RPS Goal
The RPS goal is measured by the percentage of rene wable energy delivered to serve retail load. Portfolios considered must achieve at least 60% eligible renewable energy by 2030, 90% renewabl e or zero carbon resources by 2035, 95% by 2040 and 100% by 2045. In addition, per the RPS statute, 65% of APU’s RPS obligation in any given year must come from long term contracts (i.e., greater than 10 years in length).

APU has historically procured more renewable energy than target requirements, leaving a sufficient “bank” of renewable energy credits (RECs) for renewable contracting flexibility. In 2022 and 2023, APU elected not to renew some renewable contracts due to the resources’ relatively higher prices and/or the generation profile not being in alignment with the APU system energy demand.

APU has a sufficient amount of banked, existing and soon-to-be executed long-term renewable energy resources to meet RPS compliance through year 2026. With the flexible utilization of short-term renewable agreements and unbundled REC products, APU can meet RPS compliance through 2030. In addition, APU is Sustainable
Resources
•R P S G o a l
• Emmission
Reduction Goal
• Regulatory Risk
High
Reliability
• Resource Adequacy
• Portfolio
Diversification
Affordable
Rates
• Expected Cost
• Market Exposure
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in active negotiations with renewable and hybrid resource providers to meet renewable compliance obligations post-2030. Graph 22 details the banked and existing long-term renewable energy and the renewable compliance targets.

Graph 22: Banked and Existing Long-Term Renewable Energy Credits (RECs)

Emission Reduction Goal
The greenhouse gas (GHG) emission reduction goal is calculated with (1) the 2022 Scoping Plan’s electricity sector targets: 38 MMT GHG in 2030, 35 MMT in 2032, and 30 MMT in 2035 19, and (2) APU’s share of the sector target (1.015%) as recommended by the CEC for the 2017 Scoping Plan. 20 Portfolios considered must meet the GHG emissions reduction targets ultimately established for the electricity sector by the California Air Resources Board.

Graph 23 details the planned GHG reductions assu ming both the Magnolia and Canyon power plants remain in the portfolio. The dark bar represents APU system emissions net of emission savings from transportation electrification. The transparent bar repr esents emission savings from converting internal combustion engine vehicles to electric vehicles. The gray dotted lines represent the GHG emissions target range from the 2017 Scoping Plan. The blue line represents APU’s expected share of sector GHG emissions target from the 2022 Scopi ng Plan. As the 2022 Scoping Plan only provides emissions target through 2035, the blue line is also depicted as a dotted line beyond 2036.

APU system emissions assume that (1) the coal and natural gas power plants’ emission factors remain at 2022 levels, (2) the wholesale purchase emission factor equals the published 2021 CAISO GHG

19 P. 201, Clean Energy Grid – Sector Transition, “2022 Scoping Plan for Achieving Carbon Neutrality”, https://ww2.arb.ca.gov/sites/default/files/2022-12/2022-sp.pdf 20 Table 1, POU 2030 GHG Emissions Targets, “Staff Report: Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets”, https://ww2.arb.ca.gov/sites/default/files/2020-08/appendix_b_staffreport_sb350_irp.pdf 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 ‐
500
1,000
1,500
2,000
2,500
GWh
Renewable Energy Retail Sales Renewable Target
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emissions21 divided by the corresponding system load22; and (3) the wholesale purchase emission factor has a straight-line decline through 2035; when it is at half of the 2022 emission factor and the grid achieves 95% zero emissions goal.

In summer 2025, IPP will be converted into a natural gas unit. By mid-summer 2027, APU will fully exit the IPP natural gas power plant. APU system emissions remain consistent between 2026 and 2030 except for major maintenance scheduled. The emissions start to decline b eyond 2023, with more renewable resources added and more widespread transportation electrification beyond 2030.

Graph 23: Planned Emission Reduction

Regulatory Risk
Regulatory Risk measures the ability to remain comp liant with current and anticipated future legislative or regulatory changes.

California’s RPS targets have steadily increased ov er the past decade while the GHG emissions target continues to drop. SB 100 (2017) establishes the goal of renewable energy and zero carbon resources to supply 100% of retail sales by 2045, while SB 1020 (2 022) establishes interim goals of 90% by 2035 and 95% by 2040. In addition, AB 1279 establishes the goal for California to achieve net zero GHG emissions no later than 2045. While these policy goals are not enforceable mandates, APU must consider the state’s climate initiatives, and plan to achieve such goals. Therefore, the optimum portfolio should meet APU- specific requirements to meet the State’s policy goals.

21 “Greenhouse Gas Emission Tracking Report December 2022”, http://www.caiso.com/Documents/GreenhouseGasEmissions-TrackingReport- Dec2022.pdf
22 Table 1.1, “2021 Annual Report on Market issues & Performance”, http://www.caiso.com/Documents/2021-Annual-Report-on-Market-Issues- Performance.pdf

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The optimum portfolio must consider the technolog ical risk where a generation technology becomes unfit to meet the State’s policy initiative. Nuclear and coal generation are two examples of technologies that became out of alignment with the State’s policy initiatives. One technology being considered in the 2023 IRP is the use of renewable natural gas (RNG or biomethane). It is currently considered a carbon neutral/renewable resource because RNG projects capture and repurpose highly potent, ozone depleting methane gas which is more than 25 times as potent as carbon dioxide at trapping heat in the atmosphere.

RNG production reduces the GHGs that would otherwise be emitted from using the same amount of conventional natural gas; however, RNG is not a car bon-free fuel. There is a ri sk that future policy changes could reclassify RNG an emitting resource, potentially introducing compliance implications.

In addition, the accounting for reserve margin, effective load carrying capacity (ELCC) and net qualifying capacity (NQC) has been in discussions lately. APU must consider th e possibility of a higher reserve margin requirement, and the likelihood of a resource’s ELCC or NQC being reduced in the future.

Resource Adequacy (Reliability)
Resource Adequacy is measured by the ability to achieve a 15% reserve margin above the system peak forecast while meeting forecasted system, local, and flexible capacity requirements.

Resource portfolios not achieving this measure are still included for consideration by identifying future capacity shortages and planned ca pacity purchases. Costs for capacity purchases are added to the portfolio.

Graph 24: Available Resource Adequacy (RA) System Capacity

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Graph 24 illustrates the existing and planned resources APU may use to meet Resource Adequacy requirements. When APU exits IPP in 2027, 140 MW of capacity will need to be procured to ensure resource adequacy and system reliability requirements ar e met. The new capacity can be in the form of new energy resources with capacity, capacity-only pu rchases, stand-alone energy storage, or renewable and storage hybrid resources.

Canyon Power Plant and the Bowerman and Brea landfill gas to energy plants are long-term and reliable resources located in or near Anaheim, and they provide more than 100% of the local and flexible generation capacity required by the CAISO.

The Resource Adequacy generation capacity needed after 2027, upon the expiration of the IPP contract, is system wide capacity that may be produced anywhere in the 14 western states so long as it is deliverable to California. Out-of-state capacity requires the use of CAISO Import Capability, which would need to be requested as part of the CAISO annual process, how ever it is not guaranteed that an allocation will be supplied and may need to be procured from another CAISO participant who has surplus in order to offer the resources as RA units. Without Import Capabili ty Allocations, it is more beneficial to acquire in-state resources for system RA.

APU plans to fully procure the requisite Resource Adequacy at least two years prior to the expiration of the IPP contract through competitive solicitations. APU is in the process of adding stand-alone energy storage within the LA Basin, and is in active nego tiations with other renewables, storage and hybrid resources within California. Due to the retirement of natural gas and once-through-cooling power plants, capacity prices during the summer peak months have seen drastic increases. At the same time, the large amounts of new renewable resource interconnections have driven up ancillary service charges along with price disparities over 5-minute intervals. As a result, energy storage, in combination with renewables are beginning to become viable resources to meet RPS requiremen ts and supply RA.

Portfolio Diversification
Portfolio diversification is measured by the differe nt types and length of resource investment within the portfolio. A diversified resource portfolio increases flexibility, reliability, and overall performance.

APU’s 2018 renewable portfolio consisted of 15% intermittent resources and 85% baseload resources.

The 2018 IRP recommended the procurement of additiona l intermittent resources in order to diversify the portfolio. In 2022, APU’s renewable portfolio consisted of 38% intermittent resources and 62% baseload resources.

Baseload resources are very reliable and provide local Resource Adequacy capacity, but the cost of these resources is significantly greater than intermittent resources such as solar and wind. Both types of resources, along with energy storage and hybrid resources, are being considered for new resource additions.

Expected Cost
Expected Cost is measured by the total cost to supply power. Each resource portfolio for the 2023 IRP is being evaluated with a goal to minimize impacts on customer bills and to serve customers at just and reasonable rates.
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As previously discussed, APU has been fully resourced to meet loca l demand with long-term baseload power plants. Any costs associated with additi onal resource procurement necessary to meet environmental goals must be carefully considered and prudently managed. A key consideration in selecting the optimum resource portfolio is leveraging existing resources and minimizing customer impact.

Market Exposure
Market Exposure is measured by the percentage of energy APU must purchase from the wholesale market, and the portfolio’s ability to withstand market price volatility. The financial exposure of the overall resource portfolio increases when a larger pe rcentage of energy is procured from the wholesale market.

With 236 MW of capacity, IPP meets the largest po rtion of APU baseload energy needs, with the remaining baseload energy demand supplied by the natural gas and renewable generation facilities. The predictable cost structure of a baseload unit protect s the resource portfolio from price swings in the wholesale market. The replacement energy needs resu lting from APU’s exit from IPP will come from renewable energy resources. Because of the intermitte nt nature of variable renewables (i.e., wind and solar), financial exposure must be evaluated when considering replacement energy from these types of resources.

Intermittent renewable energy resources have seasonal and hourly generation profiles that are not always aligned with energy demand and can be unpredictable at times due to changing weather patterns. Due to this variability in production, there are times when generation levels exceed energy demand, resulting in decreases in market prices and revenue from the sale s of energy. Conversely, at times of high energy demand and limited amounts of generation available, ma rket prices and the purchase of energy to meet energy demand will increase.

Modeling stress tests are introduced in Section F. Stress Testing to ensure the optimum portfolio’s overall performance is stronger under different market cost and energy demand scenarios.

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B. RESOURCE OPTIONS
B.1. NATURAL GAS POWER PLANT OPTIONS
With extensive quantitative analysis, the 2023 IRP examines several different options for the Magnolia and Canyon natural gas power plants after the IPP exit in 2027.

Graph 25 below shows the screening process used to evaluate the different options for the natural gas units.

Graph 25: Options for the Natural Gas Power Plants

1. Preserve/Extension : The units can be preserved or extended beyond their expected end dates of 2037 for the Magnolia Power Plant and 2041 for the Canyon Power Plant. ‐ Reliability Units : The natural gas units may be used as reliability units, serving APU customers and the CAISO system as they historic ally have been. California narrowly avoided rolling blackouts during the September 2022 heat wave, in which Governor Newsom’s Executive Order N-11-21 resulted in dispatch ing diesel generators to help meet peak demands. With the electrification of transportation, buildings and fuel switching, it is expected that electricity demand will continue to incr ease. Reliability has become one of the key considerations for new resource additions or extensions. Recent discussions considering the continuation of nuclear and once-through-cooling units in California also validates that baseload and dispatchable units are still necessary to ensure a smooth transition to the State’s clean energy future.
‐ Renewable Natural Gas : The Magnolia Power Plant is certified as an RPS unit allowing for the use of Renewable Natural Gas (RNG) for fuel to generate renewable energy. This option assumes that ample RNG supplies will become available by 2031, and that APU can secure long-term RNG contract(s) for the minimal dispatch portion of the resource. Currently, there is no commodity market for RNG projects. The current cost of RNG varies from $10/MMBtu to $40/MMBtu, depending on size, location, and technology. Higher fuel prices will significantly increase the unit’s dispatch cost, and there is a risk that the unit may only be B. Resource
Options
• Natural Gas
Resources
•M a r k e t
Purchases
• Renewable
Resources
• Energy Storage
•H y b r i d
Resources

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minimally dispatched in the CAISO energy market. Since Magnolia has a minimum dispatch capacity that can be self-scheduled, the dispatch will not be impacted by fuel price, therefore Magnolia is selected as the RNG unit.
‐ Carbon Capture and Sequestration (CCS): A third option considered is to retrofit the units with CCS technology. However, based upon initial research, this approach is proven geologically and technologically infeasible due to the urban location of both natural gas units and lack of identifiable sequestration sites or CO
2 pipelines to inject the captured carbon. With
current CCS technology, the solution is deemed not viable, as very limited space is available at both sites for onsite CCS implementation. In addition, the technology is costly, at $100 to $600/ton CO2e, depending on specific CCS technologies. Using the medium cost of $250/ton, Magnolia’s and Canyon’s costs increase by $100/MWh and $140/MWh, r e s p e c t i v e l y . A s C C S t e c h n o l o g y m a t u r e s , cost reductions may occur, and studies are underway for a national CO
2 pipeline system that could be used for CCS 23. While deemed infeasible for the 2023 IRP, this technology may be revisited in subsequent updates.

2. Exit/Decommission : Under this option, APU exits the Magnolia Power Plant at the expected end date in 2037 and decommissions the Canyon Power Plant at its expected end date in 2041. Renewable, storage, or hybrid resources will be procured to fill the capacity an d energy positions.

In conclusion, three portfolios are evaluated for the 2023 IRP:

1. Reliability Portfolio : Both Magnolia and Canyon Power Plants are preserved as natural gas power plants, serving capacity and energy to APU customers and the CAISO system when the renewable resources are not available.

2. RNG Portfolio: The Magnolia Power Plant is certified as an RPS unit, using RNG as fuel.

3. Zero-Emissions Portfolio : APU exits both natural gas power plants at the expected end dates.

New renewable, storage or hybrid resources are proc ured to fill the capacity and energy shortfall.

B.2. NEW RESOURCE OPTIONS
The following factors were considered in the deve lopment of new resource options. The new resources being considered include renewable, energy storage an d hybrid resources. Energy storage may be used to facilitate the integration of unpredictable intermittent resources; however, energy storage itself is not a renewable resource.

1. Determine Annual RPS Requirements
In developing the candidate portfolios, the first step is to calculate the amount of renewable energy needed to meet the RPS requirements. RPS requirements are statutorily established and, in the case

23 Carbon Capture and Sequestration (CCS) in the United States by the Congressional Research Service, https://sgp.fas.org/crs/misc/R44902.pdf 2023 Integrated Resource Plan
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of publicly owned utilities like APU, are enforced by the CEC. The requirements are calculated as a percentage of customer retail energy demand.

Retail Energy Demand Forecast * RPS % = Renewable Energy Required

Due to the inconsistent nature of renewables development and energy production, there may be years when APU exceeds its projected RPS targets. To preserve the value of the renewable energy resources, the Legislature and State agencies recognize the ability to use any excess renewable procurement for future compliance through the banking of excess renewable energy credits (RECs) as they are produced. APU has banked RECs prod uced in excess of RPS compliance requirements to date and intends to continue banking any surplu s RECs for future use to help satisfy its future RPS compliance targets in the most cost-effective manner possible.

The following assumptions are introduced:

1. A straight-line method is used to determine interim targets between 2030 (60%), 2035 (90%), 2040 (95%), and 2045 (100%).

2. Post 2030, the same rules rema in for banking, long-term resource obligation, and the limitations of renewable resources in different “buckets” or categories.

As detailed in the green bar on Graph 26 below, th e renewable generation forecast indicates that APU will have procured a sufficie nt amount of renewable energy to meet its RPS obligations through 2026, with existing long-term renewabl e agreements only. In or der to meet compliance obligations post 2026 APU will need to negotiate exte nsions of existing contracts, purchase short- term renewable products, and procure new long-term renewable resources.

2. Determine Long-Term Contract Obligation
Pursuant to SB 350, the RPS Program also requires that starting in the year 2021, 65% of APU’s RPS obligations must be met by renewable resour ces under contract for more than 10 years in length, shown by the dotted line on Graph 26. Currently, the majority of APU’s renewable energy comes from resources under long term contracts. APU is in active negotiations to secure additional long-term renewable c ontracts in combination with short-term renewable purchases in order to meet this compliance obligation.

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Graph 26: Simulated RPS Compliance Requirement

3. Determine New Resource Costs
APU utilizes the production cost model’s Long-Term Capacity Expansion (LTCE) function, which contains a database with new resource costs for different planning regions. APU selects candidate new resources from the LTCE input database, reviews cost information, and updates it with current market intelligence. Proxy costs may come from the SCPPA Request for Proposals
24 for renewable generation, recently executed/negotiated renewable agreements, or renewable agreements in APU’s existing portfolio.

The candidate resources include solar, wind, geothermal, landfill gas, energy storage, and hybrid resources (solar + storage).

Capacity calculations vary by the operating characteristics of the renewable technology.

Baseload renewables have a much higher capacity factor than intermittent resources such as wind and solar (95%, 30%, and 25%, respectively). The production cost model’s LTCE function calculates the optimal new resource builds based on resource costs, RPS requirements, capacity factor, and APU’s planning reserve margin. More details can be found under C. Model Analysis.

24 http://scppa.org/page/RFPs-ResourceProject

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C. MODEL ANALYSIS – PRODUCTION COST MODEL
The Public Utilities Code Section 9621(c)(1) requires the IRP to address procurement for energy efficiency an d demand response resources, energy storage, transportation electrification , short-term and long-term electricity, electricity related, and resource adequacy products.

Energy efficiency, demand response an d transportation electrification are considered in the demand forecast and model stress tests. This section considers energy storage, short-term and long-term electricity, electri city related, and resource adequacy products.

PRODUCTION COST MODEL
Considerable quantitative analysis was performed to evaluate the candidate portfolios. Staff used a production cost model to perform hourly chronological unit commitment and evaluated dispatch model runs of how APU would meet its energy demand for a 20-year study period, from 2023 through 2042. The following graphic shows the elements of the production cost modeling process.

INPUT ASSUMPTIONS
The main input assumptions include energy demand, environmental targets, resource constraints and costs, and fuel and carbon prices.

APU’s energy demand was developed under Section VI. Energy Demand and Peak Forecasts. APU utilized a production cost model that contains information of other utility areas energy demand forecast, and the generation, transmission, and othe r resources such as energy storage and demand response.
•Energy Demand,
Environmental Goals
•Generation, Transmission
and Other Resources
•Market Conditions (Fuel,
Carbon)
Model Input
Assumptions
•Long-Term Capacity
Expansion Study
•Deterministic Model Run
•Hourly Dispatch
Model Optimization
& Simulation
•New Resource Builds
•Resource Dispatch &
Generation
•Wholesale Energy
Prices
•Portfolio Costs
Model Output

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The production cost model has an extensive database of the Western Interconnect that includes grid wide data such as hydro conditions, fuel prices, heat rates, maintenance schedules, area demand, GHG emissions, transmission constraints, and variable and fixed unit costs. The model obtains grid- wide data via publicly available sources from th e North American Electric Reliability Corporation (NERC), the Energy Information Administrati on (EIA), the Environmental Protection Agency (EPA), and various balancing authorities. Input assumptions are periodically updated, and the model run results are validated against historical actuals.

These base assumptions can be modified to allow utility specific and detailed analysis. APU updates market conditions including fuel prices and car bon allowance costs to reflect the most updated information. Key input assumptions are detailed in D. Model Analysis - Input Assumptions.

MODEL SIMULATION
APU first uses long-term capacity expansion (LTCE) studies to determine the optimal new resource builds based on the input assumptions. Once the new resource builds are determined, APU uses the deterministic model which calculates an hourly dispatch to simulate how the energy market will dispatch the available resources to meet the region’s estimated energy demand on an hourly basis. A model simulation was performed for each of the candidate portfolios.

Once the input assumptions are incorporated into th e database, portfolio simulations or model runs are conducted. As an example, Graph 27 illustrates the system diagram for a particular hour during the model run, including the energy flow from between balancing areas containing loads and resources. The energy demand is displayed within th e utility bubble; the energy flows between utilities areas are displayed on the arrows that depict transmission lines. The colors of the bubbles are indicators of energy prices, with red representing the highest and blue representing the lowest energy prices. This process is conducted in hourly intervals for the time span specified by the user.

The results of the market simulation are retrieved in the output tables of the associated model run.

Deterministic model runs reflect expected or normal conditions for each hour of the year. For example, under deterministic analysis, weather, un it forced outages, gas prices, and intermittent resource generation are all assumed to be normal on every day of the year. The abnormal or extreme conditions are introduced after the initial model runs, in F. Stress Testing.

Note that APU is set up as a separate area only for reporting purposes. During model simulations, it is considered within the SCE area and has the same market price as the SCE region.

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Graph 27: System Diagram (Partial)

MODEL OUTPUT
With the input assumptions and model simulation, the production cost modeling software will produce the model output including the following:
 New resource builds: Optimal new resource builds that achieve the highest net revenues for the planning horizon.
 Hourly resource generation (MWh): The resources that are dispatched to meet the energy demand during the specific hour and their respective dispatch costs.  Wholesale energy prices: The wholesale energy price for the hour.  Portfolio costs: The fixed, variable, fuel, and carbon costs The output for each candidate portfolio was evalua ted and compared against each other in E. Model Analysis – Output Evaluation.

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D. MODEL ANALYSIS – INPUT ASSUMPTIONS
Key input assumptions utilized in the production cost model are shown below.

SYSTEM-WIDE GENERATION RETIREMENT AND ADDITIONS
APU’s 2018 IRP observed the declining trend of wholesale energy prices at SP 15 from 2013 to 2017 as more renewables were added to the Grid and the conventional fossil fuel generation resources remained. For the next three years, energy prices continued to decline due to the surge of utility-scale renewables without the corresponding increase in demand. The annual average wholesale price was $46.80, $39.50, and $37.90/MWh for 2018, 2019, and 2020 respectively, even though 2020 had a hotter summer which only drove prices up for part of the year.

Increasing energy prices with power plant retirements
The trend started to reverse in 2021 with an average energy price of $55.10/MWh, as more fossil fuel generation resources retired. Energy prices increased even further in 2022 at an aver age of $91.60, along with natural gas price hikes and more fossil fuel generation units retiring.

Graph 28 illustrates the average hourly energy price at SP 15 25 for 2018 through
2022. The retirement of fossil fuel resources replaced by variable energy resources continues to play a major role in shifting the supply curves and corresponding wholesale energy prices.

Graph 28: Average Annual SP-15 Energy Price

25 South of California transmission Path 15, a CAISO pricing zone covering Southern California. $0
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In September 2022, the production cost model vendor released the new WECC Zonal database, which included a calibrated LTCE database with forecasted resource additions and retirement for the next 20 years. The database forecast is based on the various RPS and carbon emissions reduction goals in all WECC States. APU utilizes this database for system-wide planned additions and retirement.

Details of the vendor’s WECC Zonal database forecast may not be shared, as it is proprietary information. Staff compared the new LTCE database with the following public reference data sources:

1. CAISO Interconnection list and the Retirement and Mothball list:

Staff reviewed the CAISO Interconnection list and the Retirement and Mothball list for planned additions and retirement and considered the possibility of using the lists as input data.

However, the CAISO lists only contain information for the next few years. In addition, not all resources on the Interconnection List are expected to be built, and the planned retirement dates may change. The LTCE database is considered a preferred data source for long-term resource planning.

2. SB 100 Joint Agency Report RESOLVE Model data:

Staff reviewed the RESOLVE model data released as part of the SB 100 Joint Agency Report26. The LTCE resource builds are compared to the resource builds under the SB100 Reference Case for the “Retail Only” and “Retail + Losses” scenarios for four simulation years 2027, 2030, 2035 and 2040. Differences are observed but deemed acceptable for the long-term planning horizon.

The 2023 IRP process is looking to compare di fferences among various approaches for the long-term outlook, and not to determine the absolute values for each approach. Indeed, with a multitude of variables involved in a 20-year long-term analysis, actual market conditions may change very quickly after the conclusion of the 2023 IRP analysis.

3. Current energy market changes:

Staff made updates to the LTCE database where necessary. For example, the planned retirement dates for the Diablo Canyon nuclear power plant and the Scattergood generating station units are extended to reflect changes after the database release.

EXISTING APU RESOURCES
For each APU resource or contract, staff examined the generic data in the model, and updated model inputs where necessary. The information updated may include heat rates, minimum run times, startup times, fuel types, variable costs, fixed costs, emission factors, capaci ty, capacity shape, planned outages, area, resource beginning and end dates, and any other information that impacts the unit dispatch.

26 https://www.energy.ca.gov/sb100
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NEW APU CANDIDATE RESOURCES
The production cost model’s WECC database contains an input table with new candidate resource profiles (including costs) for different planning regions. Staff mapped APU’s new candidate resources to the SCE candidate resources in the database. In addition, cost information is reviewed and updated with current market intelligence. The cost may come from the SCPPA Request for Proposals 27 for renewable generation, recently executed or negotiat ed APU agreements, or renewable agreements in APU’s existing portfolio.

The candidate resources include solar, wind, geothe rmal, landfill gas, energy storage, and hybrid resources (solar + storage).

ENVIRONMENTAL GOALS
Only the annual RPS goals are used for the LTCE model runs due to the following reasons:

1. Adding both the RPS and emission goals would slow down run time.

2. Portfolios meeting the RPS goals naturally achieves the emissions goals. Staff performs post model run review to ensure the emission reduction goals are met for all LCTE runs.

As previously mentioned, the RPS goals assume that:

1. A straight-line method is used to dete rmine interim targets between 2030 (60%), 2035 (90%) 2040 (95%), and 2045 (100%).

2. Post 2030, the same rules re main for banking, long-ter m resource obligation, and the limitations of renewable resources in different “buckets” or categories.

NATURAL GAS PRICE
Natural gas prices were derived from the S&P Global gas forward prices and adjusted for basis differential between Henry Hub and the SoCal City Ga te. An escalation rate of 2.5% was applied to develop the expected gas forward curve, which is consistent with the inflation rate used for the overall model run.

CAP AND TRADE ALLOWANCE PRICES
The 2023 IRP assumed the continuation of freely allocated carbon allowances for retail sales compliance through 2030, and APU’s practice of purchasing carbon allowances for compliance obligations associated with any wholesale electricity purchases. Consistent with the Cap-and-Trade regulations, the allowance price assumes an escalation rate of 5% + the Bureau of Labor Statistics Consumer Price Index (CPI).

27 http://www.scppa.org/page/RFP-Request-for-Proposals-Archives 2023 Integrated Resource Plan
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E. MODEL ANALYSIS – OUTPUT EVALUATION
Market simulations were conducted for each candidate portfolio. All input assumptions were consistent, with the ex ception of the treatment of the natural gas power plants in each portfolio. Th is allows the most accurate comparison between portfolios. The candidate portf olios’ model simula tion results were analyzed and scored based on the six performance measures.

RPS & EMISSION REDUCTION GOALS

Each portfolio meets RPS and GHG goals, as shown in Graph 29 and Graph 30 below. While each portfolio performed equally in meeting RPS requirements, the RNG Portfolio produces the least amount of GHG emissions. The Reliability Portfolio produces the highest amou nt of carbon emissions due to the retention of both natural gas power plants through the 20-year planning horizon. Under the RNG Portfolio, the Magnolia Power Plant only uses RNG as fuel starting in 2031 and is therefore considered a carbon-neutral/zero emission resource. Under the Zero-Emissions Portfolio, the Magnolia Power Plant remains in APU portfolio through June 2037. The Zero-Emissions Portfolio also requires higher wholesale purchases in the last few years of the planning horizon, thus increasing the APU system emissions slightly again.

Because all three portfolios equally meet RPS requirements, they are ranked in order of the best portfolio having the least amount of GHG emissions. Using this ranking strategy, the RNG Portfolio performed the best, followed by the Zero-Emissions Portfolio, and then the Reliability Portfolio.

PERFORMANCE MEASURE Relia bility RNG Zero-Emissions
RPS & Emission Reduction Goals 1 3 2
Legend: 3=Best, 2=Middle, 1=Worst

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Graph 29: Candidate Portfolio Results: RPS Compliance

Graph 30: Candidate Portfolio Results: Forecasted GHG Reduction

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REGULATORY RISK
PERFORMANCE MEASURE Relia bility RNG Zero-Emissions
Regulatory Risk 3 1 2
Legend: 3=Best, 2=Middle, 1=Worst

As discussed in Section A. Portfolio Considerations and Performance Measures, the preferred portfolio should also be sufficiently diversified such th at APU minimizes the technological risk where one technology becomes obsolete, less cost-effective, or not acceptable under new/changing regulations. In addition, the preferred portfolio also must consid er the possible changes in the reserve margin requirement.

The portfolio that has the highest risk exposure is the RNG Portfolio, resulting in 14% of the renewables portfolio coming from the RNG resources. Should RNG no longer be deemed acceptable due to future legislative and regulatory changes, APU most likely would have to honor costly long-term RNG agreements while procuring additional renewable resources to fill the void.

The portfolio that also has regulatory exposure is the Zero-Emissions portfoli o. Should the planning reserve margin requirements keep increasing, or the methodology for calculating Net Qualifying Capacity (NQC) continue to further discount certain resources, APU will need to quickly procure additional capacity in an already highly constrained market to meet the Resource Adequacy requirements. More details can be found under the section below, Resource Adequacy.

RESOURCE ADEQUACY
PERFORMANCE MEASURE Reliability RNG Zero-Emissions
Resource Adequacy 3 3 1
Legend: 3=Best, 2=Middle, 1=Worst
System Capacity
The new resources in each candidate portfolio all cont ribute to system capacity . The baseload, solar, and wind contracts are estimated to have a capacity factor of 95%, 30%, and 25%, respectively. Timing of the new resource addition is determined by the LTCE model runs and summarized below in Graph

31. The LTCE optimization aims to meet the capa city and RPS requirements with the highest net revenue portfolios. To allow greater flexibility, st aff developed the constraints to allow small amount (25 MW) of capacity shortfall in any given year to be met with short-term capacity purchases. Cost to fill the short-term capacity position are included in the Net Power Supply Costs analysis. 2023 Integrated Resource Plan
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In Graph 31 below, all three portfolios meet the system capacity requirement with the current CAISO Resource Adequacy accounting rules. However, while both the Reliability and RNG Portfolios still offer 333 MW of “firm” resources28 through 2042, only 128 MW of firm resources are available for system capacity in 2042 under the Zero-Emissions Po rtfolio. Firm resources refer to geothermal, biomass, biogas, nuclear, gas and coal generation, and are considered preferable under the CPUC reliability evaluations. While APU is not a CPUC-jurisdictional entity, CPUC considerations are considered for potential future impacts to the CAISO Resource Adequacy accounting rules.

Graph 31: Candidate Portfolio Results: System Capacity

Local Capacity
The CAISO local capacity requirement is determined by local energy demand and transmission availability and would not vary based on resource portfolio mix. The CAISO local capacity requirement for APU has been below 230 MW over the past few years and remains stable. Currently, APU has over 255 MW of natural gas and baseload renewable power plants located within the LA Basin Area.

Under the Reliability and RNG Portfolios, APU has sufficient local resources that exceed CAISO’s local capacity requirements through the 20-yea r planning horizon. Under the Zero-Emissions Portfolio, APU relies on the battery storage capacity built within the LA Basin.

28 P.74, CPUC Reliability Filing Requirements for Load Serving Entities’ 2022 Integrated Resource Plans, https://www.cpuc.ca.gov/-/media/cpuc- website/divisions/energy-division/documents/integrated-resource-plan-and-long-t erm-procurement-plan-irp-ltpp/2022-irp-cycle-events-and- materials/20220729-updated-fr-and-reliability-mag-slides.pdf

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Graph 32: Local Capacity Resources and LCR Requirement – Reliability and RNG Portfolios

Graph 33: Local Capacity Resources and LCR Requirement – Zero Emissions Portfolio

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Flexible Capacity
On average, APU has a monthly flexible capacity requirement of 17 MW, which peaks in May with a capacity requirement of 22 MW. Canyon Power Plant, a CAISO Category 1 flexible unit, is a Base Ramping Resource with 194 MW of eligible flexible capacity. APU has sufficient flexible capacity available through Canyon to meet the additional requirements for fl exible capacity under the Reliability and RNG Portfolios. Under the Zero-Emissi ons Portfolio, APU relies on the new battery storage units to provide flexible capacity after Canyon decommissioning.

Graph 34 and 35 show CAISO Flexible Capacity Requirements for both the Reliability and RNG Portfolio and the Zero-Emissions Portfolio.

Graph 34: CAISO Flexible Capacity Requirement – Reliability and RNG Portfolios

Graph 35: CAISO Flexible Capacity Requirement – Zero-Emissions Portfolio

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The Reliability and RNG Portfolios provide the same amount firm system capacity, local capacity, and flexible capacity and are therefore ranked equally. While the Zero Emissions Portfolio also meets the system, local, and flexible capacity requirements, it relies on non-firm resources and therefore is given a lower score.

PORTFOLIO DIVERSIFICATION
PERFORMANCE MEASURE Reliability RNG Zero-Emissions
Portfolio Diversification 1 2 3
Legend: 3=Best, 2=Middle, 1=Worst

The LTCE run recommends the new resources to be added to the resource portfolio given the RPS requirements. The resource compositions are optimiz ation results from the production cost model’s LTCE run and seek the highest net revenues over the planning horizon. When necessary, staff may modify the new resource build constraints to increase the level of diversification. As an example, staff may limit the MW of solar that can be built, even th ough it is the lowest cost resource to achieve the RPS and GHG emission goals.

Graph 36-38 below show the new resource builds for the different portfolios, as recommended by the LTCE optimization. The legends include all new resource types available for LTCE simulation calculations. The bars represent the resources select ed by the LTCE optimization. By the end of 2042, the Reliability Portfolio builds 575 MW of new resources in total: 225 MW of solar and storage hybrid (2/3 solar and 1/3 storage capacity), 100 MW of solar, and 250 MW of wind. The RNG Portfolio builds 475 MW of new resources: 225 MW of solar and stor age, and 250 MW of wind. The Zero Emission Portfolio builds 775 MW of new resources: 200 MW of stand-alone battery, 100 MW of geothermal, 300 MW of solar and storage hybrid, and 175 of wind. The biomass resource is not built in any portfolio because it has the highest build cost.

Graph 36: New Resource Builds: Reliability Portfolio

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Graph 37: New Resource Builds: RNG Portfolio

Graph 38: New Resource Builds: Zero-Emissions Portfolio

Graph 39 below shows the estimated portfolio diversificat ion for each of the candidate portfolios in 2024. All 3 portfolios are at 95% or above renewabl e and zero emissi ons in 2042. As such, only the renewable portion of the portfolio is shown below.

The Reliability Portfolio retains both natural gas units and requires the least amount of firm renewable resources. The battery storage units and natural gas generation can complement the variability in the renewable portfolio. Therefore, a higher percentage of solar and wind resources are observed. 250
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The RNG portfolio restricted Magnolia Power Plant’s generation to self-scheduled minimum capacity only, due to the high estimated cost of RNG. The self-scheduled RNG generation is categorized under the biofuel category on the renewable pie chart.

Under the Zero-Emissions Portfolio, new geothermal units are built to o ffer firm capacity. The renewable pie chart is the most diversified amongst the three candidate portfolios.

As diversity increases flexibility, reliability, and pe rformance, a higher grading is awarded for higher diversity. The highest diversified portfolio is the Zero-Emissions Portfolio; therefore, it is the preferred portfolio under this category.

Graph 39: New Resource Builds: Zero-Emissions Portfolio

EXPECTED COST
PERFORMANCE MEASURE Reliability RNG Zero-Emissions
Expected Cost 3 1 2
Legend: 3=Best, 2=Middle, 1=Worst

One of APU’s goals is to minimize impacts on cu stomer bills and to serve customers with just and reasonable rates. As such, the total power supply cost for ea ch portfolio is estimated, with lower cost portfolios being awarded a higher rating.

The Reliability Portfolio presents the overall lowest cost while the RNG Portfolio presents the highest costs due to expected high RNG fuel cost. The Zero Emissions Portfolio starts with higher costs to build the new renewable units and to reserve funding for decommissioning costs. However, post 2037, the net cost becomes lower with natural gas unit diversification. Graph 40 demonstrates the annual net power supply cost for each portfolio, and Graph 41 su mmarizes the Net Present Value (NPV) of the three different portfolios in 2023-dollar values.

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Graph 40: Candidate Portfolio Results: Net Power Supply Cost

*Net Power Supply Cost = Total power supply costs net of transmission revenues and wholesale energy revenues

Graph 41: Candidate Portfolio Results: NPV: Net Portfolio Cost

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MARKET EXPOSURE
Graph 42 below displays the estimated market exposure from the candidate portfolios. Market exposure is determined by the percentage of wholesale energy purchases compared to system load. A higher grade is awarded to the portfolios with the least amount of energy purchases required.

Overall, the Reliability Portfolio requires the smallest percentage of wholesale purchases, as both natural gas units are retained to cover short positions when the renewable resources are not available. The Zero Emission Portfolio requires a smaller percentage of wholesale purchase in the initial years, as more renewable resources are layered in earlier in the planning horizon. However, a greater percentage of wholesale purchase is required after the natu ral gas plants are decommissioned in 2037 and 2041. The RNG Portfolio has the highest overall percentage of wholesale purchases, because the high RNG cost makes the Magnolia Power Plant non-economical to dispatch and is priced out of the market except for the self-scheduled minimum capacity burns. At th e same time, fewer other renewables are built as Magnolia is already considered a renewable resource.

Graph 42: Candidate Portfolio Results: Wholesale Energy Purchase as a % of Total Energy Portfolio

SUMMARY
Overall, the Reliability Portfolio performs the best. This portfolio is estimated to have a lower overall power supply cost, offers the highest amount of firm resource capacity, and a declining reliance on natural gas power plants. It also has the least amou nt of Regulatory Risk and Market Exposure. It achieves both the RPS requirements an d emission reductions goals. Wh ile the Reliability Portfolio is the least diversified with a greater percentage of in termittent renewables, the lower cost intermittent resources result in lower overall costs.

The RNG Portfolio, which uses RNG as Magnolia’s sole fuel source starting in 2031, ranks the lowest.

Its cost is the highest due to the high RNG cost and presents the highest re gulatory risk with the uncertainty surrounding RNG’s status as a carbon-fr ee fuel source. The market exposure is also the highest, as Magnolia is priced out of the market most of the time and fewer other renewables are procured. This portfolio meets both RPS requireme nts and emission reductions, with the lowest

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emission amount. In addition, it offers the same am ount of firm resource capacity as the Reliability Portfolio, and its portfolio diversification is ranked in the middle.

The Zero Emissions Portfolio, which exits both natural gas power plants, ra nks in the middle. It presents the highest level of diversification and the lowest level of firm reso urce capacity. Other than diversification and resource adequacy, it ranks in the middle for all other categories.

The following table displays a summary of the performance measure results for each portfolio scenario considered:

PERFORMANCE MEASURE Reliability RNG Zero Emissions
RPS & Emission Reduction Goals 1 3 2
Regulatory Risk 3 1 2
Resource Adequacy 3 3 1
Portfolio Diversification 1 2 3
Expected Cost 3 1 2
Market Exposure 3 1 2
Total 14 11 12

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F. STRESS TESTING
Additional analysis of the candidate portf olios was conducted using stress tests to determine whether the portfolio pe rformance would change under extreme market and load changes. Portfolio simulations were performed for each candidate portfolio to address the following situations.

F.1. COMPONENTS OF THE STRESS TESTS
TEST 1: EXTREME HIGH-COSTS VS. EXTREME LOW-COSTS

A market simulation stress test was conducted by simulating portfolio performance under extreme cost situations. Each case uses the extreme high and low estimates of natural gas prices and the utility-scale renewable growth. In addition, a higher reserve margin of 17% was also added to the extreme high-cost scenario.

GAS PRICE
APU’s power supply portfolio includes resources that use natural gas as a fuel. In addition, resource dispatch and market prices are heavily influenced by gas prices.

Two standard deviations were added to the expected gas price to develop the high gas price scenario.

One standard deviation was deducted from the expected gas price to develop the low gas price scenario.

Standard deviations were calculated using five-year hi storical data of the SoCal Citygate price. Graph 43 shows the gas prices used to stress test the thr ee portfolios. The market volatility has increased significantly since APU’s 2018 IRP evaluation.

Graph 43: Stressed Gas Prices (Partial)

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UTILITY SCALE RENEWABLES GROWTH
In September 2022, the production cost model vendor released the new WECC Zonal database which included a calibrated LTCE database with forecasted resource additions and retirement for the next 20 years. The database forecast is based on the various RPS and carbon emission reduction goals in all WECC States.

The high utility-scale renewables growth scenario wa s developed assuming a 25% increase of all existing LTCE new resources in the production cost model da tabase. The low utility-scale solar growth assumed a 25% decrease from the LTCE new resource builds. Since the database contains proprietary information, a graph is not shown for comparison.

TEST 2: EXTREME HIGH DEMAND VERSUS EXTREME LOW DEMAND
A high demand scenario was developed by applying extremes to the base demand forecast described in Section V.A. Energy Demand Forecast Methodology & Assumptions. Energy efficiency and solar growth effects were removed from the base demand for ecast, and accelerated growth in transportation electrification was applied at 25% above the expected growth.

Similarly, a low demand scenario was also developed by applying extremes to the base demand forecast described in Section V.A. Energy Demand Foreca st - Methodology & Assumptions. Elect ric vehicle growth was reduced by 25%, while energy efficiency and solar growth was increased by 25%.

Once the High Demand and Low Demand scenarios we re calculated, they are further compared to the High Temperature Demand and Low Temperature Demand developed under Chapter VI. Energy Demand and Peak Forecast – Extreme Weather Impact. Staff took the higher of the High Demand or High Temperature Demand as the final extreme high demand scenario. Similarly, staff took the lower of the Low Demand or the Low Temperature Demand as the final extreme low demand scenario.

Graph 44 below also displays the Expected Energy Demand, High Demand, High Temperature Demand, Low Demand and Low Temperature Demand scenarios. As observed in Graph 44 below, for the final extreme high demand scenario, the High Temperature Demand was used for the initial years, followed by the High Demand. For the final extreme low demand scenario, the Low Demand was used for most years, except for a few initial years when the Low Temperature Demand was used.

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Graph 44: Stressed System Load Growth or Reduction (GWh)(Partial)

F.2. MODEL RESULTS UNDER STRESS TESTS
For each portfolio, the model runs performed for the four extreme scenarios are as follows:

1. Extreme high demand scenario: A new LTCE run is completed in case new resources need to be added to provide for the higher energy demand.

2. Extreme low demand scenario, extreme high-cos t scenario, and extreme low-cost scenario: A standard model simulation is completed assuming the resources with long-term agreements cannot be disposed of during the planning horizon.

Four extreme scenarios were run for each of the thre e portfolios. In total, twelve new model runs were conducted to compare the high and low demand, and high and low-cost scenarios.

The following table displays a summary of the performance measure results after stress testing each portfolio scenario.

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The model simulation results held constant for a ll three portfolios under the stress tests, with the Reliability Portfolio performing the best. Below are details of the tests:

Under either stress test of High versus Low Costs or High versus Low Demand, the portfolio scores of the following performance measures stayed th e same: Compliance, Regulatory Risk, Resource Adequacy, Portfolio Diversification, and Market Exposure. The only components that could change are Expected Cost, or the net power supply costs, as detailed below.

Graph 45 below displays the year-over-year simulati on results for each candidate portfolio under these cost extremes. The total portfolio cost for each candidate portfolio with high and lo w-cost scenarios are displayed as lines, and total retail revenue is displayed in columns, at the current retail rate.

The Reliability Portfolio performs extremely well under the extreme low-cost scenario. The cost increases drastically with the high-cost scenario. APU is aware of the portfolio sensitivity to natural gas prices and is in the practice of procuring mid-term and long-term natural gas products to hedge against market price volatility.

The RNG Portfolio presents a very high cost under the extreme low-cost scenario, as the RNG Portfolio has a long-term fixed price contract floati ng against the stable Henry Hub price and not the volatile So Cal City Gate price. On the other hand, because the fixed cost of RNG is not impacted by the natural gas market volatility, it outperforms the Reliability Portfolio in th e last two years of the planning horizon.

The Zero Emissions Portfolio starts out with higher costs as renewables are added earlier in the planning horizon, and as more baseload renewable (geothermal) is added to the portfolio for reliability purposes.

Costs start to decrease after APU exits the natural gas power plants. In 2041 and in 2042, the overall net power supply costs start to converge, because APU is able to sell excess energy at a higher price in the “high cost” environment where insufficient generation is built for the Grid. 2023 Integrated Resource Plan
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Over the 20-year planning horizon, the Reliability Po rtfolio still outperforms the other two portfolios.

Graph 46 displays the Net Present Value (NPV) under extreme cost conditions for all three resource portfolios. The only extreme scenario that outperfo rms the Reliability Portfoli o is the Zero Emission Portfolio under the extreme high-c ost scenario, where its NPV is 0.3% lower than the Reliability Portfolio. When the natural gas price is two standa rd deviations higher than expected through 2042, and the entire WECC’s new resource builds is 25% lower than the policy goals, the total NPV of the Zero Emissions Portfolio is marginally lower than the Reliability Portfolio.

Graph 45: Stress Test Results: Extreme High Costs vs. Extreme Low Costs

Graph 46: Stress Test Results: Portfolio Comparison - Extreme High Costs vs. Extreme Low Costs

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Similarly, stress tests were conducted by simula ting portfolio performance under extreme demand situations. A high demand extreme incorporates assumptions of high temperature or high EV growth, low solar, and low energy efficiency. A low de mand extreme incorporates assumptions of low temperature or low EV growth, high solar, and high energy efficiency. Graph 47 below displays the simulation results for each candidate portfolio under these load growth extremes.

In Graph 47, the total portfolio cost for each ca ndidate portfolio under hi gh and low load growth scenarios are displayed as lines, and total retail revenue is displayed in columns. Estimated retail revenue for the low demand scenario is disp layed as only the dark green colu mn, while estimated retail revenue for the high demand scenario is displayed as the total of the light green columns. The Reliability Portfolio, shown as the green dotted line, performs the best under both demand situations. The RNG Portfolio performs the worst, with expenses being notably high er than the Reliability Po rtfolio. The scaling to retail revenue is intended as a reference to potential rate increases needed to supplement the changing demand scenarios.

Graph 47: Stress Test Results: Extreme High Demand vs. Extreme Low Demand

Graph 48 below illustrates that under the extreme dema nd scenarios, the Reliab ility Portfolio performs the best and offers the lowest overall net power supply cost. The Zero Emissions Portfolio comes in second, and the RNG Portfolio has the highest net power supply cost.

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Graph 48: Stress Test Results: Portfolio Comparison - Extreme High Demand vs. Extreme Low Demand

G. OPTIMUM PORTFOLIO SELECTION
The optimum portfolio selection is the Reliability Portfolio, which keep both the natural gas units for reliability purposes while increa sing renewable energy to serve the retail customers. The Reliability Portfolio performed the best under normal, as well as stress conditions. It meets the RPS and emission reduction goals, provides the highest reliability and the lowest power supply cost, regulatory risk, and market exposure.

ENVIRONMENTAL GOALS AND REGULATORY COMPLIANCE
As shown in Graph 49, the Reliability Portfolio is in compliance with current legislative and regulatory requirements and meets or exceeds renewable goals and GHG emission reduction targets. APU meets the RPS goal of 97% RPS or zero carbon by 2042. In addition, APU system emissions net of EV emissions savings, are below the utility- specific goal of 305,000 MT CO2e by 2035.

Lastly, the Reliability Portfolio presents the le ast regulatory risk, as it best responds to potential changes to the treatment or accounting of renewable natural gas resources, reserve margin or NQC.

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Graph 49: Reliability Portfolio Meets or Exceeds Environmental Goals

RESOURCE ADEQUACY & RELIABILITY

The Reliability Portfolio meets Resource Adequacy r equirements for system, local and flexible capacity requirements. Local and flexible capacity requirement s are presumed to be me t with the Canyon Power Plant. Graph 50 displays the change in system capacity position from 2023 to 2042.

According to the best available information when the model run started in mid-2022, a 40 MW battery project would be added in 2025 and that other new resources would be added starting in 2026. Therefore, a 44 MW capacity short position appears in 2025, when IPP is converted to a natural gas power plant. As of the writing of the 2023 IRP, APU has entered into negotiations with several renewable, hybrid and battery storage providers, and is confident that the short capacity position in 2025 will be covered with long-term resource contracts instead of short-term capacity purchases.

A small amount of capacity purchase is observe d between 2027 and 2030, because LTCE constraints are loosened for flexibility. The model is set up to allow a small capacity gap (25 MW) to be filled by short- term capacity purchases for a few summer months only. When it happens, the capacity purchase costs are added to the net power supply costs.

The majority of APU’s system capacity will be fulfilled by firm capacity units including natural gas power plants, geothermal generation, and landfill gas units. Storage systems are also introduced to fill the capacity gap after IPP divestiture, including a local ba ttery storage system and solar plus storage hybrid resources. A smaller percentage of wind and sola r capacity is introduced la ter in the planning horizon to fill the remainder of the capacity position.

Graph 50 below assumes that solar resources have 25% dependable capacity, wind 30%, and solar plus storage 50%. The solar plus storage resources are set up to pair 1 MW of storage capacity with 2 MW of solar. As an

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example, 75 MW of solar plus storage generation is composed of 25 MW of battery and 50 MW of solar; therefore, it provides 25 MW capacity from the batte ry and 12.5 MW capacity fr om solar, totaling 37.5 MW capacity.

Graph 50: Reliability Portfolio Forecasted Resource Adequacy

DIVERSIFICATION
Graph 51 below displays the changing resource mix under the Reliability Portfolio. The new resources are recommended by the optimization model runs, which honor the RPS constraints and planning reserve margin requirements and seek to meet the environmental and reliability goals while keeping the costs down.

The renewable portfolio percentages continue to increase over the years. It starts out with more geothermal and biofuel resources. As agreements end over time, new resources with lower costs are added to the portfolio:
solar plus storage, solar, and wind.

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Graph 51: Resource Mix for Retail Energy Demand: 2025, 2030, 2035, 2040

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PORTFOLIO COSTS
The change in resource mix has a corresponding impact on the cost structure in future years. Graph 52 below displays the power supply cost structure of the portfolio in 2023 and 2042. The net cost to supply power is estimated to be $126 million higher in 2042 compared to 2023, or a 2.97% average annual increase over the next 20 years. The increase is mainly driven by procurement costs for the resources necessary to meet the State’s carbon-free energy goals and GHG emissions reductions (carbon neutrality by 2045), as well as an increase in scheduling service fees for participation in the CAISO markets.

Graph 52: Reliability Portfolio Power Supply Cost Structure

*Net power supply costs = Total power supply costs net of transmission revenues and wholesale energy revenues

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Overall Net Cost Portfolio
The years 2025 and 2026 show a jump in net costs due to the new debt service for the IPP gas unit and the STS transmission line upgrade. APU will no longer be responsible for the debt service after IPP divestiture. A steady cost increase is observed throug hout the remainder of the planning horizon, except for when debt service drops off in 2036 and 2040, or when a renewable resource starts or ends during a certain year.

Renewables vs. Thermal Resource Costs
As more renewable energy sources are being included in the portfolio, the cost of renewable energy is expected to increase by $93 million. Conversely, the di vestiture in fossil fuel resources results in a cost savings totaling $38 million.

The total energy cost will increase over the pla nning horizon. New renewable build cost has been increasing due to inflation, labor shortage and supply chain issues. In addition, the natural gas units have a higher fixed cost component relative to the rene wable resources. With more renewable generation and no proportionate decrease in natural gas unit costs, the overall portfolio cost will increase.

Wholesale Sales and Purchases
Immediately after IPP divestiture, wholesale sales decreased noticeably while wholesale purchase increased at the same time. Wholesale sales remain at the lowe r level for the remainder of the planning horizon.

Wholesale purchases show a slight increase of $8 million, a combined effect of lower MWh purchases and higher energy market prices.

Transmission and Scheduling Services
The CAISO scheduling services costs are expected to be $23 million higher in 2042 compared to 2023.

These charges consist of CAISO tran smission access charges (TAC), gr id management fees, congestion, losses, ancillary services, and other energy charges. Capacity purchases to meet the Resource Adequacy requirements are also included here.

Of all CAISO charges considered, the TAC has the highes t rate of increase, as California strengthens the existing transmission facilities to prevent wildfi res and builds new transmission lines to interconnect additional renewables at an unprecedented rate. According to the 2021-2022 Transmission Access Charge Forecast Model29, CAISO expects a cumulative 30.5% TAC rate increase between 2023 and 2030, and a cumulative 2.4% rate increase between 2031 and 2036. APU’s transmission cost model adopts CAISO published data of TAC rates of $17.0188 to $21.9406 from 2023 to 2036, and assumes that beyond 2037, the TAC rate grows at the average annual growth rate between 2031 and 2036.

The TAC increase is offset by the $15 million tran smission expense reduction from the NTS and STS lines when APU exits the IPP power plant. The combined effect of increased CAISO scheduling services costs and reductions in transmission expenses yields an increase of $8M from 2023 to 2042.

29 2021-2022 Transmission Access Charge Forecast Model with New Capital (9/23/2022 14:44), http://www.caiso.com/planning/Pages/TransmissionPlanning/Default.aspx 2023 Integrated Resource Plan
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MARKET EXPOSURE
The Reliability Portfolio has the be st overall performance under stress testing. It also has the lowest market exposure, measured by wholesale purchases as a percentage of system load. During high energy prices, natural gas units are dispatched to serve not only the retail customer but also the CAISO market.

The CAISO market dispatch brings in additional wholesale revenues that bring down the net power supply costs.

Stand-alone battery storage also mitigates price vola tility. It charges during hours of low costs and discharges during hours of high costs, lowering th e costs to serve energy. Similarly, the solar plus storage hybrid resources stores so lar generation in the midday, when both the energy demand market prices are lower. It discharges solar generation during the late afternoon and early evening, when both the energy demand and market prices are higher.

CONCLUSION
Since the introduction of the RPS standard, the en ergy market has gone through significant changes over the past decade. On the demand side, the energy demand becomes less predictable due to weather pattern changes and regulations promoting electrification. On the supply side, the resource costs become less predictable due to inflation, labor sh ortage and system-wide additions and retirements.

Over-generation was a key concern not too long ago; whereas, insufficient resources have become the key concern today and these changes are expected to continue, and likely at a more rapid rate.

The Reliability Portfolio is the optimal portfolio selected for the 2023 IRP. It meets the overall resource planning goals of affordability, re liability, and sustainability. APU is keenly aware of the need to allow flexibility to quickly respond to changing market conditions and will make adjustments to the Reliability Portfolio, as necessary, going forward.

It is important to note that the IRP process is looking to compare differences among various approaches for the long-term outlook, and not to de termine the absolute values for each approach.

Indeed, with a multitude of variables involved in a 20-year long-term analysis, actual market conditions may change very quickly after the conclusion of the 2023 IRP analysis. To name a few, these market conditions include inflation, natural gas prices, re newable resource costs and availability, timing of transmission and generation additions, and retirements within the WECC, etc.

APU works collaboratively with SCPPA members, neighboring utilities, and regional planning authorities (e.g., Southern California Association of Governments), and frequently reviews planning and forecast data from regulatory agencies. APU’s resource planning data along with its fiscal impact is updated annually as part of the City’s budget process and is reported to, recommended for approval, and approved by the Public Utilities Board and the City Council.

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H. RATE IMPACT

ANAHEIM ELECTRIC RATES
APU strives to find resources that are cost-effective and minimize rate impacts to customers while still meeting its compliance obligations for increased renewables and lower GHG emissions. By responsibly divesting of its coal assets and utilizing its peakin g resources to integrate more renewable purchases, APU has been able to maintain affordable electric ra tes. The selected Reliability Portfolio is expected to help APU maintain affordable electric rates over the planning period as net power supply costs are expected to increase by only 2.97% per year, on average, which is less than the five-year average inflation rate.

APU strives to provide affordable rates to its cus tomer-owners. Consistent with state and federal mandates, Section 1221 of the Anaheim City Charter requires that electric rates be based on the cost- of-service requirements for each customer class. The Anaheim City Council has adopted electric rates in accordance with this requir ement, and additional Charter requ irements that electric rates be sufficient to pay for all costs necessary to provid e electric service to Anaheim customers, including maintenance, operations, power supply, and infrastructure-related investment costs. APU has designed its rate schedules to not only recover these costs, but also to maintain simp licity in how rates and resulting bills are read, and to se nd pricing signals encouraging red uced consumption of electricity or shifting consumption to different parts of the day when power resources are more available and less expensive. As a publicly owned utility, APU offers several optional and standard base rate options to its customers, allowing them to choose a rate schedu le that is advantageous and most fitting for their needs. These base rates are listed below.

STANDARD BASE ELECTRIC RATES
• Domestic Service (residential)
• Small Commercial
• Medium Commercial
• Large Commercial / Industrial
• Agricultural
• Lighting
• Municipal

OPTIONAL BASE ELECTRIC RATES
• Thermal Energy Storage
• Feed-In Tariff
• Economic Development / Business Retention
• Domestic Time-of-Use
• Commercial Time-of-Use
• Industrial Time-of-Use
• Net Energy Metering
• Domestic Electric Vehicle
• Commercial / Industrial Electric Vehicle

APU’s rate structure includes a fixed customer charge, energy charges, a rate stabilization adjustment (RSA), and an underground surcharge that pays for undergrounding of overhead power lines to improve reliability and beautify the City. Rates for each customer class include these components, while medium and large commercial and industrial rates include a demand charge as well. Additionally, time- 2023 Integrated Resource Plan
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of-use rates include higher rates during on-peak time periods when the demand for energy is high and lower rates during mid-peak and off-peak time periods when the demand for energy is lower. Generally, all costs of APU’s Electric System, including power supply costs, are recovered through the application of these base rates, while the RSA recovers fluc tuations in power generation, fuel, environmental mitigation, and other power-related costs, facilitating timely cost recovery while keeping customer rates stable over time.

Most recently, APU added a commercial electric vehicle (EV) rate customer class to encourage further adoption of electric transit buses, school buses, delivery vehicles, and other fleet vehicles within the City, with this effort enhancing the City’s economic justice efforts by encouraging public transportation agencies to invest in EV fleets that serve a broad array of demographics with in the City. In addition, although APU fulfilled the State’s requirements pertai ning to net energy metering rate incentives in May 2019, APU implemented a new program in March 2020 to offer a net energy metering rate option for more solar customers that better aligns with the cost of providing electric service.

RATE AFFORDABILITY & COMPETITIVENESS

One of APU’s key tenants is maintaining affordable rates.

To that end, APU continuous ly monitors how the cost
to provide electric service impacts customer bills over time. APU performs rate comparisons throughout the
year. As the only publicly owned utility providing power in Orange County, APU compares its rates to the two
investor-owned utilities, Southern California Edison
(SCE) and San Diego Gas & Electric (SDG&E), who
provide power to other customers in the county. G
raph
53 30 shows that an average Anaheim residential
customer (using 500 kWh monthly) pays at least 39% less than customers served by another utility in the county. Anaheim also does not impose a utility user’s tax, which increases the bill total for customers in other cities.

APU’s affordability ratio, a measure of the total annual energy costs paid by a typical residential customer using 500 kWh monthly relative to the city’s median income
31 , is
approximately 1.4%. Historically, APU has maintained this ratio at low levels, indicative of how electric rates remain affordable for customers. Compared to other electric
utilities serving Orange County 32 , this ratio compares

30 Graph is current as of March 2023, and includes all applicable taxes and surcharges on a residential customer’s bill.

31 Median household income taken from most recent U.S. census data.

32 To make an appropriate comparison, SCE household income was calculated using Orange County median household income data, which is considerably higher than Anaheim. SDG&E household income was calculated using San Diego median household income.

$94.60
$155.53
$237.44
Anaheim SCE SDG&E
Monthly Residential Electric
Bills
(Based on 500 kWh)

1.4%

1.9%

3.1%
Anaheim SCE SDG&E
Affordability: Residential Electric
Bill
as % of Median Household Income
Graph 53: Monthly Avg Residential Electric Bills
Graph 54: Residential Electric Bill as % of
Median Household Income
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favorably. For those customers struggling to pay th eir bills, APU helps them through bill deferrals, payment plans, income-qualified discounts, medical allowances, and fee waivers. APU offers a 10% bill discount for customers who are 62 years of age or older, have a long-term disability, or are military veterans, and who meet income guidelines based on the size of their household and yearly household income.

Another rate comparison is the system average rate 33,
which divides the total sale s revenue from all retail
customers by total volumetric sales from those same
customers. Graph 55 shows that, on average, Anaheim
customers pay nearly 30% less per kWh than
customers served by other utilities in the county. To be fair, each of the utilities shown in the chart face
different risks in serving their respective service
territories. Nonetheless, al l of the comparison charts taken together demonstrate how APU’s rates remain
affordable and competitive relative to the other electric utilities who serve the remainder of the county.

COST IMPACT OF RELIABILITY PORTFOLIO
APU performed cost impact analyses under high, medium, and low load growth scenarios to determine the potential cost impact of various changes in regulatory requirements and resulting impacts on power supply costs. For the purposes of the 2023 IRP, the different scenarios under evaluation were overlaid onto existing forecasts of net power supply costs. Cost impacts reflected in the 2023 IRP are calculated on a system-wide basis. Please note the following information on the methodology and assumptions of the study.

 The high energy consumption scenario adopts th e higher of the two following scenarios: (1) same EE, solar and EV assumptions as the expected scenario, but under extremely high temperatures, or (2) high EV growth, low EE growth, and low local solar, under moderate weather conditions. For the majority of the planning horizon, the high energy consumption scenario is impacted by extremely high temper atures. Additionally, note that the high energy consumption scenario will result in a lower average cost of power because these costs are recovered over a greater number of billing units.
 The low energy consumption scenario adopts th e lower of the two following scenarios: (1) same EE, solar and EV assumptions as the expected scenario, but under extremely low temperatures, or (2) low EV growth, high EE gr owth, and high local solar, under moderate weather conditions. For the majority of the pl anning horizon, the low energy consumption scenario is impacted by the low EV/high EE /high solar assumptions. The low consumption scenario will result in a higher average cost of power because there are fewer billing units to allocate these costs to.

33 APU’s system average rate was calculated based on actuals from the most recent fiscal year ending June 30, 2022.

18.05¢

25.20¢

28.60¢
Anaheim SCE SDG&E
System Average Rate
(cents per kWh)
Graph 55: System Average Rate
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 The expected consumption scenario assumes moderate weather conditions.  For additional context, the average cost of power for FY 2022 was 12.59 cents per kWh and APU forecasts FY 2023 will be at 12.91 cents per kWh.

The results of this evaluation principally reflect
how the projected cost impacts to customers
is relatively modest , even under the low
consumption scenario where the average cost
of power peaks at approximately 14 cents per
kWh in FY 2027; under this scenario, the
average cost of power increases modestly at a
compound annual rate
34 of 2.37% over five
years to reach this hypothetical peak. As
shown in the chart, the average cost of power
is forecast to dip thereafter, as Anaheim will
exit from a fossil-fuel generated resource and
no longer be subject to the associated cost
obligations.

This analysis was based on forward-looking
assumptions and is subject to change due to commodity price fluctuations, policy changes, technological developments, and/or changing customer behavior. APU will continue to update its long- term plan as expectations change in order to maintain accurate forecasts. While the model used for the 2023 IRP analysis was based on information available at a single point in time, it is not uncommon for assumptions to change over time as additional information is made available.

34 This is calculated using the geometric mean or compound annual growth rate over five years. ¢
2¢
4¢
6¢
8¢
10¢
12¢
14¢
16¢
2024 2025 2026 2027 2028 2029 2030
Average Cost of Power (¢/kWh)
High Consumption Scenario Expected Consumption Scenario Low Consumption Scenario
Graph 56: Average Cost of Power (cents per kWh)
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VIII. RELIABILITY & ELEC TRIC SYSTEM OVERVIEW
This section starts with an introduction to APU’s Electric System (A.

APU Electric System Overview ) and generation and transmission resources (B. Generation and Transmission Resources).

PUC Section 9621 requires POUs to adopt an IRP to ensure that the POU meets the goal of ensuring system and local reliability. APU’s Balancing Authority is the CAISO, which has reliability and Resource Adequacy requirements for load serving entities. Section C. CAISO Resource Adequacy Requirements discusses how APU plans to meet the CAISO system, local and flexible capacity requirements during the 2023 IRP’s planning horizon.

PUC Section 9621 also requires POUs to adopt an IRP to ensure POUs achieve the goal of strengthening the diversity, sustainability, and resilience of the bulk transmission and distribution systems and local communities.

APU has several transmission contracts through Southern California Public Power Authority (SCPPA) and with the Los Angeles Department of Water and Power (LADWP) to ensure the energy from APU’s owned or contracted resources is consistently delivered into the CAISO from reso urces located outside of the CAISO footprint. On October 10, 2006, APU transferred operational control of its transmission resources to CAISO.

According to the North American Elect ric Reliability Corporation (NERC) reliability standards, APU is a Distribution Provider (DP), but not a Transmission Operator (TOP), Transmission Owner (TO), Transmission Planner (TP), Transmission Service Provider (TSP), Generator Owner (GO), or Generator Operator (GOP).

As such, the CAISO is responsible for evaluating the re gional short-term and long-term infrastructure needs during its annual Transmission Planning Process.

APU has a long-standing reputation for providing its customers with highly reliable electric distribution services over a robust and well-maintained electric distribution system. In 2020, the American Public Power Association recognized APU, once again, as a Reliable Public Power Provider (RP3). The RP3 designation lasts three years and recognizes utilities that demonstr ate high proficiency in reliability, safety, work force development, and system improvement. Of the 2,000 public power utilities nation ‐wide, only 275 hold the RP3 designation. APU’s distribution system and reliability considerations are described in section D. Distribution System Overview.

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A. APU ELECTRIC SYSTEM OVERVIEW
The City of Anaheim is the second largest city in Orange County and tenth largest city in California. It is best known as the home to the Disneyland® Resort, Honda Center, and the Anaheim Convention Center.

APU is a City-owned, not-for-profit electric and water ut ility that offers quality electric and water services to residents and businesses in Anaheim at rates among the lowest in California. It operates the only municipal electric utility in Orange County. That means that the customers of the Anaheim community own their utility, and therefore, have a say in decisions concerning its operation.

Anaheim citizens are more than just utilities customers; they are owners of their utility. They have input to the decision process both direct ly and through an appointed citizen adviso ry Public Utilities Board. With final authority vested in Anaheim’s elected City Council, decisions are made that are in the best interest of its citizens, quality of life, and local economy. As a municipal, not-for-profit utilit y, APU’s rates are based on the costs of providing water and electricity.

APU’s system delivers electricity to Anaheim’s 350,000 residents and more than 15,000 businesses, including multimillion-dollar tourism, sports, and manufacturing customers.

Although residential customers make up approximately 85% of APU’s total customers, nearly 75% of total electrical load is consumed by commercial and industrial customers. APU experiences seasonal trends in which the summer months experience higher loads due to cooling needs, while the rest of the year tends to remain fairly stable.

Graph 57: Customer Class Data

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B. GENERATION AND TRANSMISSION RESOURCES
APU’s power supply comes from resour ces located in Anaheim and across the western United States. This section introduces APU’s long-term generation and transmission resources.

GENERATION RESOURCES

BOWERMAN POWER

FACILITY
APU executed a Power Purchase
Agreement with Bowerman Power,
LLC for the purchase of 19.6 MW
of renewable energy generated
from landfill gas from the Frank R.

Bowerman Landfill in Irvine,
California.

Transmission is provided by the
CAISO. The 20-year contract
expires on April 30, 2036.

BREA POWER II
APU executed a Consolidated, Amended,
and Restated Power Purchase Agreement
with Brea Generation LLC and Brea Power
Partners II, LLC to deliver landfill gas
renewable energy to APU to help satisfy
demand.

The original 5 MW contract was superseded
by a second long-term contract for a total of
27 MW from the new unit at the Olinda
Landfill project. The 33-year contract expires on October 31, 2045.

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DESERT HARVEST
The Cities of Anaheim, Burbank, and Vernon have contracted with Desert Harvest II, LLC, through SCPPA for a share of intermittent solar energy from the Desert Harvest project.

APU’s share is 36 MW. Transmission is provided by the CAISO.

The 25-year contract expires on November 30, 2045.

THERMO NO. 1
APU executed a Power
Purchase Agreement with this
resource for energy from an 11
MW geothermal project. The
project is located in central
Utah and energy is being
delivered over the Northern
Transmission System at the
Mona interconnection tie in
the Los Angeles Department
of Water and Power
(LADWP) control area.

Additional transmission costs are required to get th e energy delivered from Thermo No. 1 to the Mona interconnection point. This 20-year agreement expires on September 30, 2033.

HIGH WINDS ENERGY CENTER
APU purchased 6 MW of intermittent renewable
wind energy from Avangrid Renewables, LLC (a
subsidiary of Iberdrola USA, Inc.). Transmission
is provided by the CAISO.

The contract includes mutual termination rights
at year 20 provided notice is given on or before
December 31, 2022. Notice was given and the
agreement expires on December 31, 2023.

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PLEASANT VALLEY ENERGY CENTER
APU has purchased 30 MW of intermittent
renewable wind energy from Avangrid
Renewables, LLC (a subsidiary of Iberdrola
USA, Inc.). Energy from the Pleasant Valley
Wind Energy Center is delivered through the
Northern Transmission System at the Mona
interconnection tie into the LADWP control
area.

APU receives and pays for energy only when the
units are operating. The 20-year contract expires
on June 30, 2025.

SAN GORGONIO WIND FARM
APU executed a Power Purchase Agreement with
San Gorgonio Farms, Inc. for 31 MW of
intermittent renewable wind energy from the
existing San Gorgonio Farms Wind Farm located
in Whitewater, California (near Palm Springs).

Transmission is provided by the CAISO. This
agreement has an initial term of ten years ending
December 31, 2023, with an option to extend for
two additional 10-year periods. The parties
exercised the option for a 10-year extension of the
agreement which extends the term through December 31, 2033.

WESTSIDE SOLAR PARK
APU executed a Power Purchase
Agreement with Westside Assets, LLC
for the purchase of 2 MW of renewable
intermittent solar energy. This project
is located in Kings County, California.

Transmission is provided by the
CAISO. This 25-year contract expires
on June 30, 2041.

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MWD COYOTE CREEK, PERRIS, RIO HONDO AND VALLEY VIEW
The Cities of Anaheim, Azusa, and
Colton have contracted with The
Metropolitan Water District of Southern
California (MWD), through SCPPA, for

17.1 MW of intermittent renewable
hydro electricity from four small
hydroelectric plants located in the Los
Angeles Basin. APU is entitled to 56.5%
of the project’s output, or 9.7 MW from
all four plants. Transmission is provided
by the CAISO. The 15-year, 2-month
contract expires on December 31, 2023.

HOOVER DAM
The Boulder Canyon Project (Hoover Dam)
consists of 17 hydroelectric generating units
located approximately 25 miles from Las
Vegas, Nevada. Forty-s ix (46) participants
within the states of Arizona, California, and
Nevada participate in the Hoover Dam
project. SCPPA members have obtained
entitlements totaling 665 MW (32% of the
Plant Capacity, of which APU has 1.9477%)
through its Power Sales Agreements with SCPPA.

The new Electric Service Contract with Boulder Canyon expires on September 30, 2067.

CANYON POWER PROJECT
The Canyon Power Project
(CPP) is a conventional simple
cycle, natural gas-fired peaking
facility comprised of four
combustion turbine generators
located in the Canyon industrial
area of Anaheim. CPP is owned
by SCPPA and operated by
APU who has 100% entitlement
to the 200 MW nameplate
capacity and energy thought a
Power Sales Agreement with

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SCPPA. CPP provides enhanced local reliability and is dispatched when it s generation costs are less than the cost to serve APU’s load.

MAGNOLIA POWER PROJECT
The Magnolia Power Project (MPP) is
a clean, natural gas-fired, combined
cycle conventional electric generating
plant located in Burbank, California.

MPP is owned by SCPPA and
operated by Burbank Water & Power.

APU has a 38% (92 MW base capacity
and 26 MW of peaking capacity)
entitlement in the project through a
Power Sales Agreement with SCPPA.

INTERMOUNTAIN POWER

PLANT (IPP)
APU executed into a Power Sales Agreement
with Intermountain Power Agency (IPP) in the
early 1980s for 13.225% of the energy output
from IPP. Thirty-six utilities serving California
and Utah receive capacity and energy from this
project. Energy is delivered to Anaheim and
other California participants through the
Southern Transmission System (STS) to the
Victorville/Lugo interconnection with the
CAISO. Upon the conversion of IPP to natural
gas in 2025, APU will take energy from the
natural gas plant until June 17, 2027, when the
original 40-year contract expires.

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TRANSMISSION RESOURCES

MEAD-ADELANTO TRANSMISSION PROJECT
APU entered into a transmission service contract with
SCPPA to acquire transmission capacity from the
Mead-Adelanto Transmission Project to bring in
energy from Nevada based projects.

A 202-mile, 500 kV AC transmission line that runs
from the Marketplace Substation near Boulder City,
Nevada to the Adelanto Substation near Victorville,
California. The transmission line has a transfer
capability of 1,291 MW; APU’s share is 159 MW.

MEAD-PHOENIX TRANSMISSION

PROJECT
APU entered into a transmission service contract with
SCPPA to acquire transmission transfer capacity from
the Mead-Phoenix Transmission Project.

A 256-mile, 500 kV AC transmission line that extends
from the Westwing Substation near Phoenix, AZ,
connects with the Mead substation near Boulder City,
NV, and terminates at the Marketplace Substation
nearby. The transmission line has a transfer capability of 1,923 MW, APU’s share is 155 MW.

NORTHERN TRANSMISSION SYSTEM (NTS)
APU entered into a transmission service contract with LADWP to acquire a share of LADWP’s transfer capability of the Northern Transmission System (NTS) to bring power from the Intermountain Power Plant (IPP) in Utah to the Mona substation in Utah and the Gonder substation in Nevada.

A 490-mile, 500 kV DC transmission line that extends fr om IPP near Delta, Utah to the Adelanto Substation in Southern California, with an AC/DC converter station at each end of the transmission line. The transmission line has a transfer capability of 2,400 MW, APU’s share is 257 MW.

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SOUTHERN TRANSMISSION SYSTEM
(STS)
APU entered into a transmission service contract with
SCPPA to acquire transfer capability of the Southern
Transmission System (STS) to bring power from the
Intermountain Power Project (IPP) near Delta, Utah
to the Adelanto Substation in Southern California.

A 490-mile, 500 kV DC transmission line that extends
from IPP near Delta, Utah to the Adelanto Substation
in Southern California, with an AC/DC converter
station at each end of the transmission line. The
transmission line has a transfer capability of 2,400 MW, APU’s share is 424 MW.

ADELANTO-VICTORVILLE/LUGO TRANSMISSION SYSTEM
APU entered into a firm bi-directional transmission
service contract with LADWP to bring power between
the Adelanto and Victorville Substations and the
Lugo/Victorville line near Victorville, California to
Anaheim.

The approximately 23-mile, 500 kV AC transmission
line extends between the Adelanto and Victorville
Substations and the midpoint of the Lugo/Victorville
500 kV line. The transmissi on line has a transfer
capacity of 2,400 MW; APU’s share is 110 MW.

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C. CAISO RESOURCE AD EQUACY REQUIREMENTS
C.1. SYSTEM RESOURCE ADEQUACY
The consequences of the California energy crisis from 2000 to 2001 highlighted several fundamental flaws in California’s existing electricity market design soon after the partial deregulation of the electric market. Key issues were identified such as the lack of long-t erm contracting between the unbundled generation and distribution sectors, and the over-reliance on spot market transactions as major causes for the market disruptions impeding system reliability. Immediately after the energy crisis, the CAISO began addressing underlying infrastructure challenges such as transmission and generation deficiencies and began a comprehensive market redesign and technology upgrade (MRTU) program upon the Federal Energy Regulatory Commission’s (FERC) approval.

State regulators implemented a Resource Adequacy (RA) obligation in 2004 requiring Load Serving Entities (LSE), such as APU, to procure capacity resources for 100% of their total forecasted customer load, as well as an additional 15% Planning Reserve Margin (PRM), for a total of 115% to ensure adequate energy resources are available when needed. This requirement is known as the “system” RA requirement.

APU uses a mix of its owned and contracted resources to meet the system RA obligations. These resources include both renewable and conventional generation within the State and imported into the State from various regions. The optimum portfolio, Reliability Portfolio, requires small capacity purchases between 2027 and 2031.

It meets the system capacity requirement with the current CAISO resource adequacy accounting rules from 2023 to 2042. The cost of capacity contracts is included in the power supply cost evaluation.

Graph 58: Reliability Portfolio Forecasted Resource Adequacy

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C.2. LOCAL RESOURCE ADEQUACY
In addition to the overall system RA requirement, the CAISO also requires that a certain amount of a LSE’s RA obligation must meet criteria known as “local” and “flexible” RA requirements. The local RA requirement addresses reliability concerns within transmission-constrained areas wh ere local generation resources are needed to ensure reliable electric grid operations to serve the area.

Under the CAISO Local Capacity Requirement (LCR) pr ogram, CAISO completes an LCR study each year using the most up-to-date information available for transmission system configuration, generation tied to the grid, and load forecasts approved by the CEC. The CA ISO uses the annual LCR Study results as a basis for establishing each LSEs proportionate share of LCR for RA purposes.

The CAISO identifies 10 transmission-constrained local pockets. APU is in the local area defined as the LA Basin Area. Results from the 2023 Local Capacity Technical Analysis issued by the CAISO on April 28, 2022, assigned a LCR of 192.31 MW for APU within the LA Basin Area.

The CAISO local capacity requirement for APU has been below 230 MW for the past few years and remained stable. Currently, APU has over 255 MW of natural gas and baseload rene wable power plants located within the LA Basin Area. During the planning horizon of the 2023 IRP, APU has sufficient local resources that exceed CAISO’s local capacity requirements under the recommended Reliability Portfolio.

Graph 59: CAISO Local Capacity Requirement – Reliability and RNG Portfolios

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C.3. FLEXIBLE CAPACITY RESOURCE ADEQUACY
The last component of RA procurement addresses the need to have generation resources available that can respond quickly to “up” and “down” electrical demand on the Grid. To meet energy demand at certain times of the day when the CAISO must respond quickly to variations in load, LSEs are required to procure a certain amount of its RA obligation from resources defined as “flexible” in the CAISO tariff.

Similar to the LCR process, the CAISO performs annually a system wide assessment of flexible capacity needs using a Monthly Maximum Three-Hour Net Load Ramp pl us the higher of the most severe single largest contingency or 3.5% of expected pe ak load to determine the required procurement target for each LSE. The net load curves represent the variable demand that the CAISO must meet in real-time. In order to maintain reliability, the CAISO must match the demand for electricity with the supply on a second-by-second basis using the remaining dispatchable generation fleet. To ensure reliability under the changing conditions seen on the Grid, the CAISO requires flexible resources with operational characteristics as follows:
 Ability to sustain upward and downward ramps;
 Respond for a defined period of time, change ramping direction quickly;  React quickly and meet expected operating levels;
 Start with short notice from zero or low electric operating level; and  Start and stop multiple times per day.

To satisfy the CAISO’s procurement target for flexible capacity, APU typically utilizes the Canyon Power Plant.

This resource is not only local to APU’s load but has the ability to start at a moment’s notice to ramp up or down as needed throughout the day providing 194 MW of eligible flexible capacity.

On average, APU has a monthly flexible capacity requi rement of 17 MW, which peaks in May with a capacity requirement of around 20 MW.

As Canyon Power Plant has 194 MW of eligible flexible capacity, APU has sufficient flexible capacity available through Canyon to meet the additional requirements for flexible capacity. Even though the optimum portfolio, Reliability Portfolio, adds intermittent renewables and may require higher flexible capacity later in the planning horizon, the Canyon Power Plant provides more than sufficient flexible capacity to accommodate the additional intermittent resources.

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Graph 60: CAISO Flexible Capacity Requirement – Reliability and RNG Portfolios

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D. DISTRIBUTION SYSTEM OVERVIEW
D.1. DISTRIBUTION SYSTEM
D.1.1. Electric System Overview
APU delivers electricity to its approximately 350,000 residents and more than 15,000 businesses, including but not limited to the Anaheim Resort Area, Platinum Triang le, sports arena, Honda Center, City National Grove of Anaheim. APU serves about 120,000 electric meters throughout its 50 square mile service area.

The APU electric system is a carefully planned and robust system. It consists of a 69 kV radial network serving thirteen 69/12 kV distribution substations, where reliable power is transformed and distributed to homes and businesses, with a total combined historic peak demand of approximately 600 MW. APU has emergency procedures and redundancy built into its system to address the unlikely ev ent of a catastrophic failure of a substation.

D.1.2. Distribution System
APU’s distribution system includes approximately 120 distribution circuits fed by fourteen distribution substations across 50 square miles. It provides high qua lity and reliable power service to its customers. The system is evaluated thoroughly on an annual basis to en sure it can meet forecasted peak demand in the five- year planning horizon, as well as maintain and improve its reliability performance under normal and emergency conditions. To achieve these goals, APU has upgraded and reinforced its electrical infrastructures with various on-going programs, and capital projects.

The new Harbor 69/12kV Substation was the latest electrical facility addition to the APU’s electric system and was placed in service in the summer of 2019. Th is substation was needed to serve new hotels and residential/commercial units as well as planned future developments in the Platin um Triangle and Anaheim Resort areas. This project added needed transformer capacity in this fast-growing area and provide loading relief to the adjacent substations. It has also greatly improved system reliability in the area. Photo 1 below shows the Harbor Substation.

In addition, a new 69/12kV transformer bank was constructed and placed in service in 2019. Similarly, this project was needed to accommodate new industrial and commercial loads in the Eastern Anaheim area. It has provided loading relief to adjacent substations and improves system reliability in the area.

APU is currently in the planning stages of upgrading the 12kV switchgears to higher ampacity rating at two of the substations located in the northern and southwest areas of Anaheim. Each is expected to be completed in the 2023-2026 timeframe. These projects are considered infrastructure replacem ent projects as they are approaching their full life expectancies and are needed to serve increased load growth in the area. These facilities will also improve the system reliability and provide operational flexibility. 2023 Integrated Resource Plan
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Photo 1: Harbor 69/12kV Substation

D.1.3. Recent Reliability Projects
In 2008, APU upgraded its electrical infrastructure
to increase system reliability by constructing the
Vermont 220/69 kV Substation which is radially
fed from Lewis Substation, normally opened at
Lewis terminal. A major 69kV network in the
affected area was reconfigured and about 4,500
circuit feet were also undergrounded. The new
Vermont Substation was built to serve as a back-
up source for Anaheim load in the event of a total
loss of the Lewis 69/12 kV Substation. Photo 2
shows Vermont 220 kV GIS switchgear.

In 2006, APU accomplished a first-of-its-kind in
the United States when it constructed an electric
substation with gas insulated switchgear (GIS) and
with the capacity to provide power to 25,000
residential customers unde rneath a park. This
project also improves system reliability in the east
of Anaheim system. Photo 3 below shows Park
Substation underneath the park.

Photo 2: Vermont 220kV GIS Switchgear
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Photo 3: Park Substation
In addition, Anaheim operates one gas-fired generating plant, Canyon Power Plant wi thin its service territory with a total combined capacity of about 200 MW. This generating resource is used to offset power imported from outside resources during peak load periods and has black start capability to serve APU load independent of the Grid in the event of a
sustained regional blackout. Canyon
Power Plant was built in 2011. The
facility received silver LEED
certification by utilizing systems that
limit environmental impacts; these
systems are using 100% recycled
water and powering the control
room with solar energy. The plant
produces enough energy to power
150,000 residential customers
annually. Photo 4 shows Canyon
Power Plant.

Photo 4: Canyon Power Plant
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D.1.4. Underground Conversion Program
In 1991, Anaheim City Council established the Underg round Conversion Program to improve reliability and aesthetics along the City’s major streets by removing overhead power, phone, and cable TV lines. Anaheim residents and businesses benefit from improved reliab ility of the electric system. As of today, APU has converted approximately 780 underground circuit miles or 65% of its existing overhead circuits. Photo 5 shows the before and after images of one of the underground projects.

Photo 5: Before and After Underground Project

D.1.5. Distributed Generation
In 2014 APU completed, at the time of
installation, the largest city-owned
convention center roof-mounted system in
North America. This 2.4 MW solar plant
can generate enough energy to support
approximately 600 homes a year. Photo 6
shows the 2.4 MW Anaheim Solar Energy
Plant at the Convention Center.

Approximately 47 MW of rooftop solar
generation is installed throughout the
Anaheim system. To date, there are little
to no impacts to the distribution network
resulting from these installations, which are
relatively small in size and not concentrated in one area, but rather scattered throughout the system.

Similarly, APU has not experienced nor expects any significant impacts to the distribution network due to transportation electrification efforts since the Electric Vehicle Supply Equipment (EVSE) have not been concentrated in one area or on a specific circuit at this point in time.

Photo 6: The 2.4 MW Anaheim Solar Energy Plant at Convention Center

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APU continues to monitor potential impact from distributed generation and from electric vehicle charging stations and will make necessary infrastructure investments to maintain syst em reliability and resiliency. As an example, APU evaluates commercial customers’ plans to install charging stations, and will upgrade local transformers when multiple charging stations are planned to be installed in a concentrated area.

D.2 SYSTEM RELIABILITY
APU provides high quality electric service to approximately 120,000 metered residential and business customers through a modern and well-maintained distribution network.

In 2019, the American Public Power Association recognized APU once again as a Reliable Public Power Provider (RP3).

The RP3 designation lasts three years and recognizes utilities that demonstrate high proficiency in reliability, safety, work force development, and system improvement. Of the 2,000 public power utilities nation‐ wide, only 235 hold the RP3 designation.

Performance metrics are regularly utilized to measure outage duration, number and type of outage events, as well as
restoration time. Electric reliability is measured by recording how many times service is interrupted (System Average
Interruption Frequency Index or SAIFI), how long th e average customer is interrupted (System Average Duration Index or SAIDI), and how long it takes to re store service once a customer is interrupted (Customer Average Interruption Duration Index or CAIDI). These three measures of reliability have been standardized and are recognized by the electric industry as best practices fo r comparing reliability performance among utilities. Below is a graph showing Anaheim’s reliability perf ormance in terms of SAIDI, SAIFI, and CAIDI since 1990.

Graph 61: Anaheim’s Reliability Performance in Terms of SAIDI, SAIFI, and CAIDI Since 1990

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Many factors that affect service reliability are beyond APU’s control, such as wind, vehicles hitting power poles, earthquakes, etc. However, other factors are controllabl e, such as maintaining equipment in good operating order by continually monitoring and inspecting the system, tightening connectors, cleaning dirt from insulators, detecting and replacing damaged or aging components before they fail, and systematically replacing equipment nearing the end of its useful life.

APU is continually working to improve its electric distribution system. For example, APU has installed a significant number of remotely controlled field switchin g to improve outage restoration times, in conjunction with a program to remove old direct-buried cable from the system and replacing it with cable encased in conduit.

APU is also aggressively converting existing overhead lines along major streets to underground as a way of enhancing reliability and the visual appeal of streetscapes throughout the community.

APU is ranked in the top 25% (quartile) of utilities nationwide when it comes to electric system reliability, which means that APU customers have fewer and shorter power outages than the other 75% of utilities nationwide.

Graph 62: APU at the Top Quartile of Utilities Nationwide for Reliability

D.3 SYSTEM RESILIENCY
The City of Anaheim has undertaken a comprehensive planning effort in developing its 2022 Local Hazard Mitigation Plan35 by organizing resources, assessing risks, and developing and implementing a mitigation plan and monitoring process. On January 10, 2023, the Anaheim City Council adop ted the 2022 Local Hazard Mitigation Plan, which was developed through City and community collaboration. It evaluates the risk of hazards and demonstrates how Anaheim will lower its risk and exposure to potentia l disasters including, but not limited to, earthquake, wildfire, and climate change.

Specifically, Chapter 3 of the 2022 Hazard Mitigation Plan details the risk factors of wildfire and preventative measures including fire mitigation education, vegetation management, routine inspections, fire resistant building material, and fire preventive building features. To ensure rapid response and adequate fire protection

35 https://www.anaheim.net/DocumentCenter/View/43389/Draft-hazard-mitigation-plan-03312022?bidId=

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in times of major fire events, Anaheim also particip ates in the Standardized Emergency Management System, which enhances multi-agency coordination for local and regional emergencies.

D.4 SMART GRID
APU has always strived to enhance its system reliability, improve efficiency and power quality, and empower customers with real time knowledge of energy demand through implementation of new commercially available and proven technologies, including but not limited to distribution automation, smart grid applications, and advanced metering infrastructure programs.

D.4.1 Distribution Automation
Smart Grid refers to modernization of the electricity de livery system primarily through automation. It allows for a more reliable, secure electrical service, and is ch aracterized by a two-way flow of information, control systems, and computer proce ssing to create an automated, widely di stributed energy delivery network. These cutting-edge technologies include adva nced sensors and relays that sens e and recover from faults in the substation automatically, automated feeder switches that re-route power to other feeders, automatic re-closers with smart protective devices that quickly restore power following momentary outages, and automated feeder capacitors that switch on/off automatically as needed to maintain constant feeder voltages.

Some major advantages of implementing Smart Grid projects are 1) a self-healing power system which uses digital information and automated control to supply more reliable power with fewer, briefer outages, 2) the ability to immediately and/or remotely validate and manage outages and restoration work which reduces the time needed to restore service, 3) a reduction in the number of times employees are sent to a particular address to validate power supply to a meter, and 4) reductions in total energy use, peak demand, energy loss, as well as potential reduction in end-user consumption.

APU performed a Smart Grid study to assess each of the distribution circuits in the system and to identify which overhead and underground switches, field capacitor banks that need to be automated, and where branch line fuses should be installed. In addition, the study al so identifies the potential locations to install automatic re-closers (AR).

Anaheim’s electric system has continually been reinforced and enhanced to meet increasing load demand while maintaining system reliability. The use of computer-b ased remote control and communication equipment can help ensure that the distribution system communicates and works together to deliver electricity more reliably and efficiently. The automated infrastructure modernizes the Grid, making it more resilient. It further reduces the number of customers affected during power outages, the frequency and duration of power outages, and the impacts of naturally occurring events . In addition, APU also benefits from a modernized Grid, including improved security, reduced peak loads, increased integration of renewables, and improved operational efficiency.

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Graph 63: Basic Characteristics of Smart Grid

APU has actively promoted, implemented, and expanded Smart Grid projects for its electric system since 2010.

To date, APU has spent several million dollars on Smar t Grid projects and auto matic devices system-wide including, but not limited to, automated re-closers, automated switches, automated capacitor banks, and SCADA linked fault indicators.

Future application of Smart Grid projects will evolve into more sophisticated and complex operations, such as predicting failing equipment and automatically isolating faulty equipment before a failure occurs, automatically restoring customers immediately after outages (self-hea ling) and integrating distri buted energy resources and demand response programs.

D.4.2 Advanced Metering Infrastructure
As a critical component of the Smart Grid, APU ha s deployed approx imately 90,000 Adv anced Metering Infrastructure (AMI) systems within its service territory. APU uses a radio frequency network communication for its electric distribution automation system for the ‘last mile’ communications from substations that utilize fiber optics for high-speed communications.

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Graph 64: Advanced Metering Infrastructure

D.5 PHYSICAL SECURITY PLAN
As an integral part of the planning and development process of its electric system, APU always strives to consider resiliency, enhanced reliability, and redundancy for its electric system.

In 2021, APU completed a comprehensive review of its enti re electric system that may be subject to physical security threats and developed a physical security plan to ensure protection of its electrical facilities from such threats. The APU Physical Security Plan was developed because of FERC directives and CPUC mandates that require electric utilities to identify vulnerable distribution assets such as substations that merit special protection and measures to reduce identified risks and consequences.

As the result of its assessment, APU concluded that all its critical electric facilities are equipped with security cameras, intrusion detection, alarm systems and 24/7 remote monitoring systems. The facilities were designed with two independent and redundant power sources, field equipment automation, and inventory of spare assets.

APU expects to review and update its Physical Security Plan in five years from its initial plan.

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IX. GREENHOUSE GAS EMISSION REDUCTION
APU’S EMISSION REDUCTION EFFORTS
To meet the AB 32 and SB 32 goals, APU began reducing its reliance on generation resources that produce GHG emissions by transitioning from fossil fuel-fired generating resources to renewable resources. The most significant contribution that APU can make in reducing GHG is the reduction of energy resources that produce GHG emissions from its power supply.

In addition to GHG emission reductions from APU’s power supply, further GHG reductions will come from
complementary efforts including continued energy efficiency measures, local solar, energy storage, electrification of homes from natural gas, and electrification of the transportation sector.

2020 GREENHOUSE GAS REDUCTION PLAN
In May 2020, APU published its follow-up utility-specific Greenhouse Gas Reduction Plan
36 with the purpose of
continuing its commitment to a clear and comprehensive long- term strategic framework to reduce GHG emissions. The Plan reviews how it doubled its 2020 goal to reduce GHG emissions by 20% below 1990 levels by 2020, as well as identifying goals for a minimum of 40% below 1990 levels by 2030 and zero- carbon by 2045. It is important to note that the 40% reduction below 1990 levels is a statewide goal; however, California utilities will likely be called upon to do more. This includes serving all retail load with zero-carbon reso urces by 2045 as prescribed in SB 100 passed in 2018.

APU doubled its goal of 20% below 1990 levels through the increased renewable generation from 11% in 2010 to 32.3% of overall sales in calendar year 2020. Further GHG emissions reductions were realized in 2018 due to the divesture of the San Juan Generating Station in 2017. Upon APU’s exit from the Intermountain Power Project in 2027, APU’s overall GHG emissions from its power supply portfolio are expected to reach or exceed 70% below its 1990 emissions by 2025. The GHG reduction targets established by CARB for POUs are currently 77% to 87% below 1990 levels by 2030. These targets are expected to be revised to align with CARB’s 2022 Final Scoping Plan for Achieving Carbon Ne utrality resulting in POU emission reduction targets of 83% to 87% below 1990 levels.

36 https://www.anaheim.net/5507/Greenhouse-Gas-Reduction Renewable
Energy
Energy
Efficiency
Local Solar
Energy
Storage
Transportation
Electrification
Building
Electrification

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In order to continue its downward emissions trajectory, APU will need to procure additional renewable energy to account for forecasted growth of transportation electrification demand. Procurement and/or development of bulk energy storage systems is another method that APU is actively pursuing to shift renewable over- generation from mid-day hours to evening demand periods where the CASIO grid managers currently depend on natural gas, and other high emitting resources, to m eet peak demand. This has a direct impact on reducing system wide emissions but may not necessarily reduce APU’s natural gas baseload or Canyon Power Project 37 resources. Significant emission reductions are observed in each of the portfolio scenarios analyzed and discussed in Section VII. Resource Portfolio Evaluation.

Graph 65: APU GHG Reduction Targets

EMISSION REDUCTIONS ASSOCIATED WITH TRANSPORTATION

ELECTRIFICATION
APU previously used the CEC’s “2016 SB 350 Co mmon Assumption Guidelin es for Transportation Electrification Analysis 3.0” workbook published in April 2017 to estimate avoided GHG emissions associated
with electric vehicle growth. In the absence of this report, APU used multiple publicly available resources, specifically the emissions saving equation associated with Low Carbon Fuel St andards (LCFS) regulation 38,

37 https://www.anaheim.net/DocumentCenter/View/21469/Canyon-Power-Project 38 https://ww2.arb.ca.gov/sites/default/files/2020-07/2020_lcfs_fro_oal-approved_unofficial_06302020.pdf Statewide Goal
20% Below 1990
GHG Emission Levels
Statewide Goal
40% Below 1990
GHG Emission Levels
SB 100 Zero‐Carbon
Obligation
APU Achieves
20% Below
1990 GHG Levels
Divestiture of San Juan
Generating Station
IPP Conversion
to Natural Gas
0 250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
MTCO2e (x 1,000)
Resource Portfolio GHG Emission Reductions
(1990 Emission Level ~2.3M MTCO2e)
Statewide GHG Reduction Targets 2022 Scoping Plan Target Share Actual Emissions Forecasted Portfolio GHG Emissions
APU GHG Emission Target Range
386,000 ‐ 305,000 MTCo2e
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Anaheim City CouncilMay 16, 2023

Anaheim City Council
May 16, 2023