2018
INTEGRATED RESOURCE PLAN
Anaheim Public Utilities
2018 Integrated Resource Plan
Table of Contents
Anaheim Public Utilities
TABLE OF CONTENTS
Table of Contents .......................................................................................................................................................... 1 Table of Graphs .............................................................................................................................................................. 4 Table of Tables ............................................................................................................................................................... 7 I. Executive Summary .................................................................................................................................................... 8 II. APU Fact Sheet ........................................................................................................................................................ 21 III. Planning Goals ........................................................................................................................................................ 22 A. Sustainable Resources ......................................................................................................................................... 22 B. High Reliability ..................................................................................................................................................... 23 C. Affordable Rates .................................................................................................................................................. 25 IV. Key Policy Drivers Affecting the Utility ................................................................................................................... 26 A. Reducing Greenhouse Gas (GHG) Emissions ....................................................................................................... 27 B. Increasing Procurement for Renewable Resources ............................................................................................. 28 C. Transformation of the Regional Grid ................................................................................................................... 29 V. Renewable Energy Procurement Plan and Enforcement Program ......................................................................... 30 A. Elements of the RPS Program .............................................................................................................................. 30 B. Planning and Procurement .................................................................................................................................. 32 C. Status of APU’s RPS Portfolio............................................................................................................................... 34 D. Potential Compliance Delays ............................................................................................................................... 35 E. Cost Limitations ................................................................................................................................................... 36 F. Enforcement Program .......................................................................................................................................... 39 VI. Energy Demand and Peak Forecasts ...................................................................................................................... 41 A. Energy Demand Forecast ‐ Methodology & Assumptions ................................................................................... 43 B. Peak Forecast ‐ Methodology & Assumptions ..................................................................................................... 53 VII. Resource Portfolio Evaluation ............................................................................................................................... 60 A. Portfolio Consideration and Performance Measures .......................................................................................... 62 B. Resource Options ................................................................................................................................................ 69 C. Model Analysis – Production Cost Model ............................................................................................................ 75 D. Model Analysis – Input Assumptions .................................................................................................................. 78 E. Model Analysis – Output Evaluation .................................................................................................................... 81 F. Stress Testing ....................................................................................................................................................... 89 G. Optimum Portfolio Recommendation ................................................................................................................. 95 H. Rate Impact ....................................................................................................................................................... 100 2018 Integrated Resource Plan
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Anaheim Public Utilities
VIII. Reliability & Electric System Overview ............................................................................................................... 106 A. APU Electric System Overview .......................................................................................................................... 107 B. Generation and Transmission Resources .......................................................................................................... 108 C. CAISO Resource Adequacy Requirements ......................................................................................................... 116 D. Distribution System Overview ........................................................................................................................... 120 IX. Greenhouse Gas Emission Reduction ................................................................................................................... 128 X. Transportation Electrification ................................................................................................................................ 134 A. Quantification, Characterization, and Location ............................................................................................ 134 B. Transportation Electrification Programs ....................................................................................................... 136 C. Prioritization and Funding Leverage .............................................................................................................. 141 D. Education and Outreach Plans ....................................................................................................................... 143 E. Alignment with State Policy and Local Needs ............................................................................................... 144 XI. Solar and Other Distributed Generation .............................................................................................................. 149 A. Customer Owned Solar PV .............................................................................................................................. 149 B. Solar for Schools .............................................................................................................................................. 151 C. Solar Power Program ....................................................................................................................................... 152 D. Anaheim Solar Energy Plant at the Convention Center ............................................................................... 152 F. Non‐Solar Distributed Generation .................................................................................................................. 153 XII. Energy Efficiency and Demand Response Programs ........................................................................................... 155 A. Program History ............................................................................................................................................... 155 B. Target Setting ................................................................................................................................................... 155 C. Program Highlights .......................................................................................................................................... 156 D. Existing Programs ............................................................................................................................................ 158 E. Challenges and Future Program Development ............................................................................................. 161 F. Demand Response Programs ............................................................................................................................. 163 XIII. Programs for the Low Income and Disadvantaged Communities ...................................................................... 165 A. Definition of Low Income and Disadvantaged Communities ............................................................................ 165 B. Interdepartmental Strategies ............................................................................................................................ 166 C. APU Strategies ................................................................................................................................................... 169 Appendix A – Renewable Procurement Plan ............................................................................................................. 171 Appendix B – Public Engagement .............................................................................................................................. 172 A. Customer Survey Summary ............................................................................................................................... 172 B. Customer Survey Types ..................................................................................................................................... 172 C. Total Surveys Collected...................................................................................................................................... 173 D. Survey Topics and Summary Results ................................................................................................................. 175 2018 Integrated Resource Plan
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Anaheim Public Utilities
E. Residential Analysis by Income Level ................................................................................................................. 184 F. Other Survey Results .......................................................................................................................................... 186 Appendix C – Portfolio Evaluation Details ................................................................................................................. 187 A. RPS and GHG Compliance .................................................................................................................................. 187 B. Regulatory Risk .................................................................................................................................................. 190 C. Resource Adequacy ........................................................................................................................................... 192 D. Portfolio Diversification ..................................................................................................................................... 196 E. Expected Cost .................................................................................................................................................... 197 F. Managed Market Risk ........................................................................................................................................ 198 Appendix D – Acronyms and Definitions ................................................................................................................... 200
2018 Integrated Resource Plan
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Anaheim Public Utilities
TABLE OF GRAPHS
Graph 1: APU GHG Reduction Targets ........................................................................................................ 28 Graph 2: Cumulative Adjustments to Base Load Forecast .......................................................................... 42 Graph 3: Anaheim Actual Energy Demand 2001 ‐ 2016 ............................................................................. 43 Graph 4: Historical and Base Energy Demand Forecast by Month ............................................................. 45 Graph 5: Estimated Electric Vehicle Energy Demand Growth .................................................................... 47 Graph 6: Estimated Behind‐the‐Meter Solar PV Impact to Energy Demand .............................................. 48 Graph 7: Adjusted Base Energy Demand Forecast ..................................................................................... 50 Graph 8: APU vs. IEPR Energy Demand Forecast ........................................................................................ 50 Graph 9: Cal‐Adapt vs APU Maximum Temperature Forecast ................................................................... 51 Graph 10: Forecasted Energy Demand with Extreme Temperatures ......................................................... 52 Graph 11: APU Historical Peak Demand ..................................................................................................... 53 Graph 12: Estimated Distributed (Behind‐the‐Meter) Solar PV Capacity ................................................... 54 Graph 13: Average Hourly Solar Profile by Month: Anaheim Convention Center...................................... 55 Graph 14: Estimated Distributed (Behind‐the‐Meter) Solar PV Impact to Energy Demand ...................... 56 Graph 15: Estimated Average Hourly Shape for Distributed Solar Generation .......................................... 56 Graph 16: Peak Demand Shift ..................................................................................................................... 57 Graph 17: Estimated Annual Peak Demand ................................................................................................ 57 Graph 18: Renewables Serving Peak Demand – Day with High Renewables & Low Energy Demand ....... 58 Graph 19: Renewables Serving Peak Demand – Day with Low Renewables & High Energy Demand ....... 59 Graph 20: Forecasted Peak demand with Extreme Temperatures ............................................................ 59 Graph 21: Selection Process of the Optimum Resource Portfolio .............................................................. 61 Graph 22: APU Resource Stack in 2006 ...................................................................................................... 62 Graph 23: APU Resource Stack in 2016 ...................................................................................................... 63 Graph 24: Historical and Planned Renewable Energy ................................................................................ 64 Graph 25: Planned GHG Reduction ............................................................................................................. 65 Graph 26: Available Resource Adequacy (RA) System Capacity ................................................................. 66 Graph 27: IPP Replacement Options ........................................................................................................... 69 Graph 28: New Power Supply Options – Cost Comparison ........................................................................ 70 Graph 29: Simulated RPS Compliance Requirement .................................................................................. 71 Graph 30: System Diagram ......................................................................................................................... 77 Graph 31: Average Annual SP‐15 Energy Price ........................................................................................... 78 Graph 32: CAISO Interconnection Projects ................................................................................................. 79 Graph 33: Candidate Portfolio Results: RPS Compliance ............................................................................ 81 Graph 34: Candidate Portfolio Results: Forecasted GHG Reduction .......................................................... 82 Graph 35: Candidate Portfolio Results: System Capacity Shortfall ............................................................. 83 Graph 36: Local Capacity Resources and LCR Requirement ....................................................................... 84 Graph 37: CAISO Flexible Capacity Requirement ........................................................................................ 84 Graph 38: Candidate Portfolio Results: Portfolio Diversity in 2030 ........................................................... 85 Graph 39: Candidate Portfolio Results: Net Power Supply Cost ................................................................. 86 2018 Integrated Resource Plan
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Anaheim Public Utilities
Graph 40: Candidate Portfolio Results: Wholesale Energy Purchase as a % of Total Energy Portfolio ...... 87 Graph 41: Stressed Gas Prices .................................................................................................................... 89 Graph 42: Stressed Carbon Prices ............................................................................................................... 90 Graph 43: Stressed Utility Scale Solar Capacity Growth ............................................................................. 90 Graph 44: Stressed System Load Growth or Reduction (GWh) .................................................................. 91 Graph 45: Stress Test Results: Extreme High Costs vs. Extreme Low Costs ............................................... 93 Graph 46: Stress Test Results: Extreme High Demand vs. Extreme Low Demand ..................................... 93 Graph 47: Variable Portfolio Meets or Exceeds Compliance Targets ......................................................... 95 Graph 48: Variable Portfolio Forecasted Resource Adequacy .................................................................... 96 Graph 49: Resource Mix for Retail Energy Demand: 2018 vs. 2030 ........................................................... 97 Graph 50: Variable Portfolio Power Supply Cost Structure ........................................................................ 98 Graph 51: Comparison of Monthly Residential Electric Bills .................................................................... 101 Graph 52: Rate Comparison ...................................................................................................................... 104 Graph 53: Total Residential Customer Monthly Bill ................................................................................. 104 Graph 54: Commercial Customer Monthly Bill ......................................................................................... 105 Graph 55: Customer Class Data ................................................................................................................ 107 Graph 56: CAISO “Duck Curve” ‐ Impacts of Variable Energy Resources ................................................. 118 Graph 57: Anaheim’s Reliability Performance in Terms of SAIDI, SAIFI, and CAIDI Since 1990 ............... 124 Graph 58: APU at the Top Quartile of Utilities Nationwide for Reliability ............................................... 125 Graph 59: Basic Characteristics of Smart Grid .......................................................................................... 126 Graph 60: Advanced Metering Infrastructure .......................................................................................... 127 Graph 61: 2015 GHG Emissions by Sector ................................................................................................ 128 Graph 62: GHG Intensity of Electricity12 ................................................................................................... 128 Graph 63: APU GHG Reduction Targets .................................................................................................... 130 Graph 64: Emission Reductions Resulting from Transportation Electrification ....................................... 131 Graph 65: APU GHG Emission for System Energy Demand ...................................................................... 133 Graph 66: EV Charging Stations within APU Service Territory .................................................................. 135 Graph 67: IRP Customer Survey Result: % Renters vs. Home Owners Who Own, Lease or Anticipate Acquiring an EV within the Next Three Years ........................................................................................... 137 Graph 68: Cumulative Solar Capacity Installed ‐ Customer Owned Solar Systems .................................. 150 Graph 69: Map of SB 1 Residential Solar Rebate and Solar for School Sites ............................................ 150 Graph 70: Annual kWh Savings Targets .................................................................................................... 155 Graph 71: Cumulative Energy Efficiency Saving Goals with CEC Adjustments ......................................... 156 Graph 72: FY 16/17 Residential Program Energy Savings ......................................................................... 160 Graph 73: FY 16/17 Commercial Program Energy Savings ....................................................................... 161 Graph 74: Map of APU’s Low Income and Disadvantaged Communities ................................................. 165 Graph 75: Map of Home Utility Checkup by Dollar Spent 2016‐2017 ...................................................... 169 Graph 76: Residential Customer Satisfaction Rating: APU vs. CMUA ....................................................... 175 Graph 77: Business Customer Satisfaction Rating: APU vs. CMUA ........................................................... 176 Graph 78: Customer Survey – Support of Renewable Energy .................................................................. 176 Graph 79: Customer Survey – Support of IRP Approach .......................................................................... 177 Graph 80: Customer Survey – Support of Over 50% RPS with Potential Rate Increase ........................... 178 2018 Integrated Resource Plan
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Anaheim Public Utilities
Graph 81: Customer Survey – Residential Controlled Group on Potential Bill Increase Due To Over 50% RPS ............................................................................................................................................................ 178 Graph 82: Customer Survey – Air Quality Ratings .................................................................................... 179 Graph 83: Customer Survey – Solar and Distributed Generation Ownership % ...................................... 180 Graph 84: Customer Survey – Residential and Small‐to‐Medium Businesses Interest in Community Solar .................................................................................................................................................................. 181 Graph 85: Customer Survey – Residential Interest in Community Solar Breakdown ............................... 181 Graph 86: Customer Survey – Current and Planned EV Ownership ......................................................... 182 Graph 87: Customer Survey – Large Business Current and Planned EV Ownership Breakdown ............. 182 Graph 88: Customer Survey – Residential Controlled Group on Impact of Rebate vs. Public Charging Accessibility on EV Ownership .................................................................................................................. 183 Graph 89: Customer Survey – Energy Efficiency Participation and Satisfaction Rating ........................... 183 Graph 90: Customer Survey – Large Business Customers Demand Response Potential .......................... 184
2018 Integrated Resource Plan
Table of Contents
Anaheim Public Utilities
TABLE OF TABLES
Table 1: Temperature Summary ................................................................................................................. 44 Table 2: APU Energy Efficiency Targets including Codes & Standards (Navigant Study) ............................ 48 Table 3: Historical Load Factors (as of December 2017) ............................................................................ 54 Table 4: Renewable Capacity Required to Meet RPS Target ...................................................................... 72 Table 5: New Resource Capacity by Candidate Portfolio ............................................................................ 79 Table 6: System Capacity Purchases Cost ................................................................................................... 83 Table 7: Anaheim EVs and Emission Savings per Vehicle ......................................................................... 131 Table 8: Types of Customer Surveys and Number of Surveys Collected .................................................. 173 Table 9: High School Student Events and Number of Surveys Collected .................................................. 174 Table 10: Customer Survey – Residential and Small‐to‐Med Businesses Open Group on Potential Bill Increase Due To Over 50% RPS ................................................................................................................. 179 Table 11: Customer Survey – Air Quality Rating by Renters vs. Homeowners ......................................... 185 Table 12: Customer Survey – Residential Controlled Group Survey Results by Income Categories ........ 185 2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
I. EXECUTIVE SUMMARY
Introduction
Anaheim Public Utilities (APU) operates a
consumer‐owned vertically integrated electric
utility, which has the privilege and obligation to reliably serve electricity customers located within its 50 square mile service territory. As such, APU is
responsible for planning adequate power
generation resources to reliably meet customer
demand for electricity after making adjustments
for i) customer energy efficiency savings, ii) added
energy demand from electric vehicles (EV), and iii)
reductions from customer‐owned power
generation (e.g. roof‐top solar), all while
considering sustainability policy goals which call for
reductions in greenhouse gas (GHG) emissions. As a
not‐for‐profit utility, APU also considers the impact
of resource additions on customer rates. The following graphic shows how APU balances adjustments to customer energy demand and sustainability goals to develop an integrated resource plan (IRP).
The IRP serves as a long‐term comprehensive roadmap 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 intensive 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 Bill (SB) 350, including the requirement to establish an IRP by January 1, 2019.
The IRP process commenced in early 2017 with customer outreach efforts, which played an important role in APU’s selection herein of the optimum power generation resource mix to reliably serve customer demand while meeting the goals established in the IRP. Customer feedback indicated broad support for APU is responsible for planning adequate
power generation resources to reliably
meet customer demand for electricity after
making adjustments for i) customer energy
efficiency savings, ii) added energy demand
from electric vehicles (EV), and iii)
reductions from customer‐owned power
generation (e.g. roof‐top solar), all while
considering sustainability policy goals
which call for reductions in greenhouse gas
(GHG) emissions.
APU is responsible for planning adequate
power generation resources to reliably
meet customer demand for electricity after
making adjustments for i) customer energy
efficiency savings, ii) added energy demand
from electric vehicles (EV), and iii)
reductions from customer‐owned power
generation (e.g. roof‐top solar), all while
considering sustainability policy goals
which call for reductions in greenhouse gas
(GHG) emissions.
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
APU’s responsible transition away from carbon intensive energy resources to an increased procurement of renewable energy resources supplemented by cleaner burning resources.
Assessment of Customer Energy Demand
APU uses a statistical model to forecast a baseline customer energy demand, which is adjusted up or down based on i) planned customer additions, ii) expected electric vehicle usage, iii) estimated customer‐owned rooftop solar installations, and iv) expected customer energy efficiency reductions.
Based on the results of this modeling, APU expects a cumulative reduction in customer energy demand of 0.86 percent between 2018 and 2030, which is effectively a zero‐growth energy demand forecast. In summary, this zero‐growth forecast is primarily the result of simultaneous, opposing dynamics of i) expected system expansion and EV growth that increase energy demand being offset by ii) customer solar installation and energy efficiency reductions that reduce energy demand. The following graphic shows the various additions and subtractions to the baseline energy demand forecast.
Transition to Clean Energy Resources
In planning to serve the customer energy demand forecast established above, APU must consider its existing power generation resource mix and plan the resource 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 zero‐growth energy demand forecast, it currently 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, businesses, schools and visitors, as well as protecting the local environment. Carbon dioxide is the primary GHG associated with electricity generation. 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.
At the end of 2017, APU fully divested of its ownership interest in the San Juan Generating Station (San Juan), a coal‐fired generating plant located in New Mexico. Once APU’s exit of the Intermountain Power Base Energy Demand Forecast
+ Energy Demand Addition
•System Expansion
•EV Penetration
‐ Energy Demand Reduction
•Solar Installation
•Energy Efficiency
= Adjusted Energy Demand
Forecast
(120)
(70)
(20)
30 80GWh
GWh
Cumulative Adjustments to Base Energy
Demand Forecast (2018‐2030)
Energy Efficiency
Solar PV
EV Adoption
Planned Expansion
Cumulative Impact on Energy Demand
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
Project (IPP) contract in mid‐2027 is complete, its power supply portfolio will be 100 percent free of coal resources. Transitioning away from coal resources and replacing them with clean renewable energy resources ultimately proved to be the optimum resource portfolio, as further described in Section VII of this IRP.
These renewable energy resource
additions, along with APU’s support for
accelerating transportation electrification,
will reduce APU’s GHG emissions by more
than 70% below 1990 emission levels by
the year 2030; significantly exceeding the
State’s overall target of 40% below 1990
emission levels by 2030.
APU’s Current Power Resource Mix
APU’s current power resource portfolio consists of a diverse mix of generation resources, which provide high reliability, stable prices, and is comprised of roughly 30% renewable energy resources. The diversity also protects APU’s customers from contingencies such as fuel unavailability, fuel price fluctuations and changes in energy policies that can drive up the cost of a particular fuel.
Renewable Energy Resource Procurement Plan
On February 28, 2017, the City Council approved APU’s latest renewable energy resource procurement and enforcement plans, 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 requires that utilities incorporate current renewable energy resource Renewable
29%
Coal
34%Large Hydro
2%
Natural Gas
28%
Purchases
7%
2018 RESOURCE MIX
Wind
24% Small
Hydro
2%
Solar
<1%Biogas
55%
Geothermal
18%
The divestiture from coal energy, along with the
support for accelerating transportation
electrification, will reduce APU’s GHG emissions by
more than 70% below 1990 emission levels by the
year 2030.
The divestiture from coal energy, along with the
support for accelerating transportation
electrification, will reduce APU’s GHG emissions by
more than 70% below 1990 emission levels by the
year 2030.
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
procurement plan into IRPs going forward. This IRP includes APU’s most recent update to its renewable energy resource procurement plan, which is in accordance with the 50% renewable energy by 2030 target previously approved by City Council. The following graphic shows the optimum renewable energy resource procurement plan that will serve as a target for compliance with the RPS required by State law by 2030.
The IRP also updates the cost limitation methodology 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. All versions of the RPS Policy previously approved by City
Council included a cost limitation provision for the protection of APU customers. This cost limitation methodology is now outdated since it was based on a
2010 base year and a 33% RPS, which has been
mandated by the State to increase to 50% by 2030. As
part of this IRP, APU is highlighting how it will procure new renewable energy resources in a manner that
does not cause an increase in overall power supply costs greater than $0.01 per kilowatt‐hour in any fiscal year, which represents a 10% increase over current power supply costs or approximately four times the expected rate of general inflation in a single year, and is considered to be an undue burden on customers.
Renewable
50%
Natural Gas
21%
Purchases
27%
Large Hydro
2%
2030 RESOURCE MIX
Wind
17%
Solar
15%
Biogas
52%
Geothermal
16%
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
Balancing the Renewables Portfolio
APU’s renewable portion of its overall power resource mix consists mainly of baseload renewables such as geothermal, landfill gas and biofuels. These baseload resources operate continuously around‐the‐ clock and are not dependent on favorable weather conditions unlike intermittent resources such as wind or solar power generation. The consistency and reliability that comes with baseload renewables has historically also come with a premium price. To maintain competitive rates for APU customers, Anaheim explored adding less expensive intermittent resources to balance its renewable portfolio in its plan to transition out of coal and procure from 30% to 50% renewable energy by 2050. The following graphics show the three resource portfolios analyzed prior to selecting the optimum resource portfolio and the overall resource mix planned to be reached by 2030:
A 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 Financial Exposure. The Variable Portfolio outperformed the other portfolios under both expected conditions and stress tested conditions, such as extreme heat, extreme carbon pricing, extreme fuel price volatility, and extreme high or low energy efficiency, solar penetration and electric vehicle penetration.
Under the recommended Variable Portfolio, APU will 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 show that the Variable Portfolio causes the lowest overall increase in power supply costs.
IPP Coal
Replacement
Variable Portfolio
(Optimum):
68% Baseload
32% Intermittent
Mixed Portfolio:
81% Baseload
19% Intermittent
Baseload Portfolio:
85% Baseload
15% Intermittent
Under the Variable 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.
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
*Net power supply costs excludes transmission and wholesale energy revenues APU’s resource portfolio will be coal‐free by mid‐2027, and at a minimum, 50% of APU’s electricity deliveries will come from renewable energy resources. Based on current law and draft regulations, APU’s optimum resource portfolio under this IRP will achieve the upper bound of the proposed GHG reduction target range (77% GHG reduction). However, the GHG reduction target for POUs is currently under development by the California Air Resources Board (CARB) and may ultimately be 77% to 87% below 1990 levels by 2030. If the final regulation requires that APU achieve the lower bound of the target range (87% GHG reduction), that target level could not be achieved without significant cost impacts to APU and its customers. If California Air Resources Board (CARB) were to indeed adopt the more stringent 87% GHG reduction target it would require the shutdown, or “stranding,” of a reliable and efficient baseload natural 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. APU is closely following relevant regulatory proceedings and will work with the CARB and CEC to recommend methodologies to further reduce APU carbon emissions, such as accounting for the effect of electric vehicle (EV) penetration on emission reduction.
$245,000
$265,000
$285,000
$305,000
$325,000
$345,000
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Thousands
New Power Supply Options ‐ Cost Comparison
Variable Portfolio Mixed Portfolio
Baseload Portfolio New Natural Gas Plant
250
350
450
550
650
750
850
950
1,050
1,150
1,250
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMT of CO2 (Thousands)
APU GHG Emission ‐ System Energy Demand
APU Emission APU Emission + EV Emission Reduction
APU GHG Emission Target Range
304,611 ‐ 538,146 MMT
(77% ‐ 87% lower than 1990 level)
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
Projected Effect 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 divesting 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 2019 through 2030 based on the recommended Variable Portfolio and the expected consumption case. Such net power supply costs are expected to increase an average of 1.34% per year from 2019 to 2030, which is less than the expected rate of inflation over the same time period.
Given the large amount of reliable baseload renewable resources in APU’s portfolio, as compared to the small amount of intermittent solar and wind resources, the cost to support and backup intermittent renewable resources attributed to APU by the California Independent System Operator (CAISO) has remained relatively low to date. However, to mitigate future renewable integration costs, APU currently has plans to add a 1 MW energy storage pilot project by December 31, 2021 and an additional 10 MW of energy storage by December 31, 2026, if the pilot project proves to be cost‐effective. Energy storage technologies include batteries and other systems that are able to store power for later use in a controlled manner.
$253 $291
‐$50
$0
$50
$100
$150
$200
$250
$300
$350Millions
Net Power Supply Cost 2019 ‐ 2030
Total Transmission Cost Scheduling Coordinator Costs Conventional Unit Fixed Costs Unit Variable Cost Unit Fuel Cost Debt Service Cost
Wholesale Purchase Cost Renewable Long Term PPA Cost Renewable Short Term PPA Cost Total Wholesale Revenue Total Transmission Revenue Total Net Cost Renewables & Storage $60M to $76M
Market Purchases $9M to $62M
Average 1.34%
annual increase
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.
Thermal $151M to $78M
Transmission and Scheduling
Services $76M to $97M
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.
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
Local Reliability and Air Quality
Of APU’s approximate 700 MWs of generation capacity, 240 MWs are located within the City. The Canyon and Kraemer Power Plants provide flexible power generation capability, known as resource adequacy capacity, near the Anaheim load center, including black‐start capability, which enhances local and statewide reliability. The power plants use clean‐burning natural gas fuel, include air emission controls to further reduce air pollutants that cause smog, have much lower GHG emissions than coal resources, and operate as flexible peaking units to support the morning and evening ramping needs of the power grid and backup fluctuations in solar output due to weather.
According to a recent APU customer survey, 95% of the respondents indicated that they have acceptable to excellent air quality near their home, and 89% of the respondents indicate the air quality has improved or stayed the same over the past few years. These respondents mainly attributed any air quality concerns to traffic and emissions from mobile sources, and none attributed it to APU’s local power generation.
To improve local air quality and support sustainability 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.
In addition, APU supported customer‐owned solar
distributed generation by fully implementing the
Senate Bill (SB) 1 solar initiative rebates. To date, over 28,000 totaling 26 MW of customer‐owned solar
systems have been installed in Anaheim. APU continues
to expand clean local distributed generation through utility‐owned solar projects. As an example, APU is installing and will maintain 1.5 MW solar carports and lunch shelters at nine public schools throughout
Anaheim through its Solar for Schools program, and is expected to continue adding solar school facilities in future years.
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
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. More recently, APU has implemented programs to address the needs of its income‐ qualified customers considering that the 2015 U.S. Census shows that nearly 58% of Anaheim households are under the low income designation. Additionally, APU has incorporated programs that assist “disadvantaged communities (DAC),” as defined by Senate Bill 535 (De León) and the most current version of CalEPA’s California Communities Environmental Health Screening Tool (“CalEnviroScreen”).
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:
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 Community and Economic Development to
service LI‐DAC customers. Some examples include:
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
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
qualifying commercial, industrial, and residential projects and multi‐family developments near freeways and within LI‐DACs.
Transitioning to LED street lights 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 park sites within LI‐DACs through grant funding opportunities.
Providing customer education and outreach on energy efficiency and income‐qualified programs at community meetings.
Hosting community outreach events within LI‐DAC areas, specifically promoting sustainable resources and
conservation programs.
Developing an income‐qualified solar discount program that integrates with the Solar for Schools energy production to allow households to receive bill savings, where these customers may otherwise not be able to access solar benefits because they are living in multi‐family dwellings.
APU’s low income energy discount is offered to seniors, military veterans, and disabled customers who meet specified income thresholds. Low Income Home Energy Assistance Program (LIHEAP) is also available for customers needing additional bill assistance.
Data analytics is utilized 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 customers applying for the Home Utility Checkup are also pre‐qualified for free weatherization installations. x
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
APU’s data analytics show in the map below that residential solar rebates were evenly distributed throughout APU, which is partially attributed to the income‐qualified solar incentives offered at a higher rate. In addition, 8 out of the 9 Solar for School sites are located in LI‐DACs.
Customer Support of IRP Approach
The Variable Portfolio, recommended by this IRP as the optimum portfolio, is also closely aligned with the preferences of APU customers, as evidenced by a
customer survey conducted in late 2017.
As a customer‐owned electric utility, APU actively solicited input from customers and received responses from approximately 1,200 residents and businesses
through online surveys, phone interviews, and outreach events. Survey respondents overwhelmingly expressed high satisfaction with APU services. Customers indicated that they are likely to contact APU for advice on solar and other distributed generation, and feel that APU will offer fair and balanced advice.
In 2016, California Municipal Utilities Association (CMUA) conducted a statewide customer satisfaction survey that reached nearly 1,400 residential customers. In comparison to the CMUA municipal customers surveyed, APU customers expressed a significantly higher overall customer satisfaction with APU services.
Customer Survey Quotes
“Good for the environment and our kids’
future!”
“Protect the planet.”
“As a community, we need to reduce
greenhouse gas emissions.”
“Reducing coal usage helps keeping air
pollution low.”
“Renewable energy is the future.”
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
Customers also expressed high support of the IRP approach to eliminate coal resources and reach a renewable energy target of 50% by 2030.
In addition to the customer survey, in March 2018 APU held community events at public locations in each of Anaheim’s six council districts, at which a summary of the IRP was presented, including greenhouse gas reductions, phasing‐out of coal resources, 50% renewable portfolio standard, transportation electrification, local solar projects, and energy efficiency.
Executive Oversight and Governing Board Approval
Executive Oversight
The IRP development is guided by an Executive Oversight group consisting of the following members:
o General Manager
o Assistant General Manager – Power Supply
o Assistant General Manager – Electric Services
o Assistant General Manager – Finance and Administration o Chief Risk Officer
During IRP development, quarterly meetings were held to discuss APU policy, guiding principles and key components of the IRP. Staff receives direction and support from the Executive Oversight group on all 55%
74%
0% 10% 20% 30% 40% 50% 60% 70% 80%
%
% of Very Satisfied Customers
2017 APU Residential
2016 CMUA Residential
65% 54%
82%
8.1 7.6
8.8 0.0
2.0 4.0
6.0 8.0
10.0 0%
20%
40%
60%
80%
100%
Residential Small ‐to‐Medium Businesses Large Businesses Support of IRP Approach by Anaheim Customers
% of Very Supportive Customers (Scores 8‐10 in a Scale of 0‐10) Average Customer Score
2018 Integrated Resource Plan
I. Executive Summary
Anaheim Public Utilities
aspects of the IRP, particularly the cross‐departmental efforts such as transportation electrification and programs and resources targeted for the low income and disadvantaged communities.
Board and Council Approval
This IRP and future updates will be presented to the Public Utilities Board for their consideration and recommendation to the Anaheim City Council for approval.
The Public Utilities Board is made up of seven Anaheim residents who are appointed to staggered four‐ year terms by members of the Anaheim City Council. Their role is to make recommendations to the Anaheim City Council on utility matters, including:
o Annual capital and operating budgets
o Renewable energy resource options
o Sources of water and power supply
o Water and electric rates
o Water and energy conservation and efficiency incentives Following the Board's recommendation for approval, the IRP will be presented to the Anaheim City Council for approval and adoption.
2018 Integrated Resource Plan
II. APU Fact Sheet
Anaheim Public Utilities
Dukku Lee
Utilities General
Manager
Brian Beelner
Assistant General Manager
Finance & Administration
Janet Lonneker
Assistant General
Manager
Electric Services
Graham Bowen
Assistant General
Manager
Power Supply
Michael Moore
Assistant General
Manager
Water Services
Janis Lehman
Chief Risk Officer
II. APU FACT SHEET
Local Ownership & Control
Anaheim Public Utilities is a city‐owned, not‐for‐profit electric 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 have input to the decision process both directly and through an appointed citizen advisory 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 Two Plants in Anaheim Service Area
2 One Plant in Anaheim Service Area
Electric Services Facts
Anaheim Public Utilities 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 multi‐million dollar
tourism, sports and manufacturing customers.
Revenues & Expenditures
APU’s total electric utility revenue is more than
$458 million a year, and net investment in utility
plants is $880 million.
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 over 700 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
3 natural gas plants (in‐state1)
1 coal plant (out‐of‐state)
1 large hydroelectric plant (out‐of‐state)
4 small hydroelectric plants (in‐state)
2 solar photovoltaic plants (in‐state2)
2 geothermal plants (1 out‐of‐state)
3 wind plants (1 out‐of‐state)
2 landfill gas plants (in‐state)
Distribution Infrastructure
Transmission, 220kV
1.2 circuit miles
Sub‐Transmission, 69kV
32.9 circuit miles of overhead
57.2 circuit miles of underground
Distribution, 12kV and lower, circuit miles
Overhead – 401 primary, 1,219 secondary
Underground – 709 primary, 963
secondary
Transformer Capacity, KVA
220kV to 69kV – 1,808,000
69kV to 12kV – 1,157,800
12kV to customer – 1,633,671
13 Substations
19,902 Streetlights
13,022 Distribution Transformers
2018 Integrated Resource Plan
III. Planning Goals
Anaheim Public Utilities
50% renewables by 2030
GHG reduction of 40% below
1990 levels by 2030
Cumulative doubling of energy
efficiency savings by 2030
Phase Out of Coal
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. This IRP supports this mission by establishing resource planning goals of 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 i) helping its customers use energy wisely and efficiently and ii) transitioning to sustainable power resources such as wind, geothermal, biogas, small hydro, and solar. APU currently serves 29% of its customer load from
renewable resources and in 2017 the Anaheim City Council adopted a policy for APU to achieve a 50% renewable portfolio standard by 2030, which are both in compliance with 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 recently expanded by the passage of Senate Bill (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, which established 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 set a goal to double electricity and natural gas energy efficiency savings statewide by 2030.
This 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
• 50% RPS
• 40% GHG
Reduction
•L o w e s t
Regulatory Risk
High
Reliability
•R e s o u r c e
Adequacy
• Portfolio
Diversification
Affordable
Rates
•L o w e s t Expected
Cost
• Managed
Market Risk
2018 Integrated Resource Plan
III. Planning Goals
Anaheim Public Utilities
Meet or exceed the following Renewables Portfolio
Standard (RPS) targets, as a percentage of retail load:
33% by December 31, 2020;
40% by December 31, 2024;
45% by December 31, 2027;
50% 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 contribute
toward a statewide GHG emissions reduction goal
of 20% below 1990 levels by 2020, and 40% below
1990 levels by 2030. The GHG reduction target for
POUs which is currently under development by
CARB may ultimately be 77% to 87% below 1990 levels by 2030.
Meet or exceed the energy efficiency targets established by the Anaheim City Council for APU electricity customers, which contribute toward a statewide cumulative doubling of energy efficiency savings in the electricity and natural gas sector final end uses by 2030. The energy efficiency target established for APU by City Council is currently a 1.1% reduction in electricity sales per year.
Phase‐out of all APU coal resources by 2027.
These sustainability goals and reasonable Regulatory Risk were considered in the development of the power supply scenarios evaluated under this 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 of 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 this IRP.
Overall electric service reliability is comprised of i) high power supply reliability and ii) high electric distribution system reliability.
High power supply reliability is measured by two quantitative 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.
Sustainable Resources
50% 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.
2018 Integrated Resource Plan
III. Planning Goals
Anaheim Public Utilities
2. Portfolio Diversification is measured by the different types of resources, fuel and contract lengths within the portfolio, which increases flexibility, reliability, and operational performance of the overall portfolio.
While the power supply portfolio scenarios evaluated under this IRP primarily considered power supply
reliability (versus distribution 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 could have an effect on electric distribution system reliability; as such, they were also considered and addressed under various sections of this 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 supply/demand 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 enjoys extremely high power supply reliability because the loss of any single generator does not affect the delivery of electricity to APU customers. There has not been a regional blackout affecting APU since August 1996, demonstrating that APU’s interconnection to the Grid serves its customers very well.
To maintain high reliability the CAISO and other Grid operators require load serving entities such as APU to maintain adequate power generation capacity beyond that required to serve its own customers, which is known as a “Resource Adequacy” requirement. CAISO’s current Resource Adequacy requirement is 15% of forecasted peak load. APU employs a diversified portfolio of power generation resources to comply with its Resource Adequacy obligation, and maintaining a diversified and resilient Resource Adequacy portfolio was a factor in the evaluation of the power supply scenarios considered under this IRP.
In addition to maintaining Resource Adequacy to 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 full compliance with NERC reliability standards, and in 2014 passed an audit of all applicable NERC standards with no violations.
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.
2018 Integrated Resource Plan
III. Planning Goals
Anaheim Public Utilities
APU adheres to the CAISO tariffs and Business Process Manuals pertaining to the Grid‐level reliability requirements. The reliability requirements and Resource Adequacy programs provide performance and deliverability criteria for generation resources required 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 50% RPS. Also, to improve system resiliency, a diversified and flexible portfolio is considered to minimize risks of unplanned facility outages accompanied with acquisition of resources with complementary generation profiles.
C. AFFORDABLE RATES
As a customer‐owned utility, maintaining affordable electric rates is a key APU goal considered in the development of this IRP. APU has consistently maintained electric rates that are lower than adjacent investor owned 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 obligation 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.
The optimum (recommended) portfolio consists of a balanced mix of renewable resources and ensures high reliability, while at the same time maintaining 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 introduced to ensure the optimal 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 Risk. Lowest expected cost is measured by the total cost to supply power, while Market Risk is measured by percentage of energy purchased from the wholesale market, and the portfolio’s ability to withstand market price volatility.
Affordable Rates
Expected Cost is measured by the
total cost to supply power.
Market Risk is measured by the
percentage of energy purchased
from the wholesale market, and the
portfolio’s ability to withstand
market price volatility.
2018 Integrated Resource Plan
IV. Key Policy Drivers Affecting the Utility
Anaheim Public Utilities
IV. KEY POLICY DRIVERS AFFECTING THE UTILITY
California is considered a leader in its many efforts to combat the effects of climate change. The overarching goal of the State’s climate change strategy is to reduce statewide GHG emissions to 40% below 1990 levels by 2030. 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.
The following table is a summary of the California laws 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
July 26, 2017 Assembly Bill 617 (Christina Garcia, Chapter 136, Statutes of 2017)
Companion to Cap-and-Trade
Establishes a groundbreaking program to measure and reduce air pollution from mobile and stationary sources at the nei ghborhood level in the communities most impacted by air pollutants. Requires the Air Resources Board to work closely with local air districts and communities to establish neighborhood air quality monitoring networks and to develop and implement plans to reduce emissions. The focus on community-based air monitoring and emission reductions will provide a national model for enhanced community protection.
July 25, 2017 Assembly Bill 398 (Eduardo Garcia, Chapter 135, Statutes of 2017)
Cap-and-Trade Extension
Extends and improves the Cap-and-Trade Pr ogram, 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 (Eduardo Garcia, Chapter 250, Statutes of 2016)
Greenhouse gas regulations
Prioritizes direct emission reductions from large stationary sources and mobile sources.
September 8, 2016 Senate Bill 32 (Pavley, Chapter 249, Statutes of 2016)
Greenhouse Gas emission reduction target for 2030
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 retail sales of renewable electricity to 50 percent by 2030 and double the energy efficiency savings in electricity and natural gas end 2018 Integrated Resource Plan
IV. Key Policy Drivers Affecting the Utility
Anaheim Public Utilities
uses by 2030.
April 12, 2011 Senate Bill X1-2 (Simitian, Chapter 1, Statutes of 2011)
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 applies to all electricity retailers in the state including publicly owned utilities (POUs), inve stor-owned utilities, electricity service providers, and community choice a ggregators. This new RPS preempts the California Air Resources Board’s 33 percent Renewable Electricity Standard.
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 greenhous e gas emissions limit equivalent to the statewide greenhouse gas emissions leve ls in 1990 to be achieved by 2020. ARB shall adopt regulations to require the reporting and verification of statewide greenhouse gas emissions and to monito r and enforce compliance with this program. AB 32 directs Climate Action T eam 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: http://www.climatechange.ca.gov/state/legislation.html
A. REDUCING GREENHOUSE GAS (GHG) EMISSIONS
The passage of AB 32 in 2006 requires a statewide reduction in GHG emissions to 1990 levels by the year 2020; effectively a 30% decline in emissions from current statewide output. In 2016, SB 32 expanded the statewide GHG emissions reduction goal to 40% below 1990 levels by the year 2030. 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 and cleaner natural gas generation technologies. 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 increased energy efficiency measures, local solar, energy storage, and transportation electrification.
In July 2015, APU developed its first utility‐specific Greenhouse Gas Reduction Plan with the purpose of developing a clear and comprehensive long‐term strategic framework to reduce GHG emissions. The Plan identifies a goal to reduce GHG emissions by 20% below 1990 levels by 2020, and a minimum of 40% below 1990 levels by 2030. 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. The California Air Resources Board, in conjunction with California Energy Commission, is in the process of developing utility‐specific GHG reduction targets for California utilities as prescribed through the passage of SB 350.
The development of utility‐specific GHG reduction targets is not expected to be completed before the adoption of this IRP; however, APU is well positioned to meet GHG reduction targets beyond the current 2018 Integrated Resource Plan
IV. Key Policy Drivers Affecting the Utility
Anaheim Public Utilities
40% mainly as a result of increased renewables procurement and divestiture plans underway for coal resources under contract.
APU achieved its goal of 20% below 1990 levels through the increased renewable generation from 11% in 2010 to 33% of overall sales in calendar year 2015. Further GHG emissions reductions are forecasted to reach near the 40% reduction target upon the divesture of the San Juan Generating Station which occurred at the end of 2017. As shown in Graph 1, upon APU’s exit from the Intermountain Power Project in 2027, APU’s overall GHG emissions from its power supply portfolio is expected to reach approximately 70% below its 1990 emissions by 2028 based on projected GHG emissions from any of the portfolio scenarios analyzed and discussed further in Section VII.
Graph 1: APU GHG Reduction Targets
B. INCREASING PROCUREMENT FOR RENEWABLE RESOURCES
APU has steadily been increasing the renewable energy component of its resource portfolio since 2003.
In response to Senate Bill 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 the statewide target to 20% by 2010. The passage of SB X1‐2 in 2011 increased the State’s renewables target to 33%
2018 Integrated Resource Plan
IV. Key Policy Drivers Affecting the Utility
Anaheim Public Utilities
by 2020, and was further expanded in late 2015 through the passage of SB 350 which requires APU to provide 50% of its retail energy sales to customers from renewable energy resources by the year 2030.
The Renewable Portfolio Standard (RPS) is a key element of the State’s strategy to reduce statewide GHG emissions. Today, APU delivers nearly one third of its retail electricity sales from renewable resources. APU is a fully resourced utility, meaning APU’s resource portfolio has sufficient generation capacity to serve customer energy demand and meet Resource Adequacy requirements. The State’s increasing renewable energy procurement mandates create a challenge in balancing the costs associated with the current resource portfolio with the added costs of further increasing the renewable energy component of the overall resource mix. Section VII further discusses the effect of an accelerated RPS, along with 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 wholesale 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 stability of energy markets. As the State’s share of variable renewable energy generation increases, 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 electricity 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 lead to additional costs if market participants own generation that cannot be ramped down due to technology constraints such as non‐dispatchable renewables or a minimum capacity requirement.
2018 Integrated Resource Plan
V. Renewable Energy Procurement Plan and Enforcement Program
Anaheim Public Utilities
V. RENEWABLE ENERGY PROCUREMENT PLAN AND ENFORCEMENT PROGRAM A. ELEMENTS OF THE RPS PROGRAM
A.1. PROCUREMENT TARGETS
Public Utilities Code Section 399.30(o), as amended by SB 350 (De Leon), directs the CEC to establish POU enforcement rules and procedures for the RPS. Unless otherwise 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 adopt and implement a Procurement Plan to demonstrate that it procures a minimum quantity of electricity products from eligible renewable energy resources, including Renewable Energy Credits (RECs). The CEC, through its formal rulemaking process, adopted multi‐year Compliance Periods and procurement targets for each calendar year (CY) through 2020. SB 350 continues the same multi‐year Compliance Period construct and establishes a 50% RPS by 2030. The CEC is scheduled to adopt the 2021 through 2030 Compliance Period and annual procurement targets in 2018. The current and proposed (*) Compliance Periods and procurement targets are outlined below:
Compliance Period
(CP)
Compliance Period Targets
CP 2
(CY 2014‐CY 2016)
Total renewable procurement for CP 2 must be equal to or greater than the sum of:
[(20% of 2014 retail sales)+(20% of 2015 retail sales)+(25% of 2016 retail sales)] 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:
[(34.8% of 2021 retail sales)+(36.5% of 2022 retail sales)+(38.3% of 2023 retail sales)+(40% 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:
[(41.7% of 2025 retail sales)+(43.3% of 2026 retail sales)+(45% 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:
[(46.7% of 2028 retail sales)+(48.3% of 2029 retail sales)+(50% 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 50% over each compliance period.
2018 Integrated Resource Plan
V. Renewable Energy Procurement Plan and Enforcement Program
Anaheim Public Utilities
A.2. PORTFOLIO CONTENT CATEGORY REQUIREMENTS
Per Section 3202(a)(2), any renewable contracts 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 allowed 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 interconnection 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.
CP 2: Minimum of 65%
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 scheduled into a CA balancing authority area.
CP 2: Maximum of 35%
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 2: Maximum of 15%
CP 3, and thereafter: Maximum of
10%
2018 Integrated Resource Plan
V. Renewable Energy Procurement Plan and Enforcement Program
Anaheim Public Utilities
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 (including the ability of the developer to secure funding), technology (i.e., new technology versus proven technology), and any other factors that can potentially delay or indefinitely postpone a project.
IR’s objective is to identify renewable projects that are viable and cost‐effective, enhance APU’s resource portfolio, and optimize each PCC in an effort to minimize overall costs.
State law requires APU to develop this Integrated Resources Plan (IRP) prior to January 31, 2019. This comprehensive plan outlines APU’s activities in order to meet a 50% RPS by 2030 and greenhouse gas (GHG) emission reduction targets. It must also address 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. Going forward, the two components of the RPS Policy, (i.e., the Renewable Energy Resources Procurement and Enforcement Plans), will be incorporated into the IRP, which will be presented for review and recommendation by the Public Utilities Board, considered for approval and adoption by the Anaheim City Council, and updated at least once every five years thereafter.
B.2 PROCUREMENT (ORIGINATION)
APU intends to demonstrate its progress in reaching its RPS targets in compliance with 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). 2018 Integrated Resource Plan
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APU has sufficient long‐term resources to meet anticipated needs. 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 mandated 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.
To date in the third Compliance Period, IR executed five (5) additional renewable energy contracts, which includes 36 MW of solar energy sourced within California. 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 every month, not only for meeting its RPS goals, but to also ensure the reliability of its distribution system. In addition, APU evaluates the viability of energy storage, demand response, and distributed generation resources to maintain grid reliability and meet the State’s overall energy policy goals.
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C. STATUS OF APU’S RPS PORTFOLIO
C.1. PROGRESS TOWARD MEETING TARGETS
APU met the Compliance Period 1 target of an average 20% of its power from renewable resources, and its Compliance 2 target of providing no less than 25% of its power from renewable resources by the end of 2016. APU is on track to meet the RPS target of 33% by 2020. Planning activities undertaken in 2017 while developing the IRP incorporate a variety of renewable resources as a way to ensure continued diversification of the portfolio while progressing toward an aggressive goal of 50% 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 grandfathered 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 development and energy production, there may be years when the APU exceeds its projected RPS targets. In order 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 for 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 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 2011‐2013 in its July 2014 compliance filing to the CEC. The second Compliance Period filing covering the years 2014‐2016 was filed ahead of the July 1 2017 deadline, and is awaiting verification from the CEC. 2018 Integrated Resource Plan
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D. POTENTIAL COMPLIANCE DELAYS
D.1 COMPLIANCE PERIOD 2 EVENTS
As discussed in Section B.1. above, in planning its renewable procurement position and needs, APU accounts for potential issues that could delay RPS compliance. Unforeseen circumstances in the future may potentially hinder APU’s ability to comply. Achieving renewable energy goals is dependent on the successful performance of renewable developers in meeting contractual obligations, completing construction milestones in a timely fashion, and achieving commercial operation. During Compliance Period (CP) 2, APU experienced delays associated with two renewable resource contracts; however, short‐term renewable energy was purchased to maintain compliance. The first contract delay was caused by the developer’s inability to secure site and fuel agreements in a timely manner, and the second contract delay was due to the difficulties the developer encountered with transmission interconnection and permitting. To the extent delays and resource underperformance occur, the amount of delivered energy which APU can rely upon to reach its goals is reduced.
APU’s forward procurement strategy includes the probability of circumstances, such as the ones outlined above, occurring, and as such, APU considers procuring additional eligible renewable resources above and beyond planned procurement to account for potential energy delivery shortfalls. 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 delay timely compliance with the RPS.
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E. COST LIMITATIONS
E.1. BACKGROUND
The State’s RPS law permits the local governing board of each POU to implement, at its sole discretion, a cost limitation for its RPS activities, consistent with Section 3206(a)(3). The City Council, in the manner set forth in this and previous versions of the RPS Policy, has implemented a cost limitation in its RPS Policy for the protection of its customers and continues to review its methodology in coordination with updates to the Procurement Plan. Previous versions of the RPS Policy included a cost limitation based on a goal of 33% renewables by 2020. APU is revising the cost limitation methodology to account for costs related to the increased State goal of a 50% RPS by the year 2030.
Through the approval and adoption of this IRP, the Anaheim City Council is implementing a cost limitation that relies on:
The most recent Procurement Plan (which is contained herein); and Procurement expenditures that approximate the expected cost of building, owning or operating eligible renewable resources, which does not include indirect expenses as described in Section 3206(a)(3)(B)(3); and
The potential that some planned resource additions may be delayed or cancelled.
This cost limitation meets all of the requirements of Section 3206(a)(3). The cost limitation value which is contained herein may be updated on a periodic basis.
E.2. SUMMARY OF COST LIMITATION ELEMENTS
APU’s cost limitation is intended to reflect current market conditions, address any disproportionate rate impacts to customers, and reflect the added costs of committing public funds to additional projects as some are delayed or permanently removed from a construction queue. The analysis for the cost limitation is calculated based on the most recent power supply forecast. The City Council, in ensuring that customers do not face a disproportionate burden, has the authority to implement a cost limitation, which may result in the temporary suspension of RPS compliance activities.
E.3. COST LIMITATION THRESHOLD
The City Council hereby approves and directs APU to implement the following RPS cost limitation threshold to prevent a disproportionate customer rate impact associated with the implementation of State‐mandated RPS procurement targets:
In no event shall the cost of procuring any new renewable energy resources cause an increase in overall power supply costs greater than $0.01 per kilowatt‐hour in any fiscal year during a 20‐year planning horizon. A $0.01 per kilowatt‐hour increase is considered to be an undue burden on customers as it 2018 Integrated Resource Plan
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represents a 10% increase over current power supply costs in a single year, which is approximately four times the expected rate of general inflation.
E.4. PROCESS FOR IMPLEMENTATION
APU continuously monitors its expenditure levels and will advise the City Council routinely of its RPS expenditures. Below is the process that APU
will follow to advise the City Council when the threshold to implement its cost limitation is met and the direction it will take, as directed by City Council:
1) APU Staff will advise City Council, via staff report, that the threshold for the cost limitation has been reached and will recommend a course of action for City Council consideration.
2) City Council, at its sole discretion, may choose to implement the cost limitation provision and direct APU to cease its activities related to RPS compliance. 3) Through the direction provided by City Council, APU will either cease its activities related to RPS compliance or continue its RPS compliance activities.
E.5. DETAILS ON COST LIMITATION THRESHOLD
This section provides background on APU’s actions, when a cost limitation threshold is reached.
1. Disproportionate Rate Impacts
APU forecasts RPS procurement costs when developing the annual power supply forecast. The forecast provides a projection of supply and demand, including costs, and provides an estimation of anticipated increases in costs. It is determined that renewable procurement costs that exceed an increase of $0.01/kWh will cause a disproportionate burden on customers. A $0.01/kWh increase is considered a disproportionate burden as it represents a 10% increase over current power supply costs in a single year, which is approximately four times the expected rate of general inflation. This cost limitation is a proactive measure which aims to prevent undue economic consequences of the RPS statute and Regulation on customers.
2. Projects Delayed or Cancelled
Per Section 3206(a)(3)(C) cost limitations can include “the potential that some planned resource additions may be delayed or canceled.”
As discussed in detail in the Procurement Plan, APU staff contracts for the required amount of RPS resources, to meet compliance obligations. However, issues outside the APU’s control (i.e., permitting, financing of the project, interconnection issues, cost 2018 Integrated Resource Plan
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projections, etc.) may delay or indefinitely postpone a project. As a POU, Anaheim must be selective when entering into contracts for renewable procurement as these contracts are associated with financial obligations and tie up public funds. The cost of the delay or indefinite postponement of any project should be included when determining detrimental rate impacts or calculating an increase to power supply costs.
3. Other Circumstances
The City Council may choose to implement additional cost limitations, consistent with the Regulation upon the occurrence of, but not limited to, the following examples:
Changes in the Regulation
In the event that the RPS Regulation is modified, there is a possibility that contracted resources may not fully count toward APU’s RPS, as anticipated. The cost of replacing the lost renewable energy that was expected to be delivered from these resources must be taken into consideration.
Force Majeure
The occurrence of a Force Majeure event which adversely impacts the delivery of renewable resources and thereby increases RPS compliance costs. It is expected that such Force Majeure events will place an undue economic burden on Anaheim as well as its customers.
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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 City 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 into the CAISO market. This may cause APU to be out of compliance for a Compliance Period. The City Council 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 resources: [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 the authority to waive APU’s compliance for this instance.
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 facility outage that prevents resources from delivering energy into the CAISO 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.
Regulatory Delays: City Council interprets this to include instances where State agencies delay timely requests by APU for registering renewable resources, certifying renewable resources, and accepting renewable resources into its 2018 Integrated Resource Plan
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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: [Section 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 balancing 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.
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 which APU evaluates a multitude of supply‐side and demand‐side resources to meet customer energy needs in an efficient, 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.
More recently, the passage of SB 350 now 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 feedback from residents, small to medium businesses, large businesses, high school students and the Latino Utilities Coalition.) 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.
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Pursuant to this 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 reduction of 0.86% between 2018 and 2030, effectively a no growth energy demand forecast, which indicates that the expected customer expansion and EV growth is being offset by customer solar installation and energy efficiency reductions.
Graph 2: Cumulative Adjustments to Base Load 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 was further adjusted (referred to as the adjusted energy demand forecast) by planned system expansion, expected EV energy demand, estimated customer‐side solar PV installation, and the effect of demand side management and energy efficiency. While system expansion and EV growth increase 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.
Base Energy Demand Forecast
+ Energy Demand Addition
•System Expansion
•EV Penetration
‐ Energy Demand Reduction
•Solar Installation
•Energy Efficiency
= Adjusted Energy Demand
Forecast
(120)
(70)
(20)
30 80GWh
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Cumulative Adjustments to Base Energy
Demand Forecast (2018‐2030)
Energy Efficiency
Solar PV
EV Adoption
Planned Expansion
Cumulative Impact on Energy Demand
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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 Business & Community Programs. Examples of such projects include City‐ wide development and expansion plans, customer‐specific capacity additions and/or energy reduction plans, and the installation of commercial‐scale solar photovoltaic (PV) 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 stabilize
in 2011 and continued to improve through 2016.
However, the corresponding demand growth was offset by behind‐the‐meter distributed generation, such as fuel cell and solar PV installation, as well as by energy efficiency in both the commercial and residential sectors.
Graph 3: Anaheim Actual Energy Demand 2001 ‐ 2016
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Base Energy Demand
Forecast
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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:
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: TEMPERATURE 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 (2011 – 2016). The forecasted monthly temperatures in degrees Fahrenheit are summarized below:
Table 1: Temperature Summary
Month Average Minimum Maximum
January 60 35 89
February 60 32 95
March 62 41 96
April 65 39 96
May 67 49 104
June 70 53 105
July 75 58 103
August 76 59 101
September 76 56 105
October 71 49 105
November 63 43 95
December 57 37 89
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VARIABLES EXCLUDED: ECONOMIC AND DEMOGRAPHIC FORECAST Anaheim is a fully developed Orange County city with historically consistent 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, and results in overly optimistic 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.
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 historical years 2013 through 2016. The forecast results are compared to historical actual values and analyzed for reasonableness. The base model was proven to produce efficient estimation results in the range of 0.4% to 2.1% variance for 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.
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 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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Historical and Base Energy Demand Forecast by Month
2012 2013 2014 2015 2016 Base Forecast
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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 open land in Anaheim is fully 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 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 33 MW capacity to Anaheim’s distribution infrastructure through 2030. When estimating the impact to load, staff took into consideration both the distribution system expansion and the varying levels of capacity factors for each customer sector.
EV PENETRATION & TRANSPORTATION ELECTRIFICATION
Electric vehicle growth is estimated using the CEC “Transportation Electrification Common Assumptions
3.0” workbook published in 20171. Anaheim’s electric vehicle energy demand forecast adopts the CEC growth assumption to meet the Governor’s Order for 1.5 million electric vehicles on the road by 2025, and assumed growth to 2.6 million electric vehicles on the road by 2030.
1 “2016 SB 350 Common Assumption Guidelines for Transportation Electrification Analysis”, Version 3.0, Updated April 6, 2017. This workbook is subsequently replaced by updated versions and no longer available via the CEC website. The most updated version is available for download at http://www.energy.ca.gov/sb350/IRPs/. A comparison of Version 3.0 and the updated version may be found under Section IX. GREENHOUSE GAS EMISSION REDUCTION.
+ Energy Demand Additions
•System Expansion
•EV Penetration
‐ Energy Demand Reductions
•Solar Installation
•Energy Efficiency & Demand Response
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According to the model within the CEC workbook, APU’s share of total California registered electric vehicles is 0.63%, or an estimated 16,280 electric vehicles by 2030.
To estimate energy demand growth, APU adopted the CEC’s assumptions in the workbook in terms of energy consumption. According to the workbook, the 16,280 electric vehicles will contribute up to 63,261 MWh in energy demand growth in Anaheim in 2030.
Graph 5: Estimated Electric Vehicle Energy Demand Growth
SOLAR INSTALLATION & OTHER DISTRIBUTED GENERATION
Historical behind‐the‐meter distributed generation information is obtained from SB 1 and City permit applications. This includes micro turbine, fuel cell, and photovoltaic (PV) installations.
Short‐term PV installation growth is estimated using system size data listed on the resident’s permit application. Long‐term PV installation growth is estimated using a linear trend of historical installation totals. APU estimates to have 33 MW of installed PV capacity by 2019, and 87 MW by 2030. To estimate PV generation, a proxy capacity factor of 18.38% is applied to the PV capacity forecast. Detailed solar PV capacity calculation and peak impact analysis may be found in the “Peak Shift Analysis” section.
In 2019, behind‐the‐meter solar distributed generation is estimated to account for 2.1% of APU’s total energy demand and is expected to grow by 0.3% annually reaching a total of 5.4% of total energy demand by 2030.
Graph 6 shows the estimated annual impact of behind‐the‐meter solar PV installation growth.
0 10,000
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2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MWh
Estimated Electric Vehicle Energy Demand
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Graph 6: Estimated Behind‐the‐Meter Solar PV Impact to Energy Demand
Planned distributed generation projects other than solar PV 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 establish 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 statewide energy efficiency savings in electricity and natural gas end uses by 2030.
APU, in conjunction with other members within the California Municipal Utilities Association, contracted with Navigant Consulting, Inc. (Navigant) to identify all potentially achievable cost‐effective electricity efficiency savings and establish annual targets for energy efficiency savings for 2018‐2027. The final report “Energy Efficiency in California’s Public Power Sector”2 was published and submitted to the CEC in 2017. Anaheim City Council adopted APU’s ten‐year energy saving goal in March 2017, based on study results from the Navigant report.
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 (Navigant Study)
* 2028‐2030 are projections based on 2027 targets. 10‐Yr Average Calculated for 2018‐2027.
APU’s voluntary demand response program is only called upon under extreme conditions, and therefore is not included in the energy demand adjustments under normal weather conditions. In addition, the
2 https://www.anaheim.net/DocumentCenter/View/11240
‐
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Net Energy Demand Solar PV
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 * 2029 *2 0 3 0 * Avg. 10 Yr. kWh 1.15% 1.15% 1.09% 1.06% 1.04% 1.00% 0.95% 0.91% 0.86% 0.80% 0.80% 0.80% 0.80% 1.00% kW 1.11% 1.12% 1.13% 1.15% 1.19% 1.14% 1.15% 1.13% 1.09% 1.04% 1.04% 1.04% 1.04% 1.13% Targets w/ C&S
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pilot residential demand response program generated 794 kWh savings in summer 2017. It is considered negligible to APU’s total energy demand at this time. Estimated adjustments for demand response reductions will be calculated when future program expansion demonstrates greater impact to the total energy demand.
A.3. ADJUSTED BASE ENERGY DEMAND FORECAST
In total, APU expects a 0.86% net energy demand reduction between 2018 and 2030, which is essentially a no growth forecast. 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 82 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 approximately 102 GWh cumulatively. The overall cumulative net energy demand reduction is estimated to be approximately 20 GWh as indicated by the red line on Graph 2.
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 bar. The total Reductions are displayed by both the light green and 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.
Base Energy Demand Forecast
+ Energy Demand Addition
•System Expansion
•EV Penetration
‐ Energy Demand Reduction
•Solar Installation
•Energy Efficiency
= Adjusted Energy Demand
Forecast
(120)
(70)
(20)
30 80GWh
GWh
Cumulative Adjustments to Base Energy
Demand Forecast (2018‐2030)
Energy Efficiency
Solar PV
EV Adoption
Planned Expansion
Cumulative Impact on Energy Demand
Graph 2: Cumulative Adjustments to Base Load Forecast
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Graph 7: Adjusted Base Energy Demand Forecast
APU’s energy demand forecast was completed in 2017. The CEC released its energy demand forecast for the 2018 Integrated Energy Policy Report (IEPR) in February 2018. Staff compared APU’s adjusted (or expected) energy demand – excluding EV Impacts – against the IEPR demand forecast: Medium Baseline Demand with Medium Additional Achievable Energy Efficiency (AAEE) and Additional Achievable Photovoltaic (AAPV). APU’s forecast is very close to the IEPR forecast in the early years, with a 4% variance observed by 2030. The difference is considered acceptable for planning purposes. In addition, a range of high and low energy demand will be tested under Resource Portfolio Evaluation – Stress Testing.
Graph 8: APU vs. IEPR Energy Demand Forecast
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
A.4. OTHER CONSIDERATIONS ‐ 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‐Adapt3 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 than 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 for the spring and summer of 2023. 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.
Graph 9: Cal‐Adapt vs APU Maximum Temperature Forecast
The econometric model described in VI.A.1. estimates a coefficient of 1.16 MWh for the temperature variable. This is interpreted as an increase in energy demand of 1.16 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 23.2 MWh. Applying the extreme temperature forecast to the economic model produces a bandwidth of expected energy demand under high and low temperature extremes.
3 http://cal‐adapt.org/
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
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 81 GWh annually, with the highest monthly impact in the month of October of 8.2 GWh. The low weather extreme results in a decrease from expected energy demand of 71 GWh annually, with the largest decrease being in the month of February of 7.5 GWh.
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.
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
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 Resource Adequacy capacity needed 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.
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 2008 to 2011, the total system peak has fluctuated over the past several years between 540 and 580 MWh. Anaheim’s annual system peak is typically observed in the month of September, when temperatures average 76 degrees and reach up to 105 degrees.
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 440
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
most recent five years. The load factors are applied to the adjusted monthly energy demand forecast to develop the peak demand forecast.
Table 3: Historical Load Factors (as of December 2017)
Month 2013 2014 2015 2016 2017 AVERAGE
July 68% 67% 66% 69% 62% 66%
Aug 68% 60% 65% 65% 63% 64%
Sept 63% 59% 59% 60% 58% 60%
Oct 57% 72% 62% 59% 50% 60%
Nov 67% 70% 66% 79% 62% 69%
Dec 78% 77% 88% 78% 80%
Jan 80% 73% 79% 78% 77%
Feb 80% 77% 72% 69% 74%
Mar 75% 76% 68% 75% 74%
Apr 77% 66% 62% 68% 68%
May 58% 55% 61% 75% 62%
June 64% 74% 66% 54% 64%
The peak demand forecast is validated by comparing the model’s “backcast” output to the previous five year’s actual data. The peak forecast’s accuracy to predict monthly peak is between 0.3% and 3.5%. The annual peak forecast accuracy was in the range of ‐1% to 5% and within the acceptable confidence level.
B.3. OTHER CONSIDERATIONS
Peak Shift
APU estimates to have 33 MW of installed PV capacity by 2019 and 87 MW by 2030. Graph 12 details the estimated installed PV capacity for APU’s service territory.
Graph 12: Estimated Distributed (Behind‐the‐Meter) Solar PV Capacity
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VI. Energy Demand and Peak Forecasts
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To develop an estimation methodology for customer‐owned, behind‐the‐meter solar PV generation, APU studied the solar generation from the City‐owned Anaheim Convention Center solar PV system. The system generates approximately 3,400 MWh of solar energy per year (as recorded in 2015 and 2016), and has a capacity factor of 18.38%.
On average, July produces the highest generation per year, with 12.5 MWh per day. The month of December produces the least amount of generation per year, on average with 4.75 MWh per day. Graph 13 details each month’s average hourly solar profile, as derived from the generation of the Anaheim Convention Center solar PV system. Peak solar generation is at noon November through March 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 PV 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 18.38% capacity factor is applied to PV capacity data collected from SB 1 applications and City permits. Graph 14 details the estimated monthly distributed solar generation in 2016, and its effect on APU energy demand. The total estimated effect on energy demand using the proposed methodology for 2016 was 26,235 MWh, or a 1% reduction of Anaheim’s total energy demand.
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
Graph 14: Estimated Distributed (Behind‐the‐Meter) Solar PV Impact to Energy Demand
The profile for distributed solar generation can also be estimated using the convention center solar shape. Graph 15 details the estimated average hourly shape for total distributed solar generation for 2016, 2019 and 2030.
Graph 15: Estimated Average Hourly Shape for Distributed Solar Generation
The estimated solar shape was applied to the daily energy demand forecast to estimate the future peak shift for APU energy demand. Assuming distributed solar grows as expected; there is a corresponding peak shift from hour 17 to 19 by 2030 as depicted in Graph 16 below. Peak demand is estimated to shift from hour 17 in 2016 to hour 18 in 2019, and hour 19 by 2030.
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VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
Graph 16: Peak Demand Shift
In addition to shifting the traditional peak hour, the solar PV penetration will also result in a peak reduction of approximately 2 MW every year throughout 2030. Graph 17 details the estimated cumulative impact to peak demand due to solar growth.
Graph 17: Estimated Annual Peak Demand
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 energy reduction measures such as energy 150
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Base Peak Demand Adjusted Peak Demand w/Solar PV Growth 2018 Integrated Resource Plan
VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
efficiency and demand response programs. The 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 2017, the Intermountain Power Plant (IPP)4 underwent a scheduled maintenance outage for most of the month, which caused a significant reduction in generation capacity.
The energy need was replaced by two firmed and shaped renewable contracts, supplemented with ample wind and hydro energy that was available during the same month. On April 16, 2017, APU’s 246 MW peak was served by 80% or 195 MW of renewables.
Graph 18: 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 employed its voluntary residential demand response events in summer 2017 to reduce energy demand; however, additional energy was still needed in the hot and humid summer days.
On September 1, 2017, APU reached a system peak of 562 MW; more than double the system peak in the previous example. During the peak hour, only 11% or 60 MW of renewable energy was available to meet the demand for various reasons, which included:
De‐rated landfill and geothermal generating units due to extreme heat; Small hydro producing less than 60% of April energy output; and Near zero wind output.
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 orange bars in Graph 19 indicate the thermal (non‐renewable) energy APU sold into CAISO market, per market dispatch signals.
4 Details of the power plant may be found in Section VIII.B. Generation and Transmission Resources Renewables
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Renewable | Retail Thermal | Retail Thermal | Wholesale Utility Customer Load 2018 Integrated Resource Plan
VI. Energy Demand and Peak Forecasts
Anaheim Public Utilities
Graph 19: 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. Energy storage is periodically evaluated; 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 weather analysis using the load factor methodology, as described in VI.B.2. DEVELOPING THE PEAK FORECAST. Graph 20 displays the impact of extreme temperatures on peak demand. On average, peak demand is estimated to be 14 MW higher with extremely high temperatures, with the highest impact of 18 MW in October. Similarly, peak demand is estimated to be 12 MW lower with extremely low temperatures, with the highest impact of 15 MW in October.
Graph 20: Forecasted Peak demand with Extreme Temperatures
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VII. Resource Portfolio Evaluation
Anaheim Public Utilities
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 current technology and market intelligence regarding resource availability. These supply‐side options were then screened to filter out the non‐ viable scenarios given APU’s planning goals, and the remaining scenarios were analyzed using extensive quantitative production cost modeling analysis. The model outputs were scored and stress tests performed before a final portfolio was recommended. Graph 21 below summarize the selection process used to choose the optimum resource additions needed to satisfy customer demand and reliability and sustainability goals:
Coal to Clean Energy Transition
2018 Integrated Resource Plan
VII. Resource Portfolio Evaluation
Anaheim Public Utilities
Graph 21: Selection Process of the Optimum Resource Portfolio
The selection process started with Section A. Portfolio Consideration and Performance Measures followed by Section B, the consideration of Resource Options. Components of the model analysis are outlined in Sections C. Model Analysis – Production Cost Model, D. Model Analysis – Input Assumptions, and E. Model Analysis – Output Evaluation. The resource portfolios under evaluation also went through a series of Stress Testing in Section F, before the optimum portfolio is recommended in Section G.
A. Portfolio
Considerations &
Performance
Measures
•Optimize Existing
Resources
•GHG Reduction;
50% Renewables
•Regulatory
Compliance
•Reliability;
Diversification
•Expected Cost;
Market Risk
B. Resource
Options
•Natural Gas
Resources
•Market Purchases
•Renewable
Resources
•Baseload,
Intermittent or
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•Energy Storage
C. D. & E. Model
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•Input
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Properties,
Market Outlook
•Dispatch Model
Simulation
•Output
Evaluation
•GHG Reduction,
Renewable %,
Reliability,
Production Cost
F. Stress Testing
•Market Volatility
•High/Low Fuel,
Energy, Carbon
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•Customer
Demand Variation
•High/Low
Temperature,
Solar, EV, Energy
Efficiency
G. Optimum
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2018 Integrated Resource Plan
VII. Resource Portfolio Evaluation
Anaheim Public Utilities
A. PORTFOLIO CONSIDERATION AND PERFORMANCE MEASURES
A.1. COAL‐TO‐CLEAN ENERGY TRANSITION
Prior to the heightened awareness about carbon intensive fuels on the environment as a result of GHG emissions, APU was fully resourced to meet local energy demand with long‐term, low‐cost, and base‐loaded coal‐fired power plants. Coal‐fired power plants were historically a preferred resource nationally due to the abundance of coal as a fuel, its low cost, and the reliable coal generation technologies available to produce electricity. Also, in the 1980s, nuclear energy was out of favor, due to the waste issue and the associated capital risk, and it was illegal to use 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 very well 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 the carbon intensive resource mix to clean renewable energy since 2003, as it has increased renewable energy from 1% to 29% while reducing coal power from 73% to 32%. Today, APU’s resource stack is very different from the historical view, with a much greater percentage of retail energy demand met by sustainable energy. The following graphs show change in APU’s power supply resource stack over the past decade, from 2006 to 2016:
Graph 22: APU Resource Stack in 2006
Note: Generation above the retail energy demand was sold into the CAISO wholesale energy market.
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VII. Resource Portfolio Evaluation
Anaheim Public Utilities
Graph 23: APU Resource Stack in 2016
Note: Generation above the retail energy demand represents energy sold into the CAISO wholesale energy market.
Roughly one‐third of APU’s 2017 energy supply still came from two coal plants – San Juan Power Plant and Intermountain Power Project (IPP). APU successfully negotiated the divestiture of the San Juan coal plant at the end of 2017, which was 5 years prior to the original contract termination date. APU has also taken action to allow its IPP coal contract to expire without renewal effective 2027, at which time APU will have divested of all coal resources.
The divested coal resources 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, APU used quantitative performance measures and production cost modeling to evaluate the portfolio scenarios pursuant to its planning goals, as briefly mentioned in Section III. Planning Goals
B.2. PORTFOLIO PERFORMANCE MEASURES
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 integrated resource planning process maintains three main planning goals to achieve the organizational mission: Sustainable Resources, High Reliability, and Affordable Rates. 0 500
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VII. Resource Portfolio Evaluation
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Achieve at Least a 50% RPS
The RPS is measured by the percentage of renewable energy delivered to serve retail load. Portfolios considered must contain at least 40% eligible renewable energy by 2024, 45% by 2027 and 50% by 2030.
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 procured a sufficient amount of renewable energy contracts to meet RPS compliance up to year 2025. However, in order to meet renewable compliance obligations post‐2025, APU will need to either extend the terms of its current renewable contracts, or procure new contracts. Graph 24 details the historical and planned renewable compliance targets.
Graph 24: Historical and Planned Renewable Energy
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• 40% GHG
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•R e s o u r c e
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• Portfolio
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•M a r k e t Risk
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VII. Resource Portfolio Evaluation
Anaheim Public Utilities
Greenhouse Gas Emission Reductions
Greenhouse gas emission reductions are measured by the percent of GHG reduction for the overall resource portfolio. Portfolios considered must meet the GHG emissions reduction targets ultimately established by the California Air Resources Board (CARB) that achieves the economy‐wide greenhouse gas emissions reductions of 20% below 1990 levels by 2020, and 40% below 1990 levels by 2030.
With the planned exit of IPP, APU is on track to meet its internal GHG reduction planning goals of 480,000 MTCO2e by 2020 and 920,000 MTCO2e by 2030, a 20% and 40% reduction, respectively. Graph 25 details the planned GHG reductions with and without the GHG emissions reductions expected from vehicle electrification. Due to the divestiture of coal units, APU is on track to meet internal GHG reduction planning goals without any changes to its remaining power resouces. Since the replacement energy is needed due to APU’s exit from IPP, it will be replaced with non‐emitting resouces, the estimated GHG reduction as displayed in Graph 25 will remain consistent for any renewable replacement options.
Graph 25: Planned GHG Reduction
Regulatory Risk
Regulatory Risk measures the ability to remain compliant with current and anticipated future legislative or regulatory changes. The State’s RPS targets have steadily increased over the past several years; therefore, this IRP considers the likelihood of higher renewable energy requirements in the future. 600
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VII. Resource Portfolio Evaluation
Anaheim Public Utilities
For example, Senate Bill 100 was introduced in the 2017 legislative session requiring electric utilities to achieve a 60% RPS by 2030. It also contains language seeking to require that eligible renewable energy resources and other zero GHG‐emitting resources supply 100% of retail energy sales no later than December 31, 2045. As of the writing of this IRP, the bill remains active in the legislature.
The optimum portfolio should have enough flexibility to absorb additional renewable purchases beyond the current 50% RPS requirement. Also, the optimum portfolio should be sufficiently diversified so that APU minimizes technological risk where one technology becomes obsolete or less cost‐effective.
Resource Adequacy (Reliability)
Resource Adequacy is measured by the ability to achieve a 15% reserve margin above the system peak forecast while meeting forecasted local and flexible capacity requirements.
Resource portfolios not achieving this measure are still included for consideration by identifying future capacity shortages
and planned capacity purchases. Costs for capacity purchases are added to the portfolio.
Graph 26: Available Resource Adequacy (RA) System Capacity
Graph 26 illustrates the resources APU may use to meet Resource Adequacy requirements. Although APU exited San Juan in 2017, ample capacity from renewable resources is available to replace the 50 0 100
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Intermountain Units 1 and 2 Magnolia Peak Magnolia Base Canyon Power Plant Anaheim CTG Geothermal Raser Thermo
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Brea Power Partners System Capacity Requirement
250 MW Capacity Needs
after IPP Divestiture
2018 Integrated Resource Plan
VII. Resource Portfolio Evaluation
Anaheim Public Utilities
MW previously provided by San Juan. When APU exits IPP in 2027, 250 MW of capacity will need to be procured to ensure resource adequacy and system reliability. The new capacity can be in the form of new energy resources with capacity, capacity‐only purchases, or both.
Canyon Power Plant and the Bowerman and Brea landfill gas‐to‐energy plants are long‐term and reliable resources located in and 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 coal contract, is system‐wide capacity that may be produced anywhere in the 14 western states as long as it is deliverable to California. Current system‐wide capacity markets indicate that this product is abundantly available at a much lower cost than building new peaking power plants or utility scale energy storage facilities. This is due to the great number of new renewable energy facilities being added system‐wide.
APU plans to procure the requisite Resource Adequacy at least two years prior to the expiration of the IPP contract through competitive solicitations; however, APU will continue to monitor the capacity markets as compared to the cost of constructing new capacity facilities locally. Given the relatively small amount of Resource Adequacy capacity needed by APU, the abundance of capacity available for purchase, the Regulatory Risk of constructing new natural gas peaking power plants that may become obsolete if State law requires 100% emission‐free resources, and the potential for a technological breakthrough that would significantly reduce the cost of energy storage, APU does not recommend committing to new Resource Adequacy facilities at this time. Also, should the cost of Resource Adequacy capacity increase significantly prior to 2027, APU has the option of investing to extend the life of the Kraemer Power Plant or build new generation facilities at the Canyon Power Plant site.
Portfolio Diversification
Portfolio diversification is measured by the different types and length of resource investment within the portfolio. A diversified resource portfolio increases flexibility, reliability, and overall performance.
APU’s 2018 renewable portfolio consists of 15% intermittent resources and 85% baseload resources.
The baseload resources are very reliable and do provide local Resource Adequacy capacity, but the cost of these resources is now significantly greater than intermittent resources such as solar and wind and APU’s local capacity requirements are satisfied with existing resources. Due to APU’s substantial investment in baseload renewable resources in the early years of the RPS Program, diversity is now an important consideration in the development of the optimum resource portfolio.
Expected Cost
Expected Cost is measured by the total cost to supply power. Each resource portfolio is evaluated with a
goal to minimize impacts on customer bills and to serve customers at just and reasonable rates. 2018 Integrated Resource Plan
VII. Resource Portfolio Evaluation
Anaheim Public Utilities
As previously discussed, APU has been and continues to be fully resourced to meet local demand with long‐term baseload power plants. Any costs associated with additional 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 Risk
Market Risk is measured by 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 percentage of energy is procured from the wholesale market.
With 236 MW of capacity, IPP meets the largest portion of APU baseload energy needs, with the remainder baseload energy demand supplied by the natural gas and renewable generation facilities. The predictable cost structure of a baseload unit protects the resource portfolio from price swings in the wholesale market. The replacement energy needs resulting from APU’s exit from IPP will come from renewable energy resources. Because of the intermittent 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 such as wind and solar 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 sales of energy. Conversely, at times when energy demand exceeds the amount of generation available, market 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 outperforms the alternatives under all market cost and load growth/reduction scenarios.
2018 Integrated Resource Plan
VII. Resource Portfolio Evaluation
Anaheim Public Utilities
B. RESOURCE OPTIONS
B.1. IPP REPLACEMENT OPTIONS
With extensive quantitative analysis, this IRP examines several scenarios for replacing the energy resulting from the exit of coal resources. Replacing the coal power plants with a new natural gas power plant or wholesale market purchases would be carbon heavy and costly. APU will still have a need to purchase renewable energy to meet the State’s environmental goals; therefore, replacing energy needs resulting from APU’s exit from coal power plants with renewable energy is the most optimal solution.
Graph 27 shows the screening process used to evaluate the options for replacing the IPP coal plant. Replacing IPP with a natural gas power plant (Scenario 1) or wholesale market purchases (Scenario 2) would still be carbon heavy as compared to renewables and would be costly because APU would still need to purchase renewable energy to meet the State’s 50% mandate, resulting in “over‐procurement.”
Graph 27: IPP Replacement Options
Graph 28 shows that a new natural gas plant is not viable given APU’s sustainability goals and State regulatory requirements. As an example, the Variable Portfolio is one of the renewable portfolios being evaluated to replace IPP. It is more costly to maintain a natural gas power plant while also acquiring renewable energy to meet the sustainability goal.
IPP Coal
Replacement
Scenario 3:
Renewables
Lower Costs;
Sustainable
Scenario 2:
Wholesale Market
Purchases
Over‐Procurement
Carbon Heavy
Scenario 1:
Gas Unit
Over‐Procurement
Carbon Heavy
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Graph 28: New Power Supply Options – Cost Comparison
*Net power supply costs excludes transmission and wholesale energy revenues
B.2. RENEWABLE OPTIONS
Determine Renewable Generation and Capacity Needs
Staff went through the following steps to determine the renewable generation and capacity needs to meet RPS targets.
1. Determine Annual RPS Targets
In developing the candidate portfolios, the first step was to calculate the amount of renewable energy needed to meet the RPS targets. RPS targets are statutorily established and in the case of publicly owned utilities like APU, are enforced by the CEC. These targets 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 (“REC”) as they are produced. APU has banked RECs produced in excess of RPS compliance requirements to date, intends to continue banking surplus RECs for future use, and will use such surplus to help satisfy its future RPS compliance targets in the most cost‐effective manner possible. $245,000
$265,000
$285,000
$305,000
$325,000
$345,000
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Thousands
New Power Supply Options ‐ Cost Comparison
Variable Portfolio New Natural Gas Plant
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As detailed in the green bar on Graph 29, the renewable generation forecast indicates that APU will have procured a sufficient amount of renewable energy to meet its RPS obligations through 2026. In order to meet compliance obligations after 2026, APU will need to negotiate extensions of existing contracts or procure new 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 resources under contract for more than 10 years in length, shown by the blue dotted line on Graph 29. Currently, most of APU’s renewable energy comes from resources under long‐term contracts. However, post‐2026, APU will need to secure additional long‐term renewable contracts in combination with short‐term renewable purchases in order to meet this compliance obligation.
Graph 29: Simulated RPS Compliance Requirement
3. Determine New Contract Size and Implementation Dates The next step in the development of candidate portfolios for consideration was to identify a timeline for new contract implementation and capacity purchases to replace the capacity lost with the divestiture of IPP. It is less expensive to purchase capacity than to over‐procure renewable generation. As such, future renewable contracts were incrementally layered into APU’s portfolio to meet renewable targets, and the capacity shortfall is planned to be covered with capacity purchases as discussed under the Resource Adequacy performance measure section.
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APU identified replacement energy from the responses to the SCPPA Request for Proposals5 for renewable generation. This list was developed based on the knowledge of expected costs and availability of a larger list of possible clean power supplies. The likely resources are:
• Wind (intermittent)
• Solar (intermittent)
• Geothermal (baseload)
• Biomass (baseload)
• Landfill Gas (baseload)
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%, 27%, and 25%, respectively). Table 4 below is an example of the estimated capacity required from all baseload, solar, or wind contracts. As expected, there is a much higher amount of megawatt capacity that must be procured if selecting intermittent resources. If APU procured only baseload renewables, it would need to procure a 15 MW contract, as opposed to 45 MW of solar or 55 MW of wind to generate the same amount of energy as a 15 MW baseload generation resource. Table 4 summarizes the amount of renewable capacity required for each resource type to meet RPS energy requirements:
Table 4: Renewable Capacity Required to Meet RPS Target Baseload Contracts Only (MW) 2027 2028 2029 2030
Baseload 1 5 5 5 5
Baseload 2 5 5
Baseload 3 5
Total Baseload 5 5 10 15
Solar Contracts Only (MW) 2027 2028 2029 2030
Solar 1 10 10 10 10
Solar 2 25 25
Solar 3 10
Total Solar 10 10 35 45
Wind Contracts Only (MW) 2027 2028 2029 2030
Wind 1 15 15 15 15
Wind 2 25 25
Wind 3 15
Total Wind 15 15 40 55
5 http://www.scppa.org/page/RFP‐Request‐for‐Proposals‐Archives 2018 Integrated Resource Plan
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Renewable Portfolios Evaluated
Baseload Portfolio (Baseload Renewables)
The first candidate portfolio replaces coal generation with baseload renewable resources such as geothermal, biomass or biogas. Baseload resources are reliable and stable, which translates to less capacity needed to generate the same amount of energy as intermittent resources. However, these resources are expensive compared to intermittent resources like wind or solar. APU’s most recent biogas resource price is $91/MWh, compared to recent offers of $37/MWh for solar and $45/MWh for wind resources in 2017.
Mixed Portfolio (50% Intermittent/50% Baseload Renewables) The second candidate portfolio replaces coal generation with 50% intermittent renewable resources and the other 50% with baseload renewable resources. This option provides the benefit of stable generation and lower cost resources.
Variable Portfolio (100% Intermittent Renewables)
The third candidate portfolio replaces coal generation with fully intermittent renewable resources and provides the advantage of procuring the lowest cost renewable resources currently available. It is called the “Variable” Portfolio due to the fact that the existing APU renewable mix is mostly composed of baseload resources. Adding more intermittent resources would inherently make the portfolio more balanced.
The candidate portfolios described are referred to from here on forward as the Baseload Portfolio, Mixed Portfolio and Variable Portfolio, respectfully.
IPP
Replacement
Variable Portfolio:
100% Intermittent
Mixed Portfolio:
25% Wind
25% Solar
50% Geothermal/Biogas
Baseload Portfolio:
100%
Geothermal/Biomass/Biogas
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B.3. ENERGY STORAGE
Energy storage may be used to facilitate the integration of unpredictable intermittent resources such as wind and solar energy; however, energy storage itself is not a renewable resource. APU is a distribution utility operating under the CAISO supply/demand balancing authority, and, as such, the CAISO requires APU to provide certain levels and types of Resource Adequacy capacity given its profile of resources used to serve APU’s load. The baseload renewable resources procured by APU provide adequate Resource Adequacy capacity, and energy storage has not been required to integrate APU’s renewable resource portfolio. Nevertheless, energy storage may play a more significant role in the future should technological breakthroughs make energy storage a viable replacement for the lost Resource Adequacy capacity upon the expiration of the IPP coal contract in 2027.
Pursuant to the requirements of Assembly Bill 2514 (Skinner, Chapter 469, Statues of 2010), APU submitted to the CEC on September 30, 2017 its latest re‐evaluation of energy storage (ES) system procurement targets. Please see the City of Anaheim’s Energy Storage Resolution No. 2017‐142, Staff Report, and Updated Energy Storage System Plan for the detailed evaluation on the CEC website at AB2514 ‐ Anaheim6 or AB2514 ‐ CEC ‐Energy Storage7.
Currently APU has a procurement target of up to 11 MW of energy storage (ES) by December 31, 2026, subject to Anaheim City Council authorization for future capital expenditures. The 11 MW target consists of a 1 MW ES pilot project at Harbor Substation, to be completed by December 31, 2021, and depending on the results of the pilot project and future ES technologies, up to 10 MW of additional ES installation at Canyon Power Plant by December 31, 2026.
Based on APU’s analyses, ES currently has a limited effect in its ability to shift energy from one time period to another in the CAISO wholesale electricity market. However, APU studied the potential for ES to provide ancillary services. The costs of regulation and spinning reserves in the CAISO market for APU have increased significantly from 2014 to 2016. Since ancillary services are much smaller in megawatt volume compared to energy products, current battery ES technologies, particularly the Lithium‐Ion technology, may be a potentially viable and cost‐effective means to self‐provide ancillary services. The 1 MW ES pilot project and continued monitoring of ancillary service costs will help determine the feasibility of these benefits for future ES projects, and whether or not market conditions dictate potential acceleration of upcoming projects.
APU considers taking incremental steps towards integrating ES within its local grid to be prudent as solar and wind generation is projected to increase over time resulting in excess generation during certain times of the day. The 1 MW ES pilot project will allow APU to gain first‐hand experience and validate the conceptual assumptions for future ES deployments. With the pilot project being completed, APU expects to have more data and experience on how to optimize the operation of ES and demonstrate value to APU customers prior to seeking City Council approval on future ES procurement.
6 http://www.energy.ca.gov/assessments/ab2514_reports/City_of_Anaheim/ 7 http://www.energy.ca.gov/assessments/ab2514_energy_storage.html 2018 Integrated Resource Plan
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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 and demand response resources, energy storage, transportation electrification, short‐term and long‐term electricity, electricity‐related, and resource adequacy products.
Energy efficiency, demand response and transportation electrification are considered in the demand forecast and model stress tests.
As previously discussed, APU has established a procurement target of up to 11 MW of energy storage by December 2026, should the 1 MW pilot energy storage project be deemed feasible, suitable and cost‐effective. This pilot project will be used to identify potential uses such as the ability to self‐provide ancillary services. In this IRP, energy storage is incorporated as a component to reduce Ancillary Service charges.
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 from the present through 2030. The following graphic shows the elements of the production cost modeling process:
INPUT ASSUMPTIONS
The main input assumptions include energy demand, resource constraints and costs, and fuel and carbon prices.
APU’s energy demand was developed under Section VI. Energy Demand and Peak Forecasts. APU has a licensing agreement for a production cost model that contains information of other utility areas’ energy •Energy Demand
•Generation, Transmission
and Other Resources
•Market Conditions (Fuel,
Carbon)
Model Input
Assumptions
•Deterministic Model
Run
•Hourly Dispatch
Model
Simulation
•Resource Dispatch &
Generation
•Wholesale Energy
Prices
•Portfolio Costs
Model Output
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demand forecast, and the generation, transmission, and other resources such as energy storage and demand response.
The production cost model has an extensive database of the Western Interconnect that includes extensive grid‐wide data such as hydro conditions, fuel prices, heat rates, maintenance schedules, area demand, emissions, transmission constraints, and variable and fixed unit costs. The model obtains grid‐ wide data via publically available sources from the North American Electric Reliability Corporation (NERC), the Energy Information Administration (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 carbon allowance costs to reflect the most updated information. Key input assumptions are detailed in D. Model Analysis – Input Assumptions.
MODEL SIMULATION
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 the database, portfolio simulations or model runs are conducted. As an example, Graph 30 illustrates the system diagram for hour 13 on January 8, 2017, including the energy flow from between balancing areas containing loads and resources. The energy demand is displayed within the utility bubble (APU is within the Southern California Edison Company – SCE – territory); 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 green 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, unit 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.
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Graph 30: System Diagram
MODEL OUTPUT
With the input assumptions and model simulation, the production cost modeling software will produce the model output including the following:
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 evaluated 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.
CAISO UTILITY SCALE RENEWABLES
Without a corresponding increase in demand, the surge of utility scale renewables on the Grid has caused wholesale energy prices to decline. Graph 31 illustrates the average hourly energy price at SP‐158 for 2013 through 2017. Between 2013 and 2017, the average SP‐15 price dropped from $44.9/MWh to $31.5/MWh.
Graph 31: Average Annual SP‐15 Energy Price
While the model has a detailed database of newer renewable resources that are currently in operation, it does not include all planned resources that are expected to come online in the future. By incorporating the planned CAISO interconnection projects for solar capacity and energy storage into the production cost model, the impact of new utility‐scale solar on market prices is captured.
Graph 32 below details the total solar and energy storage capacity that is anticipated to come online for 2017 through 2022. This data was obtained from the CAISO’s published Grid Generation Queue as of June 2017.
8 South of California transmission Path 15, a CAISO pricing zone covering Southern California. $0
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Graph 32: CAISO Interconnection Projects
EXISTING RESOURCES
For each APU resource or contract, staff examined the generic data in the model, and updated model input where necessary. The information updated may include heat rate, minimum run time, start‐up time, fuel type, variable costs, fixed costs, emission factor, capacity, capacity shape, planned outages, area, resource beginning and end date, and any other information that impacts the unit dispatch.
NEW RENEWABLE RESOURCES
1. Renewable Percentage and Contract Terms
Renewable energy was assumed to meet current regulatory requirements of 50% renewable energy by 2030. Post 2021, 65% of renewable generation was assumed to come from resources with long‐term contracts, defined as 10‐years or longer contract terms.
New resources were layered into the portfolio over several years, which strategically meet all compliance goals while keeping costs and potential over‐generation minimized. Table 5 details the new resources layered into the production cost model for each scenario. Contract terms were assumed to be 20 years.
Table 5: New Resource Capacity by Candidate Portfolio
* Intermittent resources were modeled as wind energy to offset the larger proportion of solar energy in Anaheim’s portfolio post 2027.
1.3 GW
2.2 GW
5.3 GW
8.7 GW
4.7 GW
.4 GW.5 GW
1.5 GW 2.1 GW
.7 GW .4 GW
0.0 2.0
4.0 6.0
8.0 10.0
2017 2018 2019 2020 2021 2022
GW
Planned Solar Capacity
Planned Battery Storage Capacity
Baseload Portfolio 2027 2028 2029 2030
Baseload Contract 1 5 5 5 5
Baseload Contract 2 5 5
Baseload Contract 3 5
Mixed Portfolio 2027 2028 2029 2030
Baseload Contract 1 5 5 5 5
Intermittent Contract 1 10 10
Baseload Contract 2 5 5
Variable Portfolio 2027 2028 2029 2030
Intermittent* Contract 1 15 15 15 15
Intermittent Contract 2 25 25
Intermittent Contract 3 15
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2. Renewable Resource Price
Price estimates for baseload resources were mapped to APU’s most recent baseload resource signed in 2017. Price estimates for intermittent resources were mapped to the responses obtained from a 2017 Request for Proposal administered by Southern California Public Power Authority (SCPPA). Resources assume a 2% price escalation rate, following industry common practice.
3. Resource Generation Profile
Resource shapes were mapped to existing contracts. Baseload, solar and wind resources were mapped to the most recent geothermal, solar and wind contracts in APU’s portfolio, respectively.
NATURAL GAS PRICE
Natural gas prices were derived from the Intercontinental Exchange (ICE) Henry Hub gas forward prices and adjusted for basis differential between Henry Hub and the SoCal City Gate. An escalation rate of
1.65% is applied to develop the expected gas forward curve.
CAP AND TRADE ALLOWANCE PRICES
This IRP assumed the continuation of freely allocated carbon allowances for retail sales compliance and APU’s practice of purchasing carbon allowances for compliance obligations associated with any wholesale electricity purchases assuming an escalation rate of 5% + the Bureau of Labor Statistics Consumer Price Index (CPI).
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E. MODEL ANALYSIS – OUTPUT EVALUATION
Market simulations were conducted for each candidate portfolio. All input assumptions were consistent, with the exception of the new renewable contracts layered into each portfolio. This allows the most accurate comparison between portfolios. The candidate portfolio’s model simulation results were analyzed and scored based on the six performance measures.
The analysis results are summarized in this section, with supporting information in Appendix C – Portfolio Evaluation Details.
50% RPS & 40% GHG REDUCTION
PERFORMANCE MEASURE VARIABLE MIXED BASELOAD
RPS and GHG Compliance 3 1 2
Legend: 3=Best, 2=Middle, 1=Worst
Each portfolio meets RPS and GHG targets, as shown in Graph 33 and Graph 34. While each portfolio performed equally in meeting renewable portfolio standards, the Baseload Portfolio and Mixed Portfolio produce slightly more GHG than the Variable Portfolio. By 2030, the Mixed Portfolio is estimated to produce 10,150 MTco2 more than the Variable Portfolio. The Baseload Portfolio is estimated to produce 2,551 MTco2 more than the Variable Portfolio. Because all three portfolios equally meet RPS compliance targets, they are ranked in order of the best portfolio having the least amount of GHG emissions. Using this raking strategy, the Variable Portfolio performed the best, followed by the Baseload Portfolio and then the Mixed Portfolio
Graph 33: Candidate Portfolio Results: RPS Compliance
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RPS Compliance
Variable Portfolio Mixed Portfolio Baseload Portfolio RPS Mandate
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Graph 34: Candidate Portfolio Results: Forecasted GHG Reduction
REGULATORY RISK
PERFORMANCE MEASURE VARIABLE MIXED BASELOAD
Regulatory Risk 3 2 1
Legend: 3=Best, 2=Middle, 1=Worst
As discussed in Section A. Portfolio Consideration and Performance Measures, to achieve the least amount of Regulatory Risk, the preferred resource portfolio should have enough flexibility to absorb additional renewable purchases beyond the current 50% RPS requirement. The preferred portfolio should also be sufficiently diversified so that APU minimizes the technological risk where one technology becomes obsolete or less cost‐effective.
To address the potential for higher RPS targets, APU recommends the portfolio with the lowest power supply cost and the highest degree of diversification, which is the Variable Portfolio. Please refer to the Expected Cost and Diversification sections below for details.
RESOURCE ADEQUACY
PERFORMANCE MEASURE VARIABLE MIXED BASELOAD
Resource Adequacy 1 2 3
Legend: 3=Best, 2=Middle, 1=Worst
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2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Metric Tons of CO2e
(Thousands)
GHG Reduction
Variable Portfolio Mixed Portfolio
Baseload Portfolio GHG Reduction Target
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System Capacity
Although the new resources in each candidate portfolio will contribute to system capacity, these purchases will not likely be sufficient to meet all resource adequacy requirements. The baseload, solar, and wind contracts are estimated to have a capacity factor of 95%, 27%, and 21%, respectively. The system capacity values for each portfolio are summarized in Table 5: New Resource Capacity by Candidate Portfolio.
Graph 35 details the monthly capacity shortfall for each candidate portfolio. In the short run for years 2027‐2030, the capacity shortfall is very similar between all three portfolios. Post 2030, the differences become larger and the Variable Portfolio has the largest shortfall of capacity, followed by the Mixed and Baseload Portfolios, respectively.
Graph 35: Candidate Portfolio Results: System Capacity Shortfall
* Minor differences in capacity shortfall are due to when contracts are layered in.
The capacity shortfalls will be supplemented with capacity contract purchases. Cost of replacement capacity has been estimated at the average 2017 market rate of $2/kW‐month with a 2.5% escalation rate. The Mixed Portfolio is estimated to save $146,730 in capacity purchases through 2030 compared to the Variable Portfolio. The Baseload Portfolio is estimated to save $147,133 in capacity purchases through 2030 compared to the Variable Portfolio.
Table 6: System Capacity Purchases Cost
CY 2027 CY 2028 CY 2029 CY 2030 Total
Mixed Portfolio ‐ $50,442 ‐ $51,703 ‐ $105,991 $61,406 ‐ $146,730 Baseload Portfolio ‐ $50,442 ‐ $51,703 $4,608 ‐ $49,597 ‐ $147,133 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 in the past few years and remains stable. APU has over 290 MW of natural gas and baseload renewable power plants located within the LA Basin. ‐
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During the planning horizon of this IRP, APU has sufficient local resources that exceed CAISO’s local capacity requirements. In the next IRP, APU will consider the local capacity impact of plant retirements and baseload contract expirations.
Graph 36: Local Capacity Resources and LCR Requirement
Flexible Capacity
On average, APU has a monthly flexible capacity requirement of 40 MW, which peaks in December with a capacity requirement of 80 MW. The introduction of additional intermittent resources is estimated to increase the flexible capacity requirements by 3 MW for a 20 MW solar contract and 5 MW for 20 MW wind contract.
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. The Baseload Portfolio requires the least amount of flexible capacity, while the Variable Portfolio requires the highest amount. Graph 37 shows that under all scenarios APU has ample Flexible Capacity resources throughout the planning period:
Graph 37: CAISO Flexible Capacity Requirement
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Brea Power Partners MWD Small Hydro Bowerman
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The portfolio that requires the least amount of capacity purchases is given the highest ranking. The Baseload Portfolio requires the least amount of system capacity purchases, followed by the Mixed Portfolio and then Variable Portfolio. These costs are included in the net power supply cost detailed below in the Expected Cost paragraphs.
PORTFOLIO DIVERSIFICATION
PERFORMANCE MEASURE VARIABLE MIXED BASELOAD
Portfolio Diversification 3 2 1
Legend: 3=Best, 2=Middle, 1=Worst
Graph 38 shows the estimated portfolio diversification for each of the candidate portfolios in 2030. The Variable Portfolio offers the most diversification, with 31% of the renewable generation coming from intermittent resources. This is significantly more diverse than the Mixed and Baseload Portfolios, which only have 8% and 1% intermittent resources in their portfolios, respectfully. As diversity increases flexibility, reliability, and performance, a higher grading is awarded for higher diversity. The highest diversified portfolio is the Variable Portfolio, therefore it is the preferred portfolio under this category.
Graph 38: Candidate Portfolio Results: Portfolio Diversity in 2030
EXPECTED COST
PERFORMANCE MEASURE VARIABLE MIX BASELOAD
Expected Cost 3 2 1
Legend: 3=Best, 2=Middle, 1=Worst
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Mixed Portfolio
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Baseload Portfolio
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One of APU’s goals is to minimize impacts on customer bills and to serve customers at just and reasonable rates. As such, the total power supply cost for each portfolio is estimated, with lower cost portfolios being awarded a higher rating.
The Variable Portfolio is estimated to be the least cost portfolio, costing $3.2 billion from 2019 through 2030. The Mixed Portfolio is estimated to cost an additional $15.1 million compared to the Variable Portfolio, and the Baseload Portfolio is estimated to cost an additional $17.4 million compared to the Variable Portfolio. Grading is awarded in order of the least cost being the best portfolio. The Variable Portfolio scored the highest under this performance measure.
Graph 39 displays the total annual power supply costs for each portfolio. Each portfolio performs similarly in the first several years until 2027, when new contracts come online. In the subsequent years, the cost difference grows exponentially with the Variable Portfolio remaining significantly less expensive than the other two portfolios.
Graph 39: Candidate Portfolio Results: Net Power Supply Cost
*Net Power Supply Cost = Total power supply costs net of transmission revenues and wholesale energy revenues
MARKET RISK
PERFORMANCE MEASURE VARIABLE MIX BASELOAD
Market Risk 3 1 2
Legend: 3=Best, 2=Middle, 1=Worst
Graph 40 displays the estimated financial exposure from the candidate portfolios. Financial exposure is determined by the percentage of wholesale energy purchases compared to system load as well as the cost impact of wholesale market purchases. The market purchase percentages for the Variable, Mixed, and Baseload Portfolios were very close, averaging 41.21%, 41.20% and 41.27%, respectively, from 2019 $220
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to 2030; therefore, the portfolios were awarded similar scores for this criteria. However, by 2030, the Baseload Portfolio requires an additional $139,000 annually in energy purchases compared to the Variable Portfolio, and the Mixed Portfolio is estimated to require an additional $1.2 million in energy wholesale energy purchases. A higher grade is awarded to the portfolios with the least amount of energy purchases required.
Graph 40: Candidate Portfolio Results: Wholesale Energy Purchase as a % of Total Energy Portfolio
*Slight differences in 2029 and 2030 are due to when contracts are layered in.
It is important to note that market exposure is limited by the generation capacity available from APU resources. When the wholesale market price rises above predetermined prices, all APU units will be dispatched to serve the retail customers. The percentage of market energy purchases will therefore be lower under higher wholesale market price conditions.
SUMMARY
Overall the Variable Portfolio, which replaces lost IPP generation with intermittent renewable resources, performed the best. This portfolio was estimated to have a lower overall power supply cost. It also has the least amount of Regulatory Risk and resulted in the most diverse portfolio. Due to the unpredictability of intermittent generation, this portfolio posed the highest exposure to market price spikes and required additional capacity purchases to meet Resource Adequacy capacity requirements.
However, this market exposure is mitigated by the large amount of existing baseload resources under fixed price contracts. Additionally, an analysis of the system‐wide capacity market indicates that these resources will be readily available at a much lower cost than building new peaking power plants or utility scale energy storage facilities.
The Mixed Portfolio, which replaces lost IPP generation with half intermittent and half baseload renewable resources, was ranked second best and performed averagely over most of the criteria.
The Baseload Portfolio had the least financial exposure to market dynamics due to the stable nature of baseload generation. This portfolio was also ranked the highest for Resource Adequacy as baseload 0%
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2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Variable Portfolio Mixed Portfolio Baseload Portfolio
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resources have a high capacity value. However, this portfolio was also the most expensive, provided the least amount of portfolio diversification and posed the highest Regulatory Risk.
The following table displays a summary of the performance measure results for each portfolio scenario considered:
PERFORMANCE MEASURE
VARIABLE
MIXED
BASELOAD
Compliance 3 1 2
Regulatory Risk 3 2 1
Resource Adequacy 1 2 3
Portfolio Diversification 3 2 1
Expected Cost 3 2 1
Managed Market Risks 3 1 2
Total 16 10 10
Legend: 3=Best, 2=Middle, 1=Worst
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F. STRESS TESTING
Additional analysis of the candidate portfolios was conducted using stress tests to determine whether or not the portfolio performance would change under extreme market and load changes. Portfolio simulations were performed for each candidate portfolio to address the following situations.
G.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:
resource costs, wholesale energy prices, carbon prices, and utility solar growth into the production cost model.
GAS PRICE
APU owns and contracts power 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 historical data of the SoCal Citygate price. Graph 41 shows the gas prices used to stress test the three portfolio scenarios:
Graph 41: Stressed Gas Prices
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CARBON PRICE
A high carbon price forecast was developed using a $60 increase from the floor price, as discussed in the rulemaking for Post‐2020 allowance allocation approved by the CARB on July 27, 20179. A low carbon price scenario was developed using the floor price.
Compared to the Preliminary GHG Price Projections10 used in the 2017 Integrated Energy Policy Report (IEPR) Demand Forecast, APU’s low carbon price forecast is lower than the IEPR’s low price forecast; APU’s high price forecast is higher than the IEPR’s high price forecast with the only exception in year 2030. APU chose to use its own extreme carbon price forecast as it stresses the model more. Graph 41 shows the carbon prices used to stress test the three portfolio scenarios:
Graph 42: Stressed Carbon Prices
UTILITY SCALE SOLAR GROWTH
The high utility‐scale solar growth scenario was developed assuming a 25% increase of all current planned CAISO interconnection projects and growth of 2.5% annually post 2022. The low utility scale solar growth assumed no future CAISO interconnection projects would be built. Graph 43 shows the solar growth rates used to stress test the three portfolio scenarios:
Graph 43: Stressed Utility Scale Solar Capacity Growth
9 See Table 13 Estimated Range of Cap‐and‐Trade Allowance Price 2021–2030 of the CARB California’s 2017 Climate Change Scoping Plan, https://www.arb.ca.gov/cc/scopingplan/scoping_plan_2017.pdf. The Estimated Cap‐and‐Trade Reserve Price was $56.7 above the Floor Price.
For planning purposes, this IRP uses $60 above the floor price for stress testing. 10 TN216271_20170227T161611_Preliminary_GHG_Price_Projections__Energy_Assessment_Division $0
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TEST 2: EXTREME HIGH DEMAND VS. 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 forecast, and accelerated growth in transportation electrification was applied. The accelerated EV growth was assumed to be 25% above Governor Brown’s Executive Order B‐16‐12, resulting in 45,000 registered electric vehicles in APU by 2038.
Similarly, a low demand scenario was also developed by applying extremes to the base demand forecast described in Section V.A. Energy Demand Forecast ‐ Methodology & Assumptions. Electric vehicle growth was removed from the base demand forecast, and double energy efficiency goals were applied in addition to accelerated behind‐the‐meter solar capacity installation. The accelerated PV growth was estimated to be 25% above the capacity forecast, and energy efficiency was estimated to be 3% of retail load.
Graph 44 below also displays Policy Initiative Input as a comparison with the demand stress test values.
The Policy Initiative Inputs incorporates high energy efficiency, high consumer solar installation, and high electric transportation growth assumptions to reflect the impact of the State’s policy initiatives on APU load.
Graph 44: Stressed System Load Growth or Reduction (GWh)
G.2. MODEL RESULTS UNDER STRESS TESTS
The following table displays a summary of the performance measure results after stress testing each portfolio scenario.
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2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 High Demand Low Demand Policy Initiative Input Expected Demand 2018 Integrated Resource Plan
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PERFORMANCE MEASURE
VARIABLE
MIXED
BASELOAD
Compliance 3 1 2
Regulatory Risk 3 2 1
Resource Adequacy 1 2 3
Portfolio Diversification 3 2 1
Expected Cost 3 2 1
Managed Market Risks 3 1 2
Total 16 10 10
Legend: 3=Best, 2=Middle, 1=Worst
The model simulation results held constant for all three portfolios under the stress tests, with the Variable 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 the same: Compliance, Regulatory Risk, Resource Adequacy, Portfolio Diversification, and Financial Exposure. The only components that could change are Expected Cost, or the power supply costs, as detailed below.
Graph 45 displays the simulation results for each candidate portfolio under these cost extremes. The total portfolio cost for each candidate portfolio with high and low cost scenarios are displayed as lines, and total retail revenue is displayed in columns. The Variable Portfolio, shown as the green dotted line, performs the best under both high and low cost market situations. The Baseload Portfolio performs the worst, with expenses being notably higher than the Variable Portfolio, but very close to the Mixed Portfolio costs. The scaling to retail revenue is intended as a reference to potential rate increases needed to supplement the changing portfolio.
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Graph 45: Stress Test Results: Extreme High Costs vs. Extreme Low Costs
Similarly, a load simulation stress test was conducted by simulating portfolio performance under extreme load situations. A high load growth extreme incorporates assumptions of high electric vehicle growth, low privately owned solar PV, and low energy efficiency. A low load growth extreme incorporates assumptions of low electric vehicle growth, high consumer installed solar PV, and high energy efficiency. Graph 46 displays the simulation results for each candidate portfolio under these load growth extremes.
Graph 46: Stress Test Results: Extreme High Demand vs. Extreme Low Demand
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LD Retail Revenue HD Retail Revenue Variable Portfolio Mixed Portfolio Baseload Portfolio Variable Portfolio Mixed Portfolio Baseload Portfolio $220
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High Market Cost vs Low Market Cost
Retail Revenue Variable Portfolio Mixed Portfolio Baseload Portfolio Variable Portfolio Mixed Portfolio Baseload Portfolio
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The total portfolio cost for each candidate portfolio under high and low load growth scenarios are displayed as lines and total retail revenue is displayed in columns. Estimated retail revenue for the low load growth scenario is displayed as only the dark green column, while estimated retail revenue for the high load growth scenario is displayed as the total of the light green columns. The Variable Portfolio, shown as the brown dotted line, performs the best under both load situations. The Baseload Portfolio performs the worst, with expenses being notably higher than the Variable Portfolio, but very close to the Mixed Portfolio costs. The scaling to retail revenue is intended as a reference to potential rate increases needed to supplement the changing load scenarios.
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G. OPTIMUM PORTFOLIO RECOMMENDATION
The optimum portfolio recommendation is the
Variable Portfolio, which would replace lost IPP
generation with intermittent renewable resources.
The Variable Portfolio performed the best under
normal as well as stress conditions. It is estimated to have the least power supply cost, the least
Regulatory Risk, and most diverse portfolio. As
intermittent generation is unpredictable, this
portfolio may pose a higher exposure to market
price spikes; however, this risk is forecasted to be very small, as under extreme market conditions
which simulated high market prices, this portfolio performed the best, including capacity purchases included in the power supply cost.
50% RPS & 40% GHG REDUCTION
As shown in Graph 47, the Variable Portfolio is in compliance with current legislative and regulatory requirements, and meets or exceeds renewable and GHG emission reduction targets. It is also provides the most flexibility for adjusting to potential future regulatory or legislative changes, as opposed to the other portfolio options.
Graph 47: Variable Portfolio Meets or Exceeds Compliance Targets
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20% below 1990 Level
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RESOURCE ADEQUACY & RELIABILITY
The Variable Portfolio requires capacity purchases to meet resource capacity requirements. Graph 48 displays the change in capacity from 2019 to 2030. Capacity purchases will be acquired in 2027 to replace the system capacity lost with the divestiture of IPP. Any increase in flexible capacity requirements will be met with the Canyon Power Plant.
Graph 48: Variable Portfolio Forecasted Resource Adequacy
DIVERSIFICATION
Graph 49 below displays the changing resource mix under the Variable Portfolio.
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Capacity Purchases New Intermittent Resources Intermountain Units 1 and 2 Magnolia Peak Magnolia Base Canyon Power Plant
Anaheim CTG Geothermal Raser Thermo Ormat Geothermal
Bowerman MWD Small Hydro Brea Power Partners
System Capacity Requirement
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Graph 49: Resource Mix for Retail Energy Demand: 2018 vs. 2030
The change in resource mix has a corresponding impact on the cost structure in the future years.
Graph 50 displays the power supply cost structure of the portfolio in 2019 and 2030. In total, the net cost to supply power is estimated to be $38 million higher in 2030 compared to 2019, or a 1.34% average annual increase over the next 12 years. The increase is mainly caused by estimated scheduling services fees outside of the power supply.
Scheduling services costs are expected to be $21 million higher in 2030 compared to 2019. These charges consist of CAISO transmission access charges, grid management fees, congestion, losses, Renewable
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2018 RESOURCE MIX
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Hydro
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Wind
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Solar
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Geothermal
16%
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ancillary services, and other energy charges, and are expected to increase by approximately 4% annually. Capacity purchases to meet the resource adequacy requirements are also included here.
The total energy costs will decrease even though each component may move up or down depending on the energy category. The highest increase in cost is wholesale energy purchases to serve load, which are estimated to be $53 million higher in 2030. This increase is due to higher prices and volumes purchased.
The average wholesale market energy price is forecasted to be $62/MWh in 2030, compared to $36/MWh in 2019. Also, an additional 680 MWh are forecasted to be procured in the wholesale energy in market in 2030, compared to 2019.
As more renewable energy sources are being included into the portfolio, the cost of renewable energy is expected to increase by $16 million. Conversely, the divestiture in fossil fuel resources results in a cost savings totaling $73 million.
Graph 50: Variable Portfolio Power Supply Cost Structure
*Net power supply costs = Total power supply costs net of transmission revenues and wholesale energy revenues
MARKET RISK
While the Variable Portfolio has a higher market risk due to exposure to market price spikes, it still performed the best under extreme market conditions. When energy costs are either extremely high or extremely low, the cost to maintain the Variable Portfolio is consistently the lowest.
1. When the market cost is extremely low, APU purchases the low‐cost energy from the wholesale energy market.
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Net Power Supply Cost 2019 ‐ 2030
Total Transmission Cost Scheduling Coordinator Costs Conventional Unit Fixed Costs Unit Variable Cost Unit Fuel Cost Debt Service Cost
Wholesale Purchase Cost Renewable Long Term PPA Cost Renewable Short Term PPA Cost Total Wholesale Revenue Total Transmission Revenue Total Net Cost Linear (Total Net Cost)
Renewables and Storage $60M to $76M
Market Purchases $9M to
$62MAverage 1.34%
annual increase
Thermal $151M to $78M
Transmission and Scheduling
Services $76M to $97M
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2. When the market cost is extremely high, the APU resources are dispatched to meet retail customer needs, therefore limiting the market risk.
The Variable Portfolio has the best ability to leverage lower market prices, and market risks are capped by the resources available in APU’s portfolio.
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H. RATE IMPACT
ANAHEIM ELECTRIC 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 divesting of its coal assets and utilizing its peaking resources to integrate more renewable purchases, APU has been able to maintain affordable electric rates. The recommended Variable 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 1.34% per year, on average, which is less than the expected rate of inflation.
APU strives to provide just and reasonable rates for the service it provides to customers as required by Federal Law and, at the same time in compliance with the California Constitution, the electric rates do not exceed APU's reasonable cost to provide electric service to its customers. Consistent with these 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 requirement and the additional Charter requirements that the electric rates be sufficient to pay for (1) operations and maintenance of the APU's electric system, (2) the payment of principal and interest on debt, (3) creation and maintenance of financial reserves adequate to assure debt service on bonds outstanding, (4) capital construction of new facilities and improvements of existing facilities, or maintenance of a reserve fund for that purpose, and (5) other costs. APU has designed its rate schedules to maintain simplicity and send appropriate pricing signals that encourage prudent consumption of electricity while fully complying with federal, state mandates, and the Charter. To accomplish these objectives, Anaheim offers several base rates as well as optional rates that customers may opt into if they choose.
Base Electric Rates
• Domestic Service (i.e., residential)
• Small Commercial
• Medium Commercial
• Large Commercial
• Industrial
• Agricultural
• Lighting
• Municipal
Optional Rates
• Thermal Energy Storage
• Feed‐In‐Tariff
• Economic Development / Business Retention
• Domestic
Time‐Of‐Use
• Commercial Time‐Of‐Use
• Net Energy Metering
• Domestic Electric Vehicle
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Generally, all costs of APU’s Electric System, including power supply costs, are recovered through the application of these base rates. Anaheim’s customer rates also include a Rate Stabilization Adjustment (RSA) which contains two components (1) a Power Cost Adjustment (PCA) to recover fluctuations in power supply costs and other relevant operational costs, and (2) an Environmental Mitigation Adjustment (EMA) to recover fluctuations in environmental mitigation costs related to the procurement, generation, transmission, or distribution of electricity. The RSA helps facilitate timely recovery of costs and thereby helps to maintain financial performance goals including debt service coverage ratios and reserve levels. The RSA also provides a mechanism to reduce rates when costs decrease. Additionally, APU offers a low income energy discount to seniors, military veterans, and disabled customers who meet specified income thresholds.
APU continuously monitors its rates, rate options, and fees to ensure it provides customers with options that meet their needs and that encourage adoption of environmentally friendly technologies. To that end, APU has added a commercial electric vehicle (EV) rate to encourage further adoption of electric transit buses, school buses, delivery vehicles, and other fleet vehicles within the City. This effort will also enhance the City’s economic justice efforts by encouraging public transportation agencies to invest in EV fleets that serve a broad array of demographics within the City.
AVERAGE RESIDENTIAL RATE COMPARISON
APU’s residential electric rates are competitive with other electric utilities serving Southern California.
APU residents benefit from electric bills that are 17% to 35% lower than those charged by Southern California Edison and San Diego Gas & Electric, the only electric utilities that serve Orange County residents, other than Anaheim.
Graph 51: Comparison of Monthly Residential Electric Bills
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Anaheim Burbank LADWP Riverside Pasadena SCE Glendale SDG&E Comparison of Monthly Residential Electric Bills
(Based on 500kWh)
Calculated as of July 2017 and includes taxes and surcharges, as applicable. 2018 Integrated Resource Plan
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APU balances its goal of maintaining low electric rates with the goal of providing reliable electric service to its customers and maintaining the long‐term financial viability of APU. In addition to continuous cost mitigation efforts, this requires periodic rate adjustments to help ensure adequate funding is available for investing in the system and to maintain key financial metrics that support APU’s investment grade credit rating. Key metrics include debt service coverage with a goal of 2.0x coverage and sufficient financial reserves with a goal of 90 days operating cash plus $50 million in the rate stabilization account.
The rates APU charges to its customers must be sufficient to recover, among other things, the full cost of providing reliable service and maintaining financial stability.
RATE STRUCTURES
APU’s rate structures include a fixed customer charge, tiered energy rates, the RSA, and an underground surcharge that pays for undergrounding of overhead power lines to improve reliability and beautify the City. Rates for each customer classification employ these components while medium and large commercial and industrial rates include a demand charge. Additionally, time‐of‐use rates also 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.
As mentioned earlier, the RSA contains two components, i.e. the PCA and the EMA. The PCA is structured so that it can increase up to ½¢ per kWh in any 12‐month period to collect for changes in power production costs, purchased power costs, regulatory compliance costs, debt service, and any other costs involved in delivering energy. The EMA is structured similarly to the PCA in that the annual limit of the increase is ½¢ per kWh in any 12‐month period to collect for environmental mitigation costs such as greenhouse gas emissions, purchase of emission credits, taxes on emissions, and any cost differential between renewable power supply and traditional carbon‐based power supply not recovered by the PCA.
With respect to any RSA adjustment, APU first considers costs of service recovery and the impact on customer bills with a goal of maintaining total electric charges that are competitive with those of other utilities in the region. Any change indicated by the RSA calculation is reviewed against other known long‐term factors prior to any automatic implementation of rate changes. This allows APU to blend forecasted increases or decreases in the projected power supply or operational costs to meet financial requirements and mitigate large fluctuations in electrical costs to customers.
RATE IMPACT UNDER RECOMMENDED PORTFOLIO
Using the Variable Portfolio, APU performed rate impact analyses under the high, medium, and low load growth scenarios.
APU performs financial modeling for the purpose of monitoring and forecasting the financial performance of its electric utility and for identifying necessary rate adjustments. This financial model is 2018 Integrated Resource Plan
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used to help determine the cost impact of various changes in regulatory requirements, power supply scenarios, capital improvements, and debt issuances.
For purposes of the IRP, the different scenarios under evaluation were overlaid onto the existing forecasts of capital, O&M, debt service, and other cost of service requirements. In developing the IRP, scenarios were eliminated that would result in large customer impacts. Rate impacts reflected in the IRP are calculated on a system‐wide basis.
APU’s forecasting model, like any other, includes significant assumptions. While the model used for the IRP analysis was based on information available at a single point in time, it is not uncommon for assumptions to change over time as new or better information is made available. An analysis was conducted for multiple scenarios and a range of potential rate impacts was developed to illustrate what management believes to be a realistic bandwidth of potential rate impacts over the course of the period analyzed.
The expected scenario assumes APU will meet the 50% RPS requirement, its allocated portion of the State goal of 1.5 million electric vehicles (EV) on the road in California, and meet all energy efficiency (EE) targets. It also assumes moderate local solar growth of 5 MW per year. The high energy consumption scenario assumes 50% RPS, high EV growth, low EE growth, and low local solar. The low energy consumption scenario assumes 50% RPS, no EV growth, high EE growth, and high local solar. The overall upward trend in estimated rates for all three scenarios reflects a modest increase in power supply, operating, maintenance, and debt service costs.
The results of the study suggest that the high energy consumption scenario results in lower average rate increases, as compared to the expected and low consumption scenarios. This is primarily the result of fixed system‐wide costs being recovered over a greater number of billing units. The low consumption scenario, on the other hand, is expected to result in higher average rate increases due to system‐wide costs being recovered over a smaller number of billing units. As noted, the study is based on forward‐ looking assumptions and is subject to change due to commodity price fluctuations, policy changes, technological developments, changes in cash requirements, and/or changing customer behavior.
APU will continue to update its long‐term plan as expectations change in order to maintain accurate forecasts. The following chart illustrates the results of the study based on the three scenarios described above. The chart represents forecasted average rates based on system‐wide averages and does not account for rate structure variations across and within customer classes.
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Graph 52: Rate Comparison
The above graph shows the results of a rate analyses performed pursuant to this IRP, which includes the expected power supply costs associated with the three IRP portfolio scenarios as well as non‐power supply operating and maintenance costs, debt service, and financial metric requirements. For the expected consumption rate projection case and the Variable Portfolio, net power supply costs are expected to increase an average of 1.34% per year from 2019 to 2030, which is less than the expected rate of inflation over the same time period.
Monthly bills for individual customers and customer classes may be more or less than these estimates due to the different rate structures of the various customer classifications and variations in individual customer energy consumption profiles. The charts below reflect the estimated impact to monthly customer bills for a typical residential customer and a commercial customer.
Graph 53: Total Residential Customer Monthly Bill
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Graph 54: Commercial Customer Monthly Bill
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Anaheim Public Utilities
VIII. RELIABILITY & ELECTRIC 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 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 entered into several transmission contracts through Southern California Public Power Authority (SCPPA) and with the Los Angeles Department of Water and Power (LADWP) in order to ensure the energy from APU’s owned or contracted resources is consistently delivered into the CAISO from resources located outside of the CAISO footprint. On October 10, 2006, APU transferred operational control of all contracts for transmission resources to CAISO. According to the North American Electric Reliability Corporation (NERC) reliability standards, APU is a Distribution Provider (DP), and 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 regional short‐term and long‐term infrastructure needs during its annual Transmission Planning Process.
APU has a long standing reputation of providing its customers with highly reliable electric distribution services over a robust and well‐maintained electric distribution system. In 2017, 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. 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 and the Anaheim Convention Center.
APU is a city‐owned, not‐for‐profit electric and water utility 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 this 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 directly and through an appointed citizen advisory Public Utilities Board.
With final authority vested in Anaheim's elected City Council, decisions are made in the best interest of its citizens, quality of life, and local economy. As a municipal, not‐for‐profit utility, 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 multi‐million dollar tourism, sports, and manufacturing customers.
Although residential customers make up 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. Total retail load is estimated as total system load less system losses, which have historically been approximately 3.5%.
Graph 55: Customer Class Data
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COMMERCIAL
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Commercial,
14.2%
Industrial,
0.3%
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Active Meters by Customer Class
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B. GENERATION AND TRANSMISSION RESOURCES
APU’s power supply comes from resources located in Anaheim and across the western United States.
This section introduces APU’s long‐term generation and transmission resources.
GENERATION RESOURCES
ARP‐LOYALTON BIOMASS PROJECT
APU, along with nine other California
publicly‐owned utilities, has contracted with
ARP‐Loyalton Cogen, LLC for the purchase of
renewable biomass electricity from a
biomass project located in northern
California. Transmission is provided by the
CAISO. This contract provides Anaheim with
0.81 MW of its proportionate share of
renewable biomass energy as required
pursuant to Senate Bill 859. The 5‐year
contract expires on March 31, 2023.
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 Power Purchase
Agreement with Brea Power Partners, LP
to deliver landfill gas renewable energy
to APU to help satisfy demand.
The original 5 MW contract was
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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.
DESERT HARVEST OR MAVERICK FACILITY
The Cities of Anaheim, Burbank, and Vernon have contracted with Desert Harvest II, LLC through SCPPA for a share of intermittent solar energy from one of two solar projects: the Desert Harvest project or the Maverick project. APU’s share is 36 MW. Transmission is provided by the CAISO. The 25‐ year contract expires on November 30, 2045.
HEBER SOUTH
The Cities of Anaheim, Banning, Glendale,
and Pasadena have contracted with Ormat
Technologies, through Southern California
Public Power Authority (SCPPA) for a share
of a 14 MW (net) geothermal project. The
renewable energy is delivered to the
Imperial Irrigation District’s Mirage
Interconnection and then imported into the
CAISO.
The contract includes mutual termination rights at years 15 and 20. The 25‐year contract expires on December 31, 2031.
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
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of Water and Power (LADWP) control area. Additional transmission costs are required to get the 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 has 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. The 25‐year
contract expires on December 31, 2028.
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
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December 31, 2023, with an option to extend for two additional 10‐year periods.
WESTSIDE SOLAR WSP PV1
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.
MWD COYOTE CREEK, PERRIS, RIO HONDO AND VALLEY VIEW The Cities of Anaheim, Azusa, and
Colton have contracted with The
Metropolitan Water District (MWD)
of Southern California, 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‐six (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.
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The new Electric Service Contract with Boulder Canyon commences upon expiration of the existing Agreement on October 31, 2017, and expires on September 30, 2067.
CANYON POWER PROJECT
APU entered into a Power Sales
Agreement with SCPPA for all of
the 200 MW nameplate
capacity and energy from the
Canyon Power Project (CPP).
The 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 provides enhanced local reliability and is dispatched when its generation costs are less than the cost to serve APU’s load.
KRAEMER PEAKING PLANT
APU owns 100% of the Kraemer
Peaking Plant (KPP), also known
as the Anaheim Peaking Plant. It
is a 48 MW natural gas‐fired,
combustion turbine
conventional electric generating
plant located in the northeast
part of the City, adjacent to the
City’s Dowling Substation.
There is also a heat recovery
steam generator for emissions
control and power augmentation.
Since 2000, the operations of the Kraemer Peaking Plant have increased as the California energy market has been redesigned. KPP is now dispatched when its generation costs are less than the cost to serve APU’s load.
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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 is 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 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 to the Victorville/Lugo interconnection with the CAISO. The 40‐year contract expires on June 15, 2027.
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,
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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
APU entered into a transmission service contract with LADWP to acquire a share of LADWP’s transfer capability of the Northern Transmission System 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 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 257 MW.
SOUTHERN TRANSMISSION SYSTEM
APU entered into a transmission service contract
with SCPPA to acquire transfer capability of the Southern Transmission System 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.
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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 the City.
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 transmission line has a transfer capacity of 2,400 MW; APU’s share is
110 MW.
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C. CAISO RESOURCE ADEQUACY 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‐term 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 – Variable Portfolio – requires capacity purchases to meet system RA requirements. Graph 48 displays the change in capacity from 2019 to 2030. Capacity purchases will be acquired after 2027 to replace the system capacity lost with the divestiture of IPP. The cost of capacity contracts are included in the power supply cost evaluation.
Graph 48: Variable Portfolio Forecasted Resource Adequacy
0 100
200
300
400
500
600
700
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MW
Capacity Purchases New Intermittent Resources Intermountain Units 1 and 2 Magnolia Peak Magnolia Base Canyon Power Plant
Anaheim CTG Geothermal Raser Thermo Ormat Geothermal
Bowerman MWD Small Hydro Brea Power Partners
System Capacity Requirement
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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 where local generation resources are needed to ensure reliable electric grid operations to serve the area.
Under the CAISO Local Capacity Requirement (LCR) program, 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 CAISO 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 2018 Local Capacity Technical Analysis issued by the CAISO on May 1, 2017, assigned a LCR of 225 MW for APU within the LA Basin Area.
The CAISO local capacity requirement for APU has been below 230 MW in the past few years and remained stable. APU has over 290 MW of natural gas and baseload renewable power plants located within the LA Basin. During the planning horizon of this IRP, APU has sufficient local resources that exceed CAISO’s local capacity requirements.
Graph 36: Local Capacity Resources and LCR Requirement
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. In order to meet energy demand 0 50
100
150
200
250
300
350
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MW
Local Capacity Resources and LCR Requirement
Brea Power Partners MWD Small Hydro Bowerman
Anaheim CTG Canyon Power Plant LCR Requirement
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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.
Increased amounts of variable energy resources puts further stress on what is known as the “Duck Curve” or the effect solar and wind generation resources have on net demand (demand less variable energy resources). As illustrated in Graph 56 below, in order to manage the effects of variable energy resources, the CAISO must have a resource mix to call upon that can react and adjust quickly to meet net demand while mitigating the risk of over generation. To do so, the CAISO must ramp generation resources down in the morning hours when solar generation begins to produce and ramp resources back up in the evening when solar generation drops off as the sun sets.
Graph 56: CAISO “Duck Curve” ‐ Impacts of Variable Energy Resources
Similar to LCR, the CAISO performs annually a system wide assessment of flexible capacity needs using a Monthly Maximum Three‐Hour Net Load Ramp plus 3.5% of expected peak 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 Start and stop multiple times per day
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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 requirement of 40 MW, which peaks in December with a capacity requirement of 80 MW. The introduction of additional intermittent resources is estimated to increase the flexible capacity requirements by 3 MW for a 20 MW solar contract and 5 MW for 20 MW wind contract.
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 – Variable Portfolio – requires the highest amount of flexible capacity, the Canyon Power Plant provides more than sufficient flexible capacity to accommodate the additional intermittent resources.
Graph 37: CAISO Flexible Capacity Requirement
0 50
100
150
200
250
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MW
CAISO Flexible Capacity Requirement
Variable Mix Baseload Flexi Capacity Available
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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 the Anaheim Resort Area, Platinum Triangle, sports arena, Honda Center, City National Grove of Anaheim, etc. APU serves about 119,000 electric meters throughout 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 eleven 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 event of a catastrophic failure of a substation.
D.1.2. Distribution System
APU’s distribution system includes approximately 110 distribution circuits fed by eleven distribution substations across 50 square miles. It provides high quality and reliable power service to customers. The system is evaluated thoroughly on an annual basis to ensure 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.
A new Harbor 69/12kV Substation is planned to be constructed and placed in service in the summer of 2019. It is needed in order to serve new hotels and residential/commercial units under construction and planned future developments in the Platinum Triangle and Anaheim Resort areas. This project will add needed transformer capacity in the fast growing area and also provide loading relief to the adjacent substations. It also greatly improves system reliability in the area.
A new 69/12kV transformer is planned to be constructed and placed in service in 2019. Similarly, this project is needed to accommodate new industrial and commercial loads in Eastern Anaheim area. It also will provide loading relief to adjacent substations and improves system reliability in the area.
APU is currently upgrading the 12kV switchgears to higher ampacity rating at one of the substations located in the east end of the City. It is expected to be completed in 2018. This project is needed to serve increased load growth in the area. It will also improve the system reliability and provide operational flexibility.
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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 kV Substation. Photo 1
shows Vermont 220 kV GIS switchgear.
In 2006, APU accomplished a first‐of‐its‐kind in
the United States when it constructed under a
park an electric substation with gas insulated
switchgear (GIS) and with the capacity to
provide power to 25,000 residential customers.
This project also improves system reliability in
the east of Anaheim system. Photo 2 shows
Park Substation underneath the park.
Photo 2: Park Substation
Photo 1: Vermont 220kV GIS Switchgear
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In addition, Anaheim
operates two gas‐fired
generating plants,
Canyon Power Plant and
Kraemer within its
service territory with a
total combined capacity
of about 240 MW. These
generating resources are
used to offset power
imported from outside
resources during peak
load periods, and they
both have 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 3 shows Canyon Power Plant.
D.1.4. Underground Conversion Program
In 1991, Anaheim City Council established the Underground 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 reliability of the electric system. As of today, APU has converted approximately 128 circuit miles or 50% of its existing overhead circuits. Photo 4 shows before and after of one of the underground projects.
Photo 4: Before and After Underground Project
Photo 3: Canyon Power Plant
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D.1.5. Distributed Generation
In 2014 APU completed, what was
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 5 shows the
2.4 MW Anaheim Solar Energy
Plant at the Convention Center.
Approximately 25 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 or expects any significant impacts to the distribution network due to plug‐in electric vehicles (PEV) since they are not concentrated in one area or on a specific circuit at this point in time.
APU continues to monitor potential impact from distributed generation and from electric vehicle charging stations and will make necessary infrastructure investments to maintain system 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 119,000 metered residential and business customers through a modern and well maintained distribution network.
In 2017, 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.
Photo 5: The 2.4 MW Anaheim Solar Energy Plant at Convention Center 2018 Integrated Resource Plan
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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 the average customer is interrupted (System Average Duration Index or SAIDI), and how long it takes to restore 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 for comparing reliability performance among utilities. Below is a graph showing Anaheim’s reliability performance in terms of SAIDI, SAIFI, and CAIDI since 1990.
Graph 57: Anaheim’s Reliability Performance in Terms of SAIDI, SAIFI, and CAIDI Since 1990
Many factors that affect service reliability are beyond APU’s control, such as wind, vehicles hitting power poles, earthquakes, etc. However, other factors are controllable, 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 switching 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.
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Graph 58: 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 the Hazard Mitigation Plan11 by organizing resources, assessing risks, and developing and implementing a mitigation plan and monitoring process. On May 9, 2017, the Anaheim City Council adopted the 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 potential disasters, including earthquake, wildfire, and climate change.
Specifically, Section 9 of the 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 in times of major fire events, Anaheim also participates 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 delivery system primarily through automation. It allows for a more reliable, secure electrical service, and is characterized by a two‐way flow of
11 http://local.anaheim.net/docs_agend/questys_pub/13502/13532/13533/13578/13581/2.%20Hazard%20Mitigation%20Plan13581.pdf
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information, control systems, and computer processing to create an automated, widely distributed energy delivery network. These cutting edge technologies include advanced sensors and relays that sense 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 fairly 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 also 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 based 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, makes 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.
Graph 59: Basic Characteristics of Smart Grid
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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 Smart Grid projects and automatic 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‐healing), and integrating distributed energy resources and demand response programs.
D.4.2 Advanced Metering Infrastructure
As a critical component of the Smart Grid, APU has deployed approximately 9,000 Advanced Metering Infrastructure (AMI) systems within its service territory.
APU used a radio frequency network communication for its electric distribution automation system for almost 20 years. The network consisted of over 400 radios and 130 routers installed throughout the City.
In order to leverage the existing communication network and gain the greatest synergy and lower long‐ term costs, APU plans to deploy compatible smart meters while phasing out dated technology.
Graph 60: Advanced Metering Infrastructure
Currently, APU is looking at improving the deployment process and performing other testing as needed prior to a full scale AMI deployment. Full deployment of smart electric meters will begin FY 2018/2019, along with smart water meters a year later. A full deployment of electric and water meters is expected to take approximately 5‐6 years.
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IX. GREENHOUSE GAS EMISSION REDUCTION
STATEWIDE GHG EMISSION PROFILE
The passage of AB 32 in 2006 established statewide target to reduce GHG emissions to 1990 levels by the year 2020; effectively a 30% decline in emissions from current statewide output. In 2016, SB 32 expanded the statewide GHG emissions reduction goal to 40% below 1990 levels by the year 2030.
Graph 61: 2015 GHG Emissions by Sector12
According to CARB’s 2017 GHG Emission Inventory report, emissions from the electric power sector comprised 19% of 2015 statewide GHG emissions, and was the third largest source of GHG emissions following the transportation (37%) and industrial (21%) sectors.12 From 2000 to 2015, the electricity sector has reduced emissions by 20%, while the transportation and industrial sectors reduced emissions by 6% and 2%, respectively.13 The overall emission decrease in the electricity sector is driven by reduced reliance on carbon‐based fuels, increased use of renewable energy, incrementally higher energy efficiency standards, increased deployment of distributed renewable generation, vehicle electrification, and energy storage technologies.
Graph 62: GHG Intensity of Electricity12
12 https://www.arb.ca.gov/cc/inventory/pubs/reports/2000_2015/ghg_inventory_trends_00‐15.pdf 13 2017 Edition California Greenhouse Gas Inventory for 2000‐2015 — by Sector and Activity; downloaded from:
https://www.arb.ca.gov/app/ghg/2000_2015/ghg_sector.php
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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 and cleaner natural gas generation technologies. 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 increased energy efficiency measures, local solar, energy storage, and electrification of the transportation sector.
2015
GREENHOUSE GAS REDUCTION PLAN
In July 2015, APU developed its first utility‐
specific Greenhouse Gas Reduction Plan14 with
the purpose of developing a clear and
comprehensive long‐term strategic framework to
reduce GHG emissions. The Plan identifies a goal
to reduce GHG emissions by 20% below 1990
levels by 2020 and a minimum of 40% below
1990 levels by 2030. 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.
APU achieved its goal of 20% below 1990 levels
through the increased renewable generation
from 11% in 2010 to 33% of overall sales in
calendar year 2015. Further GHG emissions
reductions are expected to reach near the 40%
target 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
14 http://www.anaheim.net/DocumentCenter/View/7996
Renewable
Energy
Energy
Efficiency
Local Solar Energy Storage
Transportation
Electrification
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supply portfolio is expected to reach or exceed 70% below its 1990 emissions by 2028. Significant emission reductions are observed in each of the portfolio scenarios analyzed and discussed in Section VII. Resource Portfolio Evaluation.
Graph 63: APU GHG Reduction Targets
EMISSION REDUCTIONS ASSOCIATED WITH TRANSPORTATION ELECTRIFICATION Electric vehicle growth is estimated using the CEC’s “2016 SB 350 Common Assumption Guidelines for Transportation Electrification Analysis 3.0” workbook published in April 2017.15 According to the CEC workbook, APU’s share of total California registered electric vehicles is 0.63%, or an estimated 16,280 electric vehicles by 2030.
The model also provides estimates of the emissions savings per vehicle. In 2015, the estimated savings in emissions per electric vehicle is 2.31 MTCO2e. As more electric vehicles are deployed, the impact on emissions per EV is expected to decline to 1.761 MTCO2e by 2030.
15 “2016 SB 350 Common Assumption Guidelines for Transportation Electrification Analysis”, Version 3.0, Updated 4/6/2017. This workbook is subsequently replaced by updated versions and no longer available via the CEC website. The most updated version is available for download at http://www.energy.ca.gov/sb350/IRPs/.
2018 Integrated Resource Plan
IX. Greenhouse Gas Emission Reduction
Anaheim Public Utilities
Table 7: Anaheim EVs and Emission Savings per Vehicle
Year Estimated Number of Vehicles Emissions Savings Per Vehicle (MTCO2e) 2018 2,343 2.125
2019 3,045 2.082
2020 3,870 2.044
2021 4,807 2.009
2022 5,844 1.976
2023 6,970 1.945
2024 8,171 1.916
2025 9,434 1.887
2026 10,748 1.860
2027 12,100 1.833
2028 13,478 1.808
2029 14,874 1.784
2030 16,280 1.761
Based on the CEC’s estimates, APU could have a total of 16,280 EVs within the service territory by the year 2030, resulting in a GHG emission reduction of approximately 28,675 MTCO2e. In APU’s high extreme energy demand forecast, the projected EV’s registered in Anaheim are 25% above the 1.5M statewide goal, which estimates 20,350 EVs by 2030 and an emissions reduction of 35,844 MTCO2e.
Graph 64: Emission Reductions Resulting from Transportation Electrification
The CEC has since released several updated versions of “2017 SB 350 Common Assumption Guidelines for Transportation Electrification Analysis” in late 2017 through early 2018.16 The most updated analysis
16 The most updated Light‐Duty Plug‐in Electric Vehicle Energy and Emissions Calculator may be found on the CEC’s Integrated Resource Planning webpage: http://www.energy.ca.gov/sb350/IRPs/
(55)
(45)
(35)
(25)
(15)
(5)
5 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Metric Tons of CO23 (Thousands)
Total Emissions Reductions from EV
1.5M by 2025 25% Above 1.5M by 2025
2018 Integrated Resource Plan
IX. Greenhouse Gas Emission Reduction
Anaheim Public Utilities
(Version 3.5‐2, dated 1/12/18) available as of the writing of this IRP resulted in slightly higher number of EVs that were still lower than the high EV extreme scenario. The updated analyses also resulted in slightly higher emission savings per vehicle. This IRP presents the original emission savings per vehicle to be consistent with the rest of the EV calculations. It also reflects a more conservative approach in EV emission savings calculation.
EMISSION REDUCTION TARGET – SYSTEM ENERGY DEMAND
Senate Bill 350, the Clean Energy and Pollution
Reduction Act of 2015 (de León, Chapter 547,
Statutes of 2015) (SB 350) requires the
California Public Utilities Commission (CPUC)
and the California Energy Commission (Energy
Commission) to establish IRP processes to
ensure that load‐serving entities (LSEs) and
qualifying publicly owned utilities (POUs) 17
meet the GHG emission reduction targets
established by the California Air Resources
Board (CARB) for the electricity sector and each LSE and POU for the year 2030.
CARB, in conjunction with CEC, is in the process of developing utility‐specific GHG reduction planning target ranges for California POUs as mandated through the passage of SB 350. The development of utility‐specific GHG reduction target ranges is not expected to be finalized before the adoption of this IRP.
While the CARB is ultimately responsible for setting the GHG reduction target ranges for all utilities, the CEC released a memo titled “Proposed Method for Setting POU‐Specific GHG Emission Reduction Targets for Integrated Resource Planning” dated February 15, 2018. In this memo, the CEC provided their interim guidance and recommended POU GHG reduction planning targets to inform and assist the CARB with establishing the official target planning ranges. As of the writing of this IRP, CARB has indicated that the GHG reduction targets being established for APU by CARB are intended to be IRP GHG reduction planning targets only.
The CEC’s methodology established a proposed range of GHG reduction targets for APU between 304,009 and 537,957 MTCO2e.
This proposed target range represents an approximate emission level between 77% ‐ 87% below APU’s 1990 emission levels. If this GHG reduction range is ultimately adopted by CARB, then it would be significantly greater than the statewide targeted reduction of 40% below 1990 emission levels established by SB 32, and lower
17 The IRP requirement applies only to POUs with annual demand exceeding 700 GWh.
The CEC’s proposed target
range represents an
approximate emission level
between 77% ‐ 87% below
APU’s 1990 emission levels.
The CEC’s proposed target
range represents an
approximate emission level
between 77% ‐ 87% below
APU’s 1990 emission levels.
2018 Integrated Resource Plan
IX. Greenhouse Gas Emission Reduction
Anaheim Public Utilities
bound of the range would be difficult to achieve without significantly increasing APU power supply costs.
Graph 65: APU GHG Emission for System Energy Demand
APU’s resource portfolio will be coal‐free by mid‐2027 and, at a minimum, 50% of APU’s electricity deliveries will come from renewable energy resources. Based on current law and regulations, APU’s optimum resource portfolio under this IRP will achieve the upper bound of the proposed GHG reduction target range; however, the lower bound of the range (i.e., 87% GHG reduction) will not be achieved without significant cost impacts. If CARB adopts the more stringent 87% GHG reduction target it would cause a significant rate impact to APU customers as it would require the shutdown, or “stranding,” of a very reliable and efficient baseload natural 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. APU is closely following relevant regulatory proceedings and will work with CARB and CEC to recommend methodologies to further reduce APU carbon emissions, such as accounting for the effect of electric vehicle (EV) penetration on emission reduction.
250
350
450
550
650
750
850
950
1,050
1,150
1,250
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMT of CO2 (Thousands)
APU GHG Emission ‐ System Energy Demand
APU Emission APU Emission + EV Emission Reduction
APU GHG Emission Target Range
304,611 ‐ 538,146 MMT
(77% ‐ 87% lower than 1990 level)
2018 Integrated Resource Plan
X. Transportation Electrification
Anaheim Public Utilities
X. TRANSPORTATION ELECTRIFICATION
Transportation Electrification (TE) is the transition from fossil‐fuel powered vehicles to vehicles powered by clean and sustainable electricity. This includes passenger and commercial automobiles as well as transit buses and medium to heavy‐duty trucks. APU’s holistic efforts related to TE date back to 2012, soon after modern EVs became commercially available. APU had a vision to facilitate customers’ interests in EVs by addressing EV readiness, charging infrastructure plans, financial tools for customers, ease of permitting, and enhanced customer service. Since then, APU has developed various programs and continues to support TE while providing environmentally sustainable and competitively priced power.
A. Quantification, Characterization, and Location
LOAD IMPACT & GHG EMISSION REDUCTIONS
Using the CEC “Transportation Electrification Common Assumptions 3.0” workbook that was distributed to California utilities in 2017, APU estimated the electricity consumption and net NOx, particulate matter, and GHG emissions reductions associated with Light Duty Plug‐In Electric Vehicle (LD PEV) deployment through 2030. APU’s demand forecast assumes the CEC growth assumptions to meet the Governor’s order of 1.5 million electric vehicles on the road by 2025. The CEC workbook calculates Anaheim’s share of total California registered electric vehicles to be 0.63%, which equals an estimated total of 16,280 electric vehicles contributing to 63,261 MWh in load growth in Anaheim by 2030.
EV CHARGING STATIONS
As of December 2017, APU has installed a total of
69 charging stations. While some of these
charging stations are located within APU and the
City’s facilities, 48 out of 69 (or 70%) are open to
the public and strategically located
in key public
venues or transportation hubs.
The IRP Customer Survey results indicate that the
surveyed residential customers who anticipate
acquiring an EV within the next three years
spread evenly throughout APU’s service territory.
Additionally, about half of these customers live in
multi‐family dwellings, signifying the possible
need for public access charging stations. APU’s
public charging stations will provide these potential EV owners geographical convenience for their fueling options.
Photo 6: Charging Stations at Anaheim Regional Transportation Intermodal Center
2018 Integrated Resource Plan
X. Transportation Electrification
Anaheim Public Utilities
According to the Alternative Fuels Data Center18 of the U.S. Department of Energy (DOE), within the City of Anaheim, there are a total of 193 public access charging stations (3 Level 1 stations, 186 Level 2 stations, and 4 DC Fast Charging stations) as of December 2017. These charging stations include both privately‐owned stations and the above mentioned public access stations under APU control.
Graph 66: EV Charging Stations within APU Service Territory
Utilities Fleet
APU’s earliest effort of fleet electrification focuses on the light‐duty field services vehicles since 1) these vehicles tend to have frequent stops such as for meter reading and 2) light‐duty EVs and hybrid plug‐in
EVs are more technologically mature and
commercially available. APU has achieved 10% low or
zero emission vehicles in its light‐duty fleet. In addition, 36% of APU’s light‐duty fleet are low
emission Compressed Natural Gas (CNG) vehicles.
18 U.S. Department of Energy’s Alternative Fuels Data Center, http://www.afdc.energy.gov/data_download, December 20, 2017.
Photo 7: Early Model Electric Toyota RAV‐4 Used by APU for Fleet Testing
2018 Integrated Resource Plan
X. Transportation Electrification
Anaheim Public Utilities
APU will continue to convert the older and higher‐polluting vehicles to EVs and hybrid EVs to meet South Coast Air Quality Management District (SCAQMD) and DOE requirements. For example, APU’s current field services light duty fleet has a total 14 vehicles, of which 6 are already low or zero emission.
APU anticipates transforming its field services fleet into 100% low or zero emission vehicles by acquiring 10 Chevrolet Bolt EVs.
Medium‐duty and heavy‐duty vehicles provide essential services such as emergency response and outage restoration during blackouts. APU relies more on traditional or biodiesel fuel to ensure that the services will not be interrupted due to mileage range limitations. As of December 2017, biodiesel (20% blend) powers 5% and 76% of APU’s medium‐duty and heavy‐duty fleet, respectively.
It is worth mentioning that APU
owns a hybrid electric bucket
truck. APU acquired the truck to
gain first‐hand experience with
heavy‐duty low emission vehicles
and is still evaluating the
performance of the hybrid truck.
APU will continue to evaluate
technological readiness for the
electrification or the medium and
heavy‐duty fleet.
B. Transportation Electrification Programs
APU’s transportation electrification programs including the following:
B.1. EMPLOYEE WORKPLACE CHARGING PROGRAM
To the extent possible, APU offers its employees and the City’s employees free charging at its EV charging stations located in the employee and fleet parking facilities. APU will continue to encourage and support its employees’ adoption of EVs
whenever feasible.
B.2. EV RATES
APU offers residential customers the option to charge their electric vehicles on a time‐based rate (Developmental Schedule D‐EV of City of Anaheim’s Electric Rates, Rules and Regulations, available online at http://www.anaheim.net/documentcenter/view/1248). The rate currently charges $0.2634 per kWh and $0.1117 per kWh for energy used during on‐peak and off‐peak hours, respectively from June 1 Photo 8: Current Nissan Leaf EV in APU Fleet
2018 Integrated Resource Plan
X. Transportation Electrification
Anaheim Public Utilities