REPORT
INTEGRATED
RESOURCE PLAN
REPORT
WATER AND
POWER
ATTACHMENT 1
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2024 BWP IRP
Acknowledgements
BWP would like to thank the following entities:
• Stakeholder Technical Advisory Group (STAG) for their input and thoughtful analysis on the development of the IRP
• The community members for attending the community
meetings, as well as responding to the survey to provide input on the IRP
• City leadership (including the BWP General Manager) for their support throughout the IRP process
• The Black and Veatch Management Consultant, LLC team, who developed the report and analysis
• The power supply management team for their efforts on the analysis, quality assurance checks, development of the presentations and leading the stakeholder engagement
efforts
• The power supply admin team for organizing the
stakeholder meetings
• The sustainability, marketing and strategy team for their work on the IRP cover art, IRP survey, stakeholder
meetings and event planning
Thank you all for your efforts on developing the 2024 BWP IRP ATTACHMENT 1
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2024 INTEGRATED RESOURCE PLAN
BURBANK, CA
B&V PROJECT NO. 415039
PREPARED FOR
Burbank Water and Power
13 NOVEMBER 2023
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City of Burbank | 2024 INTEGRATED RESOURCE PLAN
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Table of Contents
1 Executive Summary ............................................................................................................................ 1-1 2 Introduction and Background ........................................................................................................ 2-4
2.1 Introduction ........................................................................................................................................... 2-4
2.1.1 Burbank Water and Power............................................................................................ 2-5
2.1.2 Mandate for Integrated Resource Plan .................................................................... 2-6
2.1.3 Objectives of the Integrated Resource Plan ........................................................... 2-6
2.1.4 Policy Guidelines, Major Implications, and Action Items ................................. 2-6
2.1.5 Major Mandates ............................................................................................................... 2-10
2.2 Previous Integrated Resource Plans .......................................................................................... 2-12
2.2.1 Major Changes Since Burbank’s Last IRP .............................................................. 2-12
2.3 Community Outreach ....................................................................................................................... 2-14
2.4 Existing City Policies and Programs ........................................................................................... 2-14
2.4.1 Renewable Portfolio Standards ................................................................................ 2-14
2.4.2 Energy Efficiency ............................................................................................................. 2-15
2.4.3 Demand Side Management ......................................................................................... 2-17
2.4.4 Transportation Electrification and Electric Vehicles ....................................... 2-17
2.4.5 Disadvantaged Communities ..................................................................................... 2-20
2.5 Burbank Water and Power’s Existing Resources ................................................................. 2-20
2.5.1 How is Power Produced? ............................................................................................. 2-20
2.5.2 Baseload, Load-Following, Peaking, and Intermittent Power Resources ........................................................................................................................... 2-21
2.5.3 Power Generated in Burbank ..................................................................................... 2-23
2.5.4 Power Generated Outside of Burbank .................................................................... 2-26
2.6 Planning Scenarios Considered .................................................................................................... 2-33
2.6.1 Base Case ............................................................................................................................ 2-34
2.6.2 “Net Zero by 2030” Planning Scenario ................................................................... 2-39
2.6 .3 “SB1020+SMR” Planning Scenario ........................................................................... 2-42
2.6.4 “SB1020 + SMR w/ 50% DEV & EV Demand” Planning Scenario ............... 2-45
2.6.5 “10% Higher EV & DEV Demand” Planning Scenario ...................................... 2-48
2.6.6 “10% Lower EV & DEV Demand” Planning Scenario ....................................... 2-51
2.6.7 “New Transmission & PPAs” Planning Scenario ................................................ 2-54
2.6.8 Scorecard and Recommended Strategy ................................................................. 2-57
2.7 Other Planning Considerations .................................................................................................... 2-59
2.7.1 Resources ........................................................................................................................... 2-59
2.7.2 Environmental Costs ..................................................................................................... 2-60 3 IRP Filing Contents Per CEC ........................................................................................................... 3-61
3.1 Planning Period (HORIZON) .......................................................................................................... 3-61
3.1.1 Study Period ...................................................................................................................... 3-61
3.1.2 RPS Obligations ................................................................................................................ 3-61 ATTACHMENT 1
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3.1.3 GHG Targets ...................................................................................................................... 3-61
3.2 Scenarios and Sensitivity Analysis .............................................................................................. 3-62
3.2.1 Production Cost Modeling Software........................................................................ 3-62
3.2.2 Key Inputs and Assumptions ...................................................................................... 3-62
3.2.3 Summary of All Scenarios, Scorecard, and Recommended Strategy ......... 3-68
3.2.4 Emissions Summary....................................................................................................... 3-70
3.3 Standardized Tables ......................................................................................................................... 3-70
3.4 Supporting Information .................................................................................................................. 3-71
3.5 Demand Forecast ............................................................................................................................... 3-71
3.5.1 Demand Forecast Methodology and Assumptions ............................................ 3-71
3.5.2 Determination of Hourly Demand Shapes ............................................................ 3-75
3.5.3 Results of Demand Forecast ....................................................................................... 3-78
3.6 Resource Procurement Plan .......................................................................................................... 3-80
3.6.1 Diversified Procurement Portfolio and RPS Planning Requirements ................................................................................................................... 3-80
3.6.2 Energy Efficiency and Demand Response Resources ...................................... 3-81
3.6.3 Energy Storage ................................................................................................................. 3-83
3.7 System and Local Reliability .......................................................................................................... 3-86
3.7.1 Bulk Transmission Reliability .................................................................................... 3-86
3.7.2 Distribution Reliability ................................................................................................. 3-86
3.8 Greenhouse Gas Emissions ............................................................................................................ 3-87
3.8.1 GHG CARB Targets .......................................................................................................... 3-87
3.8.2 BWP’s Green Choice Program .................................................................................... 3-88
3.8.3 Burbank’s Greenhouse Gas Reduction Plan ......................................................... 3-88
3.9 Retail Rates ........................................................................................................................................... 3-89
3.9.1 Planning Scenario Rate Impact Analysis ............................................................... 3-89
3. 9.2 The Ratemaking Process .............................................................................................. 3-90
3.9.3 Appropriate Price Signals ............................................................................................ 3-92
3.9.4 Current Electric Rates ................................................................................................... 3-92
3.9.5 Energy Charge .................................................................................................................. 3-93
3.9.6 Fixed Monthly Charges ................................................................................................. 3-95
3.9.7 Demand Charges.............................................................................................................. 3-95
3.9.8 Electric Rate Comparison ............................................................................................ 3-96
3.10 Transmission System Resources ................................................................................................. 3-98
3.10.1 History of BWP’s Transmission Rights .................................................................. 3-99
3.10.2 Planned Transmission Upgrades and Additions ................................................ 3-99
3.11 Distribution System Resources ................................................................................................. 3-100
3.11.1 Anticipating Customer DER Developments ...................................................... 3-102
3.11.2 Grid Modernization ..................................................................................................... 3-103
3.12 Localized Air Pollutants and Disadvantaged Communities ........................................... 3-104 4 Energy Efficiency Analysis .......................................................................................................... 4-104 ATTACHMENT 1
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5 Public Participation ....................................................................................................................... 5-105
5.1 Stakeholder Technical Advisory Group (STAG) ................................................................. 5-105
5.2 Community Stakeholder Meetings ........................................................................................... 5-106
5.3 IRP Survey .......................................................................................................................................... 5- 106
5.4 BWP Board and City Council Update ...................................................................................... 5-106 6 Process for Updating the IRP ..................................................................................................... 6-106 7 Attachments ..................................................................................................................................... 7-106
List of Tables
Table 1-1 Summary of Planning Scenarios .................................................................................................... 1-2 Table 1-2 Rate Impacts from Planning Scenarios ...................................................................................... 1-3 Table 1-3 Initial Scorecard Results ................................................................................................................... 1-3 Table 1-4 Final Scorecard Results ..................................................................................................................... 1-4 Table 2-1 Historical Natural Gas and Energy Prices ................................................................................ 2-13 Table 2-2 Changes to Market Conditions Post-2024 IRP Development .......................................... 2-13 Table 2-3 Current Renewable Generation ................................................................................................... 2-15 Table 2-4 Commercial Charging Station Rebates in Burbank .............................................................. 2-18 Table 2-5 Existing Generation Facilities in Burbank ............................................................................... 2-23 Table 2-6 Net Capacity of Resources .............................................................................................................. 2-26 Table 2-7 IPP Contract Details .......................................................................................................................... 2-30 Table 2-8 Summary of Planning Scenarios .................................................................................................. 2-34 Table 2-9 Scorecard Details and Weighting ................................................................................................ 2-58 Table 2-10 Initial Scorecard Results ................................................................................................................. 2-58 Table 2-11 Final Scorecard Results ................................................................................................................... 2-59 Tab
le 3-1 Annual RPS Targets ........................................................................................................................... 3-61 Table 3-2 Scorecard Details and Weighting ................................................................................................ 3-69 Table 3-3 Scorecard Results ............................................................................................................................... 3-69 Table 3-4 Greenhouse Gas (GHG) Emissions in Metric Tonnes .......................................................... 3-70 Table 3-5 Annual Net Energy Demand & Net Peak Energy Demands .............................................. 3-79 Table 3-6 RPS Compliance Requirements .................................................................................................... 3-80 Table 3-7 BYOD Smart Thermostat Program Parameters ..................................................................... 3-83 Table 3-8 Rate Impacts from Planning Scenarios .................................................................................... 3-90 Table 3-9 2022 Class Cost of Service Study Results ................................................................................. 3-92 Table 3-10 Commercial Customer Classes for Rates .................................................................................. 3-93 Table 3-11 Types of Charges Applicable to Major Customer Classes .................................................. 3-93 Table 3-12 Time Periods for Time-of-Use (TOU) Rates ............................................................................ 3-94 Table 3-13 Time Periods for Time-of-Use (TOU) Rates for Residential Electric Vehicle Owners ................................................................................................................................................... 3-94 Table 4-1 Energy Efficiency Savings – Actuals vs. Goals ..................................................................... 4-105 ATTACHMENT 1
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Table 5-1 STAG Meeting Schedule ................................................................................................................ 5-105 Table 5-2 Community Stakeholder Meeting Schedule ......................................................................... 5-106
List of Figures
Figure 2-1 Transportation Electrification Statistics .................................................................................. 2-19 Figure 2-2 Magnolia Production During Heat Dome Event .................................................................... 2-25 Figure 2-3 Copper Mountain Solar 3 Production During Heat Dome Event .................................... 2-27 Figure 2-4 Ameresco Chiquita Production During Heat Dome Event ................................................ 2-32 Figure 2-5 Base Case Portfolio Capacity Mix................................................................................................. 2-36 Figure 2-6 Base Case Portfolio Generation Mix ........................................................................................... 2-37 Figure 2-7 Base Case Annual RPS Percentage .............................................................................................. 2-38 Figure 2-8 Base Case Carbon Intensity ............................................................................................................ 2-38 Figure 2-9 Base Case Total System and Energy Costs ............................................................................... 2-39 Figure 2-10 “Net Zero by 2030” Planning Scenario – Installed Capacity ............................................. 2-40 Figure 2-11 “Net Zero by 2030” Planning Scenario – Generation Mix .................................................. 2-41 Figure 2-12 Net Zero by 2030 Scenario – RPS Percentage ........................................................................ 2-41 Figure 2-13 Net Zero by 2030 Scenario – Carbon Intensity ...................................................................... 2-42 Figure 2-14 “Net Zero by 2030” Planning Scenario – Total System and Energy Costs .................. 2-42 Figure 2-15 “SB1020+SMR” Planning Scenario - Installed Capacity Mix............................................. 2-43 Figure 2-16 “SB1020+SMR” Planning Scenario - Generation Mix .......................................................... 2-44 Figure 2-17 “SB1020+SMR” Planning Scenario – RPS Percentage ......................................................... 2-44 Figure 2-18 “SB1020+SMR” Planning Scenario - Total System and Energy Costs ........................... 2-45 Figure 2-19 “SB1020+SMR” Planning Scenario - Carbon Intensity ....................................................... 2-45 Fi
gure 2-20 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Installed Capacity Mix ......................................................................................................................................... 2-46 Figure 2-21 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Generation Mix ............................................................................................................................................................ 2-47 Figure 2-22 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario – RPS Percentage ............................................................................................................................................ 2-47 Figure 2-23 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Carbon Intensity ................................................................................................................................................. 2-48 Figure 2-24 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Total System and Energy Costs ................................................................................................................ 2-48 Figure 2-25 “10% Higher EV & DEV Demand” Planning Scenario – Installed Capacity Mix ............................................................................................................................................................ 2-49 Figure 2-26 “10% Higher EV & DEV Demand” Planning Scenario – Generation Mix ..................... 2-50 Figure 2-27 “10% Higher EV & DEV Demand” Planning Scenario – RPS Percentage ..................... 2-50 Figure 2-28 “10% Higher EV & DEV Demand” Planning Scenario – Carbon Intensity .................. 2-51 Figure 2-29 “10% Higher EV & DEV Demand” Planning Scenario – Total System and Energy Costs ......................................................................................................................................... 2-51 ATTACHMENT 1
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Figure 2-30 “10% Lower EV & DEV Demand” Planning Scenario – Installed Capacity Mix ............................................................................................................................................................ 2-52 Figure 2-31 “10% Higher EV & DEV Demand” Planning Scenario – Generation Mix ..................... 2-53 Figure 2-32 “10% Higher EV & DEV Demand” Planning Scenario – RPS Percentage ..................... 2-53 Figure 2-33 “10% Lower EV & DEV Demand” Planning Scenario – Carbon Intensity ................... 2-54 Figure 2-34 “10% Lower EV & DEV Demand” Planning Scenario – Total System and Energy Costs ......................................................................................................................................... 2-54 Figure 2-35 “New Transmission & PPAs” Planning Scenario – Installed Capacity Mix ................. 2-55 Figure 2-36 “New Transmission & PPAs” Planning Scenario – Generation Mix ............................... 2-56 Figure 2-37 “New Transmission & PPAs” Planning Scenario – RPS Percentage .............................. 2-56 Figure 2-38 “New Transmission & PPAs” Planning Scenario – Carbon Intensity ............................ 2-57 Figure 2-39 “New Transmission & PPAs” Planning Scenario – Total System and Energy Costs ........................................................................................................................................................ 2-57 Figure 3-1 Planning Scenario Carbon Emissions ........................................................................................ 3-62 Figure 3-2 IEPR SoCal Citygate Natural Gas Price Forecast Comparison ......................................... 3-64 Figure 3-3 Natural Gas Price Forecast ............................................................................................................. 3-65 Figure 3-4 CAPEX Projections by Technology in Rockies Region ....................................................... 3-66 Figure 3-5 CAPEX Projections by Technology in California Region .................................................... 3-66 Figure 3-6 CAPEX Projections by Technology in California Neighbor Region ................................ 3-67 Figure 3-7 Gross and Net Energy Demand Components.......................................................................... 3-71 Figure 3-8 Forecast Electric Vehicle Energy Demand for Burbank ..................................................... 3-73 Figure 3-9 Forecasted Energy Efficiency Savings for Burbank ............................................................. 3-74 Figure 3-10 Forecasted Additional Distributed Generation for Burbank ........................................... 3-75 Figure 3-11 Average Hourly Summer Demand Profiles ............................................................................. 3-77 Figure 3-12 Average Hourly Winter Demand Profiles ................................................................................ 3-77 Fi
gure 3-13 Forecast Net Annual Demand and Annual Net Peak Demand ......................................... 3-78 Figure 3-14 Energy Efficiency Savings FYTD 2022-2023 .......................................................................... 3-82 Figure 3-15 Example: Battery Impact on the Duck Curve .......................................................................... 3-85 Figure 3-16 Battery Impact on Annual Solar Curtailment ......................................................................... 3-86 Figure 3-17 SAIFI, 5-Year Average 2017-2021 .............................................................................................. 3-87 Figure 3-18 Residential Bill for Average Single-Family Monthly Consumption ............................... 3-97 Figure 3-19 Burbank’s Existing Firm Transmission ..................................................................................... 3-98 Figure 3-20 Burbank’s Existing Distribution System ................................................................................ 3-101 Figure 3-21 Distributed Generation Installations ...................................................................................... 3-103
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1 Executive Summary
The development of Burbank’s Integrated Resource Plan (IRP) is mandated by the “Clean Energy and Pollution Reduction Act,” also known as Senate Bill 350 (SB 350). After it was passed in 2015, SB 350 required that, every five years, publicly-owned utilities with an annual electricity demand greater than 700 gigawatt-hours develop an IRP and file it with the California Energy Commission (CEC). As one of the publicly-owned utilities affected by SB 350, Burbank Water and Power (BWP) completed its previous IRP in December 2018. BWP uses its IRPs as tools to help make plans for Burbank’s energy future. As such, the IRP is a living document that will be routinely reviewed and updated as conditions in Burbank and the larger energy marketplace continue to change.
The 2024 IRP documented in this report was developed with input taken from a robust public stakeholder process. In November 2022, the Stakeholder Technical Advisory Group (STAG) was formed and included representatives from large corporations, non-profit entities, small commercial customers, civic leaders, environmental groups, and residential ratepayer advocates. In addition, BWP developed an IRP website to give the public an additional opportunity to follow along with the information shared at four community meetings that were hosted throughout 2023. At those meetings BWP provided IRP status updates and time was given for the public to ask questions about the IRP process in general and the 2024 IRP specifically. BWP’s website also contained a short, 12-question IRP survey. Between December 2022 and November 2023, the survey garnered a total of 952 responses from members of the public.
To assist in the creation of the detailed technical analysis that would be necessary for its 2024 IRP, BWP partnered with Black & Veatch Management Consulting, LLC, a wholly-owned subsidiary of Black & Veatch Holding Company. Black & Veatch Holding Company is a global engineering, construction, and consulting company. Since its founding in 1915, Black & Veatch has expanded to include over 10,000 professionals working out of more than 120 offices worldwide. Black & Veatch Management Consulting, LLC is made up of more than 170 experts from the electric, water, oil, natural gas, and technology industries. Prior to its work with BWP, Black & Veatch Management Consulting, LLC had recently engaged with clients, both in California and throughout the rest of the United States, on projects including IRPs, decarbonization strategies, market price forecasts, and long-term strategic plans for generation and transmission resources. For this project, Black & Veatch created a production cost model representing the City of Burbank that included its existing transmission and generation resources, purchased power contracts, and forecasts for energy demand, market energy prices, and fuel costs. Once the Burbank model had been completed by Black & Veatch, BWP was able to define multiple planning scenarios representing possible future conditions for the 25-year period from 2023 through 2047. A total of seven different planning scenarios were evaluated. They are listed below in Table 1-1.
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Table 1-1 Summary of Planning Scenarios
Scenario # Scenario Name Details
1 Base Case Meets SB 100 requirements of 60% renewables by 2030 and the BWP requirement of 100% zero carbon by 2040.
2 Net Zero by 2030
Meets the Base Case requirements and 100% zero
carbon by 2030 (Accomplished by assuming renewable
natural gas could be secured for Magnolia and Lake One
in addition to assuming a full conversion of
Intermountain Power Plant (IPP) to hydrogen by 2030).
3 SB1020+SMR
Meets the Base Case requirements, contracts for 25
megawatts (MW) of small modular reactor capacity by
2030 from outside CA, meets the SB 1020 goal of 90%
carbon free resources by 2035 and 100% carbon free
resources by 2040.
4 SB1020+SMR w/ 50% DEV & EV
Demand
Meets the Base Case requirements, contracts for 25 MW
of small modular reactor capacity by 2030 from outside
CA, meets the SB 1020 goal of 90% carbon free resources by 2035 and 100% carbon free resources by 2040 and
includes a 50% reduction of electrification (EV) and
development (DEV) demand as compared to the Base
Case.
5 10% Higher EV & DEV Demand
Meets the Base Case requirements and includes 10%
higher electrification (EV) and development (DEV)
demand as compared to the Base Case.
6 10% Lower EV & DEV Demand
Meets the Base Case requirements and includes 10%
lower electrification (EV) and development (DEV)
demand as compared to the Base Case.
7 New Transmission & PPAs
Meets the Base Case requirements and assumes working
with LADWP to secure additional transmission services
contracts to bring in renewables from outside CA,
through power purchase agreements (PPAs)
Simulations corresponding to each of the seven planning scenarios were run using the production cost model. The output for each planning scenario included the unique portfolio of generating assets and purchased power contracts that would provide the lowest cost, reliable energy needed to serve the people of Burbank. Greenhouse gas emissions and total system and energy costs were also calculated.
Following the completion of the modeling for each of the planning scenarios, the results were reviewed by the BWP Rate Manager who completed a rate impact analysis. Within that analysis there were two key factors that differentiated the different scenarios and drove rate impacts:
annual power supply costs and annual electric sales. Other utility costs were assumed to be the same for each of the seven planning scenarios. Two different measures of rate impact were calculated. The first was the average annual rate increase from current levels associated with achieving a target of 200 days cash on hand (DCOH) in the final analysis year of 2047. The second measure was the total bill increase projected to occur by 2047 for each of the scenarios using the previously calculated average annual rate increase and taking into account the rate increases approved for 2025 and rate increases projected for the future. The rate increases associated with ATTACHMENT 1
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the IRP are above and beyond the already approved and forecasted rate increases for BWP. This increase should be interpreted as being in addition to the current bill. That is, if the calculated bill increase is 158%, a $100 electric bill today would increase to $258 in 2047 (in nominal terms). As a point of reference, if rates were increased by 2% per year to keep pace with a general inflation rate, customer bills in 2047 would be 67% higher than they are today.
Table 1-2 Rate Impacts from Planning Scenarios
Scenario
# Scenario Name
Annual Rate Increase
(if contracts are
signed and are
available)
Bill Increase
2047 vs. Current
1 Base Case 4.03% 158%
2 Net Zero by 2030 9.49% 694%
3 SB1020+SMR 4.96% 213%
4 SB1020+SMR w/ 50% DEV &EV
Demand 5.57% 256%
5 10% Higher EV & DEV Demand 3.94% 153%
6 10% Lower EV & DEV Demand 4.12% 163%
7 New Transmission & PPAs 4.03% 158%
Once all of the results for the seven planning scenarios were available, the scenarios were ranked using a scorecard that was based on feedback from the IRP survey, the members of the STAG, and other community stakeholders.
Table 1-3 Initial Scorecard Results
After the planning scenarios were ranked using the scorecard analysis, BWP removed three of the potential scenarios from consideration. This action was taken due to recent developments affecting the underlying assumptions for those scenarios. Specifically, the lack of availability for adequate sources of renewable natural gas (RNG) made the “Net Zero by 2030” scenario significantly more challenging to achieve. Additionally, in the summer of 2023, BWP entered into negotiations with several large commercial customers that could materially add to Burbank’s annual energy demand.
As a result, the two planning scenarios that considered slower energy demand growth (“SB1020+SMR w/ 50% DEV & EV Demand” and “10% Lower EV & DEV Demand”) were also ATTACHMENT 1
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eliminated. In the end, two preferred scenarios were chosen by BWP. These were the scenarios named “SB1020+SMR” and “New Transmission & PPAs.”
Table 1-4 Final Scorecard Results
The “SB1020+SMR” planning scenario includes the updated zero-carbon energy requirements that are a part of the “Clean Energy, Jobs, and Affordability Act of 2022,” also known as Senate Bill 1020 (SB 1020), and the assumption that BWP will be able to procure a purchased power contract for 25 MW of capacity from a small modular reactor (SMR) starting in 2030. In addition to the new SMR contract, this portfolio also included new geothermal, solar, hydrogen, and battery storage assets.
The “New Transmission & PPAs” planning scenario assumes that new transmission lines would be in-service by 2035. Those new transmission resources would allow BWP to acquire power from generating resources outside Burbank that it would otherwise not be able to benefit from. New geothermal, solar, hydrogen, wind, and battery storage resources would add diversity to Burbank’s energy portfolio and align with its emission reductions goals. The results for this scenario include the costs associated with the Transmission Service Agreements (TSAs) that would be necessary for Burbank to take advantage of new transmission capacity.
Both of the preferred scenarios chosen by BWP provide a path forward for compliance with California’s renewable energy portfolio (RPS) and clean energy mandates as well as meeting the BWP goal of achieving 100% zero-carbon resources by 2040. The choice of preferred scenarios also aligns with BWP’s continuing commitment to provide reliable, affordable, and sustainable power for the residents and businesses of Burbank.
2 Introduction and Background
2.1 INTRODUCTION
The following report documents the 2024 IRP for BWP. The IRP is a long-term plan that is intended to provide guidance for BWP’s electric supply from 2023 to 2047. This IRP, like all long-term planning documents, is directional rather than determinative. In other words, the IRP helps Burbank see the broad contours of its energy future and the general direction that Burbank should head toward to reach that future.
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The utility industry continues to undergo dramatic changes and this IRP reflects them. Concerns for climate change, the growth of renewable energy and energy storage, and the pending retirement of legacy fossil fuel-fired resources are all elements that have been considered.
The IRP is also informed by public input and the perspectives of Burbank residents, businesses, and other stakeholders. BWP had engagement with the public throughout its IRP process.
As a long-term planning document, this IRP is based on assumptions about what will happen in the future. These assumptions are based on the best available information and the judgement of experts at the time they were developed. However, the utility industry is continuing to experience a period of significant changes and so the assumptions that have been made carry inherent uncertainties. Future changes to the energy markets and to federal and state policies affecting the generation and transmission of electricity will influence the choices that BWP will make in the years to come. To account for this, this IRP is a living document that will be regularly revisited and improved to incorporate new or updated assumptions and to adopt practices that further BWP’s mission to provide its customers with reliable, affordable, and sustainable electric service.
2.1.1 Burbank Water and Power
The City of Burbank is known as the “Media Capital of the World” and is home to many film and animation studios including Disney, Warner Bros., and Netflix. There are many smaller businesses in Burbank who also depend on reliable and cost-competitive electric service. About 105,000 people in a vibrant residential community call Burbank home. In total, BWP serves approximately 46,290 residential, 6,880 commercial, and 82 large commercial accounts.1 BWP is a vertically integrated municipal utility owned and operated by the City of Burbank as a not- for-profit that generates, transmits, and distributes power to its customers at cost. During calendar year 2022, BWP maintained an availability rate of 99.999% with a system average interruption of less than 5 minutes per customer.2 BWP’s continuing excellence in system performance was recognized in 2021 when it was presented with a Reliable Public Power Provider (RP3) award by the American Public Power Association and earned its highest possible score. 3 This level of
performance was achieved while maintaining customer rates at levels lower than the average California customer. For fiscal year 2022, the system weighted average electric rate for the City of
1 “City of Burbank Water and Power Annual Report, Fiscal Year 2021 -2022,” page 59, https://www.burbankwaterandpower.com/images/administrative/downloads/BWP_FY2021 - 22_AnnualReport_Audited.pdf
2 “City of Burbank, Burbank Water and Power, Staff Report,” dated February 2, 2023, page 19, https://www.burbankwaterandpower.com/images/administrative/downloads/BWP_MonthlyOpsReport_Fe bruary2023.pdf
3 “Burbank Water and Power (BWP) Wind Prestigious National Award for Electric Reliability,” April 16, 2021, https://www.burbankca.gov/newsroom/-/n ewsdetail/20124/burbank-water-and-power-bwp-wins- prestigious-national-award-for-electric-reliability
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Burbank was 15.66 Cents/kWh4 while the June 2022 system average for all of California was 23.83 cents/kWh.5
2.1.2 Mandate for Integrated Resource Plan
In accordance with the requirements of “The Clean Energy and Pollution Reduction Act” (SB 350) that was passed in 2015, publicly-owned utilities in California with an annual electricity demand greater than 700 gigawatt-hours were required to develop an IRP and submit it to the CEC.6 That IRP is required to be updated at least once every five years. As one of sixteen publicly-owned utilities affected by that IRP requirement, Burbank last completed an IRP in December 2018.
2.1.3 Objectives of the Integrated Resource Plan
Burbank’s IRP is a tool to assist the City as it makes plans for its energy future. It must serve to help guide the City in its long-term power supply planning for generation resources, transmission resources, renewable energy procurement, and greenhouse gas (GHG) emissions reductions. These long-term plans must also serve the mission of providing Burbank with reliable electrical service while minimizing the impact on ratepayer bills.
2.1.4 Policy Guidelines, Major Implications, and Action Items Through the IRP process, BWP found that, while the business of providing Burbank with reliable, affordable, and sustainable electric service continues to experience rapid change, the overarching principles that guide its business are captured in the following policy guidelines:
BWP should continue to meet electricity demand growth by first encouraging energy efficiency and conservation. Future generation resources or long-duration energy storage capabilities necessary to satisfy additional demand growth will be researched and considered on a case-by-case basis.
• BWP should optimize cost-effective energy efficiency and conservation programs. • BWP will add renewable energy to meet state mandates. • BWP should plan to achieve GHG emissions reductions in line with state and city goals. • BWP aims to maintain low cost of service for its electric customers.
During the preparation of this 2024 IRP, BWP identified a number of major implications to consider. These implications are as follows:
4 “City of Burbank Water and Power Annual Report, Fiscal Year 2021 -2022,” page 60, https://www.burbankwaterandpower.com/images/administrative/downloads/BWP_FY2021 - 22_AnnualReport_Audited.pdf
5 U.S. Energy Information Administration, Electric Power Monthly, Table 5.6.A., released August 2023, https://www.eia.gov/electricity/monthly/archive/august2022.pdf 6 Public Utility Code Section 9621(a)
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• BWP should pursue cost-effective energy efficiency and demand response programs to fulfill California energy efficiency requirements and place additional emphasis on peak demand reduction.
• BWP’s share of the Intermountain Power Project (IPP) coal-fired generating plant in Utah will be retired in June 2025. After that, BWP will continue to purchase energy from the new natural gas-fired facility at IPP that will be coming online at the same time. As a result of the conversion of IPP from coal to natural gas, the total capacity of IPP is decreasing from 1,800 MW to 840 MW. Due to that change in total site capacity, BWP’s share of that capacity will decrease from 89.28 MW to 35 MW for the period from 2025 through 2027. Then, starting in 2027, a new 50-year contract with IPP will begin and BWP’s capacity share will be further reduced to 28 MW. IPP will be 30% hydrogen capable in 2025, with an aim of 100% hydrogen by 2045.
• In accordance with SB100, BWP will need to procure additional renewable energy resources to increase their projected 41.25% share of BWP’s retail sales in 2023 to at least 60% by 2030. All of the planning scenarios documented in Section 2.6 of this report included this SB100 renewable energy requirement.
• Additional quantities of fast-ramping energy storage and dispatchable generation will be needed to address the intermittency of renewable resources. Mitigating the effects of the “Duck Curve” will necessitate expanding the capacity of energy storage resources. During the daytime, conventional and renewable energy generation is able to meet the real time needs of customers in the energy market. However, during the evening hours, as the sun sets and solar generation rapidly decrease to zero, large amounts of energy from conventional generation or energy storage needs to be available to fill that gap. Energy storage will allow renewable energy to be storage during time of excess generation and then released back into the system when it is needed.
• BWP’s greenhouse gas emissions should be dramatically reduced during the planning period, consistent with California Air Resources Board (CARB) targets set forth in the 2017 Scoping Plan. Those targets represent proportional shares of the overall California emissions reductions goals for publicly owned utilities including BWP. The CARB Scoping Plan was updated in 2022, with the dataset for greenhouse gas emissions reductions updated in September 2023.
7 The dataset for greenhouse gas emissions reductions used for this IRP is based on the 2017 Scoping Plan, since that was the only dataset that was available during the development of the IRP. Additional information about the changes to the CARB emissions targets are provided in Section 3.1.3 below. In each planning scenario within this 2024 IRP, BWP achieves its aspirational goal of 100% zero carbon resources no later than 2040.
• Similar to the 2022 CARB Scoping Plan, this IRP assumes that technologies like carbon capture and sequestration and hydrogen will be commercially available in the amount
7 California Air Resources Board, “Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets: 2023 Update,” September 2023, https://ww2.arb.ca.gov/resources/documents/irp- ghg-targets-2023-update
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necessary to achieve the greenhouse gas reductions necessary to get BWP to its 2040 zero- carbon resources goal.
• Alternative fuel technologies such as hydrogen or RNG and other dispatchable clean energy resources such as geothermal power and SMRs will need to be considered as the BWP system transitions from a 60% RPS requirement in 2030 to 100% zero-carbon resources by 2040 (though SB 100 requires 100% of resources come from zero-carbon resources by 2045, BWP has a more aggressive goal of meeting 100% of its resources from zero-carbon resources, starting in 2040). Some of these energy technologies have not reached high levels of developmental maturity or have not yet seen widespread adoption. Risks associated with the delayed deployment of these necessary technologies could impact the planning forecasts in this IRP and the ability of BWP to achieve its stated emissions reduction goals in a timely and cost-effective way.
• Electrification could have a significant impact on BWP’s energy procurement and system cost. Materially higher levels of electrification over time could result in significantly higher electricity demand and could subsequently make the transition to renewable and clean energy goals more challenging and costly. Electrification results in greater utilization of assets and can eventually drive down total costs in the future. Uncertainty about long-term trends in electrification has been addressed within the planning scenarios in this 2024 IRP Report. Sensitivity cases that include higher or lower demand from the electrification of the transportation sector are described more fully in Section 2.6. It is important to note, that state mandates for electrification; specifically, the requirement that all new passenger cars and trucks be zero-emission post-2035 and the elimination of natural gas appliances, will lead to overall savings for customers. The electric costs will go up; however, natural gas and gasoline bills should dramatically decrease.
Finally, BWP also identified a number of action items that it plans to address. • Rate Design: Design time-of-use (TOU) rates that encourage customers to shift their energy consumption away from higher cost periods to lower cost periods. BWP plans to develop a more robust TOU rate-making process in October 2024. See Sections 2.4.3 and 3.9.5.2 for more information on TOU rates.
• Demand Response (DR): Consider cost-effective BWP customer DR programs. See Section
2.1.5.3 for additional details on DR actions being pursued. • Beneficial Electrification: BWP continues to manage a comprehensive portfolio of resource efficiency programs for residential and commercial customers focused on energy efficiency, peak load reduction, transportation electrification, and greenhouse gas savings. See Section
2.4 for more information on the programs that are already in place to encourage electrification.
• Disadvantaged Communities: Develop and implement a program to target disadvantaged communities with selected BWP energy efficiency, demand response, and beneficial electrification programs. See Section 2.4.5 for additional information about BWP programs available for customers in disadvantaged communities.
• IPP Coal Replacement: Accommodate the decrease in BWP’s share of IPP’s capacity and the change in fuel types planned for IPP starting in 2025. See Section 2.5.4 for additional details about the changes planned for IPP and how they will affect BWP.
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• Transmission Delivery for Renewables: In collaboration with BWP’s Balancing Authority (the Los Angeles Balancing Authority), secure additional transmission services agreements.
The availability of long-distance electrical transmission resources to bring energy to Burbank from more distant locations gives BWP additional opportunities to seek out and procure diverse energy resources.
• Solar Over-Generation: Work to mitigate the impact of solar generation (including morning and evening ramping, overgeneration, and instantaneous intermittency) such that reliability and affordability are maintained. To achieve the high levels of renewable energy use required by its RPS targets, BWP will have to procure renewable capacity that will exceed its annual peak demand. This means that it will have more renewable energy than it needs on many days of the year when peak demands are lower than the annual peak demand. On summer days, the mismatch between renewable supply and customer demand is manageable. However, during mild spring or fall days, the non-dispatchable renewable generation may exceed total customer demand. Solar over-generation can be mitigated though the curtailment of generation assets including the solar facilities themselves. This is not the ideal solution as it limits the benefits gained through the use of renewable energy.
Another mitigation option is the use of energy storage or changes in demand (like demand response, etc.) to absorb the energy from over-generation during the day and then discharge that energy later in the day when it is needed. Section 3.6.3.3 contains additional information on how energy storage is used to increase the usefulness of intermittent renewable resources.
• EIM Participation: Evaluate possible participation in the California Independent System Operator’s (CAISO’s) Energy Imbalance Market (EIM). The EIM is an initiative by CAISO to create a larger daily wholesale electricity marketplace with more participants to ensure additional sharing of diverse energy resources. Participating is voluntary, although BWP cannot participate unless its balancing authority, the Los Angeles Department of Water and Power (LADWP), also joins. In April 2021, LADWP began its participation in CAISO’s EIM. 8 BWP will also separately assess the possibility of joining the CAISO Extended Day-Ahead Market (EDAM). The EDAM seeks to improve efficiencies within the energy market by using day-ahead commitment and scheduling of generating resources across a large geographic area across multiple states. A regional day-ahead market such as the EDAM could also improve system reliability and help to more effectively schedule renewable resources and reduce the need for clean energy curtailment.
• Resource Positioning: Position BWP’s resources to work with the Duck Curve to the greatest extent possible to minimize costs and maximize reliability for Burbank. Evaluate further improvement in the operational flexibility of the Magnolia Power Project. In 2023, BWP was awarded the “Best Practices Award from the Combined Cycle Journal,” for the General Electric or GE enhancements that were implemented at Magnolia to allow for efficient turn down of the unit, as more variable resources, such as wind and solar come on to the grid. The GE enhancements reduced the minimum output of Magnolia from 165 MW,
8 Los Angeles Department of Water & Power, “LADWP Begins Participation in Western Energy Imbalance Market (EIM),” https://www.ladwpnews.com/ladwp-be gins-participation-in-western-energy-imbalance- market-eim/
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down to 87 MW. In addition, the enhancements reduced emissions and lowered variable costs for the unit.
2.1.5 Major Mandates
2.1.5.1 Renewable Portfolio Standards
“The 100 Percent Clean Energy Act of 2018” (SB 100) revised existing laws concerning the California RPS Program9 to mandate that 60% of the total retail sales of electricity in California will be generated from eligible renewable energy resources by the end of 2030. SB 100 also included a goal of providing 100% of the retail electricity sold in California with renewable and zero-carbon power sources. Eligible resources include solar, wind, geothermal, biomass, and small hydro generation facilities. This was done with the stated purposes of benefiting the state by, among other things: displacing fossil fuel consumption, diversifying energy generation, reducing air pollution, and meeting the state’s climate change goals.
SB 1020, or the “Clean Energy, Jobs, and Affordability Act of 2022” added interim targets to the provisions of SB 100. SB 1020 required that by 2035, 90% of retail electricity sales would come from zero-carbon energy resources, with that requirement increasing to 95% by 2040.
In 2021, 36.8% of BWP’s electricity came from eligible renewable resources. 10 In 2022 renewable
resources grew to 38.5% of Burbank’s total electricity supply and it is projected that in 2023 that it will increase to 41.25%.11 As stated above, BWP must increase that amount to 60% by 2030.
2.1.5.2 Energy Efficiency
BWP has a long-standing commitment to energy efficiency as a part of its desire to maintain reliable, affordable, and sustainable electric service. BWP manages a comprehensive portfolio of efficiency programs for residential and commercial customers focusing on energy efficiency, peak load reduction, and greenhouse gas savings. 12 BWP uses its energy efficiency programs to both help it meet its own energy efficiency goals and to encourage its customers to make changes that benefit themselves. For example, when a customer replaces a single pane window with an energy- efficient one, the new window helps keep heat from escaping in the winter, the customer uses less energy to heat their home, and saves money on their electric bill.
More details on currently available energy efficiency programs sponsored by BWP are discussed in Section 2.4.2.
2.1.5.3 Demand Response
DR takes the form of economic programs that offer customers the opportunity to change their use of electricity in response to pricing signals from the wholesale energy market. DR programs seek to encourage customers to reduce energy usage during times of peak demand or when the electricity
9 Section 399.11 of the Public Utilities Code
10 Burbank Water and Power, “2021 Power Content Label,” https://www.burbankwaterandpower.com/electric/power-sources/power-content-information 11 Burbank Water and Power, “IRP Community Meeting #1,” April 20, 2023 https://www.burbankwaterandpower.com/images/2023/04/Resource%20Planning%20101%20Presentati on%20Public%20Meeting%201%2004%2020%202023.pdf
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supply is limited and energy prices are at their highest due to problems with generation or transmission infrastructure. BWP currently offers a voluntary demand response program, the “Cool Rewards” program, described in detail, below.13
For residential customers, BWP has implemented a “Cool Rewards” smart thermostat program. For customers that choose to enroll in the “Cool Rewards” program, in exchange for enrollment incentives and annual participation credits, BWP will be able to temporarily change the setpoint temperature of their thermostat to reduce the system demand from air conditioners and heat pumps during times of peak usage. BWP hopes to expand the program to commercial customers.
For customers in the large and extra-large service classes, BWP coordinates their voluntary participation with the Demand Side Grid Support (DSGS) program for the CEC. In that program, participants are compensated for upfront capacity commitments and per-unit reductions in net energy demand during extreme events. Internally, BWP itself is signed up as a DSGS provider and enrolled the Valley Pumping Plant as a DSGS participant. As a result, BWP can receive payments for qualifying demand reductions during DSGS events.
2.1.5.4 Energy Storage
The basic function of energy storage is to absorb energy when it is available but not needed, store it for a period of time with minimal losses, and then release it when it is needed. When included in the electric system, energy storage can serve a number of important roles in balancing generation and demand, especially as increasing amounts of intermittent renewable energy resources are brought onto the system. The applications of energy storage can be on a large, regional scale (e.g., within the bulk electric system) and at a more local scale (e.g., on the local distribution system or “behind the meter” on a customer’s site).
Energy storage is a potential enabling tool to achieve BWP’s commitment to provide reliable, affordable, and sustainable electric service to Burbank. For example, energy storage has the potential to help effectively integrate intermittent renewable energy resources (such as solar and wind energy) by better matching the output of those resources to Burbank’s energy needs. To date, there are 21 customer-owned battery installations in Burbank which have a total power output of 150 kW and total energy storage capacity of 541 kWh.
In late 2022, BWP announced that it was pursing the first utility-scale long-duration energy storage project for the City of Burbank as a part of a “solar plus storage” facility located at the BWP EcoCampus.
14 In that application, a 75 kW / 500 kWh iron flow battery is connected to a 265 kW solar array. BWP will partner with ESS Inc., to install this battery. BWP was awarded a grant for $125,000 through the American Public Power Association (APPA) Demonstration of Energy and Efficiency Development (DEED) program in 2022.
13 Burbank Water and Power, Staff Report, August 22, 2023, https://burbank.granicus.com/MetaViewer.php?view_id=42&clip_id=10217&meta_id=416494 14 Press Release: “BWP Partners with ESS Inc. to Bring the First Utility-Scale Battery Storage to Burbank”, published November 4, 2022, https://www.burbankca.gov/newsroom/-/n ewsdetail/20124/press-release- bwp-partners-with-ess-inc.-to-bring-the-first-utility-scale-battery-storage-to-burbank ATTACHMENT 1
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2.1.5.5 Transportation Electrification and Electric Vehicles Transportation electrification is the strategy to use electricity to provide for people’s transportation needs rather than petroleum-based fuels such as gasoline, diesel, and natural gas. BWP plays a key role in facilitating the adoption of transportation electrification through education and program development that helps customers overcome barriers to the adoption of electric vehicles.
Transportation electrification is further discussed in Section 2.4.4.
2.2 PREVIOUS INTEGRATED RESOURCE PLANS
Burbank previously completed IRPs in 2015 and 2019. Both these documents can be accessed through the BWP website.15
2.2.1 Major Changes Since Burbank’s Last IRP
Since Burbank’s last IRP was completed, both the energy market and broader economic conditions have seen significant changes.16 Updated forecasts for fuel costs, availability of different energy generation and storage technologies, and other market conditions all informed the assumptions made for this new IRP.
2.2.1.1 Energy Price Increases
The prices for renewable energy have increased by 35-60% since the last IRP was filed and the prices have continued to increase, even following the development of the 2024 IRP. This is due to a number of factors: tariff disputes on certain solar products originating outside the United States, new Federal tax incentives for domestic production and installation of renewables, global supply chain issues, historically high inflation, the lingering effects of the COVID-19 pandemic, an increased demand on renewables through Environmental, Social and Governance (ESG) policies at large companies and an increased mandate for the use of renewable energy in California have all combined to drive up the costs.
Natural gas costs have increased dramatically from an average of $3.01/MMBTU in 2020 to an average of $7.06/MMBTU in 2023. Market energy prices have also seen significant increases.
Electricity that was, on average, $47.61/MWh in 2020 has been, on average, $61.66/MWh in 2023.
15 2015 Burbank IRP:
https://www.burbankwaterandpower.com/images/administrative/downloads/IRP_Presented_to_CityCounc il_Opt.pdf
2019 Burbank IRP:
https://www.burbankwaterandpower.com/images/administrative/downloads/CityCouncilApproved_2019_ Integrated_Resource_Plan_DIGITAL.pdf
16 Burbank Water and Power, “Fiscal Year 2023-24 Proposed Budget,” BWP Board Presentation, April 6, 2023, https://www.burbankwaterandpower.com/images/budget/april- 20 23-budget- files/Proposed%20Utility%20Fiscal%20Year%202023-24%20and%202024- 25%20Budgets%20for%20BWP%20Board.pdf
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Table 2-1 Historical Natural Gas and Energy Prices17
Year
Natural Gas
Prices
[$/MMBTU]
Energy
Prices
[$/MWh]
2020 $3.01 $47.61
2021 $6.99 $61.81
2022 $9.27 $96.28
2023 (through end of
September) $7.06 $61.66
The 2023 natural gas and energy prices provided in Table 2-1 were current as of the end of September 2023.
2.2.1.2 Other Changes
The 2019 IRP report included the consideration of compressed air energy storage (CAES) located at IPP in Utah. During the intervening years it has been determined that such an energy storage project would not yet be economically feasible at IPP. As such, consideration for that CAES project has been removed from this IRP analysis. Developments at IPP and the plans to convert it to hydrogen fuel were added to this IRP and are discussed in Section 2.5.4.
Additionally, changes to market conditions have continued to occur during and after the analyses that were completed for this 2024 IRP. System demand, REC prices, project costs, and the availability of new fuel types have been observed to change since the assumptions were set at the beginning of the IRP development. Due to the timing of some of these changes, they are not all reflected in the results of this IRP.
Table 2-2 Changes to Market Conditions Post-2024 IRP Development Item Changes to Market Conditions
Demand Higher energy demand than anticipated (potentially 30% higher than the forecast)
Renewable Energy Credits (RECs)
RECs were modeled at $44/REC for Portfolio Content Category 1 resources. They are now trading at $80/REC (this increases costs by over $60 million by 2030)
Intermountain Power Project (IPP)
IPP was modeled at a total cost of $4.286 billion. Recent estimates show an increase of $400 million, bringing the cost to $4.686 billion (this increases BWP’s annual debt service share by $587,000 a year)
Renewable Natural Gas (RNG)
RNG contracts are not available in the supply needed for the Magnolia Power Project and Lake One unit. This makes any scenarios that rely on RNG unrealistic in the short term.
17 Burbank Water and Power, Stakeholder Technical Advisory Group Meeting #9, October 12, 2023 ATTACHMENT 1
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2.3 COMMUNITY OUTREACH
Public input is a fundamental part of the integrated resource planning process and a utility’s IRP should reflect the needs and desires of the community it serves. In this context, BWP set out to interact with Burbank residents and businesses to determine their perspectives on Burbank’s energy future.
A detailed description of the public education and outreach that took place as a part of this IRP process is documented in Section 5 below.
2.4 EXISTING CITY POLICIES AND PROGRAMS
2.4.1 Renewable Portfolio Standards
In 2007, Burbank became the first city to commit to a 33% renewable power supply portfolio standard. Since then, BWP has undertaken several initiatives to bring renewable resources into its power supply portfolio. By 2015, 34% of Burbank’s power supply came from renewable resources, five years ahead of schedule. It is forecasted that in 2023, renewables will make up 41.25% of Burbank’s power supply.
18 Like conventional generation resources, different types of renewable resources have different characteristics. Solar and wind are intermittent, only generating when the sun shines or the wind blows, respectively. Geothermal, biogas and to an extent, small hydroelectric are baseload and can operated around the clock.
Subsequent to Burbank making its commitment to renewable energy in 2007, the “33% by 2020” mandate was codified in California law and regulation as the RPS. In particular, the CEC adopted rules for RPS compliance to which BWP (and all California utilities) must comply. Under the RPS program, renewable energy is measured in Renewable Energy Credits (RECs). One REC represents one MWh of renewable energy.
The RPS rules divide renewable resources into three Portfolio Content Categories (also known as “buckets”), each with its own requirements.
• Portfolio Content Category 1 (PCC1) – A renewable energy generator directly connected to or delivering to a California Balancing Authority, such as LADWP, without substituting electricity from another source,
• Portfolio Content Category 2 (PCC2) – Allows energy and RECs not delivered to a California Balancing Authority. This includes energy received as a swap from previously generated energy into a California Balancing Authority within the same calendar year as the RPS- eligible generator.
• Portfolio Content Category 3 (PCC3) – RECs only, without energy.
18 Burbank Water and Power, “IRP Community Meeting #1,” April 20, 2023 https://www.burbankwaterandpower.com/im ages/2023/04/Resource%20Planning%20101%20Presentati on%20Public%20Meeting%201%2004%2020%202023.pdf
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In addition, pursuant to its own local mandate, BWP procured renewable energy supplies before the Portfolio Content Category system was enacted. This energy is referred to as “grandfathered” or “PCC0” renewable energy.
The RPS program requires a certain amount of compliance in a given year and also sets limits on how much of each Portfolio Content Category may be counted against a utility’s RPS requirements in a given year. BWP’s current Renewable Energy Resources Procurement Plan is discussed below in Section 3.6.
In 2015, SB 350 established an increased RPS requirement of 50% by 2030. Then in 2018, SB 100 further increased the RPS to 60% by 2030, with a target of 100% clean energy by 2045. The Base Case used in this IRP reflects the SB100 requirements of 60% RPS by 2030 and the goal of 100% clean energy by 2045. As a city, Burbank is pursuing an aspiration goal of becoming 100% GHG free by 2040. That goal exceeds the California state target for 100% clean energy by 2045.
SB 1020, or the “Clean Energy, Jobs, and Affordability Act of 2022” built on preexisting energy legislation and added interim zero-carbon targets. SB 1020 required that by 2035 and 2040, 90% and 95%, respectively, of retail electricity sales would have to come from zero-carbon energy resources.
Renewable resources have historically benefited from certain tax benefits under federal law, including investment tax credits (ITCs) and production tax credits (PTCs). ITCs are a one-time tax credit that is based on the dollar amount of the investment made into a project. ITCs are earned when the qualifying facility is put into service. PTCs are based on the amount of electrical generation that occurs at a qualifying facility. The owners can claim a tax credit on every kilowatt- hour of generation that occurs for a set period of time.
Table 2-3 Current Renewable Generation
Resource Name Resource
Type
BWP
Capacity
[MW]
Start
Date
End
Date
Copper Mountain Solar 3 Solar PV 40 2012 2033
Desert Harvest Solar 2 Solar PV 22 2021 2046
Milford Wind I Wind 10 2009 2029
Pebble Springs Wind Wind 10 2009 2027
Tieton Dam Small Hydro 6.8 2009 N/A
Don A. Campbell Geothermal 2.49 2013 2033
Ameresco Chiquita Landfill Gas 1.7 2010 2026
2.4.2 Energy Efficiency
BWP is committed to modernizing its infrastructure to both meet the needs of its customers and to help Burbank achieve its clean energy goals. As discussed in Section 3.11 below, as a part of that modernization, the distribution system is continuing to receive upgrades from 4 kV to 12 kV. This increase in distribution system voltage will allow greater amounts of power to reach customers and will also help to decrease system loses and increase the overall efficiency of the system.
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Beyond the upgrades to the distribution system, BWP offers numerous energy efficiency programs that result in cost savings for its customers and lowered greenhouse gas emissions through reduced energy consumption.
2.4.2.1 Residential Programs
• Home Rewards Rebates Program: BWP provides rebates for purchasing and installing ENERGY STAR® rated appliances and high-efficiency measures. • Home Improvement Program: BWP offers energy-water surveys and efficiency measure installations to all Burbank single-family residential, multi-family residential, and multi- family common area customers. Some of the HIP’s services include direct installation services of LED lighting, smart power strips, smart thermostats, air conditioning tune-ups, air sealing, attic insulation, duct sealing, and water efficiency measures for low-income single-family and multi-family common area customers, and properties within the disadvantaged community areas of Burbank.
• LED Distribution Program: BWP distributes LED light bulbs to residents at numerous events throughout the community, as wells as through energy programs and surveys. • Livingwise® Program: This program provides energy and water educational services, materials, and conservation kits to sixth-grade students attending public school in Burbank. • OPower Web Portal: This online portal offers residential customers web access to view their electric usage information in hourly, daily, weekly, and monthly intervals and help them better understand their energy use and reduce their electricity consumption. • Residential Building Electrification Rebate Program: This pilot program seeks to encourage customers to invest in the replacement of equipment that burns natural gas with more efficient electric alternatives that have zero on-site emissions. This program will provide rebates for the installation of equipment such as heat pumps and electric cooktops and ovens.
2.4.2.2 Commercial, Industrial, & Agricultural Programs • Business Rebates: Burbank businesses that retire their inefficient equipment and install new energy-efficient products are awarded rebates.
• Business Bucks Program: The program offers an energy efficiency survey and helps retrofit small and mid-sized businesses.
• Upstream HVAC Program: The program provides rebates to wholesale distributors to encourage stocking and promotion of high-efficiency HVAC equipment. • LED Street Lighting Project: In accordance with the Street Lighting Master Plan, BWP is replacing high-pressure sodium (HPS) street light luminaires with light-emitting diodes (LED) luminaires. Replacement is carried out on a maintenance basis, and LEDs are installed as the HPS luminaires burn out. LED replacements consume approximately 60% less energy. To date, 92% of the total street light luminaires have been converted to LEDs, translating to an annualized energy savings of 5,383 MWh or a 58.08% reduction in energy consumption. LED conversions have also reduced the evening load by 1,247 kW, shortening the “neck of the duck curve” and reducing the energy generation BWP needs.
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2.4.2.3 Other Efficiency Related Programs
• Energy-Saving Trees Program: This program with the Arbor Day Foundation provides up to three complimentary shade trees to residential customers and up to 15 trees for commercial customers. The program also includes an interactive website with instructional videos to ensure that the trees are properly sited and planted. When properly sited, mature shade trees provide shade that helps reduce air conditioning costs.
2.4.3 Demand Side Management
Demand-side management (DSM) is similar to demand response (See Section 2.1.5.3), but instead of responding to real-time events in the wholesale energy market, DSM seeks to shift the use of energy away from times of peak demand to reduce overall energy costs. Time-of-Use (TOU) rates can be a tool to help implement DSM. TOU rates can offer cost savings by encouraging customers to shift energy use from high to low demand times, optimizing system offerings, and reducing operating costs. In a similar vein, Advanced Metering Infrastructure (AMI) also lends itself to demand-side programs, allowing customers to see and control their energy use and BWP to develop and implement programs to incentivize energy use reduction during critical periods. Ultimately, these strategies will help to reduce peak demands on distribution facilities, prolong distribution asset life, and defer capital investment in new generation and transmission assets.
2.4.4 Transportation Electrification and Electric Vehicles Electric vehicles are an essential part of BWP’s strategy to reduce GHG emissions and further accommodate integration of clean energy. BWP is promoting the use of transportation electrification as a demand resource to help achieve new environmental goals, integrate renewable energy, and maintain grid reliability. BWP can benefit from transportation electrification through better grid utilization by incentivizing EV charging in lower cost hours when energy usage is typically low or mitigating the effects of rooftop solar generation by managing EV demand during the day. Per SB 676, BWP plans to and has implemented electrification grid integration strategies that work best for its ratepayers. BWP continues to improve upon its electrification strategy to enhance adoption of electric vehicles across the BWP territory.
BWP is pursing the installation of BWP-owned EV chargers in high-density residential areas and in public parking lots. BWP is also committed to making public charging easy. Burbank now has 93 EV charging ports at 22 sites with plans to install an additional 116 ports by 2032. During the same period, BWP also anticipates providing rebates for the installation of another 779 privately-owned charging ports. BWP is also looking into providing technical assistance to help facilitate private workplace and fleet charging for interested businesses. BWP’s plans for the expansion of EV charging facilities are based on the Integrated Energy Policy Report (IEPR) forecast for future EV adoption and specific information about the actual number of EVs within its service territory.
In FY 2023 BWP continued implementing a Used EV Rebate Program, Residential EV Charger Rebate Program, and Commercial EV Charger Rebate Program. • Used EV Rebates: The program offers residential customers a $1,000 rebate towards a pre- owned EV purchase to support the adoption of EVs. The program is designed for customers who prefer pre-owned EVs or have income constraints to acquire a new EV. • Residential Charging Station Rebates: Residential customers who install a Level 2 (240V) EV charger are eligible for a rebate from BWP. Residential customers can get rebates of up to $500 for a smart charger and up to $1,250 with an electric panel upgrade. Customers living ATTACHMENT 1
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in a Disadvantaged Community (DAC) area of Burbank can qualify for increased rebate amounts of up to $600 for a smart charger and up to $1,500 with an electric panel upgrade. and commercial customers can get a rebate for up to $2,000 per charging station for their business.
• Commercial Charging Station Rebates: Commercial customers in Burbank are eligible to receive rebates per charge port, up to the amounts in the following table.
Table 2-4 Commercial Charging Station Rebates in Burbank
DACs and/or
Public Access
Multi-family
Residences Other
Without Utility Infrastructure Upgrade
Level 1 N/A $3,500 N/A
Level 2 / DC Fast Charger $4,000 $4,000 $1,800
With Utility Infrastructure Upgrade
Level 2 / DC Fast Charger $7,500 $7,500 $3,500
For its part, BWP is at the forefront of fleet EV adoption as a fundamental component of its commitment to sustainability. Sixty percent of BWP’s fleet cars are either all-electric, plug-hybrid, or hybrid and four hybrid bucket trucks are in service. Three propane-fueled forklifts have been replaced with all-electric forklifts and additional electric vehicles are on order.
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Figure 2-1 Transportation Electrification Statistics19
19 Burbank Water and Power, Monthly Operations Report, October 2023.
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2.4.5 Disadvantaged Communities
Historically, communities were defined as “disadvantaged” using socio-economic factors such as income, education, and occupation. The State of California has added to the definition to include exposure to environmental pollutants.
BWP offers programs for customers who meet income qualifications such as discounted electric rates, assistance to make a one-time payment, and energy efficiency programs. California law encourages utilities to include programs for disadvantaged communities in their plans. The following BWP programs are available to customers located in disadvantaged communities:
• Burbank Utility Service Subsidy (BUSS) Program: Offers an ongoing 12% discount to income-qualified residents.
• Lifeline Program: Offers a reduced electric rate and an exemption from the monthly Customer Service Charge for income-qualified customers. • Life Support Program: Offers customers that require the use of Life Support Equipment in their home an exemption from the utility user tax.
• Project Share Program: Offers income qualified customers a one-time yearly stipend towards their electric utility bill.
• Home Improvement Program (HIP): Offers energy and water surveys and efficiency measure installations to all Burbank single-family residential, multi-family residential, and multi-family common area customers. Some of the HIP’s services include direct installation services of LED lighting, smart power strips, smart thermostat, air conditioning tune-ups, air sealing, attic insulation, duct sealing, and water efficiency measures for low-income single-family and multi-family common area customers, and properties within the disadvantaged community areas of Burbank.
In addition, BWP operates 77 of its electric vehicle charging ports within disadvantaged communities and provides additional rebates for residential 20 and commercial21 customers in
disadvantaged communities that install their own electric vehicle charging stations.
2.5 BURBANK WATER AND POWER’S EXISTING RESOURCES
Burbank is currently adequately resourced to meet its demand and any growth or new requirements over the next several years. Growth can also be addressed through the use of energy efficiency, more efficiency rate design, demand-side management, and new sources of renewable energy.
2.5.1 How is Power Produced?
A reliable power system does not depend on a single power generation resource or a single method of producing power. Rather, a reliable power system uses diversity of resources, technologies,
20 Burbank Water and Power, Residential EV Charger Rebate, https://www.burbankwaterandpower.com/electric-vehicles/residential-ev-charger-rebate 21 Burbank Water and Power, Commercial EV Charger Rebate, https://www.burbankwaterandpower.com/leadthecharge
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customer activities, fuels, and power plant operating characteristics to maintain reliable electric service at all times.
Integration of different fuels and technologies produce the least-cost, highest reliability power production mix. Power production costs change because the input fuel costs – including natural gas, coal, and nuclear fuel – change over time. The uncertainty of the future costs of these fuels translates into uncertainty for the production cost of electricity. This is known as production cost risk. Like a balanced financial investment portfolio of stocks and bonds, a diversified energy supply portfolio is the most cost-effective tools available to manage production cost risk – particularly during periods of technological and cost uncertainty. In addition, a diverse power generation technology mix is essential to cost-effectively integrating renewable energy.
Conventional methods of power generation use coal, natural gas, nuclear, or water (i.e., hydroelectric power plants) to produce electricity. Power can also be produced from renewable sources, including wind, solar, geothermal energy, and landfill gas.
Both conventional and renewable energy resources are important, and BWP relies on a mix of both conventional and renewable generation. Each type of generator has its own role to play in BWP’s supply portfolio.
For example, take solar generation. Once a solar plant is built, the energy produced has no fuel costs and no emissions. But if there is cloud cover or it is nighttime, no solar power is produced.
That is why conventional, dispatchable sources are still important since they can generate power on demand.
2.5.2 Baseload, Load-Following, Peaking, and Intermittent Power Resources Some power plants, like coal-fired, nuclear, and geothermal, can run near continuously, day and night, and in all types of weather. Facilities like that are called “baseload” power plants. Other power plants, usually fueled with natural gas, can more easily adjust their output as loads change throughout the day. For that reason, they are called “load-following” power plants. For BWP, Magnolia can serve both baseload and load-following roles. “Peaking” power plants also primarily use natural gas but can include energy storage as well. These types of facilities are quick-starting, quick-ramping power plants or energy storage resources that supply power when loads exceed the output of the baseload and load-following power plants, or when load is changing quickly. Peaking plants are also used to help integrate intermittent renewable energy like wind and solar.
2.5.2.1 Baseload Resources
Baseload resources help serve the steady load that BWP must always meet. As such, a baseload resource can run for months on end without interruption. When operated this way, baseload resources produce reliable, cost-effective power. Baseload resources can use natural gas, coal, nuclear fuel, water (in the form of hydroelectric power), landfill gas, or geothermal energy.
Baseload resources are slower to increase and decrease power output, or “ramp.” In this way baseload resources are the freight locomotives of power generation – the best option for long, steady hauls. However, recent technological updates to the Magnolia Power Project coordinated through General Electric, have allowed the unit to operate at lower minimum power levels and ramp up and down more quickly. These updates allow the Magnolia Power Project to better support intermittent renewable energy resources, such as wind and solar.
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More recent development in energy supply have resulted in a decreasing emphasis on traditional baseload resources. Instead, the use of large quantities of intermittent renewable resources such as wind and solar facilities, are providing large portions of the energy previously provided by baseload power plants. This change in the energy markets has also accentuated the need for fast-reacting, flexible resources to integrate increasing amounts of renewable energy in a reliable manner.
2.5.2.2 Load-Following Resources
While the generation from baseload resources can be predictable, load may not be. As people and businesses go about their days, load increases and decrease minute-by-minute and hour-by-hour.
Load-following resources increase and decrease their output with it. Like some baseload power plants, load-following resources are usually fueled with natural gas, but they are designed to ramp more quickly. This is usually done with some cost in efficiency. As such, load-following resources can be thought of as the 18-wheelers of power generation – not as efficient as baseload resources, but able to drive in the “heavy traffic” of changing loads.
Hydroelectric resources play a load-following role in the power system, as they can start, stop, and ramp relatively quickly. Emerging energy storage resources can also fill a load-following role.
2.5.2.3 Peaking Resources
Peaking resources are the sprinters of the group – power plants than can be switched on and ramped up quickly when power is needed, usually within minutes.
Peaking power plants have traditionally been fueled by natural gas. These facilities, usually based on the design of jet aircraft engines, are designed for maximum operational flexibility at the cost of efficiency. In contrast, baseload power plants are designed for efficiency at the cost of operational flexibility.
Hydroelectric resources can provide peaking services in the power system since they can start, stop, and ramp relatively quickly. Energy storage batteries can also operate as peaking resources with high levels of operational flexibility. Their primary applications include helping to integrate renewable resources.
2.5.2.4 Intermittent Resources
Conventional baseload, load-following, and peaking resources, despite their differences, are all dispatchable to one degree or another. Operators can change their output by controlling the rate at which fuel is used by the power plant. Intermittent resources have no such control and generally have lower production potential compared to conventional baseload resources. In order to account for these limitations, entities can over-procure intermittent resources to meet their demand.
However, any over-procurement of intermittent resources needs to account for the hourly generation shape associated with the production of such resources both at daily and seasonal levels. For example, solar production is typically high during daytime hours and the summer season, whereas wind production is typically high during evening hours and the winter season.
Therefore, entities would need to procure or over-procure a mix of intermittent resources with complimentary profiles (like wind and solar), to meet their around-the-clock demand.
For example, solar power plants, by virtue of using sunlight as fuel, only produce power when the sun is shining, but not when clouds pass over or at nighttime. In the same way, wind turbines only produce power when the wind is strong enough. The availability of wind and solar can only be predicted within a short time frame. Therefore, intermittent resources challenge efforts to balance generation and load in real-time.
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2.5.3 Power Generated in Burbank
BWP’s currently operating local generation resources are natural gas-fired facilities that were placed in service between 1959 and 2005.
Table 2-5 Existing Generation Facilities in Burbank
Name Type Power Load Type Capacity (MW) In-Service Date Olive 1 Steam Turbine Baseload (in dry-layup) 40* 1959
Olive 2 Steam Turbine Baseload (in dry-layup) 50* 1964
Lake One Combustion Turbine Peaking 45 2002
Magnolia Combined-Cycle Baseload & Load Following 75.6** / 244 2005 *While in dry-layup, Olive 1 & 2 have a functional capacity of zero. **BWP has a 31% interest in the SCPPA-owned Magnolia plant that is located in Burbank.
Olive 1 & 2 (Reserves)
The Olive 1 & 2 steam generating units are BWP’s oldest exiting units, and went into service in 1959 and 1964, respectively. Starting in 2011 for Olive 1 and 2012 for Olive 2, both units have been in “dry-layup” for the long-term preservation of the boiler, condenser, turbine, and related piping. As a consequence of being in that state, a 274-day notice is required to restart a single unit and a 365- day notice is required to restart both units.22
BWP is investigating options to replace Olive 1 & 2 with combustion turbines similar to Lake One, internal combustion engines, renewables, storage (such as batteries), or a mix of technologies that could yield the flexibility required to operate in the future.
Lake One (Peaking)
The Lake One unit is a 47 MW General Electric LM-6000 simple-cycle combustion turbine that became operational in 2002. At the time it was placed in-service, the Lake One unit represented the “best in class” in combustion service technology.
Lake One is operated as a peaking unit. It often generates electricity during hot summer days when loads are high. When sitting idle during period of lower demand, it serves as a reserve unit.
22 Burbank Water and Power, Staff Report, dated February 2, 2023, page 35, https://www.burbankwaterandpower.com/images/administrative/dow nlo ads/BWP_MonthlyOpsReport_Fe bruary2023.pdf
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(Lake One, Photo Source: BWP)
Magnolia Power Project (Baseload / Load-Following)
In 2002, BWP participated in the construction of combined-cycle generating plant that was built in and operated by Burbank and is known as the Magnolia Power Project or just “Magnolia.” In September 2005, when this unit went into service, it used what was considered “best in class” natural gas combined-cycle technology. This unit can be used either for baseload or load-following power.
Magnolia is based on a General Electric 7FA combustion turbine. The term combined-cycle refers to how the plant recycles the waste heat from the combustion turbine by using it to boil water to create steam in order to power a steam turbine. The nominal output of the plant is 242 MW, but for limited periods of time it can be augmented with supplemental firing (similar to afterburners on jet aircraft) and steam injection to produce up to 310 MW.
Burbank is the operating agent for Magnolia and operates the plant. Burbank has an entitlement to 31% of its output. This equals approximately 75 MW (or up to 95 MW during times when supplemental firing and steam injection are used). The ability to ramp Magnolia up and down quickly, can be shown below in Figure 2-2. During the heat dome event on September 8, 2022, Magnolia was able to ramp up and down in coordination with intermittent resources and respond to price signals from the energy market.
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Figure 2-2 Magnolia Production During Heat Dome Event
(Magnolia, Photo Source: BWP)
Valley Pumping Plant
In 2002, BWP installed a micro-hydro system to take advantage of a required pressure reduction where Burbank’s water facilities interface with the Metropolitan Water District of Southern California (MWD) at the Valley Pumping Plant. Peak output of the facility is approximately 550kW and is used when BWP purchases water from MWD. Due to the small capacity of the Valley Pumping Plant, it was not included in the modeling for the planning scenarios within this IRP.
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2.5.4 Power Generated Outside of Burbank
Nearly all of the power imported into Burbank is generated outside of California. BWP enters into long-term contracts for this power or jointly owns them with other municipal partners. This enables the economies of scale needed to procure power at favorable prices, fund large projects, and obtain the most favorable financing rates.
BWP often participates with other municipally owned electric utilities in Southern California through a Joint Powers Authority called the Southern California Public Power Authority (SCPPA) to develop and participate in new generation and transmission projects. SCPPA has been used by BWP to finance participation in the Southern Transmission System (STS), the Palo Verde Nuclear Generating Station, Magnolia, and Hoover Dam. A similar agency based in Utah called the Intermountain Power Agency (IPA), is the Operating Agent for IPP.
Many of the power resources located outside of Burbank are provided via power supply agreements whose terms expire within the planning period of this IRP.
Table 2-6 Net Capacity of Resources
Plant Name Technology
Nameplate
Capacity
[MW]
BWP Net
Capacity
[MW]
Expiration
or
Retirement
Date
BWP Role
Copper Mountain Solar 3 Solar PV 250 40 05/13/2033 PPA Offtaker Desert Harvest Solar 2 Solar PV 70 22 01/01/2046 PPA Offtaker Hoover Dam Hydro 2,079 20.125 12/31/2054 PPA Offtaker
Tieton Dam Hydro 14 6.8 12/31/2054 Operator
Milford Wind I Wind 204 10 11/15/2028 PPA Offtaker
Pebble Springs Wind Wind 99 10 02/01/2026 PPA Offtaker
Intermountain Power
Project Coal 1,800 74 07/01/2025 PPA Offtaker
Don A. Campbell Geothermal 25 2.49 12/05/2032 PPA Offtaker Ameresco Chiquita Landfill Gas CT 10 1.7 11/23/2029 PPA Offtaker Palo Verde Nuclear 4,010 9.5 10/31/2030 PPA Offtaker
Copper Mountain Solar 3 (Intermittent)
In late 2012, BWP entered into a 20-year contract for solar power from the Copper Mountain photovoltaic site near Boulder City, Nevada. Burbank has rights to 16% of the output, or about 40 MW nominally. Copper Mountain generation fluctuates dramatically throughout the day and its intermittent nature often leads to BWP buying energy from the market.
Figure 2-3 below shows the generation of Copper Mountain on September 8, 2022 during the heat dome event. This figure shows the intermittent nature of Copper Mountain and the lack of production when market prices were highest.
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Figure 2-3 Copper Mountain Solar 3 Production During Heat Dome Event
(Copper Mountain Solar 3, Photo Source: BWP)
Desert Harvest Solar 2 (Intermittent)
BWP started a 25-year contract with the Desert Harvest Solar 2 site in 2020. Located in Riverside County, California, this facility provides Burbank with approximately 43,000 MWh of energy per year.
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(Desert Harvest Solar 2, Photo Source: BWP)
Hoover Dam (Baseload)
Hoover Dam, located on the Colorado river along the Nevada-Arizona border provides 20 MW of zero-carbon energy to Burbank.
(Hoover Dam, Photo Source: BWP)
Tieton Dam (Baseload)
In 2009, BWP began receiving 50% of the output of the Tieton Hydropower Facility, located in south-central Washington State. Then, later in 2009, the Cities of Burbank and Glendale purchased the facility via SCPPA.
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(Tieton Dam, Photo Source: BWP)
Milford Wind I (Intermittent)
In 2009, BWP began receiving 10 MW of wind power from Milford Wind I under a long-term contract. The wind farm is in Utah, south of the Intermountain Power Project.
(Milford Wind, Photo Source: BWP)
Pebble Springs Wind (Intermittent)
In 2009, BWP began receiving 10 MW of wind power from the Pebble Springs Wind Project under a long-term contract. The wind farm is located in northern Oregon. Pebble Springs Wind provides about 29,000 MWh of generation per year.
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(Pebble Springs Wind, Photo Source: BWP)
Intermountain Power Project (Baseload)
As previously mentioned in Section 2.1.4, significant changes are occurring in the near future at the IPP coal-fired generating plant in Utah. In 2025, the existing 1,800 MW coal-fired power plant will be retired and replaced with 840 MW of natural gas-fired capacity.
Two years later, in 2027, BWP’s existing contract with IPP will expire and a new contract will begin.
BWP’s decision to commit to the new IPP contract that starts in 2027 was based on several important considerations. First, renewal of the contract was necessary to secure rights on the Southern Transmission System (STS). The transmission rights on STS are important to BWP because they will provide important access to many renewable resources that are located east of Burbank. The ability to procure renewable energy from wind, solar, and geothermal power from that area is contingent on having the transmission capacity necessary to bring it back to BWP customers in Burbank. BWP’s generation and transmission terms for the current and new IPP contracts are listed below in Table 2-7.
Table 2-7 IPP Contract Details
Item Existing Contract
(1987 – 2027)
Renewal Contract
(2027 – 2077)
STS Capacity 2400 MW 2400 MW
BWP % Share of STS 4.49% 4.20%
BWP STS Share (MW) 107.95 MW 101.4 MW
BWP % Share of IPP Generation 4.17% 3.33%
BWP IPP Generation Share (MW) 89.28 MW coal (until June 2025), 35.028 MW natural
gas (July 2025 to June 2027)
28 MW, starting June 16, 2027 (after
the termination of the original Power
Sales Contract for IPP coal)
The STS will be a critical tool used by BWP to achieve its renewable and clean energy goals in the future. Second, renewal of the IPP contract will also allow BWP to benefit from the prospect of a future conversion of the new natural gas-fired capacity at IPP to run on green hydrogen. The possible conversion of IPP to be fueled by hydrogen gas would represent an important opportunity ATTACHMENT 1
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for BWP to secure a source of dispatchable zero-carbon energy in the future. That conversion would also provide valuable experience that could be used by BWP to evaluate the potential future conversion of the Magnolia and Lake One units to use hydrogen as well.
(Intermountain Power Project, Photo Source: BWP)
Don A. Campbell (Baseload)
In 2013, BWP entered into a 20-year contract for geothermal power from the Wild Rose Geothermal Project in Mineral County, Nevada. Wild Rose has since been renamed and is now known as the Don A. Campbell Geothermal Project. Burbank has rights to 15.4% of the facility’s output which is nominally equal to about 2.49 MW.
(Don A. Campbell, Photo Source: BWP)
Ameresco Chiquita (Baseload)
In 2010, BWP began to receive almost 1.7 MW from the Ameresco Landfill Gas to Energy project pursuant to a long-term contract. This project produces energy by using landfill gas (methane) from the Chiquita Canyon Landfill, which is located approximately five miles west of Santa Clarita along State Highway 126.
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This resource produces a consistent amount of energy throughout the day. Figure 2-4 below is a snapshot of the performance of Chiquita Canyon on September 8, 2022, during the heat dome event.
This facility’s stable production did not increase or decrease in response to changes in market prices.
Figure 2-4 Ameresco Chiquita Production During Heat Dome Event
(Ameresco Chiquita, Photo Source: BWP)
Palo Verde (Baseload)
The Palo Verde Nuclear Generating Station provides Burbank with 9.5 MW of baseload capacity from its location west of Phoenix, Arizona. This is a carbon free resources that makes up approximately 8% of BWP’s energy sources, annually.
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(Palo Verde, Photo Source: BWP)
2.6 PLANNING SCENARIOS CONSIDERED
In each of the planning scenarios considered in this IRP, different sets of assumptions and/or modeling inputs were used to create potential “futures” under which Burbank would act to meet its energy needs. Once the desired changes to the base assumptions were specified by BWP for each planning scenario, Black & Veatch ran a series of simulations in the PLEXOS model to determine the portfolio of generating assets best suited to each set of assumptions. The Base Case discussion, brief summary overviews of each alternate planning scenario, their major assumptions, and the model results are discussed below.
These planning scenarios assume that certain new technologies enter the marketplace at the scales necessary to facilitate decarbonization goals. In the event that hydrogen fuel is not available under the assumed timeline or that hydrogen fuel costs are higher than expected, the results of these planning scenarios would be materially affected. Likewise, the availability of renewable energy at cost-competitive prices is also a key assumption.
A total of seven planning scenarios (including the Base Case) were run in the production cost model. A summary of each scenario is provided below. Each planning scenario and its results are discussed in greater detail staring in Section 2.6.1 below. Outside the scope of this IRP, BWP is also in the process of conducting additional studies on carbon capture and sequestration and hydrogen capabilities at MPP and Lake.
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Table 2-8 Summary of Planning Scenarios
Scenario # Scenario Name Details
1 Base Case Meets SB 100 requirements of 60% renewables by 2030 and the BWP requirement of 100% zero carbon by 2040.
2 Net Zero by 2030
Meets the Base Case requirements and 100% zero
carbon by 2030 (accomplished by assuming renewable
natural gas could be secured for Magnolia and Lake One
in addition to assuming a full conversion of IPP to
hydrogen by 2030).
3 SB1020+SMR
Meets the Base Case requirements, contracts for 25 MW
of small modular reactor capacity by 2030 from outside
CA, meets the SB 1020 goal of 90% carbon free resources by 2035 and 100% carbon free resources by 2040.
4 SB1020+SMR w/ 50% DEV & EV
Demand
Meets the Base Case requirements, contracts for 25 MW
of small modular reactor capacity by 2030 from outside
CA, meets the SB 1020 goal of 90% carbon free resources by 2035 and 100% carbon free resources by 2040 and
includes a 50% reduction of electrification (EV) and
development (DEV) demand as compared to the Base
Case.
5 10% Higher EV & DEV Demand
Meets the Base Case requirements and includes 10%
higher electrification (EV) and development (DEV)
demand as compared to the Base Case.
6 10% Lower EV & DEV Demand
Meets the Base Case requirements and includes 10%
lower electrification (EV) and development (DEV)
demand as compared to the Base Case.
7 New Transmission & PPAs
Meets the Base Case requirements and assumes working
with LADWP to secure additional transmission services
contracts to bring in renewables from outside CA.
2.6.1 Base Case
The Base Case is a least-cost portfolio based on the best available information regarding availability of technologies, future costs of renewable and non-renewable resources, energy storage, future cost of fuel, and the future capital costs at the time the analysis was conducted. The Base Case portfolio also complies with meeting all SB 100 state mandates and Burbank’s aspirational goal of being 100% clean energy by 2040. The portfolio achieves 60% renewable energy by 2030 and 100% clean energy by 2040. Within this context, all non-fossil fuel technologies such as wind, solar, hydro, geothermal, hydrogen-fueled turbines, and nuclear are considered to be “clean energy.” All of those technologies are also considered to be “renewable” except for large hydro facilities (e.g. Hoover Dam) and nuclear energy. SB 100 mandates 100% clean energy by 2045; however, BWP’s goal is to accelerate this target by five years and be at 100% clean energy by 2040.
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Figure 2-5 shows how Base Case portfolio’s capacity mix changes over the planning horizon.
Intermountain is converted from coal to natural gas in mid-2025 which causes the capacity dip in 2025-2026 due to a lower BWP ownership share after the conversion. Decreases in wind capacity in the 2020s is due to contracts expiring for Milford Wind Corridor I and Pebble Springs. The decrease in geothermal capacity in 2033 is due to BWP’s contract with Don A. Campbell expiring.
New resources were allowed to be constructed within the capacity expansion model starting in 2027. That is the earliest available procurement date for new resources that BWP could make considering resource availability and interconnection queue delays. Between 2027 and the mid- 2030s the two primary types of resources built are new solar and geothermal units with the exception being a ~3MW solar plant paired with a storage facility going in-service in 2027.
The Inflation Reduction Act (IRA) is a key driver in resource selection. The IRA has increased the economic incentive for solar, wind, geothermal, energy storage, and nuclear technologies. The Base Case portfolio selects solar aggressively in the short term due to its relatively competitive capital cost, zero fuel cost, and IRA Production Tax Credits (PTCs). Another contributing factor to solar buildout is that BWP does not currently have a high level of solar penetration; therefore, the incremental value of solar is higher in the short term. Solar growth slows down post-2035 due to solar generation starting to saturate which results in a lower incremental value for additional solar resources. As solar penetration increases, the time at which the net demand peak occurs is pushed towards hours where solar generation is lower. In this context, the net demand is the total demand minus the contributions from wind and solar generation. As the net demand peak moves into parts of the day when solar energy’s contributions begin to decrease, the incremental value of solar energy decreases and other types of generation become relatively more valuable. Furthermore, as electric vehicle adoption increases, energy demand will shift towards the night/early morning hours when vehicle owners are charging their vehicles and solar generation is low or zero. A key driver in the timing of solar and wind buildout is the IRA. Solar and wind resources are built during the years where PLEXOS’ capacity expansion logic can take advantage of the IRA’s PTCs for renewable resources. In the later years of the planning horizon, the IRA tax credits will have expired and solar and wind resources lose a material economic incentive relative to other technologies.
Energy storage plays an important role in the Base Case portfolio due to its ability to shift renewable energy to different hours to meet demand around the clock. Battery Energy Storage Systems (BESS) appear in the portfolio beginning in 2027; however, its major period of growth is between 2033-2039 when it can take advantage of higher levels of intermittent generation. BESS facilities are able to store energy during periods of surplus supply and then discharge that energy during hours of peak load when it is needed. Another benefit of building BESS during the 2030s is that the assets will still be able to capture the benefits from ITC from the IRA.
As solar generation saturates, wind turbines can become preferable to solar power plants. PLEXOS starts building wind resources in 2036 to help diversify the portfolio and complements the hourly generation profile for solar. Wind and solar energy can complement each other because each technology has different strengths related to their expected generation profiles. For example, wind generation typically peaks in the overnight hours and while solar generation will peak during the day.
Geothermal buildout was guided by what BWP is currently seeing in the market and by what they can realistically procure based on the interconnection queue data. BWP is currently pursuing geothermal resources in Utah which drove the buildout in the model.
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All existing natural gas resources are converted to run on hydrogen in 2040. This is needed to achieve 100% zero-carbon resources by 2040. This conversion includes Magnolia, IPP and Lake One. The current cost assumption is that BWP will only have to pay its share of the conversion costs; however, if other co-owners do not approve the conversion, the cost could be much higher for BWP. In addition to the natural gas-to-hydrogen conversions, new hydrogen-fueled combustion turbines are built between 2040 and the end of the planning horizon. Hydrogen-fueled combustion turbines are Zero Emitting Load Following Resources (ZELFRs) that decreases the amount of market purchases required and increase system reliability.
It will be important for new technologies, such as hydrogen-fueled turbines/engines, to come to fruition and be built at the scale necessary to meet decarbonization goals. If hydrogen or other emerging ZELFRs do not materialize, the cost of deep decarbonization will increase significantly. It would require significant over-procurement of renewables and storage to ensure BWP can meet real-time demand around the clock. Lack of ZELFR technology would also increase the risk of not being able to serve load due to renewable energy output variability and demand forecast errors.
Figure 2-5 Base Case Portfolio Capacity Mix
Figure 2-6 shows the generation mix for the Base Case portfolio. The generation mix shows coal generation going away mid-2025, and natural gas generation ramping up in the short-term. As the 100% clean energy goal approaches, natural gas generation declines until the existing turbines are converted to burn hydrogen in 2040. Increasing solar and geothermal generation helps meet load growth, lower market purchases, and lower CO2 emissions through lower gas generation. Post-2040 hydrogen generation is increasing to keep up with load growth.
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Figure 2-6 Base Case Portfolio Generation Mix
Figure 27 shows the Base Case Portfolio’s annual RPS achievement and target. The RPS target comes from SB100. Additional REC Purchases are required in the short term until BWP can procure new renewable resources. The Base Case portfolio is able to meet the 60% RPS requirement in 2030 without needing to purchase additional RECs and continues to procure renewables to ensure load growth can be met. There is a significant jump in RPS percentage achieved in 2040 which surpasses 100% RPS. The reason for this is that the natural gas units convert to hydrogen and the solar generation that is being used to create hydrogen through electrolysis is counted towards the RPS percentage. This solar generation is not modeled as a load serving generator in the model but rather is being used to calculate the hydrogen fuel price forecast. In other words, the solar generation associated with hydrogen fuel production is being counted towards RPS compliance while the load associated with the electrolysis process was not counted towards retail sales.
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Figure 2-7 Base Case Annual RPS Percentage
Figure 2-8 Base Case Carbon Intensity
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Figure 2-9 Base Case Total System and Energy Costs
2.6.2 “Net Zero by 2030” Planning Scenario
The Net Zero by 2030 planning scenario examines the effects of significantly accelerating decarbonization efforts. In this scenario a requirement to meet Burbank’s energy needs through zero-carbon resources by 2030 was added to the Base Case model. Here, it should be noted that Scope 3 emissions from market energy purchases are not included when calculating that zero- carbon requirement. In a change in assumptions from the Base Case, it was assumed that energy from an SMR would be available starting in 2030.
To reach the early decarbonization goals, Magnolia and Lake One had to convert from conventional natural gas to RNG starting in 2030. This differs from the Base Case in which those units were converted from natural gas to hydrogen fuel starting in 2040. The early conversion of Magnolia, Lake One, and IPP to net zero carbon fuels like RNG and hydrogen is predicated on sufficient quantities of those fuels being available at the times they are needed. Hydrogen conversion for Magnolia and Lake One was not available in 2030 because it is unlikely that hydrogen infrastructure will be sufficient by that time to maintain healthy capacity factors at these existing locations. Fuel & portfolio diversity is going to play a key role in decarbonizing the electric sector and so IPP was selected to be the existing unit to convert to hydrogen. Within this scenario, IPP converts to natural gas in 2025 and begins blending hydrogen fuel that same year. “Blending hydrogen” meaning that the unit is burning a blend of hydrogen and natural gas fuel. IPP fully converts to run on hydrogen by 2030 to meet the net-zero goal.
Another diversifying asset in this portfolio is the SMR PPA that is assumed to become available in 2030. SMRs offer baseload clean energy and could be a hedge against any uncertainties surrounding hydrogen fuel availability. Likewise, RNG, hydrogen, and batteries could hedge against the uncertainties surrounding SMR technology risks and project timelines. This portfolio built ~80MW more BESS resources compared to the Base Case to help shift clean energy to hours where the system needs it the most. It is important to note that standalone BESS resources do not have to only charge from renewables but can also charge from baseload clean energy resources like SMRs.
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RNG, hydrogen, BESS, and SMR resources play a key role for ensuring system reliability in the “Net Zero by 2030” planning scenario. Achieving 100% clean energy with only intermittent renewables and batteries would result in over-procurement of those resources and additional system costs associated with that significant buildout. ZELFRs like SMRs or power plants fueled by RNG or hydrogen help mitigate risks associated with intermittent resource generation forecast errors and help ensure system reliability. However, this planning scenario would be very challenging to implement by 2030 given the lack of RNG contracts on the market and the tight timeline to convert IPP to run on 100% hydrogen by 2030.
The actions necessary to reach decarbonization goals early resulted in a total system cost over the study period that is significantly higher than the Base Case and is the highest cost portfolio in the IRP modeling analysis. The system cost drastically increases in 2030. This increase in system cost is mainly driven by two key factors. Firstly, there are significant transmission costs associated with upgrades needed to transfer enough clean energy around the clock by 2030. In comparison, the Base Case had these transmission costs incurred in 2040. Secondly, there are significant costs associated with capital investment to achieve Net Zero by 2030. SMRs are capital intensive investments, and that capital cost is being passed to BWP through variable costs in the modeled PPA agreement. Also, BWP’s assumption is that they would be responsible for the total all-in cost to convert Magnolia to RNG which includes both fixed and variable costs during and post-conversion.
This assumption implies that there would not be enough support from the other co-owners for the conversion that BWP would have to pay to convert the entire plant in 2030 as well as the variable operating costs associated with the plant thereafter. System cost could be materially lower if there would be enough support from other co-owners to convert the plant.
Figure 2-10 “Net Zero by 2030” Planning Scenario – Installed Capacity
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Figure 2-11 “Net Zero by 2030” Planning Scenario – Generation Mix
Figure 2-12 Net Zero by 2030 Scenario – RPS Percentage
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Figure 2-13 Net Zero by 2030 Scenario – Carbon Intensity
Figure 2-14 “ Net Zero by 2030” Planning Scenario – Total System and Energy Costs
2.6.3 “SB1020+SMR” Planning Scenario
The SB1020+SMR planning scenario incorporates the interim targets added by The Clean Energy, Jobs, and Affordability Act of 2022 (SB1020). The updated model for this scenario includes a 60% RPS requirement in 2030 that shifts to a linearly increasing 90% clean energy requirement by 2035. The 95% clean energy requirement for 2040 and 100% zero-emissions requirement in 2045 used in the Base Case remain unchanged.
This planning scenario includes the assumption that BWP will enter into a purchased power agreement for 25 MW of capacity from a SMR starting in 2030. Additionally, IPP is assumed to fully ATTACHMENT 1
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convert to burning hydrogen instead of natural gas starting in 2035 as opposed to 2040 in the Base Case.
With the addition of baseload ZELFR resources such as SMR and the hydrogen conversion at IPP, the need for renewables and storage is less relative to the Base Case. This scenario does not include any new wind energy besides that which was already being provided by the preexisting wind power contracts at Milford and Pebble Springs. Total solar energy buildout by the end of the planning period was ~76MW less when compared to the Base Case. With fewer intermittent renewable resources needed due to ZELFR resources, there is less intermittent generation available for storage assets to shift to meet system needs. Therefore, the total amount of stand-alone battery storage needed in this scenario is also reduced.
As compared with the Base Case, the SB1020+SMR scenario results in an accelerated decrease in carbon emissions due to the earlier conversion of IPP to hydrogen and the inclusion of the zero- carbon energy from the SMR contract. Total carbon emissions over the study period are 14% lower than in the Base Case, However, this scenario also has a total system cost over that same period that is materially higher.
Figure 2-15 “SB1020+SMR” Planning Scenario - Installed Capacity Mix
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Figure 2-16 “SB1020+SMR” Planning Scenario - Generation Mix
Figure 2-17 “SB1020+SMR” Planning Scenario – RPS Percentage
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Figure 2-18 “ SB1020+SMR” Planning Scenario - Total System and Energy Costs
Figure 2-19 “ SB1020+SMR” Planning Scenario - Carbon Intensity
2.6.4 “SB1020 + SMR w/ 50% DEV & EV Demand” Planning Scenario The uncertainties inherent in the forecast of long-term trends in the demand for electricity made it prudent to include sensitivity cases focused on the effects of Burbank’s demand that might be higher or lower than what was assumed in the Base Case. This sensitivity scenario includes assumptions that are largely the same as the SB1020 + SMR scenario above, but also includes a 50% reduction in the demand associated with new development projects within Burbank and a 50% reduction in the anticipated electric vehicle charging demand. The remaining components of the demand forecast remain the same as those used in the Base Case. Additional detail on how Burbank’s demand was calculated is included in Section 3.5 below.
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Since the additional demand from new development projects is assumed to be phased over a period of seven years starting in 2025 and the additional demand from electric vehicle charging is expected to accelerate over time, the early years of the simulation are the least affected by the change in assumptions for demand. However, as electric vehicle demand becomes an increasingly large fraction of the total Burbank load over time, the assumed 50% reduction becomes more evident and therefore has a greater impact in the latter half of the study period. Note that in the time since the modeling assumptions for this IRP were finalized, it has come to pass that more development projects have been planned for Burbank. Therefore, a 50% reduction in new development demand may not be a high probability outcome.
Buildout was lower in this scenario compared to both the Base Case & SB1020 + SMR portfolios due to the lower demand assumption. Particularly of note were reductions in solar and wind energy along with less hydrogen-fuel based generation being built late in the study period. Market purchases of energy were also found to be lower than in the Base Case. These changes in results were all in line with expectations due to the assumptions made for this scenario.
Lower demand within this scenario (approx. 13% lower than the Base Case) resulted in overall lower carbon emissions (approx. 20% lower than the Base Case) since less total energy, some of which comes from fossil-fuel resources prior to 2040, had to be generated to meet Burbank’s needs.
Total system cost over the study period was higher than in the Base Case, but lower than in the SB1020 + SMR planning scenario.
Figure 2-20 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Installed Capacity Mix
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Figure 2-21 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Generation Mix
Figure 2-22 “SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario – RPS Percentage
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Figure 2-23 “ SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Carbon Intensity
Figure 2-24 “ SB1020+SMR w/ 50% DEV & EV Demand” Planning Scenario - Total System and Energy Costs
2.6.5 “10% Higher EV & DEV Demand” Planning Scenario
The uncertainties inherent in the forecast of long-term trends in the demand for electricity made it prudent to include sensitivity cases focused on the effects of Burbank’s demand that might be higher or lower than what was assumed in the Base Case. Of particular interest are the contributions to future demand from planned development projects within Burbank and the demand associated with the increased adoption and charging of electric vehicles because they are the key drivers in Burbank’s demand growth. Within this sensitivity scenario, the assumed demand ATTACHMENT 1
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from those two categories was increased by 10%. All other assumptions and inputs from the Base Case remained unchanged.
With the assumption that total demand will be higher in this scenario, more total energy was needed to be generated to meet Burbank’s energy needs. Consequently, moderate increases in the total build-out of generating facilities were calculated within the model. Compared with the Base Case, more hydrogen-fueled combustion turbine capacity was built along with higher wind and solar capacity. Market purchase of energy were also found to be somewhat greater. All of those results were in line with expectations due to the assumptions made for this scenario.
Since electric vehicle and new development demand are only a portion of total demand, this scenario resulted in a total demand increase relative to the Base Case of 2.6% with an increase in total system cost. Likewise, a small increase of about 1% in total carbon emissions was calculated.
This was expected due to the need to generate slightly more electricity from fossil-fueled resources prior to their phase out in 2040.
Figure 2-25 “10% Higher EV & DEV Demand” Planning Scenario – Installed Capacity Mix
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Figure 2-26 “10% Higher EV & DEV Demand” Planning Scenario – Generation Mix
Figure 2-27 “10% Higher EV & DEV Demand” Planning Scenario – RPS Percentage
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Figure 2-28 “ 10% Higher EV & DEV Demand” Planning Scenario – Carbon Intensity
Figure 2-29 “ 10% Higher EV & DEV Demand” Planning Scenario – Total System and Energy Costs
2.6.6 “10% Lower EV & DEV Demand” Planning Scenario
The uncertainties inherent in the forecast of long-term trends in the demand for electricity made it prudent to include sensitivity cases focused on the effects of Burbank’s demand that might be higher or lower than what was assumed in the Base Case. Of particular interest are the contributions to future demand from planned development projects within Burbank and the demand associated with the increased adoption and charging of electric vehicles because they are the key drivers in Burbank’s demand growth. Within this sensitivity scenario, the assumed demand ATTACHMENT 1
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from those two categories was decreased by 10%. All other assumptions and inputs from the Base Case remained unchanged.
With the assumption that total demand will be lower in this scenario, less total energy was needed to be generated to meet Burbank’s energy needs. Consequently, moderate decreases in the total build-out of generating facilities were calculated within the model. Compared with the Base Case, less hydrogen-fueled combustion turbine capacity was built along with lower wind and solar capacity. Market purchase of energy were also found to be somewhat lower. All of those results were in line with expectations due to the assumptions made for this scenario.
Since electric vehicle and new development demand are only a portion of total demand, this scenario resulted in a total demand decrease relative to the Base Case of 2.6% with a decrease in total system cost. Likewise, a small decrease of about 1% in total carbon emissions was calculated.
This was expected due to the need to generate slightly less electricity from fossil-fueled resources prior to their phase out in 2040.
Figure 2-30 “10% Lower EV & DEV Demand” Planning Scenario – Installed Capacity Mix
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Figure 2-31 “10% Higher EV & DEV Demand” Planning Scenario – Generation Mix
Figure 2-32 “10% Higher EV & DEV Demand” Planning Scenario – RPS Percentage
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Figure 2-33 “ 10% Lower EV & DEV Demand” Planning Scenario – Carbon Intensity
Figure 2-34 “ 10% Lower EV & DEV Demand” Planning Scenario – Total System and Energy Costs
2.6.7 “New Transmission & PPAs” Planning Scenario
To achieve a carbon free future for Burbank, the obstacle of transmission investments, upgrades, and advancements will need to be addressed. Transmission upgrades can dictate where future generating resources can be located, and it is important for BWP to keep a close eye on how the transmission system advances in the case that certain upgrades could lead to beneficial resource procurement opportunities. The New Transmission & PPAs planning scenario is predicated on the addition of new transmission lines that would potentially be in-service by 2035. These new transmission lines would allow BWP to acquire power from resources it otherwise would not be ATTACHMENT 1
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able to due to transmission constraints. It is important to note that if these transmission upgrades do not materialize that this portfolio would no longer be a viable option.
The major changes from the Base Case made to create this scenario are the transmission upgrades and the new generating resources that they facilitate. The new generating resources are 50MW of solar within California, 50MW of geothermal power (also from within California), and 25MW of wind from New Mexico & Arizona. These potential resource additions are diverse and align with BWP’s RPS and CES goals. Although BWP does not have to provide the new transmission capital, BWP will have to enter into Transmission Service Agreements (TSAs) for these resources. The cost associated with the TSAs have been incorporated into this analysis.
As compared to the Base Case, the major portfolio change in this planning scenario is the addition of an additional 50MW of geothermal power starting in 2035. Geothermal power plants have a higher capacity factor than intermittent solar or wind facilities. This higher capacity factor resulted in a reduced buildout of other resources such as solar, BESS, and wind.
Compared to the Base Case, the system cost is relatively equivalent until the mid-2030s when the new transmission projects are assumed to go in-service and new PPAs can be executed. The system cost is higher in the mid to late 2030s for this portfolio compared to the Base Case; however, it is better positioned for Burbank’s 2040 net-zero carbon goal and system cost is lower post 2039.
Figure 2-35 “New Transmission & PPAs” Planning Scenario – Installed Capacity Mix
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Figure 2-36 “New Transmission & PPAs” Planning Scenario – Generation Mix
Figure 2-37 “New Transmission & PPAs” Planning Scenario – RPS Percentage
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Figure 2-38 “ New Transmission & PPAs” Planning Scenario – Carbon Intensity
Figure 2-39 “ New Transmission & PPAs” Planning Scenario – Total System and Energy Costs
2.6.8 Scorecard and Recommended Strategy
Based on the feedback from the IRP survey, the STAG and the community stakeholders, a scorecard was developed to rank each scenario. The IRP survey (provided as Attachment 2 to this report), indicated a preference for reliability first, followed closely by affordability and then minimizing environmental impacts. Reliability means ensuring that the lights turn on when you flip the switch and that outages are minimized. Affordability is the rate impact to BWP’s customers. BWP has one of the lowest electric rates in the state. Minimizing environmental impacts means to procure ATTACHMENT 1
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renewable energy above and beyond what is required and to significantly reduce GHG emissions.
The weights assigned to these characteristics along with additional details of the scorecard are listed below:
Table 2-9 Scorecard Details and Weighting
Item Details Weight
Cost/Ratepayer Impacts The total overall cost of the portfolio (the lower the cost, the higher the weight or score) 40%
Reliability
Lower transmission losses and lower market
purchases (the lower the losses and purchases, the
higher the weight or the score)
40%
Environmental
Stewardship
Total greenhouse gas emissions (the lower the
emissions, the higher the weight or the score) 10%
Diversity
Type of resource, length or term of the contract,
type of resource technology (like wind, solar,
geothermal, etc.), location of resource, a mix of
baseload and variable resources, etc.
Diversification of resources is required under SB
350
10%
Total 100%
Table 2-10 Initial Scorecard Results
2.6.8.1 Recommended Scenario(s)
Given that the market conditions on which the model assumptions were based have continued to change since the initial development of the IRP, BWP removed three scenarios from consideration.
Scenarios “Net Zero by 2030,” “SB1020+SMR w/50% DEV & EV Demand,” and “10% Lower EV & ATTACHMENT 1
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DEV,” were all removed. Through continuous monitoring of the relevant market factors, BWP determined that those three scenarios were the least likely to match Burbank’s energy future.
The “Net Zero by 2030” scenario was removed because it relied solely on RNG to achieve zero carbon emissions at Magnolia and Lake One Unit. Unfortunately, as of October 2023, there are not enough RNG contracts available on the market to reach that goal. In order to plan for this scenario, BWP would need to find RNG contracts and start to negotiate for these contracts immediately.
The “SB1020+SMR w/50% DEV & EV” and “10% Lower EV & DEV“ scenarios are no longer considered to be the best planning options since additional planned development projects were added to BWP’s mix after the IRP assumptions were developed. As of late summer 2023, BWP has entered into negotiations with several large commercial customers which will add 30-35 MW of demand around the clock. This would add approximately 275,000 MWh of demand annually, which is a 25% increase relative to BWP’s current annual energy demand. These new commercial projects were not known about at the time the assumptions and scenarios for this IRP were developed. As a result of this added demand, any scenario that projects slower energy demand growth may no longer be an optimal choice for planning future decisions.
Below in Table 2-11 are all the scenarios that were identified by BWP as being practical. Based on the results of the scorecard, the “New Transmission & PPAs” and “SB1020+SMR” options were selected as the preferred scenarios. Both scenarios were selected, as the plan for the long-term future is based on the availability of technology and ability to secure additional transmission service agreements with the Los Angeles Department of Water and Power. Both scenarios provide a path forward to SB 100 and SB 1020 compliance as well as meeting the BWP 2040 goal of 100% zero-carbon resources.
Table 2-11 Final Scorecard Results
2.7 OTHER PLANNING CONSIDERATIONS
2.7.1 Resources
2.7.1.1 Renewable and Storage Options
The PLEXOS model used for the planning scenarios included several types of new renewable generation resources as possible future expansion options for BWP. These were wind turbines, ATTACHMENT 1
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stand-alone solar, and hybrid solar plus energy storage. Stand-alone storage was also included as an option as well.
The contributions from customer-owned distributed generation and energy efficiency were included as a part of the demand forecast and not as separately modeled generation resources.
2.7.1.2 Non-Fossil Fuel Dispatchable Technologies
Modeling provisions were also made for the construction of new hydrogen-fueled combined cycle and combustion turbines along with the conversion of existing natural gas-fired power plants to use hydrogen or RNG.
2.7.1.3 Fossil Fuel Technologies
Burbank does not plan for any new fossil fuel power generation to be added to its portfolio in the future and the construction of new natural gas- or coal-fired resources were not a part of any of the scenarios that were studied. Existing fossil-fuel power plants were assumed to continue to be used in the near-term until they are retired either due to reaching their natural end-of-life or due to the requirements to meet RPS or clean energy targets. Within the model, fossil fuel generators were also converted to use other less carbon-intensive fuels such as renewable natural gas or hydrogen.
2.7.1.4 Energy Purchases
The PLEXOS model included the ability for the BWP system to make purchases in the energy market for times when it would be the least cost option for meeting BWP’s demand needs. These purchases from the spot energy market are not tied to any generating resource owned by BWP or to any long-term purchased power contract that it has entered into. Spot energy market prices are not fixed and are largely outside of the control of BWP and can therefore represent a potential risk if spot market purchases form too large of a portion of BWP’s energy supply.
2.7.1.5 Reserve Obligations
In 2015, following negotiations involving technical, operational, commercial, legal, and regulatory issues, LADWP, BWP, and Glendale Water and Power (GWP) were successful in negotiating a Balancing Authority Area Services Agreement (BAASA) that is cost-based and founded on modern industry policy and practice. It is comprehensive, flexible, fair, and provides a durable basis for BWP’s operations and planning.
As a part of the BAASA, BWP also negotiated the opportunity to purchase all of its reserve obligations from LADWP instead of using BWP’s own assets and limited market access to provide for the reserves. BWP reserve obligations were determined during and through negotiation of the BAASA as 40 MW of spinning capacity and 40 MW of supplemental capacity for a total of 80 MW of reserve capacity. LADWP does not guarantee that the full 80 MW of these reserves will be available for purchase every year, subject to LADWP’s load growth and resource planning. BWP staff works closely with LADWP staff to manage this risk.
With BWP’s reserve obligations being met through LADWP, no additional reserve margin was accounted for in the modeled planning scenarios within this IRP.
2.7.2 Environmental Costs
As a city, Burbank is pursuing an aspiration goal of becoming 100% zero-carbon by 2040. That goal exceeds the California state target for 100% clean energy by 2045. Meeting mandated GHG and RPS targets unavoidably incurs costs. The costs of new energy contracts and resources that are ATTACHMENT 1
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compliant with those targets are built into all of the scenarios that were modeled for this IRP. BWP is committed to meeting its environmental mandates and goals while maintaining system reliability and affordable rates for its customers.
3 IRP Filing Contents Per CEC
3.1 PLANNING PERIOD (HORIZON)
3.1.1 Study Period
The Burbank 2024 IRP evaluates the period from 2023-2047. This study period exceeds the minimum requirements of PUC Section 9621 and allows for additional insights to be gathered as they relate to long-term planning and decision making that could impact BWP and its customers.
3.1.2 RPS Obligations
All the planning scenarios considered in this IRP include the RPS mandates from SB100 requiring an RPS of 60% by 2030. Table 3-1 details the Annual RPS Targets BWP plans to meet using a mixture of existing resources/contracts, additional procurement of renewable assets, and REC purchases. These annual RPS targets were used as a constraint in the PLEXOS model.
Table 3-1 Annual RPS Targets
Target Quantities of Renewable Energy Resources (%)
Compliance Period 4 Compliance Period 5 Compliance Period 6 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030+
36% 39% 41% 44% 46% 50% 52% 55% 57% 60%
Consistent with regulations, BWP is not required to demonstrate a specific quantity of procurement in any of the intervening years between 2021 up to and including 2030, however, BWP must demonstrate procurement equal to the compliance period target. BWP will submit its annual and compliance period compliance reports, as required under the California Energy Commission (CEC).
Compliance periods beyond compliance period 6 will consist of three years. Each compliance period beyond compliance period 6 will need to meet an average of 60% RPS or greater of its retail sales as required by law.
3.1.3 GHG Targets
In addition to the 100% carbon free energy by 2045 target from SB100, the planning scenarios also consider Burbank’s own goal of 100% carbon free energy in 2040. This is accomplished through the assumption that existing natural gas-fired generating units will be converted to run on either renewable natural gas or hydrogen fuel no later than 2040.
In the fall of 2023, the California Air Resources Board (CARB) updated its greenhouse gas planning targets for 2030. In that update, the target planning range for Burbank changed from 129,000 – 228,000 metric tonnes of carbon dioxide equivalent (MTCO2e) to 129,000 – 163,000 MTCO2e. This change in CARB planning targets was finalized after the modeling for this IRP was completed. All planning scenarios in this IRP result in large reductions of carbon emissions, and all achieve a net zero carbon result by 2040. However, while all the planning scenarios satisfy the previous CARB ATTACHMENT 1
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targets by 2030, only three of the planning scenarios (Net Zero by 2030, SB1020+SMR, and SB1020+SMR w/ 50% EV & DEV) achieve greenhouse gas emission reductions in line with the new CARB planning targets.
Figure 3-1 Planning Scenario Carbon Emissions
3.2 SCENARIOS AND SENSITIVITY ANALYSIS
3.2.1 Production Cost Modeling Software
The PLEXOS models evaluated resource combinations that Burbank could use to meet future requirements in the 2023-2047 planning period. PLEXOS is an industry standard capacity expansion and production cost model that is used all around the world by many different utilities and energy sector professionals. PLEXOS was used to create least cost portfolios for each of the seven planning scenarios discussed in Section 2.6. Results were calculated while obeying the operational constraints defined for the power plants and transmission components, maintaining system reliability, and serving the forecasted demand.
3.2.2 Key Inputs and Assumptions
As a long-term planning, document, the IRP is based on significant assumptions about the future.
This carries inherent uncertainty, especially with the utility industry undergoing dramatic change.
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renewable energy generation and electric transmission resources to the growth of electric demand in Burbank. As a result, the IRP is treated as living document and will be regularly reviewed and updated. Future revisions to the IRP will incorporate changes to energy market conditions, environmental and energy policies, and the results of actions taken by BWP in the interim.
3.2.2.1 Demand
BWP serves the electricity needs of Burbank. In utility terms, these needs are called “demand.” Managing and forecasting Burbank’s demand is necessary to ensure that electricity can be generated or purchased at low prices and that sufficient supplies of electricity are available to meet the needs of BWP’s customers. A full description of the method by which demand was forecast for this IRP analysis is provided in Section 3.5 below.
3.2.2.2 Natural Gas Prices
The natural gas prices used within the Burbank PLEXOS model are built from two major data sources: market quotes and the natural gas price forecast published as a part of the IEPR 2023 Preliminary Electric Generation Price Model.
23 In the short-term, the natural gas prices are developed as a blend of actual market quotes received by BWP and forward prices based on S&P Global IQ data. Natural gas prices and, in general commodity prices, have been high over the past couple of years primarily due to global supply constraints and disruptions especially in Europe due to the loss of Russian natural gas imports. US exposure to global natural gas markets has also increased mainly due to an increase in domestic liquified natural gas (LNG) export capabilities. However, in 2023, some of these supply pressures have eased because of warmer than expected weather, improved energy efficiency, and reduced industrial activity that has put downward pressure on global natural gas demand.
In the long-term, Black & Veatch projects natural gas prices in US to continue declining over the next few years as it transitions to the fundamental forecast from the IEPR, primarily due to an increase in natural gas production from an increase in drilling activity and overall strength in US natural gas resources in the Permian basin (West Texas) and the Marcellus/Utica shale area (Pennsylvania, Ohio, and West Virginia).
In April 2023, the CEC published its 2023 IEPR Preliminary Electric Generation Model, where the monthly natural gas price forecast was updated and extended to 2050. A Base Case and two sensitivity cases – one for high gas supply, one for low gas supply – were included in this model update. Figure 3-2 demonstrates the forecasted curves of the three IEPR cases in 2023 real dollars.
In this IRP, it is assumed the existing price premiums diminish over time and eventually disappear in 2032, 5 years after the current market quotes end. The SoCal Citygate price point from the Base Case is selected as the fundamental forecast price starting from July 2032 (i.e., FY32). A linear regression was developed in the interim period to form a gradual transition between the two forecast methods.
23 2023 IEPR Preliminary Electric Generation Price Model, Docket 23-IEPR-03, Filed on 04/18/2023 ATTACHMENT 1
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Figure 3-2 IEPR SoCal Citygate Natural Gas Price Forecast Comparison To capture both data sources, three periods of pricing were created. The first period, FY2023/2024 through FY2026/2027, is based off BWP market quotes. The second period, FY2027/2028 through FY2031/2032 is a transition during which the higher natural gas prices from the BWP market quotes are linearly transitioned down to the expected long-term IEPR forecast prices. Finally, the third period is based solely on the data from the 2023 IEPR.
For all periods and data sources, prices were inflation adjusted to 2023 dollars. Figure 3-3 shows the monthly natural gas price forecast for the full planning horizon. The result of the forecast was a set of data providing monthly natural gas prices that were used as an input into the PLEXOS model.
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Figure 3-3 Natural Gas Price Forecast
3.2.2.3 Capital Costs
For each of the potential generating technologies considered for capacity expansion in this IRP, assumptions had to be made regarding their capital (CAPEX) and operations and maintenance (O&M) costs. Cost projections were developed by Black & Veatch and were further broken down into three regions – California, the Rockies, and regions neighboring California – to better capture geographical cost differences. These forecasts were developed based on a combination of previous assessments and projects performed by Black & Veatch and review of publicly available sources such as the Energy Information Administration (EIA) and National Renewable Energy Laboratory (NREL).
The ITC available through the federal IRA were assumed to be applicable for battery storage resources. The tax credit equals 30% of the projects’ capital costs starting from 2023. The ITC is assumed to decrease to 22.5% in 2034, 15% in 2035 to 2040, and then completely phase out after 2040. The same percentages were taken out from the full values of capital costs to reflect the ITC received. This resulted in the capital costs of battery storage appearing to go up over years as opposed to other technologies whose costs decreased over time.
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In this IRP, Black & Veatch assumed both solar and wind generating facilities are eligible to apply for PTC now available through the IRA. PTCs were reflected as a negative variable O&M cost in the production cost model. Capital costs of wind and solar were modeled at their full values.
As discussed in previous sections, RNG fuels were expected to be available after 2030 to meet BWP’s Net Zero goal. Hydrogen technologies were not expected to be available locally in Burbank until 2040.
Figure 3-4 C APEX Projections by Technology in Rockies Region
Figure 3-5 CAPEX Projections by Technology in California Region
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Figure 3-6 CAPEX Projections by Technology in California Neighbor Region
Figure 3-7 Fixed O&M Cost Projections by Technology
3.2.2.4 Base Case Assumptions
3.2.2.4.1 Existing and New Generation Resources
See Section 2.5 for the discussion of BWP’s existing resources portfolio.
In order to meet BWP’s RPS and emission reduction targets, Black & Veatch primarily considered renewable resources, clean alternative fuels and storages when constructing future generation portfolios. Combining the understanding of Burbank’s future transmission and infrastructure 0 500
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readiness, Black & Veatch selected solar, wind, combined cycle gas turbine with carbon capture and sequestration (CCS), hydrogen-fueled combined cycle and combustion turbine as potential resources and technologies that can be part of BWP’s future portfolio.
3.2.2.4.2 Grid Operational Efficiencies
In the modeling, five percent of transmission losses were applied on generation delivered in BWP region. This is based on historical records on BWP’s resource budget. Another three percent of distribution losses were then applied to reported retail sales.
3.2.2.4.3 Energy Storage
Assumptions on energy storage are discussed in detail in Section 3.6.3 below. Lithium-ion batteries were included in PLEXOS when analyzing potential portfolios for each scenario.
3.2.2.4.4 Distributed Energy Resources
Assumptions on distributed energy resources (DER) are discussed in detail in Section 3.5.1.6 below.
Forecast of DER, more specifically, distributed solar resources was developed based on 2022 IEPR baseline. It was then used as the demand side adjustment during dispatch modeling.
3.2.2.4.5 Energy Efficiency
Assumptions on energy efficiency are discussed in detail in Section 3.5.1.5 below. Similar to DER, forecast of energy efficiency was based on 2022 IEPR and was used as a demand side adjustment.
3.2.2.4.6 Short-Term and Long-Term Products
Regarding new resources, Black & Veatch estimated levelized capital carrying rate based on various financing assumptions. Existing PPA contract durations were included in the optimized modeling of each scenario.
3.2.2.4.7 RPS Procurement
BWP aims to secure most of its renewable contracts where transmission is available and already contracted for; and resources in diverse locations, with variable term lengths and ultimately, on a least-cost and best-fit basis. For any additional RPS requirements that are not met by the current and future generation portfolio, BWP would purchase RECs in various Portfolio Content Categories (PCCs). The required amount of RECs from each PCC is discussed in Section 3.6.1.1.
All SB 100 cases reached the target of 60% RPS by 2030, with both contracted renewable resources and PCC procurements. The reported amounts of RECs for each scenario assume that any excess procurement that occurs yields RECs that can be either banked for future RPS compliance or sold if there is a significant excess of RECs in a given future year. However, with the addition of the solar generation associated with IPP green hydrogen, excess RECs post 2030 are so large that the value of banking is not clear.
3.2.3 Summary of All Scenarios, Scorecard, and Recommended Strategy Based on the feedback from the IRP survey, the STAG and the community stakeholders, a scorecard was developed to rank each scenario. The weight of the scorecard and details of the scorecard are listed below:
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Table 3-2 Scorecard Details and Weighting
Item Details Weight
Cost/Ratepayer Impacts The total overall cost of the portfolio (the lower the cost, the higher the weight or score) 40%
Reliability
Lower transmission losses and lower market
purchases (the lower the losses and purchases, the
higher the weight or the score)
40%
Environmental
Stewardship
Total greenhouse gas emissions (the lower the
emissions, the higher the weight or the score) 10%
Diversity
Type of resource, length or term of the contract,
type of resource technology (like wind, solar,
geothermal, etc.), location of resource, a mix of
baseload and variable resources, etc.
Diversification of resources is required under SB
350
10%
Total 100%
3.2.3.1 Scorecard Results
The scorecard rankings show that the “Basecase+Zero Carbon by 2030” scenario ranks highest.
Unfortunately, the lack of contracts available to get us to RNG at the Magnolia Power Project makes this scenario invalid. As mentioned earlier, the assumptions for the IRP were taken earlier in the year and many items changed. This includes the lack of RNG contracts available and higher than expected load forecast.
Table 3-3 Scorecard Results
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3.2.4 Emissions Summary
In September 2023 the California Air Resources Board (CARB) released an update to the “Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets.”24 The lower 2030 planning target of 129,000 metric tonnes of CO2 equivalent (MTCO2e) remained unchanged from that considered under the 2019 Burbank IRP. However, the upper 2030 planning target has been reduced from 228,000 MTCO2e to 163,000 MTCO2e. As can be seen in Table 3-4, only three of the planning scenarios meet the new CARB planning targets. All the planning scenarios evaluated in this 2024 IRP report make significant reductions in CO2 emissions with net zero emissions being achieved by no later than 2040.
Table 3-4 Greenhouse Gas (GHG) Emissions in Metric Tonnes
3.3 STANDARDIZED TABLES
Due to formatting constraints, copies of the CEC’s Standardized Tables containing the results of the two preferred scenarios chosen through the scorecard analysis described in Section 2.6.8 (the “New Transmission & PPAs” and “SB1020+SMR” options) will be submitted separately to the CEC.
24 California Air Resource Board, “Senate Bill 350 Integrated Resource Planning Electricity Sector Greenhouse Gas Planning Targets: 2023 Update,” https://ww2.arb.ca.gov/sites/default/files/2023-09 /sb350-final- report-2023.pdf
Year Base Case Net Zero by 2030 SB1020 + SMR
SB1020 + SMR w/
50% DEV & EV
Demand
10% Higher EV &
DEV Demand
10% Lower EV &
DEV Demand
New Transmission
& PPAs
2023 343,469 351,766 342,936 342,440 343,644 343,453 343,151 2024 346,419 354,389 346,029 345,331 346,504 346,276 346,489 2025 274,157 250,672 274,276 259,156 277,337 271,225 274,147 2026 275,852 240,564 275,194 271,605 276,056 275,298 275,679 2027 253,008 214,517 251,065 234,093 255,840 249,497 252,446 2028 199,145 162,476 209,531 194,770 202,786 195,560 199,155 2029 197,464 151,629 208,328 196,170 201,797 195,280 197,612 2030 187,840 - 104,568 107,072 190,767 185,670 187,496
2031 197,292 - 118,301 115,091 200,617 194,559 197,037
2032 193,522 - 117,989 107,706 197,678 189,033 192,060
2033 178,373 - 137,145 125,283 179,676 175,597 177,566
2034 163,004 - 126,306 111,543 166,528 163,483 164,956
2035 157,107 - 95,176 84,908 159,777 153,517 112,192
2036 146,122 - 92,856 80,454 149,139 141,160 112,569
2037 129,758 - 88,598 71,872 132,656 126,115 108,640
2038 115,161 - 85,757 63,719 113,473 109,703 88,699
2039 92,111 - 85,474 55,482 90,526 88,083 70,069
2040 - - - - - - -
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2042 - - - - - - -
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2046 - - - - - - -
2047 - - - - - - -
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3.4 SUPPORTING INFORMATION
The assumptions that were relied on in the analysis documented in this report are discussed in the relevant sections and footnoted and linked to online resources where appropriate. Any additional analyses, data, or other materials not already contained in, or referenced by, the body of this IRP report will be provided on request in order to facilitate the CEC’s review.
3.5 DEMAND FORECAST
Burbank Water and Power (BWP) serves the electricity needs of Burbank and its people. In utility terms, these needs are called “demand.” BWP serves Burbank’s demand by delivering power through the electrical system: the network of wires, transformers, switches, and other equipment that make up the electric grid. BWP generates a portion of this electricity itself, purchases some through power plant contracts, and buys energy from the electricity markets when it is necessary to meet customer demand.
Managing and forecasting Burbank’s future demand for electricity is necessary to ensure current and future affordability and reliability. As BWP moves forward, there will be challenges in forecasting BWP’s demand due to changing customer use patterns brought about by new energy efficiency measures, an increasing adoption of electric vehicles, generation contributions from customer-owned rooftop solar, and legislative mandates to reduce Greenhouse Gas (GHG) emissions. Therefore, it is essential to understand hourly demand profiles, annual energy needs, and peak energy requirements. This information will help inform resource procurement decisions made by BWP as it makes plans to meet the unique challenges of Burbank’s energy future.
3.5.1 Demand Forecast Methodology and Assumptions
A multi-step process is used to forecast the demands that BWP must account for in its long-term planning. The methodology and process used for forecasting annual demand as well as the detailed hourly demand profiles is described below.
The gross energy demand forecast for Burbank comprises energy demands for residential, commercial, future development, and future electric vehicle components. Gross energy demand is then offset by savings from energy efficiency measures and the contributions from distributed generation to calculate net energy demand.
Figure 3-7 Gross and Net Energy Demand Components
3.5.1.1 Residential Energy Demand
The forecasted residential base energy demand was based on a regression analysis of historical demand data for Burbank. Annual residential retail sales from 1998 through 2022 were used along with city population, average personal income, and the annual number of cooling degree days ATTACHMENT 1
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(CDD) to develop the appropriate regression coefficients. Once the relationship between these variables was determined, annual residential energy demand was calculated for the years 2023 through 2047. During that forecast period, the residential base energy demand is estimated to grow at a Compound Annual Growth Rate (CAGR) of 0.5%.
3.5.1.2 Commercial Energy Demand
The commercial base energy demand was forecasted in a similar fashion to the residential base energy demand. Historic demand data from 1998 through 2022 was used with a set of independent variables to perform a regression analysis. For commercial energy demand, the chosen independent variables were city population, the amount of commercial floor space, average personal income, and the number of employees working in the commercial sector. Like the residential base energy demand, annual commercial base energy demand was calculated for the years 2023 through 2047. During that forecast period, the commercial base energy demand is estimated to grow at a CAGR of 0.8%.
3.5.1.3 New Development Energy Demand
Known development projects planned within Burbank were reviewed and their impact on residential and commercial energy demands was considered. The estimated peak energy demand in megawatts for each development project was used together with a load factor of 43%25 and a conservative project success factor of 60% to calculate the total annual energy demand impact. The success factor was used to account for any potential delays or cancellations of these development projects and to account for any potential differences between the actual usage from these development projects vs. the peak energy demand assumed for designing the required distribution system. Once found, this new development energy demand was phased in over a period of seven years starting in 2025 to account for the time it would take for the projects to be completed.
3.5.1.4 Electric Vehicle Energy Demand
Annual electric vehicle energy demand through 2035 was based on a blend of the California Energy Commission’s (CEC’s) 2022 Integrated Energy Policy Report’s (IEPR’s) Additional Achievable Transportation Electrification (AATE) scenarios. The Burbank-Glendale (BUGL) planning area AATE scenarios were scaled down using data from the 2022 IEPR Load Serving Entity (LSE) and Balancing Authority (BA) data to derive Burbank’s share of the forecast electric vehicle energy demand. In addition to the baseline AATE forecast from the IEPR, Burbank’s electric vehicle energy demand was also based on the increasing rates of electric vehicle adoption shown in AATE Scenarios 2 and 3. A blending of the three scaled AATE scenarios, shown below in Figure 38, was used to calculate the annual electric vehicle energy demand for Burbank. The blending of the 3 AATE scenarios was used to account for an adoption rate for electric vehicles that is anticipated to increase over time. In 2022, the California Air Resources Board (CARB) promulgated the “Advanced Clean Cars II” regulations requiring that by 2035 all new cars and light trucks sold in California will have to be zero-emission vehicles. Since the AATE scenarios only contained a forecast though 2035, that data was extrapolated out through 2047 using a second order polynomial regression model.
25 43% load factor is based on the historical load factor data for the Burbank region.
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Figure 3-8 Forecast Electric Vehicle Energy Demand for Burbank
3.5.1.5 Energy Efficiency Savings
The forecast for Burbank’s energy efficiency savings was developed using data taken from the CEC’s 2022 IEPR’s AAEE Scenario 3. Unlike the AATE data, the AAEE data was available through 2050 and could be directly used for the entire planning horizon without the need for extrapolation. As can be seen in Figure 3-9, the annual increases in energy efficiency savings are assumed to decrease over time. Benefits from the implementation of energy efficiency programs are expected to eventually saturate as the most impactful and cost-effective changes are made first and programs with smaller benefits are implemented later.
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Figure 3-9 Forecasted Energy Efficiency Savings for Burbank
3.5.1.6 Contributions from Additional Distributed Generation The forecast for Burbank’s additional distributed generation, beyond what is already present in the city, was based on data taken from the CEC’s 2022 IEPR baseline forecast. The 2022 IEPR baseline forecast annual distributed generation data was only available through 2035; therefore, it was extrapolated out through the end of the planning horizon using the same method as was used for the AATE data. A trend toward increasing contributions from distributed generation is in line with the general trends seen in the broader energy markets. Incentives like those that are a part of the Inflation Reduction Act are expected to further encourage expansion of customer-owned generation resources.
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Figure 3-10 Forecasted Additional Distributed Generation for Burbank
3.5.1.7 Annual Peak Energy Demand
Another regression model was used to develop the annual peak values for Burbank’s non-electric vehicle gross energy demand. Electric vehicle energy demand was not included in this peak energy demand regression due to its drastically different hourly demand profile compared to residential and commercial demands. The non-electric vehicle gross energy demand comprises residential, commercial, and non-electric vehicle development demands. For the peak energy demand regression analysis, historical net peak was the dependent variable and historical net demand and maximum CDD were the independent variables. This regression analysis provided the coefficients necessary to forecast peak energy demand values. Max CDD for the 2023-2047 peak forecast was assumed to be weather normal. The peaks for electric vehicles, energy efficiency, and distributed generation are a function of their annual forecasts and their hourly shapes.
3.5.2 Determination of Hourly Demand Shapes
Beyond the annual values for each of the contributing categories that make up Burbank’s net energy demand, hourly demand profiles for contributing categories for each year in the planning horizon (2023-2047) were also generated. The hourly data is used for detailed modeling of future energy needs and determination of the best types and amounts of generation that will be required to meet them.
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3.5.2.1 Residential. Commercial, and Future Development Hourly Demand The hourly demand shape for residential, commercial, and future non-electric vehicle development energy demands was adopted from Burbank’s actual 2018 demand profile. The 2018 demand profile was found to be the most weather “normal” year based on historical CDD and energy consumption data; therefore, it was used as the basis for the creation of the hourly demand profile for this part of the overall net system demand. PLEXOS was used to build the hourly forecast based on annual demand, peak, and the 2018 demand profile.
3.5.2.2 Electric Vehicle Hourly Demand
The 2022 IEPR electric vehicle hourly demand profile for the CAISO planning scenario was scaled down to match Burbank’s forecast electric vehicle demand. Since that IEPR demand profile did not span the entirety of the planning horizon, the last year of that forecast (2035) was used as the basis for the hourly demand shape in the years 2036-2047.
3.5.2.3 Hourly Savings from Energy Efficiency
The hourly profile for energy efficiency savings was also taken from the 2022 IEPR. Scenario 3 from the 2022 IEPR AAEE & Additional Achievable Fuel Substitution (AAFS) forecasts was used in conjunction with the 2022 IEPR AAEE Hourly Impacts forecast for the BUGL planning area to create the hourly energy efficiency forecast for the entire planning horizon. The BUGL hourly forecast was scaled down to match the Burbank Annual AAEE Scenario 3 forecast from the 2022 IEPR. Since both IEPR sources included data through 2050, no extrapolation or regression was required.
3.5.2.4 Hourly Contributions from Distributed Generation An hourly solar generation profile for the Los Angeles area was used together with the annual distributed generation forecast described above to create the hourly contributions from distributed generation located within Burbank.
3.5.2.5 Sum of Hourly Demand Profiles
Once all the hourly demand profiles were completed, (residential and commercial energy demand including the demand from new developments, electric vehicle energy demand, energy efficiency savings, and energy contributions from distributed generation), they were all combined on an hourly basis to create the final hourly demand forecast. In the figures below, the forecasted change in the average summer and winter hourly demand profiles can be seen. As time passes, the effects of increased demand can be seen as the hourly demands shift upwards and peak demands increase.
The adoption of electric vehicles can be seen in the more pronounced energy usage in the overnight hours. This is particularly evident in Figure 3-12 where the winter peak is shifted towards the overnight hours due to electric vehicle charging.
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Figure 3-11 Average Hourly Summer Demand Profiles
Figure 3-12 Average Hourly Winter Demand Profiles
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3.5.3 Results of Demand Forecast
In the historic demand data from 2018-2022 listed in Table 3-5 and Figure 3-13 below, the annual net energy demand and net peak energy demand for Burbank show a temporary decrease in 2020 and 2021 that is associated with the impacts of the COVID-19 pandemic. The forecast from 2023- 2047 assumes that demand will return to “pre-COVID” levels and will increase largely due to new residential and commercial developments and the increasing adoption of electric vehicles.
The forecasted demand for Burbank from 2023-2047 is also provided in Table 3-5 and Figure 3-13 below. Annual net energy demand is given in units of gigawatt-hours (GWh) and annual net peak energy demands are given in units of MW.
Figure 3-13 Forecast Net Annual Demand and Annual Net Peak Demand
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Table 3-5 Annual Net Energy Demand & Net Peak Energy Demands Year*
Net
Energy
Demand
(GWh)
Net
Peak
Energy
Demand
(MW)**
2018 1,151 306
2019 1,108 283
2020 1,049 292
2021 1,033 248
2022 1,079 297
2023 1,004 288
2024 1,023 290
2025 1,078 301
2026 1,132 310
2027 1,186 319
2028 1,217 326
2029 1,250 331
2030 1,284 336
2031 1,324 344
2032 1,332 343
2033 1,342 338
2034 1,355 344
2035 1,373 345
2036 1,383 349
2037 1,396 349
2038 1,409 346
2039 1,423 346
2040 1,437 351
2041 1,467 354
2042 1,499 359
2043 1,534 362
2044 1,573 361
2045 1,615 371
2046 1,639 372
2047 1,665 374
* Historic demand data is provided for years 2018-2022. The forecast is for years 2023-2047. ** The forecast peak demand data includes transmission losses.
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3.6 RESOURCE PROCUREMENT PLAN
3.6.1 Diversified Procurement Portfolio and RPS Planning Requirements In December 2021, BWP revised its Renewable Energy Resources Procurement Plan to incorporate the target of procuring at least 60% of annual retail electricity sales from eligible renewable resources by the end of 2030. Post-2030, eligible renewable resources are to continue to meet or exceed that 60% target.
Most of the long-term renewable energy contracts solicited by BWP are done jointly though its membership in the SCPPA. By joining with other SCPPA members to purchase renewable energy, BWP is able to access a more diverse set of projects that it would be otherwise unable to participate in due to its relatively small energy demand within the broader electricity market.
BWP splits its procurement of renewable energy between both baseload and peaking resources and seeks to include a diversity of contracts that include both fixed and market-based energy prices.
3.6.1.1 Forecasted RPS Procurement Targets
Included in the table below, taken from the current BWP Renewable Energy Resources Procurement Plan, are the procurement targets for compliance periods leading up and following the December 31, 2030 deadline to reach 60% RPS.
Table 3-6 RPS Compliance Requirements26
3.6.1.2 Renewable Procurement
The resource portfolios for each of the planning scenarios are described in Section 2.6. The figures provided for the different scenarios include data on the forecasted capacity, total generation in
26 Burbank Power and Water, Renewable Energy Resources Procurement Plan & Enforcement Program, Version 3, December 2021.
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MWh, and annual RPS percentages for each of the years in the study period. The same information is also included in the Standardized Tables in Section 3.3.
3.6.1.3 RPS Procurement Plan
The current BWP Renewable Energy Resources Procurement Plan & Enforcement Program is included as Attachment 1 to this IRP report.
3.6.1.4 Other RPS Procurement Plan Information
3.6.1.4.1 City Council Discretion and Cost Limitations
Within the BWP Renewable Energy Resources Procurement Plan, it is acknowledged that certain future circumstances may impact its ability to comply with RPS procurement targets. Under these circumstances, the Burbank City Council may choose to delay the timely procurement of renewable energy:
• Inadequate Transmission Capacity
• Permitting or Interconnection Delays
• Unanticipated Curtailment or Unforeseeable Circumstances • Unanticipated Increase in Retail Sales Due to Transportation Electrification
In the circumstances listed above, there may be occurrences beyond the control of BWP that could limit its ability to procure or receive renewable energy on a schedule that supports meeting its RPS targets or its ability to procure renewable energy at reasonable prices.
The Burbank City Council has the ability to set a cost limitation in place if it determines that there would be adverse cost impacts to ratepayers due to the procurement of new long-term renewable energy resources. If the City Council uses its authority to delay or modify any of the RPS procurement targets, it will do so at a public meeting and ensure that all necessary and reasonable efforts have been made to achieve compliance.
3.6.1.4.2 Enforcement Program
The responsibility of executing the Renewable Energy Resources Procurement Plan falls to the General Manager of BWP. If the General Manager determines that BWP will not meet one of its RPS procurement targets, they will notify the Burbank City Council in a public meeting and present a plan laying out the ways in which BWP will seek to bring itself back into compliance.
3.6.2 Energy Efficiency and Demand Response Resources
BWP manages a comprehensive portfolio of Energy Efficiency (EE) programs for residential and commercial customers to assist with energy conservation and peak shaving measures. One of these EE programs is the Home Improvement Program (HIP). HIP offers energy-water surveys and efficiency measure installations to all Burbank single-family residential, multi-family residential, and multi-family common area customers. A total of 587 customers participated in the HIP in FY2022/2023.
BWP also offers a Refrigerator Exchange Program. This program offers income-qualified customers a new Energy Star-Certified refrigerator in exchange for their old, inefficient refrigerator. The Refrigerator Exchange Program had 74 refrigerators exchanged during FY2022/2023. BWP’s Shade Tree Program provides an arborist visit and delivers shade trees to help customers shade their ATTACHMENT 1
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properties, reduce A/C usage, and clean the air. The program delivered 204 trees during FY2022/2023. BWP’s A/C Replace it Before it Breaks program assisted 36 customers replace their old A/C systems and resulted in 19 rebates issued during the fiscal year. Some additional EE programs include residential and commercial rebates for the purchase and installation of high efficiency retrofit measures and LivingWise energy/water efficiency education and kits for 6th graders. Figure 314 shows the EE savings BWP saw in FY2022/2023.
Figure 3-14 Energy Efficiency Savings FYTD 2022-2023
These existing levels of EE measures were incorporated into the residential and commercial demand forecasts. For more information about historical EE measures in BWP, see Table 4-1. The incremental EE forecast used into the model comes from the California Energy Commission’s (CEC’s) Additional Achievable Energy Efficiency (AAEE) Scenario 3 forecast for BWP. For more discussion on the incremental EE forecast, see Section 3.5.1.5.
While BWP offers several energy efficiency and conservation programs to its customers, it did not offer any Demand Response (DR) programs while this IRP’s planning scenarios were being developed. However, BWP has requested voluntary peak load reductions from its residential customers in previous summers during high system load days as part of a “behavioral DR” pilot. It has also reduced certain Burbank demands during the heat dome even in early September 2022 as part of a new CEC program called Demand Side Grid Support (DSGS). BWP is aiming to expand DR offerings across its customer base such as a Bring Your Own Device (BYOD) program for residential and small commercial customers and the facilitation of an expanded DSGS program for larger commercial customers.
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A BYOD program allows utility customers to enroll certain types of devices in a program and have the devices receive signals to reduce electricity usage during DR events. In return, customers earn a monetary incentive each year by participating in the program. The most common type of BYOD program is for customers with smart thermostats, where utilities can use Distributed Energy Resource Management Systems (DERMS) to turn up the temperature on participating thermostats by several degrees, thereby reducing the electricity required by the air conditioner or heat pump.
This temperature increase is generally preceded by about an hour of “precooling,” where the premise is cooled to a temperature below the thermostat setpoint to lessen the impact of the event.
The BYOD program proposed in the current scope of services is a smart thermostat program, but the DERMS could host other programs if BWP decides to expand offerings in the future.
The ability of a BYOD program to directly reduce cooling load from customers enrolled in the program will allow BWP to reduce system load during peak periods and provide a more reliable load reduction than behavioral DR. Reducing cooling load lowers operating costs by reducing energy purchases during the most expensive market periods and reduce stress on the grid during heat wave events.
BWP commenced its first year of the BYOD smart thermostat program in September 2023. Summer 2024 will be the first year of full participation from May 1st – October 31st. Table 37 describes the program parameters for this DR initiative.
Table 3-7 BYOD Smart Thermostat Program Parameters
BYOD Smart Thermostat
Program Parameters
Season Window for Events: May 1st to October 31st
Available Days: Monday-Friday, no holidays
Control Window: 12:00 pm - 09:00 pm local
Scheduling Lead time: Typical: 24 hours
Minimum: 1 hour
Maximum Number of
Events:
No more than 3 events per week
No more than 20 events per DR season
Maximum Event Duration: 4 hours
3.6.3 Energy Storage
Energy storage resources will play a key role in best positioning BWP’s portfolio for the clean energy transition. As stated in Section 2.1.4, energy storage will be needed to address the intermittency of renewable resources and are required to properly integrate them while maintaining reliability. One phenomenon energy storage resources help mitigate is the “Duck Curve”, which will only worsen as renewable penetration increases to meet BWP’s energy needs as well as achieve its RPS targets. The Duck Curve is what some call the net demand shape after incorporating the contributions of intermittent resources into the demand profile. This net demand profile can drop dramatically as solar generation increases in the middle of the day; however, solar generation might not last through the peak load hours in the evening which causes a sharp increase in the net demand profile as the sun sets. The result is that the system will need to respond quickly to potential demand increases while solar generation is declining at the same time. Energy storage ATTACHMENT 1
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resources help mitigate the Duck Curve in two ways. Firstly, when solar generation is high in the middle of the day, batteries can increase system demand by using the solar generation to charge and reduce the need to possibly curtail those solar resources. Secondly, energy storage can then use that stored energy to help with meet system demand and ramping needs in the evening as solar generation is on the decline, but the system is still experiencing high demand.
3.6.3.1 Demand-Side Energy Storage
Demand-side energy storage typically takes the form of batteries that are purchased and installed by individual residential or commercial customers and are usually paired with solar photovoltaic systems. A combined solar + storage system allows a customer to store energy generated during times of maximum generation and then consume that energy later. This can help to moderate peak demands at an individual customer level. The capacity of demand-side storage systems are typically in the 5 – 20kWh range, but can be larger depending on the application. BWP has existing requirements for the design and installation of demand-side energy storage systems.27 Currently, there are 21 installations of demand-side energy storage systems in BWP’s service territory. As shown in Figure 3-21, these installations equate to 150kW/540.8kWh of storage capacity.
3.6.3.2 Supply-Side Energy Storage
Supply-side energy storage is energy storage at a utility scale. Power output of these facilities can be many megawatts and the capacities of the largest facilities in operation can reach into the hundreds of MWh. Energy storage facilities that are connected to the transmission grid serve a similar purpose as demand-side energy storage, but at scales hundreds or thousands of times larger. Similar to demand-side energy storage, supply-side energy storage can absorb energy when renewable generation is greater than customer demand and then discharge it when it is needed the most. For this IRP analysis, 4-hour lithium-ion batteries were the only energy storage systems evaluated and incorporated into PLEXOS as an available energy storage resource.
3.6.3.3 Impact of Energy Storage on Base Case
To highlight the potential system impact of energy storage resources in Burbank’s energy future, the Base Case sensitivity scenario was re-run with all standalone energy storage removed from the portfolio. The analysis confirmed that energy storage resources play a key role in a reliable and diversified portfolio.
Figure 315 illustrates how the standalone battery energy storage system (BESS) assets mitigated the Duck Curve. The data was taken from the peak summer day in 2040 and it shows the batteries increasing the net system demand in the middle of the day while the batteries are charging and then decreasing the net system demand in the evening when the stored energy is discharged.
Another point of interest is that the ramping needs from the middle of the day to the evening are lower and the demand profile is not as steep.
27 Burbank Water and Power, “Electrical Interconnection and Metering Agreement for Solar Electric Generating Facilities and/or Battery Energy Storage Systems,” https://www.burbankwaterandpower.com/images/administrative/downloads/BWP_AppendixD_SolarInterc onnectionAgreement_May2018.pdf
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Figure 3-15 Example: Battery Impact on the Duck Curve28
Figure 316 shows how energy storage in the Base Case reduced the amount of solar generation curtailed by the PLEXOS model. The reason for this is that the Base Case without standalone BESS resources had materially higher solar curtailment due to not being able to efficiently move the energy around with storage. This results in a demand profile that assumes no solar curtailment to accentuate the Duck Curve phenomenon. Furthermore, using available energy is a better representation of what BWP is striving to do, which is to maximize the value of the assets they procure. Curtailment lowers the utilization and overall value of renewable assets, especially in light of the Inflation Reduction Act (IRA) and the production tax credits associated with renewable generation.
28 Solar curtailment was removed from Figure 2-15 to better illustrate the impact storage assets have regarding the Duck Curve.
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Figure 3-16 Battery Impact on Annual Solar Curtailment
3.7 SYSTEM AND LOCAL RELIABILITY
3.7.1 Bulk Transmission Reliability
BWP is a member of LADWP Balancing Area (BA). As such, bulk transmission (i.e., above 69 kV) is the responsibility of LADWP. Accordingly, bulk transmission system reliability is not a BWP responsibility outside of operating its electric system and resources in accordance with the conventions established by the Western Electricity Coordinating Council (WECC) and commonly accepted utility practice.
3.7.2 Distribution Reliability
BWP monitors Burbank’s electric system performance in order to measure and maintain electric reliability. During calendar year 2022, BWP maintained an availability rate of 99.999% with a system average interruption of less than 5 minutes per customer. 29 BWP’s continuing excellence in
system performance was recognized in 2021 when it was presented with a Reliable Public Power Provider (RP3) award by the American Public Power Association and earned its highest possible score.
30 This level of performance was achieved while maintaining customer rates at levels lower than the average California customer.
29 “City of Burbank, Burbank Water and Power, Staff Report,” dated February 2, 2023, page 19, https://www.burbankwaterandpower.com/images/administrative/downloads/BWP_MonthlyOpsReport_Fe bruary2023.pdf
30 “Burbank Water and Power (BWP) Wind Prestigious National Award for Electric Reliability,” April 16, 2021, https://www.burbankca.gov/newsroom/-/n ewsdetail/20124/burbank-water-and-power-bwp-wins- prestigious-national-award-for-electric-reliability
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Figure 3-17 SAIFI, 5-Year Average 2017-2021
BWP is one of the most reliable electric utilities in the nation and was recently recognized as a national leader in electric reliability by the American Public Power Association (APPA) earning the Reliable Public Power Provider Diamond level designation. This is the highest designation possible, with BWP scoring 100 out of a possible 100 points.31
By having a long-term vision and approach, BWP is strategically addressing these issues, as well as planning methodically to age BWP’s assets gracefully while continuing to maintain reliability.
3.8 GREENHOUSE GAS EMISSIONS
3.8.1 GHG CARB Targets
SB 100 also included a statewide target of powering 100% of retail electricity through the use of renewable and zero-carbon resources by the end of 2045. The GHG planning target ranges for
31 “Burbank Water and Power (BWP) Wins Prestigious National Award for Electric Reliability,” April 16, 2021, https://www.burbankca.gov/newsroom/-/n ewsdetail/20124/burbank-water-and-power-bwp-wins- prestigious-national-award-for-electric-reliability
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publicly owned electric utilities were first published in the July 2018 Staff report from CARB. As discussed in Section 3.1.3 above, the September 2023 update to those planning targets included a decrease in the high end of the target planning range for Burbank. The upper end of the range was decreased from 228,000 MTCO2e to 163,000 MTCO2e.
All of the emissions requirements for planning scenarios examined in Section 2.6 were initially formulated under the higher CARB target planning range. Only after the modeling was completed did CARB finalize its new targets. As such, not every one of the planning scenarios achieves the GHG reductions targeted by CARB for 2030. The scenarios with more aggressive emissions reduction goals or the use of new generation technologies and fuel types see a more rapid decline in forecasted emissions. However, those scenarios contain higher estimated total system and energy costs, or increased risks associated with possible implementation delays inherent in unproven types of clean energy. It must also be noted that all the planning scenarios reach net zero emissions by 2040, five years ahead of the California state goal of 100% clean energy by 2045.
3.8.2 BWP’s Green Choice Program
BWP operates a voluntary, opt-in “Green Choice Program” that allows its customer to pay 1.8₵ per kilowatt-hour more than their regular residential electricity rate. The revenue that BWP generates through customer participation in this program are used to purchase renewable energy credits (RECs) from the market. The purchase of RECs helps to offset the participating customer’s energy usage with renewable energy and encourages additional renewable energy to be used throughout California.32
3.8.3 Burbank’s Greenhouse Gas Reduction Plan
Starting in 2013, the City of Burbank has had a Greenhous Gas Reduction Plan (GGRP) that acknowledges the impacts to the climate from human activities. The projected effects of climate change on the residents of the City of Burbank include increased average temperatures, more days with extreme temperatures, an elevated risk of drought, and the possibility of reduced air quality from more frequent wildfires.33 The GGRP includes long-range policies that focus on: social equity, connectivity with community and resources, structural change, cost effectiveness and financing, outreach and education, and effective greenhouse gas reductions. Within the scope of GGRP related to BWP and the procurement and use and greenhouse gas-neutral energy, a number of strategies are being considered. Among these are:
• Electrification of all new construction,
• Conversion of existing natural gas-fuel HVAC and water heating units to electric heat pumps,
• Increased building energy efficiency through rebate and incentive programs, • 100% greenhouse gas-neutral electricity generation by 2040.
32 Burbank Water and Power, https://www.burbankwaterandpower.com/conservation/residential- programs-rebates/green-choice-program
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3.9 RETAIL RATES
As a not-for-profit locally owned public utility, BWP’s electric rates are designed to recover only the cost of providing highly reliable electric service to its customers while maintaining sound financial standing. The costs to serve BWP’s ratepayers include the cost of owning, operating, and maintaining its power plants, power purchases (including renewable energy), transmission and distribution infrastructure, metering and billing systems, customer service and energy efficiency programs, communications equipment, buildings, and transportation fleet. BWP will be modifying its rate structure starting in October 2024. SB 437 requires utilities to discuss transportation electrification customer outreach efforts as well as assess a rate design across the transportation section for electrification. As a result, SB 437 will be addressed in more detail in future IRPs.
3.9.1 Planning Scenario Rate Impact Analysis
Following completion of the modeling for each of the planning scenarios, the results were reviewed and a rate impact analysis was completed by BWP’s Rate Manager.
BWP maintains and regularly updates a financial and demand forecast model that looks forward ten years to help plan power supply needs and rate adjustments. Power supply costs make up a substantial portion of the overall annual electric revenue requirement, but there are also other costs related to operations and maintenance, electricity delivery, customer service, and other utility functions. An increase in power supply costs of 5% does not necessarily require a rate increase of 5%, as the rate increase percentage would depend on the amount of the increase for other utility costs – along with the projected sales volume.
Each IRP scenario has two key drivers that determine what the rate impacts will be: annual power supply costs and annual electric sales in MWh. For other utility costs that make up the annual revenue requirement, the analysis assumes typical escalation factors and cost trends inherent in the 10-year forecast model and extends them out to 2047. For example, the 10-year projection assumes that transmission costs will continue increasing by 2.5% per year for the next ten years and this analysis extended this trend through 2047. For each of the seven scenarios, the underlying cost drivers remain constant throughout the analysis period apart from power supply costs and sales volumes, which differentiate the scenarios.
Table 3-8 below, shows the results of the rate impact analysis for each of the seven scenarios. The analysis used two measures to reflect the impact to electric rates and customer bills. The first was the average annual rate increase needed to reach 200 days cash on hand (DCOH) in the final year of the analysis period (2047). The target of 200 DCOH is the midpoint between 160 and 240 DCOH, which is the range recommended by the BWP Financial Reserves Policy approved in 2023. Setting the DCOH target in 2047 can lead to some interim years prior to 2047 having DCOH values less than the minimum threshold and some years well above recommended levels, but the single value provides a useful measure for comparing the rate impact of each scenario as opposed to a series of varying rate adjustments which may be more realistic but harder to compare across scenarios.
The second measure for comparing customer impacts is the bill increase, expressed as the percent increase from current levels to 2047. The bill increase is calculated by applying the average annual rate increase and compounding it through 2047 (after applying the 8.0% increase for 2025). Thus, if the value for this measure were 158%, then a $100 electric bill today would increase to $258 in 2047 (in nominal terms). The 2047 bill increase can be found in column, “Bill Increase 2047 vs.
Current.”
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Table 3-8 shows average annual rate increase for each scenario (in column “Annual Rate Increase”).
The increases range from a low of 3.91% for Scenario 6, 10% Lower EV & DEV Demand to a high of
9.49% for Scenario 2, Net Zero by 2030. The third column from the left shows the 2047 bill increases. These have the same scenarios for highest and lowest impacts, with bills for Scenario 6, 10% Lower EV & DEV Demand increasing by 151% and those for Scenario 2, Net Zero by 2030 increasing by 694%. As a point of reference, if rates were increased by 2% per year just to keep pace with general inflation, customer bills in 2047 would only be 67% higher than they are today.
The rate increases associated with the IRP are above and beyond the already approved and forecasted rate increases for BWP. For example, we have an approved rate increase of 8% for 2025, so the increase in 2025 would be the approved rate increase of 8%+the rate increase impact from the IRP scenario(s) below. For the Base Case, the increase in 2025 would be 8%+4.03%, for a total of 12.03%.
Table 3-8 Rate Impacts from Planning Scenarios
Scenario
# Scenario Name
Annual Rate Increase
(if contracts are signed
and are available)
Bill Increase 2047
vs. Current
1 Base Case 4.03% 158%
2 Net Zero by 2030 9.49% 694%
3 SB1020+SMR 4.96% 213%
4 SB1020+SMR w/ 50% DEV
&EV Demand 5.57% 256%
5 10% Higher EV & DEV
Demand 3.94% 153%
6 10% Lower EV & DEV
Demand 4.12% 163%
7 New Transmission & PPAs 4.03% 158%
It is important to note that BWP’s financial forecast model is in annual increments, with each year being the BWP fiscal year (FY) running from July to June. The IRP scenarios are in calendar years (CY) from January to December. The analysis assumed that the “current” time period was FY 2023- 24 and calendar year 2024. The Burbank City Council has already approved an 8.0% rate increase to take effect in July of 2024 for FY 2024-25. This 8.0% increase occurs between CY 2024 and CY 2025 in the analysis.
3.9.2 The Ratemaking Process
The ratemaking process is generally composed of three steps: 1) determining the revenue requirement, 2) completing a cost-of-service analysis, and 3) rate design.
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3.9.2.1 Revenue Requirements
BWP’s electric utility revenue requirement is the total amount of revenue it must recover in order to pay for its operations and maintenance expense, pay-as-you-go (PAYGO) capital, debt service coverage, and reserve requirements. This approach to determining the revenue requirement is sometimes referred to as the “cash-needs” approach, which differs from a rate of return or “utility basis” approach common among investor-owned utilities. BWP’s annual revenue requirements are calculated prospectively for five years as part of BWP’s annual financial planning and budget process; however, the revenue requirement is only approved one year at a time by the Burbank City Council.
3.9.2.2 Cost-of-Service
The purpose of a cost-of-service study is to ensure that each customer class is paying its fair share of total system costs by determining what it costs to serve each class. In doing so, it greatly informs the rate design process because rates are often designed to recover specific system costs.
A cost-of-service analysis is used to determine each customer class’s fair share of the annual revenue requirement and to inform rate design. Each customer class’s share of the revenue requirement as determined by the cost-of-service analysis can be referred to as the “class cost of service.” BWP generally completes an electric cost-of-service analysis every five years at which time each class cost of service may be updated. The most recent cost-of-service analysis for the electric utility was completed in 2022.34 BWP has most frequently chosen to use an average or “embedded” cost approach to completing its cost-of-service analyses. An embedded cost-of-service analysis typically involves three steps: 1) functionalization, 2) classification, and 3) allocation. The basis for the analysis is typically a recent year of actual operating results which is called the “test year.”
3.9.2.2.1 Functionalization
Functionalization is the process of categorizing the utility’s operations and maintenance expense and net assets (original cost less depreciation or “book value”) into system functions such as generation, transmission, distribution, and customer service.
3.9.2.2.2 Classification
Classification is the process of classifying costs by function according to how those costs vary. For example, bulk power supply costs tend to vary based on energy throughput, while distribution capacity costs tend to vary based on peak demand. In these cases, bulk power supply costs are classified by the energy classification type while distribution capacity costs are classified by the peak demand classification type. Each classification type describes units of service for all customer classes. Common classification types include energy, demand, customers, and meters.
3.9.2.2.3 Allocation
Allocation is the process of assigning the classified costs to customer classes in proportion to each class’s share of the total units of service for each classification type. For example, all costs that are classified by the energy classification type are allocated among the different customer classes based on each class’s share of the total energy units of service measured in kilowatt-hours. This class cost
34 City of Burbank, Burbank Water and Power, Staff Report, dated June 6 , 2023, https://www.burbankca.gov/documents/20124/0/SR+-+Public+Hearing+for+Rates+Increase.pdf ATTACHMENT 1
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of service is the total cost allocated to each class for each classification type. BWP currently has five major customer classes: residential, small commercial, medium commercial, large commercial, and extra-large commercial. Street lighting is also included as a separate class.
Table 3-9 2022 Class Cost of Service Study Results
Customer Class Cost of Service Results
(%)
Residential 36.6%
Small Commercial 8.5%
Medium Commercial 18.9%
Large Commercial 16.8%
Extra Large Commercial 18.8%
Street Lighting 0.4%
Total 100.0%
3.9.2.3 Rate Design
Once the class cost of service is determined for each customer class, rates can be designed to recover that amount. Rate design may vary between and within the major customer classes depending on, for example, the type of residential customer (standard, lifeline, or electric vehicle owner), or the service voltage (primary or secondary). Rate design may also vary due to differing objectives for certain classes or subclasses and/or due to billing system constrains. A detailed discussion of BWP’s current rates in presented in the Current Electric Rates section below.
3.9.3 Appropriate Price Signals
Beyond ensuring each customer class pays its fair share for operating and maintaining the electric utility, BWP believes its rates should send appropriate price signals to customers to help them understand – and respond to – how the utility’s costs vary overall. Naturally, the more energy customers use, the most costs are incurred. However, when and how customers use more energy greatly impacts which costs are incurred for BWP and how much. BWP believes electric rates should be designed to reflect the impacts of when and how costs are incurred.
3.9.4 Current Electric Rates
BWP currently has five major customer classes: residential, small commercial, medium commercial, large commercial, and extra-large commercial. Residential service includes service for lifeline customers and electric vehicle owners. Lifeline customers are senior and/or disabled customers that are eligible for discounted electric rates. Electric vehicle owners may elect to receive service under BWP’s optional electric vehicle owner rate schedule which offers lower energy rates during off-peak periods. This rate schedule is discussed in further detail below.
BWP’s commercial customers are assigned one of the four commercial classes based on their monthly demand – the maximum instantaneous 5- or 15-minute interval reading per billing period.
Commercial customers are assigned to classes as summarized below.
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Table 3-10 Commercial Customer Classes for Rates
Commercial Class Monthly Demand
Small Less than 20 kVA
Medium Between 20 kVA and 250 kVA
Large Between 250 kVA and 1,000 kVA
Extra Large More than 1,000 kVA
Table 3-11 Types of Charges Applicable to Major Customer Classes Energy Charges Fixed Monthly Charges Demand Charges
Customer
Class
2-Tier
Inclining
Block Energy
Charges*
Time of
Use
Energy
Charges
Customer
Service
Charge
Service
Size
Charge
Demand
Charge
Distribution
Demand
Charge
Reliability
Services
Demand
Charge
Residential X X X
Small
Commercial X X
Medium
Commercial X X X
Large
Commercial X X X X
Extra-Large
Commercial X X X X
*Includes Energy Cost Adjustment Charge (ECAC)
Each customer class is subject to either a “2-part tariff” or a “3-part tariff.” Residential customers and small customers are subject to 2-part tariffs in which they pay a monthly fixed service charge and per-kWh energy charges. Medium, large, and extra-large commercial customers are likewise subject to monthly service and energy charges; however, they are also subject to per-kVA demand charges. Each rate, or “part,” is generally designed to recover specific costs, which are revealed by the cost-of-service analysis.
3.9.5 Energy Charge
All of BWP’s metered customers are subject to per-kWh energy charges, which are inclusive of the energy cost adjustment charge (ECAC). The ECAC is an energy charge that specifically recovers the cost of variable power supply costs including, but not limited to, fuel and purchased power expenses. BWP currently employs two types of energy charges: 2-tier inclining-block and time-of- use.
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3.9.5.1 2-Tier Inclining-Block Energy Charges
Residential service customers, except for those customers that elect the optional electric vehicle rate, are subject to 2-tier inclining-block energy charges. 2-tier inclining-block energy charges offer energy at two inclining or increasing rates. The first, cheaper rate, applies to consumption up to the upper bound of the first “block” or tier. The second, more expensive rate, applies to incremental consumption above the first block or tier. For standard residential customers, the upper bound of the first block is 300 kWh. For residential lifeline customers, the upper bound of the first block is 400 kWh. The purpose of inclining-block energy charges is to encourage conservation, as higher consumption is subject to a higher rate.
3.9.5.2 Time-of-Use Energy Charges
Time-of-Use (TOU) energy charges are energy charges that vary based on the time of day, day of week, month of year, and observance of holidays. Currently, all commercial customers are subject to time-of-use energy charges. This rate schedule is designed to shift energy use from high-cost periods, such as in the evening between 4pm and 7pm, to low-cost periods.
Table 3-12 Time Periods for Time-of-Use (TOU) Rates
Summer Non-Summer
Time Weekday Weekends
& Holidays Weekday Weekends
& Holidays
Midnight to 8am Off Off Off Off
8am to 4pm Mid Off Mid Off
4pm to 7pm On Off Mid Off
7pm to 11pm Mid Off Mid Off
11pm to Midnight Off Off Off Off
Table 3-13 Time Periods for Time-of-Use (TOU) Rates for Residential Electric Vehicle Owners
Time Summer Non-Summer
Midnight to 8am Off Off
8am to 4pm Mid Mid
4pm to 7pm On Mid
7pm to 11pm Mid Mid
11pm to Midnight Off Off
The summer season is from June 1 through October 31, and the non-summer season is from January 1 through May 31, and November 1 through December 31. Observed holidays are New Year’s Day (January 1), Presidents’ Day (third Monday in February), Memorial Day (last Monday in May), Independence Day (July 4), Labor Day (first Monday in September), Veterans Day (November 11), Thanksgiving Day (fourth Thursday in November), and Christmas (December 25).
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BWP believes that time-of-use rates are a useful demand side management tool for reducing overall system costs. TOU rates can encourage customers to change their consumption patterns such that they reduce the utility’s need to procure energy and capacity during the most expensive periods of the year. TOU rates can also encourage customers to shift their consumption to periods of the year when energy (often renewable) and capacity is in excess. These changes in consumption patterns can be beneficial to both the customer and BWP in terms of cost savings.
TOU rates will become an increasingly important tool for BWP as it continues to integrate more intermittent renewable resources. BWP believes in the potential for residential customers to respond to TOU rates, lowering their bills and decreasing the utility’s cost to serve customers on a long-term basis.
3.9.6 Fixed Monthly Charges
Fixed monthly charges are generally designed to recover the cost of customer service and billing.
For residential customers, they may also take the form of a service size charge which is designed to recover secondary distribution system costs.
3.9.6.1 Service Size Charge
The service size charge recovers customer-specific system costs, including the cost of wires and transformers and is determined by the customer’s electrical panel size and the number of homes or buildings sharing a single transformer.
Customers are categorized as follows for service size charges:
• Small: Service Location with two or more meters per service drop and does not meet the definition of Large; typically multifamily residential. • Medium: Service location with one meter per service drop and does not meet the definition of Large; typically single family residential.
• Large: Service with panel size greater than 200A.
3.9.6.2 Customer Service Charge
All customers are subject to a fixed monthly customer service charge with the exception of residential lifeline customers. This charge ranges from $12.07 (FY 2023-24) for residential basic service rate customers to $122.51 (FY 2023-24) for extra-large commercial customers. Note that for commercial customers, the monthly customer service charge may vary depending on whether the customer is unmetered, has single-phase service, or three-phase service.
3.9.7 Demand Charges
Demand charges are typically designed to recover capacity cost associated with transmission, distribution, and/or generation. The simple demand charge, which is designed to recover all of these costs only applies to medium commercial customers on a per-kVA basis. Two separate demand charges apply to large and extra-large commercial customers as discussed below.
3.9.7.1 Demand Charge – Medium Commercial
Medium commercial customers are subject to a simple demand charge, which is designed to recover the cost of distribution, transmission, and generation capacity. This charge is measured on a per-kVA basis.
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3.9.7.2 Distribution Demand Charge
The distribution demand charge is a per-kVA demand charge that applies to both large and extra- large commercial customers. It is designed to recover distribution capacity costs. It is measured on an all-hour or “non-coincident peak” (NCP) basis, meaning that the demand reflects the maximum interval read of all reads during a given billing period. This is in contract to a “coincident peak” (CP) basis for demand measurement, which only measures demand during a subset of monthly hours when the entire system is believed to peak.
3.9.7.3 Reliability Services Demand Charge
The reliability services demand charge is also a per-kVA demand charge that applies to both large and extra-large commercial customers. It is designed to recover generation capacity or “peaking costs.” It is also measured on an NCP basis.
3.9.8 Electric Rate Comparison
BWP’s residential electric rates remain among the lowest in the region including other municipal utilities, as well as investor-owned utilities.
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Figure 3-18 Residential Bill for Average Single-Family Monthly Consumption35
All fees and charges are brought before the City Council for approval on an annual basis.
BWP has also developed short-term as well as long-term energy procurement strategies to reduce price risks and volatility. These strategies are monitored by BWP management using the Energy Risk Management Policy, originally adopted in 2004 and amended in April 2009 and December 2017. Under the Energy Risk Management Policy, the Risk Oversight Committee was formed and meets regularly to discuss the power supply risks, market conditions, and transactions needed to maintain reliable and affordable rates for Burbank.
35 Burbank Water and Power, FY 2023-23 & FY 2024-25 Proposed Budget, April 6, 2023 presentation, https://www.burbankwaterandpower.com/images/budget/april-2023 -budget- files/Proposed%20Utility%20Fiscal%20Year%202023-24%20and%202024- 25%20Budgets%20for%20BWP%20Board.pdf
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3.10 TRANSMISSION SYSTEM RESOURCES
Power transmission is the delivery of energy from its place of generation, purchase, or sale to the distribution system that takes it to meet demand. Burbank has ownership in or contractual entitlements to numerous regional transmission facilities. Transmission lines bring in electric energy to meet demand and BWP uses its contractual and ownership rights to deliver the electricity it generates and purchases to customers in Burbank.
Figure 3-19 Burbank’s Existing Firm Transmission
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3.10.1 History of BWP’s Transmission Rights
The utility business has changed tremendously over the years. Historically, BWP has worked with the SCPPA and other entities to participate in major new transmission projects so that BWP can move power from generation facilities, or other entities, throughout the western United States.
Over time, BWP has focused on engaging in new transmission contracts and on finding advantageous power resources or supplies that help keep electric rates low. SCPPA was formed in 1980 to help finance these transmission projects for municipal utilities to leverage economies of scale and keep costs low. BWP worked with other participants through SCPPA to jointly build major transmission lines such as Mead-Phoenix and Mead-Adelanto. Since BWP helped build those projects, it has rights to schedule and move power over those transmission lines.
These transmission rights are adequate to serve BWP’s current energy needs. They also enable BWP to participate in the wholesale power market. However, as more renewable energy is added and/or replaced, it may be necessary to acquire additional transmission service or participate in the development of new transmission lines.
BWP can also enter into swaps and other agreements to use a third party’s transmission assets. In those cases, BWP might purchase renewable energy from a distant power plant and swap it to a third party, which would then deliver substitute energy to BWP from closer to Burbank. In that sort of arrangement, the third party also absorbs the intermittency of that renewable energy source, if any. Arrangements like those are another method of acquiring resources in the most cost-effective manner.
3.10.2 Planned Transmission Upgrades and Additions
3.10.2.1 Southern Transmission System
The Southern Transmission System (STS) currently consists of a high voltage direct current (HVDC) line from the IPP site near Delta, Utah to Adelanto, California. This line currently carries the baseload output of the IPP coal plant. As discussed in Section 2.5.4, the IPP coal plant is scheduled for retirement in 2025 and will be replaced with natural gas-fired generation. BWP’s new contract with IPP begins in 2027 and was entered into, in part, to secure future transmission rights on the STS. Use of those STS transmission rights will be key to accessing additional renewable energy resources located outside of Burbank. Prior to the renewal of the IPP contract in 2027, BWP will maintain a 4.49% share of the STS capacity, equal to 107.95 MW. Per the terms of the contract renewal, from 2027 through 2077, BWP will have a 4.2% share of the transmission capacity on the STS, equal to 101.4 MW.
3.10.2.2 Transmission Expansion Considered Within the IRP The production cost model created for the Base Case in this IRP was optimized around the existing transmission system that serves Burbank. As such, no transmission expansion was either “hard- wired” into the model or included as a possible expansion project for the model to choose. In the Base Case, all demand on the BWP system through 2047 could be met with the transmission capacity that already exists. However, it should be noted that by the end of the planning period, that the existing transmission capacity was at times fully utilized. Demand growth beyond what was forecast for 2047 could result in the need to acquire additional transmission rights or to physically expand the capacity of the transmission system that delivers power to Burbank. Where transmission expansion was included within the other planning scenarios, it has been noted. See Section 2.6 for scenario specific information.
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Due to the long development periods necessary for such acquisitions or upgrades, BWP will continue to monitor its transmission margins on an ongoing basis to ensure future shortfalls do not occur.
3.11 DISTRIBUTION SYSTEM RESOURCES
BWP provides Burbank with electrical service through a distribution network which includes electric substations, sub-transmission lines, distribution lines, and transformers. An electric power distribution system is the final stage in the delivery of electric power that carries electricity to individual customers. With its current high reliability, BWP’s distribution system is well-positioned for the future.
A large portion of Burbank’s electric infrastructure was initially constructed from the 1940s through the 1960s to serve the typical loads of that era, with 4 kV service. The infrastructure has since been expanded and updated. Commercial developers supported and assisted in funding the expansion of the BWP system, beginning the transition from a 4 kV system to the more reliable 12 kV service and from large air-insulated electric substations to smaller, more modern, gas-insulated substations. Updating the distribution lines from 4 kV to 12 kV allowed BWP to deliver three times as much energy, reducing power losses in the system, and improving reliability.
With the investment in more reliable 12 kV substation capacity, including the San Jose, Golden State, Keystone, Hollywood Way, Burbank, and Ontario Substations, BWP has been steadily transferring customers from the 4 kV service to the more reliable and efficient 12 kV service.
The 12 kV substations are primarily served from the 34.5 kV systems. Future substations will be served from the 69 kV system where possible, allowing BWP to realize additional efficiency and reliability. While BWP has made significant progress in the last 20 years, several 4 kV substations and associated distribution systems remain.
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Figure 3-20 Burbank’s Existing Distribution System
BWP’s distribution system consists of the following:
• A service area of approximately 17 square miles
• Approximately 33 miles of 69 kV sub-transmission
• Approximately 44 miles of 34.5 kV sub-transmission
• Thirteen distribution substations, two customer substations, and four switching stations • Approximately 185 miles of 4 kV distribution
• Approximately 151 miles of 12 kV distribution
• Approximately 10,800 poles
• Approximately 5,800 distribution transformers
Over the decades, the residential and small commercial load has grown, primarily driven by increasing population, increasing air conditioning installations, larger homes, and the addition of the electronic devices and appliances that provide modern conveniences and creature comforts.
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reducing air pollution and GHG emissions. These efforts are consistent with BWP’s goals of reliability, affordability, and sustainability. BWP has taken significant steps to reduce losses among all its major distribution system elements.
BWP recognizes that the expansion of customer-owned distributed energy resources like rooftop solar will likely have more significant effects on the distribution system in the future.
3.11.1 Anticipating Customer DER Developments
BWP recognizes that larger quantities of customer-owned distributed energy resources (DER), such as battery storage and rooftop solar, can impact the reliability of the distribution system. The impacts to reliability could include, but are not limited to, circuit loading, system protection, voltage excursions, power quality, substation equipment limits, and operational flexibility. While BWP does not currently have large penetrations of DER that yield these types of reliability issues, BWP will continue to monitor its DER applications and perform capacity studies, as necessary, to ensure reliability of the electric distribution system. In addition, because of its grid modernization efforts, BWP monitors distribution system voltages and circuit loading using data analytics from its advanced metering infrastructure.
Furthermore, BWP is also mindful of the lower levels of fault current produced by non-rotating sources and anticipates that further studies and additional protective relaying technology may be required to account for these lower levels of fault current. Lastly, recognizing the potential future need for battery storage within Burbank, BWP is considering the use of land at decommissioned substations for the installations of energy storage facilities as strategic, cost-effective locations for connecting energy storage to BWP’s sub-transmission and distribution systems.
BWP has taken steps to support a larger penetration of sustainable, customer-owned DER. In 2016, BWP updated its distributed generation interconnection agreement for distributed generation above one megawatt to reflect the City’s policy of meeting additional energy demands from renewable energy sources instead of fossil-fuel generation.
Customer-owned rooftop solar has both benefits and drawbacks. It is environmentally friendly and does not require transmission to reach customers. On the other hand, it is an intermittent resource – it only generates electricity when the sun is shining and virtually no generation occurs at night or in substantial cloud cover. This swing in generation not only presents a challenge to electric grid reliability, but also influences rate design.
In the early days of solar PV technology and when the cost of installation was high, BWP offered rebates through the Solar Support Rebate program. As solar PV prices have declined and customer decisions to install rooftop solar became independent of rebates, BWP discontinued its rebate program. However, since the 30% Federal Investment Tax Credit makes purchasing solar and/or battery systems more accessible, Burbank continues to see new installations of rooftop solar capacity.
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Figure 3-21 Distributed Generation Installations36
Solar generation will increasingly affect BWP’s resource planning. BWP must be prepared to deal with the impacts that distributed solar generation has on BWP’s system in the middle of the day when solar power is being generated. Properly balancing the increase of this intermittent power source to BWP’s system will be important for maintaining the system’s high reliability.
3.11.2 Grid Modernization
BWP’s grid modernization has enhanced Burbank’s distribution system with advanced technology including digital meters, energy storage, renewable energy sources, and other improvements. The new meters and devices allow for sending and receiving meter data or device status to the utility without any manual intervention such as meter reading, having customers calling in meter reads, or
36 Burbank Water and Power, Monthly Operations Report, October 2023.
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physically inspecting electrical equipment. BWP uses this enhanced data to provide numerous benefits to customers, and for operational and energy efficiency as well.
This data, in turn, has been used to make targeted improvements in BWP’s distribution system to the benefit of BWP’s customers. By applying state-of-the-art analytic tools, BWP can analyze and better understand load growth, circuit loading, and power quality. BWP can analyze the incoming meter data and develop strategies to improve system performance and operational characteristics.
After upgrading its software tools in the future with an advanced distribution management system (ADMS), BWP will be able to use this data to manage system demand and optimize system performance. This data has also helped with right-sizing of transformers and improving system reliability during times of high load.
At the same time, the data allows BWP’s customers to become more informed about their energy consumption and empowers them to change how they consume electricity. BWP delivers a personalized report to its customers that compares their energy consumption with the energy consumption of their neighbors.
3.12 LOCALIZED AIR POLLUTANTS AND DISADVANTAGED COMMUNITIES Many disadvantaged communities identified by the State of California in the Burbank area are located along the route of Interstate Highway 5. Interstate 5 and Highway 134 are sources of significant air emissions from gasoline and diesel-fuel vehicles. As transportation transitions to electric vehicles, the disadvantaged communities adjacent to the Interstate will benefit from reduced air pollution.
Potential sources of air emissions in or near the disadvantaged communities within the purview of BWP are the Magnolia, Lake One, and Olive 1 and 2 natural gas-fired generating plants on the BWP campus next to the Interstate highway which, in the early 2000s, replaced older, less environmentally friendly, and less efficient units that caused significantly more pollution than Magnolia and Lake One. As a result, emissions from power generating units the BWP campus have decreased significantly since that time.
4 Energy Efficiency Analysis
BWP manages a comprehensive portfolio of efficiency programs for residential and commercial customers focusing on energy efficiency, peak load reduction, transportation electrification and greenhouse gas savings. These programs are described in Section 2.4.2.
With the approval of the Burbank City Council, BWP has established an annual goal of achieving energy efficiency savings equal to 1% of electric sales, and peak demand savings equal to one percent of total grid demand. In practice, these goals have been equal to approximately 10,000 MWh of consumption savings and demand savings of slightly less than 3 MW. Over the past four fiscal years, BWP has reported actual energy efficiency savings as listed in Table 4-1 below.
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Table 4-1 Energy Efficiency Savings – Actuals vs. Goals Actuals Goals
Fiscal Year
Demand
Savings
[MW]
Consumption
Savings
[MWh]
Demand
Savings
[MW]
Consumption
Savings
[MWh]
FY 2019-2020 2.50 7,341 3.02 10,605
FY 2020-2021 1.23 4,696 2.83 10,194
FY 2021-2022 1.65 6,747 2.92 10,172
FY 2022-2023 1.79 5,450 2.92 10,172
5 Public Participation
BWP develops each IRP with input from the public. Public participation is vital for BWP, in order to understand the implications on the IRP to different ratepayers. BWP’s robust IRP website provides details on the public process. The IRP website was updated through every step of the IRP process.
The website can be found here: https://www.burbankwaterandpower.com/2024-irp
5.1 STAKEHOLDER TECHNICAL ADVISORY GROUP (STAG)
In December 2022, the STAG was selected by BWP. The STAG represents a diverse group of ratepayer and city representatives.
Table 5-1 STAG Meeting Schedule
Meeting Date STAG Discussion
1 12/15/2022 IRP 101, IRP Survey and Roles and Responsibilities of the STAG 2 01/26/2023 Power Plant 101, Resource Planning 101, Energy Control Center 101 and Burbank Solar and Storage Projects update
3 02/23/2023 Natural Gas and Energy Price update, Renewable Portfolio Standard 101 and IPP 101
4 03/23/2023 Black and Veatch Update and Power Supply Update 5 04/27/2023 Magnolia Power Project (MPP) Tour, Survey Update and Power Supply Update
6 06/21/2023 Black and Veatch Base case, Survey Update and Power Supply Update 7 08/07/2023 IRP Update and Scenario Discussion
8 08/17/2023 Scenario Discussion, Scorecard Development and Survey Update 9 10/12/2023 Final Survey Results, Scorecard Results, Scenario Overview and Preferred Scenario Selection
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5.2 COMMUNITY STAKEHOLDER MEETINGS
BWP hosted four community stakeholder meetings to discuss the IRP with the community at large.
Below is a list of the community meeting and topics discussed. The details on each community meeting can also be found on the BWP IRP website.
Table 5-2 Community Stakeholder Meeting Schedule
Meeting Date Community Stakeholder Discussion
1 04/20/2023 IRP 101, Resource Planning 101, IRP Survey Discussion and Base Case and Scenario Discussion
2 07/13/2023 Resource Planning Update, IRP Survey Results and Black and Veatch Assumptions Update and Base Case Discussion
3 08/10/2023 IRP 101 Discussion, Survey Discussion and Base Case and Scenario Update 4 10/26/2023 Final Survey Results, Scorecard Results, Scenario Overview and Preferred Scenario Selection
5.3 IRP SURVEY
In December 2022, BWP posted the IRP survey on the IRP website. A link to the survey was also distributed via billing inserts and the monthly BWP newsletter, “Currents.” 952 responses to the survey indicated a preference for high reliability and affordable rates. The results of the IRP survey are included as Attachment 2 to this report.
5.4 BWP BOARD AND CITY COUNCIL UPDATE
Staff presented an update to the IRP, to the BWP Board monthly. Staff provided an update to City Council on the IRP on April 25, 2023 and July 25, 2023. 6 Process for Updating the IRP
In accordance with the requirements of PUC Section 9621, BWP will update its IRP at least once every five years. The 2019 IRP was approved by the Burbank City Council in December 2018 and was submitted to the CEC in April 2019. To meet the five-year update requirement, BWP kicked off its IRP process in December 2022 and worked throughout 2023 to engage with stakeholders and the public as it developed the inputs and assumptions as well as the scenarios that would drive this analysis.
7 Attachments
Attachment 1: BWP Renewable Energy Resources Procurement Plan & Enforcement Program Attachment 2: IRP Survey Results
Attachment 3: List of Acronyms
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2024 BWP IRP
Attachment 1
BWP Renewable Energy Resources
Procurement Plan & Enforcement Program
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BURBANK WATER AND POW
ER
RENEWABLE ENE
RGY RESOURCES PROCUREMENT PLAN &
ENFORCEMENT PROGRAM
(VERSION 3)
DECEMBER 2021
TABLE OF CONTENTS
PURPOSE ............................................................................................................. 1 TARGET QUANTITIES OF RENEWABLE ENERGY RESOURCES ..................... 2 ELIGIBLE RENEWABLE ENERGY RESOURCES ................................................ 3 CURRENT RENEWABLE RESOURCES AND PROGRESS TO SB 100 TARGET ............................................................................................................................... 4 BWP PROCUREMENT PROCESS ....................................................................... 5 RENEWABLE PORTFOLIO REQUIREMENTS ..................................................... 6 BWP RPS COMPLIANCE TO DATE AND PLANNED COMPLIANCE WITH LAW8 ENFORCEMENT PROGRAM ................................................................................ 9 VERSIONS ............................................................................................................ 9
PURPOSE
To fulfill unmet long-term generation resource needs, each publicly owned electric utility (POU) governing board must adopt and implement a renewable energy resources procurement plan pursuant to § 399.30 of the Public Utilities Code (PUC) that implements a 60% renewable resource procurement target by December 31, 2030 as required by S enate Bill 100 (SB 100), passed into law on September 10, 2018.
The regulati
ons related to the procurement of renewable resources for local publicly owned electric utilities are established in Article 16 (commencing with section 399.11) of Chapter 2.3 of Part 1 of Division 1 of the PUC. The California Energy Commission (CEC) establishes the regulatory procedures for publicly owned utilities in conformance with the requirements in the PUC.
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This docume
nt supplants Burbank’s October 2012 RPS (Renewal Portfolio Standard) Procurement P lan and Enforcement Program to procure 33% by December 31, 2020 by restating it to continue procurement of eligible renewable resources to at least 60% of the electric utility’s annual retail sales by December 31, 2030 and to remain at or greater than 60%, post 2030.
TARGET QUANTITIES OF RENEWABLE ENERGY RESOURCES
Consistent with § 399.15 of the PUC, Burbank Water and Power (BWP) shall continue procurement of eligible renewable resources consistent with the requirements in order to achieve a sustained level of 60 percent of its annual retail energy sales by December 31, 2030. Energy from eligible renewable sources will be procured to meet the following targets in the indicated compliance periods. • Compliance
Period 4 - January 1, 2021 - December 31, 2024. BWP will procure eligible renewable energy products within the period sufficient to meet the sum of 35.75% of its 2021 retail sales, 38.50% of its 2022 retail sales, 41.25% of its 2023 retail sales, and 44% percent of its 2024 retail energy sales.
• Compliance
Period 5 - January 1, 2025 - December 31, 2027. BWP will procure eligible renewable energy products within the period sufficient to meet the sum of 46% percent of its 2025 retail sales, 50% percent of its 2026 retail sales, and 52% percent of its 2027 retail sales. • Compliance
Period 6 - January 1, 2028 - December 31, 2030. BWP will procure eligible renewable energy products within th e period sufficient to meet or exceed the sum of 54.67% of its 2028 retail sales, 57.33 % of its 2029 retail sales, and 60% percent of its 2030 retail sales. • Compliance
Periods 7 and beyond are three years in duration. BWP shall maintain procurement of eligible renewable energy products within each additional period sufficient to meet an average of 60% or greater of its retail sales in each compliance period as required by law
Consistent
with regulations, BWP is not required to demonstrate a specific quantity of procurement in any of the intervening years between 2021 up to and including 2030, however, BWP must demonstrate p rocurement equal to the compliance period target. BWP will submit its annual and compliance period compliance reports, as required under the California Energy Commission (CEC).
Retail sales m
ay exclude sales to customers taking service under the optional BWP Green Choice Program option or any shared renewable generation program. Sales Attachment 1: BWP Renewable Energy Procurement Plan & Enforcement Program-2 ATTACHMENT 1
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to retail cus
tomers taking Direct Access Service, energy consumption by BWP, electricity used by BWP for water pumping, and electricity produced for onsite consumption under (self-generation) that was not sold to the customer by B WP, shall not be included in this definition of Retail Sales.
For a c
ustomer participating in BWP’s Green Choice Program option or any shared renewable generation project, if the renewable energy is excluded from the calculation of Retail Sales, the Portfolio Content Category (“PCC”) 1 Renewable Energy Credits (“RECs”) associated with the electricity credited to such customer under the program will not be used by B WP for compliance with state mandated RPS procurement requirements . The RECs will be retired on behalf of the participating customer, and may not be further sold, transferred, or otherwise monetized for any purpose. To the extent possible, the electricity products excluded from retail sales will be procured by BWP from eligible renewable energy resources that are located in close proximity to the BWP service territory.
ELIGIBLE RENEWABLE ENERGY RESOURCES
Renewable energy resources procured to comply with this Compliance Plan can be located anywhere along the high-voltage interconnected transmission systems known together as the Western Interconnection and shall meet the requirements defined in the Renewable Portfolio Standard (RPS) Eligibility guidebook published by the CEC in effect at the time the resource was procured. As of October 2021, this document is in its 9th edition.
In gener
al, renewable energy resources allowed are from carbon neutral, and carbon free resour ces. T he following types are examples of what constitute “eligible” resources: biomass, biomethane, solar thermal, solar photovoltaic, wind, geothermal, fuel cells using renewable fuels, low impact small hydroelectric generation, digester gas, municipal solid waste, landfill gas, ocean wave, ocean thermal, tidal current, or renewable distributed generation on the customer s ide of the meter.
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CURRENT RENEWABLE RESOURCES AND PROGRESS TO SB 100
TARGET
Burba
nk has a diverse portfolio of long term resources. The last contract BWP entered into was with EDF, which came online in 2021. The majority of these contracts were done with the assistance of the Southern California Public Power Authority (SCPPA) and partnering with other SCPPA affiliated public utilities.
Name Resource
Type
MW Start
Date
End
Date
Copper Mountain Solar 40 MW 2012 2033
Milford Wind 10 MW 2009 2029
Pebble Springs Wind 10 MW 2009 2027
Tieton Small Hydro 6.8MW 2009 NA
Pleasant Valley/Wyoming
Wind
Wind 5 MW 2006 2022
Don A. Campbell Geothermal 2.49
MW
2013 2033
Ameresco Landfill Gas 1.7
MW
2010 2026
Valley Pumping Small Hydro 550
kW
2002 NA
EDF Solar 22 MW 2021 2046
*Note: REC+Index refers to paying a set REC price plus market price for the energy.
The char
t below provides BWP’s progress towards compliance with SB 100. BWP plans to procure at least two additional long- term contracts by the end of 2023.
BWP will also seek to secure PCC 2 and PCC 3, on an annual basis, in order to mitigate costs.
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BWP PROCUREMENT PROCESS
BWP solicits a majority of its long- term renewable resources through open Requests for Proposals (RFPs) conducted by its joint powers authority, SCPPA .
This allows BWP (and other SCPPA members) to purchase the output of portions of multiple diverse projects and gain economies of scale, rather than limit the projects that they would be capable of participating in due to the comparatively small demand of most of the individual utilities.
Sinc
e BWP is part of the Los Angeles Balancing Authority, BWP aims to secure a majority of it s renewable contracts, where transmission is available and already contracted for. BWP will secure resources in diverse location, with variable term lengths and ultimately, on a least-cost and best-fit basis.
BWP will d
ivide its outstanding RPS procurement between base-load and peaking renewable resources and complying with the PUC. BWP will also seek products with energy pricing tied to electricity market indices as well as fixed- priced. The SCPPA RFPs are considered an open and “rolling” solicitation, generally issued in January, with responses accepted through December of each year. The SCPPA RFP solicits proposals for power purchase agreements with and without ownership options, and also invites energy storage and other innovative proposals. BWP initially screens prospective renewable resource proposals received through SCPPA and through direct contact with renewable project developers based on the levelized offer price ($/MWh) for resources with a project size and proposed delivery period that matches BWP’s procurement targets. For larger projects, joint 33% 36% 39% 41% 44% 46% 50% 52% 55% 57% 60%
0%
10%
20%
30%
40%
50%
60%
70%
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
BWP RPS NEEDS
PCC 0 PCC 1 PCC 2 PCC 3
PLANNED PCC 1 PLANNED PCC 2 PLANNED PCC 3 % RPS REQUIREMENT Attachment 1: BWP Renewable Energy Procurement Plan & Enforcement Program-5 ATTACHMENT 1
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participati
on with other SCPPA members may be desirable to obtain the best project economics and contract terms.
RENEWABLE PORTFOLIO REQUIREMENTS
The renewable energy generated by a ll renewable resources is tracked by associating each megawatt -hour of energy generated to a unique identification number, called a REC. The RECs are used to help ensure there is no double counting, and that each unit of energy generated by a renewable resource can only be claimed once by any load serving entity.
In conf
ormance with §399.16 of the PUC, the RECs associated with the output of the resource are categorized as three types and named in regulation maintained by the CEC for POU as Portfolio Content Categories.
The Por
tfolio Content Category (PCC) of each REC is not assigned to a type of resource, rather they are differentiated by how the utility can use them to meet the requirements of law and how the electricity associated with the REC affected the day-to-day operation of the Western Interconnection . For example, a REC associated with energy generated in the past is in a different PCC than a REC associated with energy being generated in real -time with respect to how a utility obtained the RECs and/or any energy associated with it. BWP, and all other compliance entities under the law, have met their renewable resource procurement requirements through the procurement of renewable energy through all three PCC’s i n order to efficiently integrate renewable resources against their native electric load requirements. BWP will continue to use all three PCC’s as provided in order to meet renewable resources to 60% of retail load by December 31, 2030 as cost effectively as possible.
The thr
ee Portfolio Content Categories are:
• PCC 1 - Directly Scheduled: A REC associated with a certified renewable resource AND the energy from the same resource, bundled together and procured, at the same time , in real -time. The eligible renewable energy resource must have a first point of interconnection with a California balancing authority or are scheduled into a California balancing authority without substituting electricity from another source.
• PCC 2
- Firmed and Shaped: A REC associated with the energy from a certified renewable resource, that was generated in the past, AND is bundled together with the energy from a different another resource, procured at the same time, in real-time.
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• PCC 3 - Unbundl
ed RECs: A REC associated with the energy from a
certified renewable energy resource, that was generated in the past, purchased with zero associated energy. In this case the REC is unbundled from the energy and sold separately
There i
s also a PCC 0, which refers to resources procured prior to June 1, 2010.
These resources were procured before the formal RPS regulations and are considered “grandfathered.” The total RPS requirement (the % of retail sales that needs to be renewable), minus the PCC 0 resources that count in full, will result in a “Net” RPS Requirement, against which the other PCC requirements will apply (Net Procurement Requirement).
• Exam
ple of how a PCC 0 resource impacts the Net Procurement Requirement:
o Using the following information for a given calendar year:
Description Numerical Example
Retail Sales 100 Gigawatt hours(GWh)
PCC 0 25 GWh
RPS % Requirement 50%
Total GWh of PCC 1-3 RPS 100 GWh Retail-25 GWh PCC 0= 75 GWh. PCC 1-3 requirements apply to the
remainder of the 75 GWH, based on 50%
RPS
RPS Needs= 75 GWh* 50%= 37.5 GWh
which need to meet the PCC rules
Consi
stent with §399.13, at least 65 percent of the procurement applied towards any compliance period after January 1, 2021 shall be from contracts of 10 or more years in duration or through ownership agreements for the renewable energy resource. This Long-term Requirement (LTR) is discussed in detail under the CEC RPS Enforcement Regulations , titled “Modification of Regulations Specifying Enforcement Procedures for the Renewable Portfolio Standard for Local Publicly Owned Electric Utilities,” which went into effect on July 12, 2021.
Cons
istent with t he limits provided for in §399.16(c) , the amount of renewable energy from each Portfolio Content Category that BWP can apply in each compliance period is as follows:
• PCC 1 - not less than 75 percent.
• PCC 2 - not more than 15 percent
Attachment 1: BWP Renewable Energy Procurement Plan & Enforcement Program-7 ATTACHMENT 1
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• PCC 3 - not
more than 10 percent
A st
reamlined table of all RPS procurement requirements is listed below.
Burbank Water and Power
California Energy Commission RPS Procurement Requirements by Calendar Year
California RPS
Mandatory
Procurement
Requirement
Compliance
Period 4
Compliance
Period 5
Compliance
Period 6
Compliance
Period 7+
1/1/2021-
12/31/2024
1/1/2021-
12/31/2027
1/1/2028-
12/31/2030
3 calendar
year blocks
44% RPS by
12/31/2024
52% by
12/31/2027
60% RPS by
12/31/2030
60% RPS
PCC 1 Minimum ≥ 75% of Net Procurement Requirement
PCC 2 Maximum ≤ 25% of Net Procurement Requirement
PCC 3 Maximum ≤ 10% of Net Procurement Requirement
LTR At least 65% of all RPS contracts must be long-term in duration (at least 10 years in duration)
CITY COUNCIL DISCRETION AND COST LIMITATIONS
The Burbank City Council has the responsibility and discretion to define and establish a cost limitation if it determines that committing to a new long-term resource, for the purposes satisfying BWP’s procurement requirements under the law, would result in adverse cost impacts to the ratepayers of Burbank . Burbank Council reserves the authority to modify or delay compliance with the procurement targets set forth herein.
If Bur
bank City Council exercises such authority, it shall do so at a properly noticed public meeting consistent with the following:
• Counci
l shall establish additional reporting requirements to satisfy future procurement requirements consistent with §399.15(b)(6). • Counci
l shall not waive enforcement unless all necessary reasonable efforts have been taken to achieve compliance §399.15(b)(7).
BWP RPS COMPLIANCE TO DATE AND PLANNED COMPLIANCE WITH LAW Consistent with §399.15, occurrence of the following items , as well as others that are allowed under §399.15, are instances where City Council may delay timely procurement sufficient to reach 60% of retail sales by December 31, 2030 (or any interim target).
• Inadequate Transmission Capacity: BWP has limited transmission rights to market hubs and scheduling points within the Western Interconnection and Attachment 1: BWP Renewable Energy Procurement Plan & Enforcement Program-8 ATTACHMENT 1
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cannot on its ow
n finance the development of high- voltage transmission projects to new resource developments. Burbank’s ability to access new eligible renewable energy resource developments across the Western United State are constrained. A delay may apply if BWP has inadequate transmission capacity despite taking reasonable measures under its control to develop or otherwise obtain transmission for potential eligible renewable energy resources,
• Permitting or Interconnection delays . Delays affect ing the completion , interconnection or operating date of new eligible renewable power projects or result in an inadequate supply of such projects beyond the control of the utility.
• Unanticipated Curtailment or unforeseeable circumstances. Unexpected and sudden loss of a resource.
• Unanticipated increase in retail sales due to transportation electrification. In the event that adoption of transportation electrification through 2030 greatly exceeds current load estimates, BWP may not be able to meet compliance period targets without disproportionate rate impacts.
ENFORCEMENT PROGRAM
The General Manager of Burbank Water and Power shall have the duty an d responsibility of executing the Renewable Procurement Plan outlined above and ensuring that is done in full compliance with the law and any applicable regulations issued there under.
It is BWP
’s practice to discuss Burbank’s renewable energy portfolio with the public during the annual budget meetings that take place with Burbank City Council and Utility Board. BWP shall maintain the practice of reporting on its renewable procurement progress during these public meetings.
The General Mana
ger shall inform the City Council at a separate public meeting if they determine that BWP will not meet a procurement target set out above. The General Manager shall present a plan to bring the utility back into compliance at the same meeting for City Council’s consideration for adoption.
VERSIONS
• VERSION 1: Initially Adopted – November 22, 2011
o New mandate to comply with SBX1 2
• VERSION 2: Amended – October 30, 2012
o Update on renewable energy contracts
• VERSION 3: Amended – December 14, 2021
o Show compliance with SB 100
o Incorporate RPS Regulations as approved on July 12, 2021 Attachment 1: BWP Renewable Energy Procurement Plan & Enforcement Program-9 ATTACHMENT 1
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2024 BWP IRP
Attachment 2
IRP Survey Results
ATTACHMENT 1
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Attachment 2: IRP Survey-1
ATTACHMENT 1
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Attachment 2: IRP Survey-2
ATTACHMENT 1
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Attachment 2: IRP Survey-3
ATTACHMENT 1
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Attachment 2: IRP Survey-4
ATTACHMENT 1
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Attachment 2: IRP Survey-5
ATTACHMENT 1
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Attachment 2: IRP Survey-6
ATTACHMENT 1
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Attachment 2: IRP Survey-7
ATTACHMENT 1
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Attachment 2: IRP Survey-8
ATTACHMENT 1
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Attachment 2: IRP Survey-9
ATTACHMENT 1
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Attachment 2: IRP Survey-10
ATTACHMENT 1
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Attachment 2: IRP Survey-11
ATTACHMENT 1
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Attachment 2: IRP Survey-12
ATTACHMENT 1
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Attachment 2: IRP Survey-13
ATTACHMENT 1
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2024 BWP IRP
Attachment 3
List of Acronyms
ATTACHMENT 1
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Attachment 3: List of Acronyms-1
List of Acronyms
AAEE Additional Achievable Energy Efficiency
AAFS Additional Achievable Fuel Substitution
AATE Additional Achievable Transportation Electrification ADMS Advanced Distribution Management System
AMI Advanced Metering Infrastructure
APPA American Public Power Association
BA Balancing Authority
BAASA Balancing Authority Area Services Agreement
BESS Battery Energy Storage Systems
BUGL Burbank-Glendale Planning Area
BUSS Burbank Utility Service Subsidy
BWP Burbank Water and Power
BYOD Bring Your Own Device
CAES Compressed Air Energy Storage
CAGR Compound Annual Growth Rate
CAISO California Independent System Operator
CAPEX Capital Expenditure
CARB California Air Resources Board
CCS Carbon Capture and Sequestration
CDD Cooling Degree Days
CEC California Energy Commission
CP Coincident Peak
CY Calendar Year
DAC Disadvantaged Community
DCOH Days Cash On Hand
DEED Demonstration of Energy and Efficiency Development DER Distributed Energy Resources
DERMS Distributed Energy Resource Management System
DEV Development (specifically, demand related to new development) DR Demand Response
DSGS Demand Side Grid Support
DSM Demand-Side Management
ECAC Energy Cost Adjustment Charge
EDAM Extended Day-Ahead Market
ATTACHMENT 1
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Attachment 3: List of Acronyms-2
EE Energy Efficiency
EIA Energy Information Administration
EIM Energy Imbalance Market
ESG Environmental, Social, and Governance
EV Electric Vehicle
FY Fiscal Year
GGRP Greenhouse Gas Reduction Plan
GHG Greenhouse Gas
GWh Gigawatt-hour
GWP Glendale Water and Power
HIP Home Improvement Program
HPS High-Pressure Sodium
HVDC High Voltage Direct Current
IEPR Integrated Energy Policy Report
IPA Intermountain Power Agency
IPP Intermountain Power Project
IRA Inflation Reduction Act
IRP Integrated Resource Plan
ITC Investment Tax Credit
kWh kilowatt-hour
LADWP Los Angeles Department of Water and Power
LED Light Emitting Diode
LNG Liquified Natural Gas
LSE Load Serving Entity
MPP Magnolia Power Project
MTCO2e Metric Tonnes of Carbon Dioxide Equivalent
MW Megawatt
MWD Metropolitan Water District of Southern California
NCP Non-Coincident Peak
NREL National Renewable Energy Laboratory
O&M Operations and Maintenance
PAYGO Pay-As-You-Go (type of capital)
PCC Portfolio Content Category
PCC0 "Grandfathered" renewable energy
PCC1 Portfolio Content Category 1
ATTACHMENT 1
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Attachment 3: List of Acronyms-3
PCC2 Portfolio Content Category 2
PCC3 Portfolio Content Category 3
PTC Production Tax Credit
REC Renewable Energy Credit
RNG Renewable Natural Gas
RP3 Reliable Public Power Provider
RPS Renewable Portfolio Standard
SCPPA Southern California Public Power Authority
SMR Small Modular Reactor
STAG Stakeholder Technical Advisory Group
STS Southern Transmission System
TOU Time-of-Use
TSA Transmission Service Agreement
WECC Western Electricity Coordinating Council
ZELFR Zero Emitting Load Following Resource
ATTACHMENT 1
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