extent CCCFA incurs any SPO Fee if the bonds are not issued as a result of the Project Participant’s unwillingness or inability to proceed, other than due to an inability to achieve a minimum established target discount, the Project Participant agrees that it will be liable for such SPO Fee and make direct payment to Kestrel therefor, or to CCCFA if the SPO Fee was already paid by CCCFA.
Morgan Stanley shall have no responsibility for any fees or expenses incurred by CCCFA or the Project Participant, or their agents, employees, advisors or counsel, in connection with the issuance of the Bonds and the purchase of the Prepaid Energy, other than the Rating Agency Fee and SPO Fee as described in this MOU and as further described in the Bond Purchase Agreement (as defined herein).
Miscellaneous
CCCFA and Project Participant each acknowledge and agree that: (i) the transaction contemplated by this MOU is, in each case, an arm’s length, commercial transaction between the CCCFA and Morgan Stanley (in its role as “Underwriter” and/or the “Energy Supplier”, as applicable) in which the Underwriter and the Energy Supplier are each acting solely as a principal and not acting as a municipal advisor, financial advisor or fiduciary to CCCFA or the Project Participant; and (ii) CCCFA and the Project Participant will consult their own legal, accounting, tax, financial and other advisors, as applicable, to the extent each has deemed appropriate.
CCCFA acknowledges and agrees that Morgan Stanley is not making a commitment to extend credit, make a loan or otherwise fund the Bonds beyond the obligations contained in a mutually satisfactory bond purchase agreement (the “Bond Purchase Agreement”). CCCFA acknowledges that the services provided under this MOU involve professional judgment on Morgan Stanley’s part and that the results cannot be, and are not, guaranteed.
Nothing contained herein shall preclude the Underwriter from carrying on its customary and usual business activities. The Underwriter specifically reserves the right, but is not obligated, to bid for and maintain secondary markets on any of CCCFA’s outstanding bonds subject to appropriate information barriers. Services provided by the Underwriter in connection with this MOU shall not limit the Underwriter from providing services for CCCFA or the Project Participant in conjunction with other services requested by CCCFA or the Project Participant except as limited by rule of law or regulation.
In connection with the services agreed to herein, it is understood that the Underwriter will render professional services as an independent contractor. Neither the Underwriter nor any of its agents or employees shall be deemed an employee of CCCFA or the Project Participant for any purpose.
Except as described in this paragraph, this MOU is intended to be, and shall be construed only as, a non-binding MOU, intent on summarizing and evidencing discussions between CCCFA, the Project Participant, and Morgan Stanley, as of the date hereof. Except as described below, any legally binding obligation of the parties with respect to the transaction described herein shall exist only upon the execution and delivery of definitive agreements related thereto, into which this MOU and all prior discussions shall merge. It is expressly understood that this MOU is not a contract to execute any definitive agreements or to otherwise consummate the transactions described Memorandum of Understanding
December 24, 2025
herein. The parties will cooperate in negotiating definitive agreements providing for the transactions contemplated by this MOU, but each party reserves the right of final approval or disapproval, for any reason, of the documentation relating to such agreements. Notwithstanding the foregoing, the provisions above under the headings “Rating Agency Fee and SPO Fee” shall be binding upon the parties.
Sincerely,
_________________________
Grant Fraunfelder, Executive Director
MORGAN STANLEY & CO. LLC
ACCEPTED AND AGREED:
ORANGE COUNTY POWER AUTHORITY
By: ____________________________
Name: Joe Mosca
Title: Chief Executive Officer
Date: __________________
CALIFORNIA COMMUNITY CHOICE FINANCING AUTHORITY
By:
Name: Garth Salisbury
Title: Treasurer – Controller
Date: December 24, 2025
1 REVISED DRAFT 1.7.26
APPENDIX A
THE PROJECT PARTICIPANT
ORANGE COUNTY POWER AUTHORITY
Introduction
Orange County Power Authority (“OCPA”) is a joint powers authority organized and existing pursuant to the Joint Exercise of Powers Act (constituting Chapter 5 of Division 7 of Title 1 (commencing with Section 6500) of the California Government Code, as amended or supplemented from time to time) (the “Joint Powers Act”), as a “community choice aggregator” (“CCA”) as defined in Section 331.1 of the Public Utilities Code of the State of California, as amended (the “Public Utilities Code”). For a general description of CCAs in California, see the section “COMMUNITY CHOICE AGGREGATORS” in this Official Statement.
Formation, History, and Purpose of OCPA
General. OCPA was created on November 20, 2020, as a CCA in California pursuant to a “joint powers agreement” by and among the cities initially participating in OCPA: the Cities of Buena Park, Fullerton, Huntington Beach, and Irvine. Residents of participating cities receive bundled electric services from Southern California Edison (“SCE”). OCPA was created in order to provide opportunities by which parties can work cooperatively to create economies of scale and implement sustainable energy initiatives that reduce energy demand, increase energy efficiency, provide consumer choice and cost savings, and advance the use of clean, efficient, and renewable resources in the region for the benefit of all parties and their constituents.
Pursuant to OCPA’s implementation plan, it further describes its goal of providing electricity customers the opportunity to join together to procure electricity from competitive suppliers, with such electricity being delivered over SCE’s transmission and distribution system.
Its goals include the creation of innovative programs for voluntary purchases of renewable energy, net energy metering to promote customer-owned renewable generation, energy efficiency, demand responsiveness to promote reductions in peak demand, distributed energy generation, customized pricing options for large energy users, and support of local renewable energy projects by offering a standardized power purchasing agreement or Feed-In Tariff.
Commencement of Service and Expansion. OCPA successfully initiated retail service as a CCA in April 2022, providing electric generation service to approximately 36,000 service accounts located within the Cities of Buena Park, Fullerton, Huntington Beach, and Irvine. In October 2022, OCPA successfully completed phase two of its customer enrollment process, which increased its customer account total to approximately 290,000, with expected annual retail sales for these customers increasing to approximately 3,500 GWh. OCPA ended the 2023 calendar year serving 232,810 residential and 33,361 commercial customers. Following the withdrawal of Huntington 2 Beach in 20241, OCPA ended the 2024 calendar year serving over 175,000 residential and commercial customers. OCPA’s current customer enrollment stands at 156,493 residential and 24,110 commercial customers, with its forecast total retail load consumption for the 2025-2026 fiscal year projected to be 2,150 GWh.
Service Area
Communities Served by OCPA. OCPA currently serves three jurisdictions located in the County of Orange, California: its participating cities are Buena Park, Fullerton, and Irvine (“Members” or “Member Cities”), with the City of Fountain Valley expected to begin service in October 2026.
Service Area Map. OCPA is responsible for the acquisition of electric power for customers in its service area, shown in the following map, which includes the expected Fountain Valley service area:
Governance and Management
Board of Directors. OCPA is governed by a board of directors (the “Board of Directors” or “Board”), with board members consisting of representatives of each Member City and serving 1 In June 2023, the City Council of Huntington Beach made the decision to withdraw from OCPA for largely ideological reasons after a significant shift in the membership of the Council. The OCPA Joint Power Agreement provides an orderly process for withdrawal and the withdrawal was successfully completed in 2024 with no disruption to OCPA operations. 3 two year terms. There are currently five directors serving on the Board of Directors. OCPA’s Board of Directors has the rights and powers to conduct all business and carry out all functions of OCPA, which include entering into contracts for the purchase or sale of electrical energy; acquiring property; incurring debts, liabilities, and obligations; issuing revenue bonds and other forms of indebtedness; and receiving revenues from the sale of electricity and other energy-related programs.
Committees of its Board of Directors include a Legislative and Regulatory Committee and a Marketing and Communications Committee. The Board of Directors is also advised by a Community Advisory Committee, consisting of two representatives from the communities of its Member Cities, and two at-large members. OCPA also has a Risk Oversight Committee composed of members appointed by the Chief Executive Officer, who serves as committee chair; while the Board Chair and Vice Chair attend Risk Oversight Committee meetings as observers.
Management. Biographical information for key officers, directors, and managers is set forth below.
Joe Mosca, Chief Executive Officer. Joe Mosca joined OCPA as the Director of Communications and External Affairs, and later, in June 2023, the Board of Directors appointed him to lead OCPA as its Interim CEO. As of March 2024, Mr. Mosca was appointed to the position of Chief Executive Officer. As the CEO of OCPA, Mr. Mosca is responsible for all aspects of OCPA’s operations. He also represents OCPA on the Board of Directors of the California Community Choice Association (CalCCA), advocating for the interests of OCPA and all California-based CCAs at the state and federal levels.
Mr. Mosca deeply understands the California energy sector and local governments. He previously worked for two California utilities: San Diego Gas & Electric and Southern California Gas Company. He also served as mayor of Sierra Madre in Los Angeles County and later as president of San Dieguito Water District while serving as deputy mayor of Encinitas, San Diego County. In addition, he has served on several other regional boards and committees, including the San Diego County Water Authority, the San Diego Association of Governments, the Encina Wastewater Authority, the LOSSAN Rail Corridor Agency, Metrolink, and the League of California Cities.
Mr. Mosca was a founding member and former Chair of the Board of Directors of San Diego Community Power, California’s second-largest CCA. He is passionate about clean energy and environmental sustainability and believes that CCAs can help move communities toward a healthy, clean energy future.
Mr. Mosca is a 20-year member of the California Bar Association and holds a Juris Doctorate from Quinnipiac University School of Law and a bachelor’s degree in political science from Rhode Island College.
Tiffany Law, Chief Financial Officer. Tiffany Law joined OCPA in October 2021 as Chief Financial Officer, providing strategic leadership over OCPA’s financial and data technology functions. In this role, she oversees accounting, budgeting, treasury, ratemaking, financial 4 planning and analysis, green bond prepayment structural finance, big data management, and compensation and benefits. She also supports the Budget and Finance Committee and Board of Directors in their oversight of OCPA’s financial performance, risk management, and long-term financial sustainability.
Prior to joining OCPA, Ms. Law served as the Chief Financial and Technology Officer and was the first employee hired by the CEO of Central Coast Community Energy (“3CE”). As a member of the start-up leadership team, she helped build the organization from the ground up and led core accounting, finance, rate design, data, and internal operations, including human resources, information technology, and administration. During her tenure, 3CE achieved revenue growth of more than 140% within three years, grew annual revenues to approximately $239 million, built a net position of approximately $185 million, and became the first Community Choice Aggregator to receive an “A” credit rating from S&P Global. She also led the industry’s first transition from an IOU-minus rate structure to a cost-of-service rate design, adopted by the 3CE Board in 2021.
Ms. Law brings more than 25 years of experience across the public and private sectors, with deep expertise in accounting and auditing, budgeting, treasury, credit and cash flow management, ratemaking, data management, and information technology. Her prior experience includes finance leadership roles in global organizations, where she managed complex financial operations, large-scale system implementations, internal controls, and strategic financial modeling.
Ms. Law holds a Bachelor of Science in Accounting from Azusa Pacific University and is a Certified Public Accountant in the State of California.
Owen Lee, Director of Finance & Data Analytics. As Director of Finance & Data Analytics at OCPA, Mr. Lee supports core finance and data technology functions that shape OCPA’s financial planning, rate setting, and power supply analytics, including cost of energy forecasting, load forecasting, and analysis of utility rate schedules. He leads a full range of professional accounting, budgeting, retail rate analysis, and data analytics work, translating hourly and sub-hourly load, customer usage and billing data, and cost-of-energy forecasts into actionable insights, including ongoing forecast reconciliation.
Mr. Lee joined 3CE in December 2019 and joined OCPA in June 2022. He brings 15 years of experience spanning forecasting, budgeting and accounting, and financial and scenario modeling, with a strong track record of applying rigorous analytical approaches to support strategic and operational decision-making.
Mr. Lee holds a Master’s degree in Accounting from The University of North Carolina at Chapel Hill and is a Certified Public Accountant in the State of Georgia.
Louis Ting, Director of Power Resources. As OCPA’s Director of Power Resources, Louis Ting serves as a high-level technical advisor on energy projects and contracts. He manages complex short- and long-term energy resource planning and procurement activities for OCPA, leading to a cleaner, more sustainable and reliable electricity grid for OCPA communities and customers.
5 The Director of Power Resources plays a crucial role in guiding OCPA’s procurement success and the continued diversification of its energy portfolio, securing all energy and capacity in order to ensure that OCPA’s customers’ energy needs are met.
Mr. Ting brings over three decades of experience managing power and water projects for the Los Angeles Department of Water and Power (LADWP), the nation’s largest municipal utility, where he spearheaded projects and studies in power generation, transmission, and distribution systems.
During his tenure with LADWP, Mr. Ting was responsible for the vital transition to a clean energy future. He focused on modernizing the grid to enable clean electrification programs, implementing strategies to strengthen Los Angeles’ distribution and transmission grids, and executing major power system programs. Mr. Ting also led a seasoned team in collaboration with diverse stakeholders to transition a coal-to-natural gas project with green hydrogen-powered combined-cycle units.
Jacquie Henderson, Director of Communications & External Affairs. As Director of Communications & External Affairs at OCPA, Jacquie Henderson oversees all aspects of brand marketing and communications, public outreach and government relations, and customer program development and deployment. Her work across the agency and with key stakeholders promotes OCPA’s mission to provide renewable energy at affordable rates and equitably reinvest in energy-related customer programs to support sustainable communities.
Ms. Henderson’s two decades of experience as a communications and marketing professional include working at high-profile brands and not-for-profit organizations, including most recently with Burbank Water and Power (BWP). At BWP, she supported marketing and creative design for customer programs, and as head of marketing and communications at a $45 million agency, she was responsible for corporate communications strategy, public relations, and industry and stakeholder relations.
Ms. Henderson holds a Bachelor of Arts in mass communications and media from the University of South Florida. She is also actively involved in the community, serving on the Board of Directors for the Santa Ana Chamber of Commerce and volunteering with various dog rescue organizations.
Customers
General. OCPA currently provides energy to more than 180,000 residential, commercial, and industrial accounts, serving approximately 79% residents and businesses in its service area.
The current mix of OCPA’s customer base is approximately 34% residential and 66% commercial/industrial by the percentage of load served and 40% residential and 60% commercial/industrial by the percentage of revenue.
OCPA offers three different energy service choices, called 100% Renewable Choice, Smart Choice, and Basic Choice.
6 • 100% Renewable Choice: This energy service offers entirely renewable energy sources for OCPA customers, at a slightly higher rate than its Basic Choice and Smart Choice services. In 2024, customers receiving 100% Renewable Choice service were provided with 100% renewable energy, sourced from a mix of wind, solar, and hydroelectric. This service has continued to offer 100% renewable energy in 2025.
• Smart Choice. This energy service offers predominantly renewable and carbon-free energy sources, at a rate below that of the 100% Renewable Choice service, but higher than Basic Choice. In 2024, customers electing to receive Smart Choice service were provided with 72% renewable energy, sourced from a mix of wind, geothermal, solar, biomass, and system energy sources. In 2025, Smart Choice provided 55% renewable and 40% carbon-free energy, which will increase to 60% renewable and 40% carbon-free energy in 2026.
• Basic Choice. This is OCPA’s most affordable plan, which provides a significant portion of its energy sources from renewable and carbon-free providers. In 2024, customers receiving Basic Choice service were provided with 25% renewable energy, sourced from a mix of wind, geothermal, solar, small hydro, biomass, and system energy sources, plus 19% unbundled Renewable Energy Credits, for a total of 44% total renewable energy. In 2025, Basic Choice rates provide 47% renewable energy.
In addition, OCPA offers its customers access to bill and payment assistance, community grants, offers and rebates, as well as the following optional Energy Programs:
• OCPA Disadvantaged Community Green Tariff (DAC-GT) Program: a CPUC-regulated program designed to provide eligible low-income customers in disadvantaged communities with access to 100% solar energy and an additional 20% total bill discount for up to 20 years. OCPA anticipates launching this program in Q3 2026, pending final CPUC approval.
• Solar/Net Energy Metering (NEM): a program whereby OCPA customers who produce solar energy will have their contributions to the energy grid credited to their accounts on an annual basis each April.
• GreenP100NEER: provides marketing and publicity support to individuals and businesses who use OCPA’s 100% Renewable Choice service. • OCPA Incentive Finder: a program that assists OCPA customers in finding all available state, federal, and local rebates and incentives for which they may be eligible.
• OCPA Marketplace: an online store for customers to purchase discounted energy-saving products. 7 • Residential Battery Rebate Program: a program that provides a $1,000 rebate to eligible residential customers who install a qualifying battery energy storage system.
• Future Programs: additional customer programs are expected to launch following Board approval of the Community Power Plan (CPP) in Q1 2026, ensuring that new offerings are responsive to member community needs and deliver meaningful impact.
Customer Enrollment. Member Cities select which OCPA energy plan will serve as their default plan, in which their customers will be automatically enrolled. Customers may opt out of their Member City’s default plan by selecting a different OCPA plan, or they may opt out of OCPA service entirely and instead receive generation service from SCE. The City of Buena Park has selected the Smart Choice plan as its default energy plan, having switched from the 100% Renewable Choice plan in March 2025, and will switch back to the 100% Renewable Choice plan in January 2027. The City of Irvine has selected the Basic Choice plan as its default energy plan, having switched from the 100% Renewable Choice plan effective February 2025. The City of Fullerton has selected the Smart Choice energy plan as its default energy plan. Overall, approximately 40% of OCPA customers are served on Smart Choice and 100% Renewable Choice combined, while the remaining approximately 60% are served on the Basic Choice plan.
New Customers. OCPA is the default generation service provider for residents and businesses in its Member Cities. OCPA anticipates that the City of Fountain Valley will begin service within the OCPA in October 2026.
Customer Election to Opt-out of OCPA Service. Customers can opt-out of OCPA service and return to service from their traditional electric service provider, SCE, either initially upon the transition to OCPA or at any time after OCPA becomes the generation service provider. There is no fee associated with opting out of the OCPA, though opt-outs become effective at the end of the monthly billing cycle.
Cumulative Opt-Out Rate and Customer Retention. Since program inception, cumulative opt-outs represent approximately 21% of the eligible customer base. The majority of these opt-outs occurred during OCPA’s initial implementation phase, driven by early launch dynamics and localized policy considerations. Opt-out activity has declined steadily since that period. In 2025, opt-outs accounted for approximately 0.6% of the eligible customer base, reflecting current customer behavior and demonstrating OCPA’s strong and stable customer retention. This trend also indicates sustained customer engagement and continued confidence in OCPA’s service over time.
Service Rates
General. Rates for OCPA energy service are determined by its Board of Directors and are not regulated by the CPUC. In addition to OCPA’s charges for generation services, customers’ rates include amounts for transmission and distribution of electricity established by SCE, as well 8 as a “power charge indifference adjustment” (“PCIA”) and other non-by-passable load charges imposed by the CPUC in order to compensate investor-owned utilities for investments in power generation and long-term power purchase contracts associated with the loss of customers to CCAs, which in each case are passed through on a customer’s bill in the amounts established or imposed.
Determination of Rates for Energy. The rates OCPA charges for 100% Renewable Choice, Smart Choice, and Basic Choice energy services are based on the current generation rate charged by SCE and the current PCIA fee. All value propositions are priced inclusive of the PCIA. Under OCPA’s 2025 rate plan, the Basic Choice service is priced at a 3% discount below the cost of SCE’s equivalent generation rate, while the Smart Choice energy plan is the Basic Choice rate plus 1 cent per kWh, and the 100% Renewable Choice plan is the Basic Choice rate plus 1.5 cents per kWh.
Current and Historical Rate Information. An OCPA customer’s total cost of electric service is determined by OCPA’s charges for generation services and includes SCE charges for transmission, distribution, and other non-by-passable charges. Among such non-by-passable charges, OCPA’s customers pay a PCIA which can vary annually based on several market factors including benchmarks for regional energy costs, resource adequacy, the year in which their community joined OCPA, and other considerations. OCPA publishes, jointly with SCE, its current and historical rate information as compared to SCE’s rates. OCPA’s published residential and commercial industrial rates as of October 1, 2025 as compared to SCE’s are as follows:
9 California Renewable Portfolio Standards and Other Regulations General. Community choice aggregators such as OCPA are “load-serving entities” (“LSEs”) and as such are required to comply with California’s Renewable Portfolio Standard, Resource Adequacy requirements and Power Source Disclosure requirements described below.
Renewable Portfolio Standard. California’s Renewable Portfolio Standard (“RPS”) requires LSEs to supply their retail sales with minimum quantities of eligible renewable energy.
Senate Bill 100 directs all LSEs to procure 60% of their portfolios from RPS-eligible resources by 2030 and 100% of their retail sales from zero-carbon resources (or eligible renewable resources) by 2045. Based on OCPA’s approved service offerings for 2025, 57% of retail sales are from zero-carbon resources comprised of RPS-eligible resources, such as solar, wind, geothermal, biomass, and small hydroelectricity with over 74% of total energy served being carbon-free. OCPA intends to meet Board-directed goals and orders by the CPUC under the Mid-term Reliability Procurement decision (D.21-06-035) and the Supplemental Mid-Term Reliability Procurement Order (D-23-02- 040). OCPA is on target to meet the Board approved renewable energy goals for 2025, and has already executed two long-term power purchase agreements meeting its share of the CPUC directed procurement orders.
Resource Adequacy. Resource Adequacy (“RA”), a California program jointly administered by the CPUC, the California Energy Commission (“CEC”) and the California Independent System Operator (“CAISO”), directs LSEs to secure forward capacity and offer it into the CAISO’s Day-Ahead and Real-Time markets to ensure that there will be enough supply in the right locations and with sufficient ramping capability to meet load. The RA program is comprised of three products: System RA; Local RA; and Flexible RA, although rules and categories are subject to modification by state agencies. Local RA obligations have been assigned to a Central Procurement Entity as of 2023. OCPA has a strong track record of meeting its RA obligations and expects to meet its future RA obligations in compliance with its policies.
Integrated Resource Planning. Integrated Resource Planning (“IRP”) requires LSEs to forecast their customer load and develop a plan to serve such load in alignment with their own vision and values and in accordance with regulatory requirements. In October 2015, California codified this LSE responsibility with the passage of SB 350, which requires the CPUC to establish 10 and oversee an IRP process to assist with meeting the state’s aggressive greenhouse-gas (“GHG”) targets (i.e., 40% below 1990 levels by 2030). The IRP process, which is used in many states across the U.S., generally produces 10- to 20-year plans that map out both the supply-side and demand-side resources required for meeting customer load. Given the complexity of the grid and the time required to plan and build generating facilities, IRP plans are critical for ensuring safe, reliable and clean power in a cost-effective manner. In addition to addressing the long-term planning horizon typical of an IRP process, the IRP process has been used in recent years to direct procurement of new capacity to meet near- and mid-term reliability and clean energy needs per CPUC Decision (“D.”) 19-11-016, D. 21-06-035 and D. 23-02-040. Pursuant to the procurement orders in these CPUC Decisions, LSEs are required to procure “Incremental System Capacity,” which is RA capacity from non-emitting, storage, and/or renewable resources that are in addition to the resources identified on a baseline list of existing, on-line and operating resources. OCPA is working toward full compliance with these requirements, and maintains policies and procedures to ensure continuing compliance therewith.
Power Source Disclosure. California law requires LSEs to disclose the types of power resources used to supply retail sales. This mandate, known as the Power Source Disclosure Program (“PSDP”), is a consumer information program managed by the CEC on an annual basis.
A key output of the PSDP is the Power Content Label (“PCL”). The PCL is an LSE-specific document that shows the breakdown of power resource types for each of the LSE’s energy products used to serve retail load, as well as a breakdown of resource types for the overall California grid.
The PCL is distributed to OCPA customers each year in compliance with the foregoing.
Energy Demand
OCPA utilizes its load forecasting model/methodology for three primary purposes: (1) for portfolio management and procurement; (2) for the development of financial projections; and (3) for Resource Adequacy compliance with the CPUC and CAISO. The adopted load forecasting methodology focuses primarily on the projected customer counts within the OCPA service territory and incorporates historical per capita usage data to derive the load forecast.
The load forecast is developed for each of the twelve major customer classes served by OCPA. These include the following customer classes:
11 OCPA’s load forecasting process starts with a baseline-forecast of current customers by end-use classification (residential, commercial, industrial, etc.), utilizing historical usage data and customer counts. OCPA also uses historical weather data and linear regression models to estimate relationships between weather variables (heating degree days, cooling degree days, and solar insolation) and customer consumption patterns. The resulting coefficients are then applied to normalized weather conditions, over a 5-year observation period, and current customer counts to derive a forecast for the existing customer base. Potential impacts of climate change are captured by utilizing the most recent 5-years of observed weather data as the benchmark for normal weather conditions. Hourly load profiles for each of the twelve major customer classes, created by analyzing historic recorded meter data for OCPA’s customer base, are applied to translate the monthly usage data into hourly values.
For load projections beyond the current year, OCPA assumes a long-term annual growth rate of 0.5%, which reflects the estimated net increase in customer consumption due to economic and demographic variables. The table below shows OCPA’s long-term retail and loss-adjusted load forecast for 2026-2056. OCPA does not have a long-term history for its current customer base with which to compare the reasonableness of the projected long-term growth rate. However, OCPA believes that it is generally consistent with the net growth rate in the SCE service area as a whole. OCPA has not included the potential effects of incremental energy efficiency, demand response, distributed energy resources, and other behind-the-meter programs in its current long-term forecast. If and when OCPA administers demand-modifying customer programs, OCPA will update its load forecast accordingly.
For OCPA’s peak demand forecast, in April 2024 OCPA coordinated with SCE through a meet and confer process to address load migration and data quality issues with the historical usage data SCE provided to OCPA. Through the meet and confer process, OCPA and SCE exchanged their respective 2024 load forecasts for the OCPA area, and as a result of that process, OCPA has aligned its monthly peak demand forecast methodology with SCE’s to ensure appropriate accounting between the two entities. SCE modelled its peak forecast by averaging the top three 12 peak load days in each month of observed historic data, and compared such peak average to the average historic load, creating a load-to-peak forecast ratio for each month. In order to account for the data quality issues mentioned above, OCPA adopted SCE’s load-peak ratios for the 2024 forecast period which were applied to OCPA’s internal monthly load forecast to derive its 2024 and beyond peak forecasts.
OCPA utilizes historical consumption data to calibrate and adjust its load forecast. The calibration process is run monthly and compares the most recent monthly kWh and peak kW usage data to the forecast energy and peak demand values, respectively. The forecast is tracked relative to both the initial usage estimates (T+9) reported to the CAISO as well as the final reported usage (T+70). To the extent that the monthly forecast error exceeds a 5% threshold, OCPA evaluates the potential causes of the variance and, if such error is deemed likely to persist, adjusts the forecast going forward.
OCPA’s assigned load forecast is as follows:
OCPA Load Forecast (GWh)
Year Load Forecast
2026 2,339
2027 2,545
2028 2,570
2029 2,582
2030 2,602
2031 2,622
2032 2,651
2033 2,663
2034 2,683
2035 2,704
2036 3,011
2037 3,078
2038 3,138
2039 3,194
2040 3,244
2041 3,294
2042 3,346
2043 3,398
2044 3,451
2045 3,505
2046 3,560
2047 3,616
2048 3,672
2049 3,730
2050 3,788
2051 3,847
2052 3,907
13 OCPA Load Forecast (GWh)
Year Load Forecast
2053 3,968
2054 4,030
2055 4,093
2056 4,157
Sources of Energy
General. OCPA prioritizes securing sufficient, low-cost, clean sources of electricity that achieve OCPA’s priorities while ensuring reliability and meeting regulatory mandates. During the normal course of business, OCPA purchases electrical power from numerous suppliers. Electricity costs include the cost of energy and capacity arising from bilateral contracts with energy suppliers as well as wholesale sales and generation credits, and load and other charges arising from OCPA’s participation in the CAISO’s centralized market. OCPA purchases capacity commitments from qualifying generators to comply with the RA Program. OCPA is in compliance with external mandates and self-imposed benchmarks.
Energy Purchases. In 2024, OCPA procured approximately 2,480,201 MWh of electricity for its customers. OCPA anticipates that roughly 74% of its total 2025 retail sales will be sourced from carbon-free resources including renewables such as wind, solar, small hydroelectric, and biomass. OCPA does not anticipate sourcing energy from large hydroelectric or nuclear providers.
Energy Load and Supply Risk Management. Volumetric risk reflects the potential uncertainty in the quantity of different power supply products (e.g., renewable energy, carbon free energy and capacity) required to meet the needs of OCPA customers. This uncertainty can lead to adverse financial outcomes, as well as create potential for OCPA to fail to meet reliability or renewable energy compliance requirements established by the State of California and/or OCPA’s own policies. Customer load is subject to fluctuation due to customer opt-outs or departures, temperature deviation from normal, unforeseen changes in the growth of behind-the-meter generation by OCPA customers, unanticipated energy efficiency gains, new or improved technologies, as well as local, state and national economic conditions. OCPA monitors its positions on a regular basis to reduce exposure to CAISO day-ahead market prices.
OCPA manages energy delivery risks by ensuring that contracts include appropriate contractual penalties for non-delivery, acquiring energy from a geographically and technologically diverse portfolio of generating assets (with a range of generation profiles that are generally complementary to the manner in which OCPA’s customers use electric power). Due to known production variability and supply uncertainty related to renewable and other carbon-free energy products, OCPA includes planning margins in its procurement of such products to ensure that related targets/mandates are achieved.
OCPA manages load forecasting and related weather risks by contracting with qualified data management and scheduling coordinators, which independently or jointly provide the systems and data necessary to forecast and schedule load using good utility practice. Load variability is 14 also considered in establishing appropriate planning margins for renewable and other carbon-free energy sources.
OCPA’s load scheduling strategy, as executed by its Director of Power Resources, shall be in accordance with the adopted Load Bidding/Scheduling Guidelines. This strategy ensures that price risk in the day-ahead and real-time CAISO markets is managed effectively and is consistent with good utility practice.
Procurement. OCPA’s procurement strategies focus on diversity among technologies, production profiles, project sizes and locations, counterparties, length of contract, and timing of market purchases. OCPA requires a competitive process whereby OCPA issues requests for proposals (“RFPs”) and requests for qualifications (“RFQs”) for any purchase of goods or services in excess of $100,000. Smaller contracts may follow an informal bidding procedure, but should typically include proposals for at least three providers; contracts under $10,000 in value do not require such processes.
Energy Storage
OCPA currently has 42 MW of wholesale storage in operation. OCPA has around 8 MW of additional battery storage under contract scheduled to come online by 2028.
On September 16, 2025, OCPA announced that it had finalized an agreement with Lock Energy Center, LLC to purchase up to 115 MW of capacity for its customers from a new-build battery energy storage system.
On October 27, 2025, OCPA’s Board of Directors approved a 15-year agreement with Athos Storage, LLC to procure 52 MW of resource adequacy capacity from a new-build battery energy storage project in Riverside County, CA. This will provide the necessary Net Qualifying Capacity as directed by the CPUC under the Supplemental Mid-Term Reliability Procurement Order (D-23-02-040).
Information Technology, Data Analytics and Cyber Security OCPA prioritizes operational resilience, data integrity, and cybersecurity to safeguard market-sensitive information and ensure reliable, uninterrupted service delivery. Information technology and data analytics are critical enterprise assets that support OCPA’s core operations, regulatory compliance, financial management, power supply planning, customer service, and strategic decision-making. These systems are managed to ensure information remains accurate, complete, confidential, and available for authorized business use.
OCPA’s data analytics platform integrates dynamic and historical datasets, including customer enrollment and billing data, interval load data, weather data, utility rate schedules, and cost-of-energy forecasts. This platform supports short- and long-term load forecasting, rate setting, power supply analytics, customer load profile analysis, opt-out analysis, accounts receivable aging, and customer product performance evaluation. Advanced analytics enable OCPA to translate hourly and sub-hourly data into actionable insights that inform demand response 15 design, energy storage and incentive programs, retail rate updates, and financial forecasting and reconciliation.
Proper management of information technology and data assets is essential to supporting regulatory compliance, minimizing legal and operational risk, reducing exposure to cyber threats, and maintaining stakeholder and customer confidence. OCPA’s cybersecurity framework aligns with industry-leading standards and regulatory requirements and is designed to proactively mitigate risk.
In May 2025, OCPA achieved a BitSight Security Rating of 780 out of 820, placing OCPA among the top-performing public agencies nationwide. This rating reflects strong cybersecurity controls, including advanced firewalls, secure VPN usage, multi-factor authentication, zero-trust architecture principles, endpoint protection, and comprehensive employee cybersecurity training.
OCPA partners with SDI Presence, a professional IT managed services provider specializing in government and utility clients, to deliver proactive cybersecurity protection, infrastructure management, and system monitoring. Together, OCPA and SDI Presence ensure timely updates to devices, firewalls, and network equipment and maintain robust security protocols for both in-office and remote operations.
To reinforce governance and accountability, OCPA maintains and publicly posts policies related to data confidentiality, records management and retention, acceptable use, and computer and email management. These policies, combined with experienced internal staff and external expertise, support continuous improvement of OCPA’s technology environment while reducing risk and enhancing operational efficiency.
Financial Information
Revenues from Energy Sales and Operating Expenses. OCPA’s revenue primarily derives from retail electricity sales, driven by generation rates designed to cover power procurement, operating and non-operating expenses, capital expenditures, and contributions to the operating reserve.
OCPA classifies its operating expenses into seven categories: Data Management & SCE Service Fees; Staffing Costs; Professional Contracts; Legal & Lobbying Support; Marketing and Outreach; General and Administrative Expenses; and Energy Programs. The cost of energy is OCPA’s largest operating expense by a considerable margin, constituting approximately 94% of the projected expenditures in OCPA’s Approved Budget for the Fiscal Year 2025/2026.
In Fiscal Year 2024/2025, uncollectible accounts were reduced from 1.75% to 1.50% of operating revenue, reflecting a low incidence of long-term aging accounts. 16 Results of Operations. The following is a summary of OCPA’s results of operations for fiscal years ending June 30:
17 Assets, Liabilities, Deferred Inflows or Resources and Net Position. The following table is a summary of OCPA’s assets, liabilities, deferred inflows or resources and net position for fiscal years ending June 30:
18 Other Sources of Revenue. While OCPA derives revenue from investment and other miscellaneous income, this constitutes a very small portion of its annual revenue. Its Approved Budget for the Fiscal Year 2025-2026 projects such income to constitute approximately 1% of its total projected net revenue.
Financial Reserves. OCPA prudently manages its operations in a manner that supports its long-term financial independence and stability while providing sufficient financial capacity to meet short term obligations. The Reserve Policy outlines the appropriate types and target levels (minimum and maximum) of unrestricted/undesignated reserves, with a minimum reserve balance equal to 30% of total operating budget expenditures, and a maximum of 75% thereof.
OCPA maintains adequate reserves to satisfy working capital requirements, procure energy at competitive rates, comply with loan covenants, and position itself to obtain and maintain an investment grade credit rating around 2027. These reserves also help cover unanticipated expenditures and ensure cash availability, avoid interest expense, and support rate stability.
Reserves are defined as the Net Position plus funds held in the Rates Stabilization Fund.
The Net Position represents the difference between OCPA’s assets and liabilities as defined by the Government Accounting Standards Board and consistent with Generally Accepted Accounting Principles. The Reserve Policy allows the reserve balance to be used to: (i) provide revenues to make up for unanticipated revenue shortfall of spikes in power supply expenses; (ii) provide temporary resources in the event of an economic downturn while expenditure reductions and/or rate adjustments are implemented; and (iii) provide resources to meet emergency expenditures.
Operating Reserve. OCPA also maintains a Rate Stabilization Reserve Fund (RSF) in accordance with the Board-approved Rate Stabilization Fund Policy. The RSF is designed to defer revenue for future years when financial conditions necessitate draws on reserves. By deferring and subsequently recognizing revenue, OCPA aims to mitigate the need for sudden rate increases resulting from spikes in renewable energy procurement costs, broader market volatility, regulatory shifts, and other unforeseen circumstances. In fiscal year 2024, OCPA set aside $45,000,000 in the RSF, reflecting significantly higher renewable energy costs and a strategic decision to maintain rate stability for customers. In fiscal year 2025, OCPA recognized $15,000,000 in revenue from the RSF to help offset rising energy costs, operating expenses, and debt service, while continuing to meet lender-required financial metrics.
Risk Management. OCPA maintains risk management policies, procedures and systems that help mitigate credit, liquidity, market, operating, regulatory and other risks that arise from participation in the California energy market. Internal controls and compliance mechanisms are in place to manage operational and regulatory risks, ensuring adherence to legal and market regulations. Risk monitoring and oversight are continuously performed through frequent reporting, with critical risks communicated promptly to stakeholders. This integrated approach enables OCPA to maintain a balanced risk profile while adapting to evolving market conditions.
OCPA employs a Finance & Risk manager who reports to the Director of Finance & Data Analytics and is responsible for identifying, monitoring, and managing OCPA’s financial and operational risk. The role is filled by Hongyan Sheng, who joined OCPA on November 18, 2024, and brings 25 years of experience from Southern California Edison, where she led financial 19 analysis, risk management, budgeting, and demand forecasting, and supported wholesale trading and renewable procurement. Hongyan developed SCE’s risk analytics framework and holds a Ph.D. in Economics and a master’s degree in Mathematical Behavioral Science, and has been a Chartered Financial Analyst (CFA) since 2004.
Credit Rating. OCPA does not currently have a credit rating.
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.2
--------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Board of Directors
From: Pranesh Venugopal, Energy Programs Manager
Jacquie Henderson, Director of Communications and External Affairs Approved by: Joe Mosca, Chief Executive Officer
Subject: COMMUNITY POWER PLAN RESULTS PREVIEW
Date: January 12, 2026
--------------------------------------------------------------------------------------------------------------------
STRATEGIC GOALS
☐ Enrich & Grow the OCPA Community:
☐ Prioritize Fiscal Sustainability & Affordability:
☒ Design & Deploy Community-Aligned Customer Programs:
☐ Energize Our Community with Renewable Energy:
☐ Raise Awareness of Community Energy & Advocate for Our Customers:
☐ Not Applicable:
RECOMMENDED ACTION(S)
Receive and file the high-level overview of the Community Power Plan (CPP) results and provide any feedback on recommended program priorities.
BACKGROUND
The CPP is a guiding framework that outlines how Orange County Power Authority (OCPA) will design and implement programs to provide clean, reliable, and equitable energy solutions to its customers. It establishes a foundation for program development based on community input, operational alignment, and existing funding opportunities while maintaining flexibility for future adaptation as market conditions and customer needs evolve.
The plan was developed between November 2024 and January 2026 in partnership with the Board approved third-party contractor, The Energy Coalition (TEC). It represents OCPA’s first comprehensive roadmap for community energy programs based on a combination of technical analysis, stakeholder engagement, and fiscal projections. The process drew from several phases of research and input to ensure that each program recommendation is both impactful and achievable within OCPA member cities.
During preliminary discussions in 2025, the OCPA Board of Directors and the Community Advisory Committee (CAC) provided recommendations on community needs as well as outreach priorities to ensure representative input. The draft plan was subsequently presented to the CAC in December 2025 for feedback, which was considered as the final iteration was composed. That final iteration was then released for public comment through an online feedback tool, with the comment period open from December 18, 2025 through December 25, 2025. Public comments received during this period were also considered for incorporation into the final plan.
DISCUSSION/ANALYSIS
The plan was informed by five coordinated efforts:
Community Needs Assessment conducted between February and August 2025.
This process gathered input from OCPA communities and feedback solicitation reached 54,000 residents. OCPA and its partner the Asian Business Association Coalition promoted the Community Needs Assessment at 25 community events and hosted seven (7) listening sessions.
In total, 1,244 responses were received from a representative group across OCPA member cities.
Feedback identified affordability, air quality, equity, and grid stability as the most important electricity issues.
Operational Alignment Assessment conducted between June and July 2025.
This process gathered input from OCPA staff to identify the program structures that best meet operational goals. Staff prioritized programs that improve community impact, shift energy use to off-peak periods, and promote customer satisfaction.
Existing Programs Assessment conducted between July and August 2025.
This process researched the programs that are already available through other agencies like Southern California Edison (SCE) and the Southern California Regional Energy Network (SoCal REN). The results provided a clear understanding of the existing program landscape and helped identify gaps in the marketplace. A total of 44 programs offered by 16 administrators were reviewed, including 13 programs operated by other community choice aggregators. Evaluation metrics included target market, program type, delivery model, energy savings measures, priority populations served, application processes, and current funding sources.
Funding Opportunities Assessment conducted between July and November 2025.
This process analyzed federal and state funding sources that can reduce OCPA’s program administration costs. Nine (9) funding opportunities were identified for further consideration after evaluation of 23 different funding sources. These opportunities represent a mix of grants and programs that can help support program implementation and expand OCPA’s ability to deliver meaningful customer benefits.
Cost-Benefit Analysis conducted between September and October 2025.
This final process integrated all data from the previous assessments. A six-member scoring committee of Community Choice Aggregator (CCA) programs experts evaluated each proposed program using their program implementation expertise and gauging its impact, alignment, and feasibility. The results produced a ranked portfolio that distinguishes between near-term, medium-term, and long-term opportunities.
The resulting Community Power Plan established a thoughtful program portfolio that is prioritized and phased for maximum impact. Programs to be implemented have been categorized as high-priority, medium-priority, or long-term based on their readiness for implementation, expected community impact, and feasibility.
The presentation accompanying this report will provide the Board with a high-level overview of the Community Power Plan’s purpose, development process, and recommended program direction. A subsequent presentation and report in February 2026 will seek formal consideration and adoption of the Community Power Plan and will include additional details related to cost benefit analysis, program prioritization, and launch sequencing.
FISCAL IMPACT
None.
ATTACHMENT(S)
None.
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.3
-------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Board of Directors
From: Tiffany Law, Chief Financial Officer
Approved by: Joe Mosca, Chief Executive Officer
Subject: APPROVAL OF 2026 OCPA GENERATION RATE STABILIZATION
APPROACH AND GREEN DISCOUNT PROGRAM PARAMETERS
Date: January 12, 2026
--------------------------------------------------------------------------------------------------------------------
STRATEGIC GOALS
☐ Enrich & Grow the OCPA Community:
☒ Prioritize Fiscal Sustainability & Affordability:
☐ Design & Deploy Community-Aligned Customer Programs:
☐ Energize Our Community with Renewable Energy:
☐ Raise Awareness of Community Energy & Advocate for Our Customers:
☐ Not Applicable:
RECOMMENDED ACTIONS
1. Approve a temporary 2026 OCPA generation rate stabilization approach that maintains the existing 2025 OCPA generation rates and product differentials for Basic Choice, Smart Choice, and 100% Renewable Choice for calendar year 2026, unless modified by future Board action in response to unanticipated changes in OCPA’s financial results or material changes in SCE’s 2026 generation rates or Power Charge Indifference Adjustment (PCIA) charges.
This action is intended to provide rate continuity, reduce exposure to Southern California Edison’s (SCE) rate volatility and PCIA-related distortions, and ensure that OCPA meets its 2026 revenue requirement. Staff will monitor SCE’s rate changes during 2026 and may return to the Board with an amended rate design proposal if SCE’s generation rates or PCIA are materially adjusted or if other statewide or market changes materially improve or worsen long-term cost comparability. Staff also expects to return later in 2026 with an updated outlook and recommended refinements for 2027, consistent with OCPA’s Board-approved Rate Development Policy.
2. Approve Green Discount Program parameters and authorize implementation beginning in calendar year 2026 as a voluntary non-net energy metering (NEM) residential discount option, subject to ongoing financial sustainability, with core parameters as described in this report.
Staff is authorized to administer the program and finalize operational details consistent with these parameters, and will report back to the Board on program performance and any recommended continuation or changes to core parameters through a future Board item.
I. BACKGROUND AND BOARD POLICY FRAMEWORK
Since launch, OCPA has structured its rate design by indexing to SCE’s generation rates and has proactively adjusted its financial and procurement strategies to protect customers from wholesale energy market volatility and frequent utility rate changes. OCPA has had to navigate a highly volatile and rapidly changing energy commodity market, and its rate recommendations have consistently sought to manage that volatility in a fiscally responsible way rather than react to every short-term price movement.
Through these actions, OCPA has positioned itself as a locally controlled public agency focused on customer affordability, financial prudence, and clean energy outcomes, while keeping rate products clear and predictable. As a not-for-profit, OCPA reinvests any net revenues back into the communities it serves through customer programs and local clean energy investments. This experience is consistent with the broader Community Choice Aggregation (CCA) sector in California, where more than two dozen operating CCAs now serve roughly one-third of the state’s electricity customers and have repeatedly adapted their strategies to manage changing market and regulatory conditions.
On April 19, 2023, and June 18, 2024, the Board adopted three key financial and rate policies that frame this item and guide staff’s recommendations:
Operating Reserve Policy
Establishes a target operating reserve range of 30% to 50% of total operating expenses. Reserves are intended to provide a buffer against economic volatility, market risk, changes in member agency participation, and other uncertainties, while supporting investment-grade credit expectations and avoiding unnecessary short-term borrowing.
Rate Development Policy
Establishes a transparent, accountable framework for rate setting that emphasizes full cost recovery (including power procurement, operations, debt service, and prudent reserve contributions), while balancing local control, competitiveness with SCE, rate stability, and responsiveness to changing market and regulatory conditions.
Rate Stabilization Fund (RSF) Policy
Allows OCPA to defer revenue from financially strong years for use in future years experiencing fiscal stress, reducing the need for sudden rate increases. The RSF is intended to mitigate impacts from uncontrollable events such as investor-owned utility (IOU) rate volatility (e.g., rising PCIA or declining bundled generation rates1), unexpected energy price spikes, changes in customer participation, increased defaults during economic downturns, regulatory shifts, or falling demand due to affordability concerns.
Taken together, these policies provide the foundation for the recommended 2026 rate approach and Green Discount Program by prioritizing fiscal resilience, stable and predictable rates, and prudent management of volatility over short-term price reactions. 1 Bundled generation rate: The generation portion of the total bundled rate paid by customers who receive both generation and delivery from SCE.
II. RECENT CUSTOMER PROTECTION ACTIONS (2024-2025)
2024 Rate Design and Rising Energy Costs
On January 24, 2024, the Board approved a 2024 rate design that established a 3% discount on Basic Choice rates compared to SCE’s equivalent generation rates. Smart Choice was set at +1.0 cent per kWh above Basic, and 100% Renewable Choice at +1.5 cents per kWh above Basic.
During 2024, SCE implemented four major rate changes (January, March, June, and October) driven by Energy Resource Recovery Account (ERRA) balancing adjustments, changes to authorized cost of capital, removal of the 2023 ERRA Trigger surcharge, and reduction of prior overcollections. Collectively, these actions produced bundled generation rate reductions of roughly 7% to nearly 12%. Despite these unexpected changes, OCPA maintained a stable rate design and continued to deliver a 3% Basic discount relative to SCE’s equivalent generation rates.
At the same time, OCPA’s average cost to procure energy increased by roughly 20% between FY2022/23 and FY2023/24, driven by higher market prices for energy, resource adequacy (RA), and renewable attributes. These higher costs flowed directly into OCPA’s FY2024/25 procurement expenses and made it more challenging to maintain affordability. OCPA’s ability to hold its rate design steady while continuing to offer a discount reflects deliberate and careful financial and procurement management; OCPA absorbed a meaningful share of market risk rather than passing those cost increases directly through to customers.
SCE 2025 Volatility and OCPA’s 2025 Rate Design
SCE’s 2025 rate projections highlighted the degree of uncertainty OCPA must plan around when indexing to SCE. In October 2024 alone, SCE issued three separate 2025 projections using different methodologies, while the California Public Utilities Commission (CPUC) released updated Market Price Benchmarks (MPB) that were considerably higher than earlier estimates.
Across these iterations, projected bundled generation rates, revenue requirements, and PCIA levels varied significantly.
In December 2024, the CPUC adopted SCE’s October 21, 2024 alternate update, with adjustments for actual November 2024 costs. Final 2025 rates, released December 30, 2024, reflected approximately:
0.9 cents per kWh (about 8%) decrease in bundled generation rates; and 0.8 cents per kWh (about 43%) increase in PCIA for vintage 20212 .
Because OCPA’s 3% Basic discount was benchmarked to SCE’s generation rates, these decreases in SCE’s bundled generation put additional downward pressure on OCPA’s FY2024/25 revenues, even as underlying energy costs were rising.
To preserve customer affordability, OCPA:
Maintained the 3% Basic discount and product differentials in its 2025 rate design; Deferred $45 million of FY2023/24 revenue under GASB Statement No. 62 into 2025 to help cover FY2024/25 and FY2025/26 costs and meet lender-mandated financial requirements; and 2 OCPA’s initial customer enrollment began in April 2022 for commercial customers, who were assigned to vintage 2021. SCE applies the PCIA using the concept of “vintaging” to allocate costs to customers based on the month and year they departed SCE. For example, customers are assigned to vintage 2021 if they transitioned from SCE to join OCPA before July 1, 2022.
Recommended city default product adjustments (using Smart Choice as a temporary default for Buena Park and, initially, for Irvine) to mitigate bill impacts while preserving the underlying rate structure and customer choice.
Irvine ultimately elected Basic Choice as its default product effective February 2025. Buena Park designated Smart Choice as its default beginning March 2025, with a plan to restore 100% Renewable Choice as the default in January 2027. Throughout, any customer could opt up or down among OCPA products based on their own bill sensitivity and clean energy preferences.
On January 22, 2025, the Board approved the 2025 rate design, maintaining the 2024 structure.
This decision demonstrates that OCPA has already used one-time tools (deferred revenue, temporary default adjustments) to maintain competitiveness and avoid rate increases through 2025, leaving limited room to repeat those tools in 2026 without jeopardizing financial stability.
III. SCE VOLATILITY, 2026 PCIA CHANGES, AND STRUCTURAL DISTORTION Ongoing SCE Volatility
Throughout 2025, SCE continued to implement frequent and significant rate changes:
January 1, 2025: New ERRA rates effective, with an ~8% decrease in bundled generation rates and a ~43% PCIA increase.
March 1, 2025: Further adjustments to remove amortized 2021 expenses and modify time-of-use differentials (affecting delivery charges). June 1, 2025: Delivery-side changes, including recovery of 2017 Thomas Fire costs and transmission access charge updates.
October 1, 2025: System-average bundled generation rates increased by about 18.8% compared to January 2025, ending an off-cycle reduction driven by an approximately $750 million overcollection of generation revenues, and SCE implemented a ~10% delivery rate increase from its General Rate Case (GRC), affecting all customers, including OCPA’s.
In summary, SCE adjusted rates multiple times per year, with bundled generation rate changes of roughly 8% to 19% over only a few months. For customers, the actual impact is better reflected by the average SCE equivalent generation rate over time than by any single point-in-time rate.
Using SCE’s equivalent generation rate data from 2023-2025, the average SCE equivalent residential generation rate is approximately 13.7¢/kWh, very close to OCPA’s proposed 2026 Basic Choice average residential rate of about 13.9¢/kWh.
CPUC RA MPB / PCIA Methodology Change for 2026
In 2025, the CPUC adopted a new methodology for the RA Market Price Benchmark (RA MPB) within the statewide PCIA framework (Decision 25-06-049). IOUs advocated strongly for this change. RA market prices began to fall in 2025; under the prior method, that would have lowered the RA MPB. The new methodology, however, amplifies the effect of lower RA prices in the PCIA calculation and was applied retroactively to true up 2025 PCIA charges already in effect.
As a result, for 2026:
SCE’s bundled generation rates appear lower than they would under prior methods; PCIA charges are significantly higher, particularly for CCA customers across the state; and These outcomes are driven by mechanical accounting changes, not a corresponding reduction in IOU underlying power costs.
California Community Choice Association (CalCCA) has formally opposed this decision, filed an application for rehearing at the CPUC followed by an appeal in the Court of Appeal, arguing that the current approach reallocates costs and value in a way that favors IOU bundled customers, shifts costs onto CCA customers, and introduces improper retroactive ratemaking that destabilizes CCA budgeting and long-term planning statewide.
SCE’s 2026 ERRA Forecast and Final Rates
SCE’s 2026 ERRA forecast went through multiple rounds of updates and corrections in 2025. In an updated 2026 forecast issued in October 2025, SCE projected:
Lower bundled generation rates (about 1.3¢/kWh, roughly 12% below 2025); and Much higher PCIA charges (about 3.0¢/kWh increase for vintage 2021, more than tripling the 2025 level).
After SCE and CalCCA identified modeling and accounting errors, SCE filed an Amended 2026 ERRA Forecast on October 27, 2025, followed by a further update on November 17, 2025. That November update showed that SCE’s 2026 system-average bundled generation rate is approximately 11% lower than 2025 (about 1.3¢/kWh), while PCIA for vintage 2021 increases by about 2.3¢/kWh, again more than three times the 2025 amount.
SCE subsequently filed Advice Letter 5725-E on December 30, 2025, establishing its final 2026 rates. The final rates show bundled generation rates decreasing between approximately 9% and 16%, depending on customer class, with the system-average bundled generation rate decreasing by about 11% and the PCIA for vintage 2021 increasing by about 2.3¢/kWh relative to 2025, more than tripling the prior-year charge.
Together, the RA MPB decision, CalCCA’s statewide analysis, and SCE’s ERRA updates confirm that:
2026 is an unusual comparison year characterized by significantly reduced bundled generation rates paired with substantially higher PCIA charges; and These dynamics create structural headwinds for CCAs and their customers, rather than reflecting OCPA-specific management decisions.
IV. BILL IMPACTS AND DRIVERS OF CUSTOMER COSTS
Total electric bills are driven by two main components:
Generation charges, set by OCPA for OCPA customers or by SCE for bundled customers; and Delivery charges, set and collected by SCE for all customers in its service territory (including OCPA customers), which fund transmission, distribution, metering, and related infrastructure.
According to the CPUC’s Public Advocates Office, average SCE residential electricity rates increased about 83% between January 2015 and April 2025.
Delivery charges are projected to account for nearly 70% of a typical SCE residential bill in 2026, with generation charges around 30%. In recent years, most of the total bill increases have occurred on the delivery side, which OCPA does not control. As a result, even as SCE and OCPA generation rates have decreased at times, customers have seen limited overall bill relief because rising delivery charges have offset savings from lower generation rates. Illustrative graphs prepared for this item show:
The growth of delivery costs (yellow bars) versus generation costs (dark blue bars) from 2022- 2025; and
Seasonal variation in residential bills for a typical Fullerton customer, with kWh usage and total charges roughly doubling in summer compared to winter.
These visuals reinforce that the bill pressure customers experience is largely driven by statewide transmission and distribution costs, not by OCPA’s generation rates, and they provide important context for evaluating the proposed 2026 rate stabilization approach.
For a typical residential customer using 425 kWh per month, under the proposed 2026 OCPA rates and SCE’s adopted 2026 bundled rates (with SCE’s default service at 38% renewable content per its 2024 Power Content Label):
Basic Choice (49% renewable): total monthly bill about 12% higher than an SCE bundled customer;
Smart Choice (60% renewable + 40% carbon-free): total monthly bill about 15% higher; 100% Renewable Choice (100% renewable): total monthly bill about 16% higher in exchange for substantially higher renewable content than SCE’s default.
In all three cases, the total bill difference reflects:
OCPA’s higher clean energy content; and
The temporary distortion created by SCE’s unusually low 2026 bundled generation rates and elevated PCIA.
From a total-bill perspective, the 2026 rate stabilization approach does not introduce a new OCPA-driven increase. It holds OCPA’s generation share of the bill at current levels while SCE’s mechanically reduced 2026 generation rates temporarily make SCE’s total bills lower for many customers.
V. 2026 REVENUE REQUIREMENT, RESERVES, AND RATE STABILIZATION 2026 Revenue Requirement and Projected Gap
Staff projects that OCPA’s total revenue requirement to recover projected 2026 costs is approximately $268 million, as summarized below:
$ in thousands CY2026 Projection
Cost of Energy $248,106
Other Operating and Non-Operating Expenses 20,056
Total Revenue Requirement $268,162
Under the proposed rate stabilization approach (holding 2025 generation rates and product differentials through 2026), staff estimates:
Projected Revenue – Rate Stabilization: $264,419,000
This implies a projected revenue shortfall of approximately $3.7 million for calendar year 2026, which staff expects to offset with estimated energy cost savings from the potential green bond prepayment structure if executed in Q1 2026. If the prepayment is not executed on the expected timeline, or if actual savings differ materially from estimates, staff will return to the Board with options to address the variance while maintaining financial stability.
Reserves and Credit Considerations
A critical component of this recommendation is maintaining and, over time, rebuilding OCPA’s operating reserves in line with Board policy and credit-analyst expectations. Under the proposed 2026 rate approach, staff projects:
Operating reserves of approximately $42.3 million as of December 31, 2026; Equivalent to about 21% of total operating expenses, which is below the Board’s 30%-50% target range.
Operating reserves:
Provide a safeguard against risks such as changes in member agency participation, which can destabilize power contracts and raise concerns among suppliers and rating agencies; Help buffer external risks such as PCIA and SCE rate volatility, wholesale energy price swings, economic downturns, and potential shifts in customer usage patterns; and Are a key factor in achieving and maintaining an investment-grade credit rating, supporting working capital needs, competitive procurement, and compliance with lender and supplier covenants.
Peer CCAs, such as Clean Power Alliance (CPA), project reserve levels of roughly 50% of total expenditures as of June 30, 2026, illustrating the expectations credit analysts bring to the sector.
Against this backdrop, further lowering OCPA’s 2026 generation rates to match SCE’s temporarily reduced bundled generation rates would push reserves even further below policy targets and weaken OCPA’s financial resilience and credit profile. The rate stabilization proposal is therefore grounded in fiscal responsibility as well as customer protection.
Rate Stabilization Proposal
Under the proposed 2026 approach:
OCPA will maintain 2025 generation rates in 2026;
The existing 2025 rate levels for Basic, Smart (+1¢/kWh), and 100% Renewable (+1.5¢/kWh) will be maintained, unless modified by future Board action; and Staff will monitor actual financial results, SCE’s 2026 rate updates, and statewide proceedings affecting PCIA and RA MPB, and will return to the Board if conditions materially change.
Freezing rates at current levels is a deliberate and conservative response to:
1. OCPA’s prior use of one-time tools (deferred revenue, default product adjustments) to preserve a 3% discount and avoid rate increases through 2025;
2. The new statewide RA MPB / PCIA methodology that temporarily lowers SCE’s 2026 bundled generation rates while sharply increasing PCIA costs and making comparisons structurally unfavorable to CCAs; and
3. SCE’s pattern of four to six rate changes per year, which makes point-in-time benchmarking unreliable.
From a total-bill perspective, OCPA customers will not see a bill increase as a direct result of the 2026 rate freeze. Generation charges remain at 2025 levels; any total bill differences versus 2025 are driven primarily by SCE’s adopted 2026 delivery rates and PCIA structure.
VI. GREEN DISCOUNT PROGRAM
To provide targeted bill relief for cost-sensitive customers while maintaining overall revenue stability, staff proposes a Green Discount Program beginning in 2026.
Core parameters:
Eligibility: Non-NEM residential customers who voluntarily opt down from their existing OCPA product;
Discount: 1% discount below SCE’s equivalent residential generation rates; Resource mix: Up to 40% carbon-free energy;
Program availability: up to net savings from the prepayment transaction (net of the estimated $3.7 million revenue gap);
Prioritization: CARE, FERA, and other income-qualified households, as administratively feasible.
Together with the 2026 rate freeze, the Green Discount Program provides a focused safety valve for households facing affordability challenges, while preserving OCPA’s overall financial stability and supporting its mission to protect families and communities over the long term.
VII. 2027 OUTLOOK AND RATE-SETTING APPROACH UNDER THE RATE
DEVELOPMENT POLICY
Looking ahead, early indicators for 2027 are more favorable than 2026. PCIA rates are expected to moderate as market conditions normalize and the effects of the new RA MPB/PCIA methodology work through the system. This suggests that the 2026 environment is a temporary distortion driven by methodology changes and short-term conditions, not a permanent shift.
At the same time, tying OCPA’s rates directly and automatically to SCE’s frequently changing bundled rates has contributed to bill volatility and customer confusion. SCE’s pattern of four to six rate changes per year and the 2026 comparison year underscore how quickly bundled-rate mechanics and PCIA implementation can move in opposite directions.
OCPA’s existing Rate Development Policy already provides a robust, Board-approved framework for rate setting: staff is directed to design rates that recover revenue requirements and support target reserves while balancing competitiveness, stability, and long-term financial viability.
Consistent with that policy, staff will:
Continue applying this framework in 2026;
Refine cost-based analytics that reflect OCPA’s own portfolio energy costs, hedging strategy, potential prepayment savings (if executed), and local program priorities, rather than IOU accounting changes; and
Evaluate practical rate-setting approaches, including cost-based benchmarks, long-term benchmarking to SCE, and hybrid structures that blend cost recovery, competitiveness targets, and reserve-building in stronger years.
In parallel, staff will continue reviewing hedging and contracting practices to ensure PCIA-related risks and other market exposures are explicitly reflected in portfolio planning, consistent with evolving CCA risk-management practices statewide.
Based on updated market information and Board direction, staff expects to return later in 2026 with recommended refinements to OCPA’s 2027 rate-setting approach that:
Align with the Rate Development Policy;
Reduce reliance on automatic SCE indexing;
Keep OCPA competitive with SCE on a long-term, average basis; and Provide clearer, more stable pricing signals for customers.
Taken together, the 2026 rate freeze, the Green Discount Program, and a policy-grounded shift away from reactive SCE-driven adjustments support OCPA’s long-term strategy: stabilize customer bills in a volatile market, protect and rebuild operating reserves toward Board targets, and align prices and programs with OCPA’s own costs and community priorities.
VIII. SUMMARY OF RECOMMENDED 2026 RATE STRATEGY
For 2026:
OCPA is not raising its generation rates.
Compared with 2025, any increase OCPA customers see on their total bills will be driven primarily by higher SCE delivery charges and PCIA mechanics, which OCPA does not control. Compared with SCE’s 2026 bundled customers, higher OCPA total bills are driven mainly by statewide CPUC/PCIA accounting changes and SCE’s unusually low 2026 bundled generation rates, not by any OCPA “markup” to its share of the bill. Over 2023-2025, SCE’s average equivalent residential generation rate has been about
13.7¢/kWh, very close to OCPA’s proposed 2026 Basic Choice average residential rate of about 13.9¢/kWh, demonstrating that the 2026 proposal is broadly aligned with recent historical SCE levels even though SCE’s 2026 bundled generation rates are temporarily lower on paper.
The recommended approach:
Pairs a temporary 2026 rate freeze with a targeted Green Discount Program option; Protects and stabilizes operating reserves in a structurally challenging year; and Positions OCPA to bring back a policy-grounded, locally controlled, competitively informed rate-setting framework for 2027 that better reflects OCPA’s own costs and long-term community goals.
This strategy is consistent with the Board-adopted Reserve, Rate Development, and Rate Stabilization Fund policies and with credit-analyst guidance for CCAs. It is designed to protect customers and OCPA’s financial strength while the statewide RA MPB/PCIA issues are addressed.
FISCAL IMPACT
Under the proposed 2026 generation rate stabilization approach, OCPA would maintain existing 2025 generation rates and product differentials (see attachments). Based on current projections, 2026 revenues, together with OCPA’s estimated green bond prepayment savings (if executed in Q1 2026), are expected to be sufficient to meet OCPA’s total 2026 revenue requirement of approximately $268 million.
Green Discount Program costs are expected to be limited. Staff will actively monitor financial impacts and will return to the Board with any recommendation to expand, extend, or significantly change program parameters.
Staff will continue to monitor wholesale market conditions, SCE’s ERRA and PCIA outcomes, and customer load trends. Updated forward projections and any recommended budget or rate-related adjustments will be presented in the OCPA FY2025/26 Mid-Year Budget Update (Spring 2026), and staff expects to return in Q3 2026 with an updated outlook and recommended refinements for 2027, consistent with the Board-approved Rate Development Policy.
ATTACHMENTS
1. Glossary
2. OCPA Existing Rates Schedules Effective October 20, 2025 – Residential and Commercial Customers
3. Policy No. 19 Reserve
4. Policy No. 21 Rate Development
5. Policy No. 24 OCPA Rate Stabilization Fund Policy
6. CalCCA – PCIA Explanation
Glossary
Power Charge Indifference Adjustment (PCIA)
The PCIA is a fee charged by IOUs to CCA customers to ensure that remaining utility (bundled) customers do not face cost increases due to customers migrating to a CCA. The PCIA calculation methodology is established by the CPUC and is updated annually. Vintages are assigned based on the year of customer departures from the utility.
CCA customers are responsible for paying this fee, which is set by utilities. However, CCAs, including OCPA, typically set their rates lower to help offset the impact of the PCIA on their customers.
Community Choice Aggregation (CCA)
In 2002, the California State Legislature allowed for cities and counties to procure electricity for customers within their respective jurisdictions. CCAs allow local governments to purchase renewable energy on behalf of their communities, while still receiving transmission and distribution service from for-profit utilities.
OCPA launched in 2022 and is part of a growing movement of 25 CCAs serving more than 15 million customers in California across 200 communities.
Energy Resource Recovery Account (ERRA) Forecast
ERRA is a utility account used to track and recover the actual costs of fuel and power provided for customers. Utilities use ERRA proceedings to determine the rates they can charge customers for these costs. Utilities do not make any profit on these costs but are authorized to fully recover the actual expenses incurred on a reasonable basis.
Balancing accounts
A balancing account is an accounting tool utilities use to track the difference between projected and actual expenses or revenues. The California Public Utilities Commission (CPUC) uses balancing accounts to monitor funds authorized for recovery or amortization.
The ERRA is an example of a two-way balancing account that records and recovers power costs.
It tracks both overcollections and undercollections, ensuring that any surplus is returned to ratepayers, while deficits are collected from them.
2023 ERRA Trigger surcharge
SCE 2023 ERRA trigger surcharge was a request for a rate adjustment submitted to the CPUC. SCE filed this request on January 31, 2023.
California Public Utilities Commission (CPUC)
CPUC is a state agency that regulates investor-owned utilities (IOUs) in California. Its responsibilities include overseeing utility services, protecting consumers, safeguarding the environment, and ensuring Californians have access to safe and reliable utility infrastructure and services.
While the CPUC does not regulate the pricing of Community Choice Aggregators (CCAs), it enforces various operational requirements mandated by the legislature. These include compliance with the Renewable Portfolio Standard (RPS), Energy Storage mandates, Resource Adequacy (RA) requirements, public goods charge energy efficiency funding, and rate comparison disclosures.
Market Price Benchmark (MPB)
The MPB is an average of utility portfolio costs used in calculating the ERRA Forecast Updates. It is a key component in the PCIA calculations. The MPB is determined using the volume-weighted average of market transactions and is used to calculate the final energy values in the PCIA.
Investor-Owned Utility (IOU)
An IOU is a private, for-profit company that provides essential services like electricity, gas, or water. It operates as a regulated monopoly in a specific area to deliver services to customers while generating returns for its shareholders. Southern California Edison (SCE) is the IOU that serves OCPA’s customers.
Governmental Accounting Standards Board (GASB)
The GASB establishes accounting and financial reporting standards for U.S., state, and local governments that follow generally accepted accounting principles (GAAP). GAAP is a set of rules, standards, and procedures for financial reporting in the U.S.
General Rate Case (GRC)
GRCs are proceedings used to address the costs of operating and maintaining the utility system and the allocation of those costs among customer classes. GRCs are parsed into two phases.
Phase I determines the total amount the utility is authorized to collect, while Phase II determines the share of the cost each customer class is responsible for and the rate schedules for each class.
Public Advocates Office (Cal Advocates)
The Public Advocates Office was created in 1984 and is a State entity charged with helping ensure Californians are represented at the California Public Utilities Commission and in other forums. Their mission is to advocate for the lowest possible bills for customers of California’s regulated utilities consistent with safety, reliability, and the state’s climate goals.
Resource Adequacy (RA)
The CPUC adopted a RA policy framework in 2004, as outlined in Public Utilities Code section 380, to ensure the reliability of electric service in California. This framework established RA obligations for all LSEs within the CPUC’s jurisdiction, including IOUs, energy service providers (ESPs), and CCAs.
The RA policy framework, implemented through the RA program, guides resource procurement and promotes infrastructure investment by requiring LSEs to procure capacity to ensure that resources are available to the California Independent System Operator (CAISO) when and where they are needed.
To ensure LSEs can meet peak demand, the CPUC requires CCAs to submit annual and monthly filings demonstrating compliance with specified capacity procurement percentages. The RA program includes separate requirements for system, local, and flexible RA.
Resource Adequacy Market Price Benchmark (RA MPB)
The RA MPB determines the value of capacity resources in the IOUs’ portfolios that the IOUs retain to serve their bundled customers. It is one of the components that go into calculating the forecast portfolio value, which will be subtracted from portfolio costs to get the PCIA.
California Community Choice Association (CalCCA)
CalCCA represents the interests of California’s community choice electricity providers in the legislature and at state regulatory agencies. CalCCA’s voting membership is comprised of operating CCA programs in California that are serving load or about to launch. CalCCA’s mission is to create a legislative and regulatory environment that supports the development of long-term sustainability of locally run CCAs in California.
Renewable Portfolio Standards (RPS)
RPS are regulations that require energy providers to generate a minimum percentage of their energy from renewable sources.
California's RPS program was established in 2002 by Senate Bill (SB) 1078 (Sher, 2002), which initially mandated that 20% of electricity retail sales be served by renewable resources by 2017.
The program was later expanded by SB 100 (de León, 2018), which increased the RPS requirement to 60% by 2030 and mandated that 100% of California’s electricity come from carbon-free resources by 2045.
The California Energy Commission (CEC) verifies the eligibility of renewable energy procured by LSEs, including retail sellers, publicly owned utilities (POUs), and other entities serving retail electricity sales in California that are obligated to participate and report to the RPS program.
Eligible renewable resources are defined in California Public Resources Code § 25741 and include facilities using the following technologies: Biomass, Solar Thermal, Photovoltaic, Wind, Geothermal, Fuel cells using renewable fuels, Hydroelectric under 30 MW, Digester gas, Municipal solid waste conversion, Landfill gas, Ocean wave, Ocean thermal, Tidal current.
Power Content Label (PCL)
Under the California Energy Commission Power Source Disclosure Program, retail suppliers, including OCPA and SCE, are required to disclose the mix of sources used to provide electricity service during the previous calendar year. The information is reported and presented in the PCL, according to high prescriptive regulations, and reviewed by the California Energy Commission.
Net Energy Metering (NEM)
NEM is a billing mechanism that allows customers with renewable energy systems, like solar panels, to receive credit for surplus electricity they send back to the grid.
California Alternate Rates for Energy (CARE)
CARE is a financial assistance program administered by SCE that helps qualifying families lower their monthly energy bills with a 32.5% bill discount. OCPA customers have access to the same rate assistance programs offered by SCE and CARE remains available to eligible OCPA customers.
Family Electrical Rate Assistance (FERA)
FERA is another financial assistance program administered by SCE that helps qualifying families lower their monthly energy bills with an 18% bill discount. OCPA customers have access to the same rate assistance programs offered by SCE and FERA remains available to eligible OCPA customers.
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
DOMESTIC
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.13983 $ 0.14983 $ 0.15483 $ All electric usage TOU-D-4 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.27772 $ 0.28772 $ 0.29272 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.15845 $ 0.16845 $ 0.17345 $ 4pm - 9pm, Saturday, Sunday, & holidays SUMMER OFF-PEAK 0.09541 $ 0.10541 $ 0.11041 $ All other hours WINTER MID-PEAK 0.20482 $ 0.21482 $ 0.21982 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.12398 $ 0.13398 $ 0.13898 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.10466 $ 0.11466 $ 0.11966 $ 8am - 4pm, every day TOU-D-5 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.42963 $ 0.43963 $ 0.44463 $ 5pm - 8pm, Monday - Friday SUMMER MID-PEAK 0.23069 $ 0.24069 $ 0.24569 $ 5pm - 8pm, Saturday, Sunday, & holidays SUMMER OFF-PEAK 0.08550 $ 0.09550 $ 0.10050 $ All other hours WINTER MID-PEAK 0.29519 $ 0.30519 $ 0.31019 $ 5pm - 8pm, every day WINTER OFF-PEAK 0.12225 $ 0.13225 $ 0.13725 $ 8pm - 8am, every day WINTER SUPER OFF-PEAK 0.09415 $ 0.10415 $ 0.10915 $ 8am - 5pm, every day TOU-D-A Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.30576 $ 0.31576 $ 0.32076 $ 2pm - 8pm, Monday - Friday SUMMER OFF-PEAK 0.13544 $ 0.14544 $ 0.15044 $ 8am - 2pm & 8pm - 10pm, Monday - Friday 8am - 10pm, Saturday, Sunday & holidays
SUMMER SUPER OFF-PEAK 0.09933 $ 0.10933 $ 0.11433 $ 10pm - 8am, every day WINTER ON-PEAK 0.18702 $ 0.19702 $ 0.20202 $ 2pm - 8pm, Monday - Friday WINTER OFF-PEAK 0.10631 $ 0.11631 $ 0.12131 $ 8am - 2pm & 8pm - 10pm, Monday - Friday 8am - 10pm, Saturday, Sunday & holidays
WINTER SUPER OFF-PEAK 0.10132 $ 0.11132 $ 0.11632 $ 10pm - 8am, every day TOU-D-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.45185 $ 0.46185 $ 0.46685 $ 2pm - 8pm, Monday - Friday SUMMER OFF-PEAK 0.13539 $ 0.14539 $ 0.15039 $ 8am - 2pm & 8pm - 10pm, Monday - Friday 8am - 10pm, Saturday, Sunday & holidays
SUMMER SUPER OFF-PEAK 0.05525 $ 0.06525 $ 0.07025 $ 10pm - 8am, every day WINTER ON-PEAK 0.18080 $ 0.19080 $ 0.19580 $ 2pm - 8pm, Monday - Friday WINTER OFF-PEAK 0.10631 $ 0.11631 $ 0.12131 $ 8am - 2pm & 8pm - 10pm, Monday - Friday 8am - 10pm, Saturday, Sunday & holidays
WINTER SUPER OFF-PEAK 0.05622 $ 0.06622 $ 0.07122 $ 10pm - 8am, every day TOU-D-PRIME Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.33509 $ 0.34509 $ 0.35009 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.12780 $ 0.13780 $ 0.14280 $ 4pm - 9pm, Saturday, Sunday, & holidays SUMMER OFF-PEAK 0.08974 $ 0.09974 $ 0.10474 $ All other hours WINTER MID-PEAK 0.29466 $ 0.30466 $ 0.30966 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.07790 $ 0.08790 $ 0.09290 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.07790 $ 0.08790 $ 0.09290 $ 8am - 4pm, every day TOU-D-T Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.17374 $ 0.18374 $ 0.18874 $ 12pm - 6pm, Monday - Friday except holidays*
SUMMER OFF-PEAK 0.15916 $ 0.16916 $ 0.17416 $ All other hours WINTER ON-PEAK 0.13239 $ 0.14239 $ 0.14739 $ 12pm - 6pm, Monday - Friday except holidays*
WINTER OFF-PEAK 0.12156 $ 0.13156 $ 0.13656 $ All other hours
RESIDENTIAL CUSTOMERS
*Holidays are New Year's Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas.
OCPA Rate RIN - Basic Choice RIN - Smart Choice RIN - 100% Renewable TOU-D-4 USCA-XXOC-0017-0000 USCA-XXOC-0125-0000 USCA-XXOC-0124-0000 TOU-D-5 USCA-XXOC-0018-0000 USCA-XXOC-0127-0000 USCA-XXOC-0126-0000 TOU-D-A USCA-XXOC-0019-0000 USCA-XXOC-0129-0000 USCA-XXOC-0128-0000 TOU-D-B USCA-XXOC-0020-0000 USCA-XXOC-0131-0000 USCA-XXOC-0130-0000 TOU-D-PRIME USCA-XXOC-0021-0000 USCA-XXOC-0133-0000 USCA-XXOC-0132-0000 TOU-D-T USCA-XXOC-0022-0000 USCA-XXOC-0135-0000 USCA-XXOC-0134-0000 Orange County Power Authority Rate Identification Number (RIN) Key The tables below show the corresponding Rate Identification Number (RIN) to Orange County Power Authority (OCPA) rate.
OCPA rates that are not time-dependent or Time-of-Use (TOU) do not have a corresponding RIN and are therefore excluded from this key. Your RIN can also be found below the "Details of your new charges" section on the generation portion of your utility bill.
Residential Customers
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
TOU-GS-1-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.12953 $ 0.13953 $ 0.14453 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11766 $ 0.12766 $ 0.13266 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07956 $ 0.08956 $ 0.09456 $ 9pm - 4pm, every day WINTER MID-PEAK 0.12235 $ 0.13235 $ 0.13735 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08847 $ 0.09847 $ 0.10347 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.06798 $ 0.07798 $ 0.08298 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00050) (0.00050) $ (0.00050) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00095) (0.00095) $ (0.00095) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00098) (0.00098) $ (0.00098) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 17.25 $ 17.25 $ 17.25 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 5.30 $ 5.30 $ 5.30 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 2-50kV ($/kW)
$ (0.19) (0.19) $ (0.19) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 51-219kV ($/kW)
$ (0.45) (0.45) $ (0.45) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 220kV ($/kW)
$ (0.45) (0.45) $ (0.45) $ 4pm - 9pm, Monday - Friday
TOU-GS-1-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.46378 $ 0.47378 $ 0.47878 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.12867 $ 0.13867 $ 0.14367 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.09401 $ 0.10401 $ 0.10901 $ 9pm - 4pm, every day WINTER MID-PEAK 0.19162 $ 0.20162 $ 0.20662 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.10960 $ 0.11960 $ 0.12460 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.06090 $ 0.07090 $ 0.07590 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00137) (0.00137) $ (0.00137) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00299) (0.00299) $ (0.00299) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00305) (0.00305) $ (0.00305) $ All electric usage TOU-GS-1-ES Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.49370 $ 0.50370 $ 0.50870 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.14024 $ 0.15024 $ 0.15524 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.09926 $ 0.10926 $ 0.11426 $ 9pm - 4pm, every day WINTER MID-PEAK 0.18386 $ 0.19386 $ 0.19886 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.10280 $ 0.11280 $ 0.11780 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.05772 $ 0.06772 $ 0.07272 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00138) (0.00138) $ (0.00138) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00300) (0.00300) $ (0.00300) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00305) (0.00305) $ (0.00305) $ All electric usage TOU-GS-1-A Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.17096 $ 0.18096 $ 0.18596 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.16037 $ 0.17037 $ 0.17537 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.15457 $ 0.16457 $ 0.16957 $ All other hours WINTER MID-PEAK 0.11585 $ 0.12585 $ 0.13085 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.10498 $ 0.11498 $ 0.11998 $ All other hours TOU-GS-1-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.09646 $ 0.10646 $ 0.11146 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.09068 $ 0.10068 $ 0.10568 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08753 $ 0.09753 $ 0.10253 $ All other hours WINTER MID-PEAK 0.11585 $ 0.12585 $ 0.13085 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.10498 $ 0.11498 $ 0.11998 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 12.67 $ 12.67 $ 12.67 $ 12pm - 6pm, Monday - Friday
COMMERCIAL CUSTOMERS
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
SUMMER MID-PEAK 4.12 $ 4.12 $ 4.12 $ 8am - 12pm & 6pm - 11pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
TOU-GS-2-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.12530 $ 0.13530 $ 0.14030 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11491 $ 0.12491 $ 0.12991 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07639 $ 0.08639 $ 0.09139 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08700 $ 0.09700 $ 0.10200 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08748 $ 0.09748 $ 0.10248 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04946 $ 0.05946 $ 0.06446 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00096) (0.00096) $ (0.00096) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00214) (0.00214) $ (0.00214) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00214) (0.00214) $ (0.00214) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 21.88 $ 21.88 $ 21.88 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 5.75 $ 5.75 $ 5.75 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 2-50kV ($/kW) $ (0.50) (0.50) $ (0.50) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 51-219kV ($/kW) $ (1.14) (1.14) $ (1.14) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (1.16) (1.16) $ (1.16) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 2-50kV
($/kW)
$ (0.13) (0.13) $ (0.13) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 51-
219kV ($/kW)
$ (0.30) (0.30) $ (0.30) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.30) (0.30) $ (0.30) $ 4pm - 9pm, Monday - Friday
TOU-GS-2-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.40463 $ 0.41463 $ 0.41963 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11491 $ 0.12491 $ 0.12991 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07639 $ 0.08639 $ 0.09139 $ 9pm - 4pm, every day WINTER MID-PEAK 0.13145 $ 0.14145 $ 0.14645 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08748 $ 0.09748 $ 0.10248 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04946 $ 0.05946 $ 0.06446 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00144) (0.00144) $ (0.00144) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00323) (0.00323) $ (0.00323) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00325) (0.00325) $ (0.00325) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 6.08 $ 6.08 $ 6.08 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 2.35 $ 2.35 $ 2.35 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 2-50kV ($/kW) $ (0.20) (0.20) $ (0.20) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 51-219kV ($/kW) $ (0.47) (0.47) $ (0.47) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (0.48) (0.48) $ (0.48) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 2-50kV
($/kW)
$ (0.04) (0.04) $ (0.04) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 51-
219kV ($/kW)
$ (0.12) (0.12) $ (0.12) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.12) (0.12) $ (0.12) $ 4pm - 9pm, Monday - Friday
TOU-GS-2-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.09275 $ 0.10275 $ 0.10775 $ 12pm - 6pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
SUMMER MID-PEAK 0.08724 $ 0.09724 $ 0.10224 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08421 $ 0.09421 $ 0.09921 $ All other hours WINTER MID-PEAK 0.11111 $ 0.12111 $ 0.12611 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06867 $ 0.07867 $ 0.08367 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 15.17 $ 15.17 $ 15.17 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 5.10 $ 5.10 $ 5.10 $ 8am - 12pm & 6pm - 11pm, Monday - Friday TOU-GS-2-R Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.29310 $ 0.30310 $ 0.30810 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.14318 $ 0.15318 $ 0.15818 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08421 $ 0.09421 $ 0.09921 $ All other hours WINTER MID-PEAK 0.11111 $ 0.12111 $ 0.12611 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06867 $ 0.07867 $ 0.08367 $ All other hours
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00246) (0.00246) $ (0.00246) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00556) (0.00556) $ (0.00556) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00562) (0.00562) $ (0.00562) $ All electric usage Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
TOU-GS-3-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11657 $ 0.12657 $ 0.13157 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10693 $ 0.11693 $ 0.12193 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07455 $ 0.08455 $ 0.08955 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08493 $ 0.09493 $ 0.09993 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08540 $ 0.09540 $ 0.10040 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04827 $ 0.05827 $ 0.06327 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00097) (0.00097) $ (0.00097) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00213) (0.00213) $ (0.00213) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00216) (0.00216) $ (0.00216) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 18.78 $ 18.78 $ 18.78 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 6.79 $ 6.79 $ 6.79 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 2-50kV ($/kW) $ (0.43) (0.43) $ (0.43) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 51-219kV ($/kW) $ (1.00) (1.00) $ (1.00) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (1.01) (1.01) $ (1.01) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 2-50kV
($/kW)
$ (0.17) (0.17) $ (0.17) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 51-
219kV ($/kW)
$ (0.36) (0.36) $ (0.36) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.37) (0.37) $ (0.37) $ 4pm - 9pm, Monday - Friday
TOU-GS-3-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.33108 $ 0.34108 $ 0.34608 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10693 $ 0.11693 $ 0.12193 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07455 $ 0.08455 $ 0.08955 $ 9pm - 4pm, every day WINTER MID-PEAK 0.13266 $ 0.14266 $ 0.14766 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08540 $ 0.09540 $ 0.10040 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04827 $ 0.05827 $ 0.06327 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00179) (0.00179) $ (0.00179) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00399) (0.00399) $ (0.00399) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00404) (0.00404) $ (0.00404) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 5.22 $ 5.22 $ 5.22 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 2.79 $ 2.79 $ 2.79 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 2-50kV ($/kW) $ (0.17) (0.17) $ (0.17) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 51-219kV ($/kW) $ (0.42) (0.42) $ (0.42) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (0.41) (0.41) $ (0.41) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 2-50kV
($/kW)
$ (0.07) (0.07) $ (0.07) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 51-
219kV ($/kW)
$ (0.16) (0.16) $ (0.16) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.15) (0.15) $ (0.15) $ 4pm - 9pm, Monday - Friday
TOU-GS-3-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.08856 $ 0.09856 $ 0.10356 $ 12pm - 6pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
SUMMER MID-PEAK 0.08318 $ 0.09318 $ 0.09818 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08043 $ 0.09043 $ 0.09543 $ All other hours WINTER MID-PEAK 0.11047 $ 0.12047 $ 0.12547 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06737 $ 0.07737 $ 0.08237 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 12.58 $ 12.58 $ 12.58 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 4.20 $ 4.20 $ 4.20 $ 8am - 12pm & 6pm - 11pm, Monday - Friday TOU-GS-3-R Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.24347 $ 0.25347 $ 0.25847 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.12371 $ 0.13371 $ 0.13871 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08043 $ 0.09043 $ 0.09543 $ All other hours WINTER MID-PEAK 0.11047 $ 0.12047 $ 0.12547 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06737 $ 0.07737 $ 0.08237 $ All other hours
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00209) (0.00209) $ (0.00209) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00469) (0.00469) $ (0.00469) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00476) (0.00476) $ (0.00476) $ All electric usage Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
TOU-8-SEC-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11595 $ 0.12595 $ 0.13095 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10635 $ 0.11635 $ 0.12135 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07431 $ 0.08431 $ 0.08931 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08469 $ 0.09469 $ 0.09969 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08517 $ 0.09517 $ 0.10017 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04804 $ 0.05804 $ 0.06304 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 19.75 $ 19.75 $ 19.75 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 6.05 $ 6.05 $ 6.05 $ 4pm - 9pm, Monday - Friday TOU-8-PRI-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11007 $ 0.12007 $ 0.12507 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10118 $ 0.11118 $ 0.11618 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07065 $ 0.08065 $ 0.08565 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08062 $ 0.09062 $ 0.09562 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08124 $ 0.09124 $ 0.09624 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04589 $ 0.05589 $ 0.06089 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 18.80 $ 18.80 $ 18.80 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 7.03 $ 7.03 $ 7.03 $ 4pm - 9pm, Monday - Friday TOU-8-SUB-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.10331 $ 0.11331 $ 0.11831 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.09522 $ 0.10522 $ 0.11022 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06616 $ 0.07616 $ 0.08116 $ 9pm - 4pm, every day WINTER MID-PEAK 0.07555 $ 0.08555 $ 0.09055 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.07637 $ 0.08637 $ 0.09137 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04314 $ 0.05314 $ 0.05814 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00062) (0.00062) $ (0.00062) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 20.77 $ 20.77 $ 20.77 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 6.71 $ 6.71 $ 6.71 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (0.20) (0.20) $ (0.20) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.06) (0.06) $ (0.06) $ 4pm - 9pm, Monday - Friday
TOU-8-SEC-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.31943 $ 0.32943 $ 0.33443 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10635 $ 0.11635 $ 0.12135 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07431 $ 0.08431 $ 0.08931 $ 9pm - 4pm, every day WINTER MID-PEAK 0.12420 $ 0.13420 $ 0.13920 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08517 $ 0.09517 $ 0.10017 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04804 $ 0.05804 $ 0.06304 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 5.49 $ 5.49 $ 5.49 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 2.48 $ 2.48 $ 2.48 $ 4pm - 9pm, Monday - Friday TOU-8-PRI-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.29991 $ 0.30991 $ 0.31491 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10118 $ 0.11118 $ 0.11618 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07065 $ 0.08065 $ 0.08565 $ 9pm - 4pm, every day WINTER MID-PEAK 0.14162 $ 0.15162 $ 0.15662 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08124 $ 0.09124 $ 0.09624 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04589 $ 0.05589 $ 0.06089 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 4.61 $ 4.61 $ 4.61 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 0.81 $ 0.81 $ 0.81 $ 4pm - 9pm, Monday - Friday TOU-8-SUB-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.32885 $ 0.33885 $ 0.34385 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.09522 $ 0.10522 $ 0.11022 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06616 $ 0.07616 $ 0.08116 $ 9pm - 4pm, every day WINTER MID-PEAK 0.12476 $ 0.13476 $ 0.13976 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.07637 $ 0.08637 $ 0.09137 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04314 $ 0.05314 $ 0.05814 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00079) (0.00079) $ (0.00079) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 1.97 $ 1.97 $ 1.97 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 0.95 $ 0.95 $ 0.95 $ 4pm - 9pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (0.02) (0.02) $ (0.02) $ 4pm - 9pm, Monday - Friday
WINTER MID-PEAK (WEEKDAYS)
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.01) (0.01) $ (0.01) $ 4pm - 9pm, Monday - Friday
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
TOU-8-SEC-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.08820 $ 0.09820 $ 0.10320 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.08256 $ 0.09256 $ 0.09756 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08008 $ 0.09008 $ 0.09508 $ All other hours WINTER MID-PEAK 0.10615 $ 0.11615 $ 0.12115 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06815 $ 0.07815 $ 0.08315 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 13.60 $ 13.60 $ 13.60 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 4.46 $ 4.46 $ 4.46 $ 8am - 12pm & 6pm - 11pm, Monday - Friday TOU-8-PRI-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.08405 $ 0.09405 $ 0.09905 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.07836 $ 0.08836 $ 0.09336 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07634 $ 0.08634 $ 0.09134 $ All other hours WINTER MID-PEAK 0.10878 $ 0.11878 $ 0.12378 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06634 $ 0.07634 $ 0.08134 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 13.23 $ 13.23 $ 13.23 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 4.26 $ 4.26 $ 4.26 $ 8am - 12pm & 6pm - 11pm, Monday - Friday TOU-8-SUB-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.07876 $ 0.08876 $ 0.09376 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.07320 $ 0.08320 $ 0.08820 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07153 $ 0.08153 $ 0.08653 $ All other hours WINTER MID-PEAK 0.10058 $ 0.11058 $ 0.11558 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06287 $ 0.07287 $ 0.07787 $ All other hours
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00062) (0.00062) $ (0.00062) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 15.13 $ 15.13 $ 15.13 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 4.90 $ 4.90 $ 4.90 $ 8am - 12pm & 6pm - 11pm, Monday - Friday
SUMMER ON-PEAK AND MID-PEAK
VOLTAGE DISCOUNT - DEMAND 220kV
($/kW)
$ (0.30) (0.30) $ (0.30) $ 8am - 11pm, Monday - Friday
TOU-8-SEC-R Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.24436 $ 0.25436 $ 0.25936 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.12057 $ 0.13057 $ 0.13557 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08008 $ 0.09008 $ 0.09508 $ All other hours WINTER MID-PEAK 0.10615 $ 0.11615 $ 0.12115 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06815 $ 0.07815 $ 0.08315 $ All other hours TOU-8-PRI-R Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.23375 $ 0.24375 $ 0.24875 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.11226 $ 0.12226 $ 0.12726 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07634 $ 0.08634 $ 0.09134 $ All other hours WINTER MID-PEAK 0.10878 $ 0.11878 $ 0.12378 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06634 $ 0.07634 $ 0.08134 $ All other hours TOU-8-SUB-R Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.23170 $ 0.24170 $ 0.24670 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.10682 $ 0.11682 $ 0.12182 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07153 $ 0.08153 $ 0.08653 $ All other hours WINTER MID-PEAK 0.10058 $ 0.11058 $ 0.11558 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.06287 $ 0.07287 $ 0.07787 $ All other hours
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00098) (0.00098) $ (0.00098) $ All electric usage TOU-8-SEC-RBU Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11595 $ 0.12595 $ 0.13095 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10635 $ 0.11635 $ 0.12135 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07431 $ 0.08431 $ 0.08931 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08469 $ 0.09469 $ 0.09969 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08517 $ 0.09517 $ 0.10017 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04804 $ 0.05804 $ 0.06304 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 19.75 $ 19.75 $ 19.75 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 6.05 $ 6.05 $ 6.05 $ 4pm - 9pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
COMMERCIAL CUSTOMERS
TOU-8-PRI-RBU Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11007 $ 0.12007 $ 0.12507 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10118 $ 0.11118 $ 0.11618 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07065 $ 0.08065 $ 0.08565 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08062 $ 0.09062 $ 0.09562 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08124 $ 0.09124 $ 0.09624 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04589 $ 0.05589 $ 0.06089 $ 8am - 4pm, every day DEMAND CHARGE ($/KW) SUMMER ON-PEAK 18.80 $ 18.80 $ 18.80 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 7.03 $ 7.03 $ 7.03 $ 4pm - 9pm, Monday - Friday TOU-8-SUB-RBU Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.10331 $ 0.11331 $ 0.11831 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.09522 $ 0.10522 $ 0.11022 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06616 $ 0.07616 $ 0.08116 $ 9pm - 4pm, every day WINTER MID-PEAK 0.07555 $ 0.08555 $ 0.09055 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.07637 $ 0.08637 $ 0.09137 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04314 $ 0.05314 $ 0.05814 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00062) (0.00062) $ (0.00062) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 20.77 $ 20.77 $ 20.77 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 6.71 $ 6.71 $ 6.71 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK VOLTAGE DISCOUNT -
DEMAND 220kV ($/kW) $ (0.20) (0.20) $ (0.20) $ 4pm - 9pm, Monday - Friday
WINTER WEEKDAYS VOLTAGE
DISCOUNT - DEMAND 220kV ($/kW) $ (0.06) (0.06) $ (0.06) $ 4pm - 9pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
TOU-EV-7 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.34960 $ 0.35960 $ 0.36460 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.12867 $ 0.13867 $ 0.14367 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.10699 $ 0.11699 $ 0.12199 $ 9pm - 4pm, every day WINTER MID-PEAK 0.19162 $ 0.20162 $ 0.20662 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.12464 $ 0.13464 $ 0.13964 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.06090 $ 0.07090 $ 0.07590 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00137) (0.00137) $ (0.00137) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00299) (0.00299) $ (0.00299) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00305) (0.00305) $ (0.00305) $ All electric usage TOU-EV-8 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.38599 $ 0.39599 $ 0.40099 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11491 $ 0.12491 $ 0.12991 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.09057 $ 0.10057 $ 0.10557 $ 9pm - 4pm, every day WINTER MID-PEAK 0.16229 $ 0.17229 $ 0.17729 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.10515 $ 0.11515 $ 0.12015 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04946 $ 0.05946 $ 0.06446 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00246) (0.00246) $ (0.00246) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00556) (0.00556) $ (0.00556) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00562) (0.00562) $ (0.00562) $ All electric usage TOU-EV-9-SEC Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.30008 $ 0.31008 $ 0.31508 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10635 $ 0.11635 $ 0.12135 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.08415 $ 0.09415 $ 0.09915 $ 9pm - 4pm, every day WINTER MID-PEAK 0.15160 $ 0.16160 $ 0.16660 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.09557 $ 0.10557 $ 0.11057 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04804 $ 0.05804 $ 0.06304 $ 8am - 4pm, every day TOU-EV-9-PRI Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.27293 $ 0.28293 $ 0.28793 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10118 $ 0.11118 $ 0.11618 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07907 $ 0.08907 $ 0.09407 $ 9pm - 4pm, every day WINTER MID-PEAK 0.14947 $ 0.15947 $ 0.16447 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08947 $ 0.09947 $ 0.10447 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04589 $ 0.05589 $ 0.06089 $ 8am - 4pm, every day TOU-EV-9-SUB Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.26595 $ 0.27595 $ 0.28095 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.09522 $ 0.10522 $ 0.11022 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07378 $ 0.08378 $ 0.08878 $ 9pm - 4pm, every day WINTER MID-PEAK 0.13291 $ 0.14291 $ 0.14791 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08309 $ 0.09309 $ 0.09809 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04314 $ 0.05314 $ 0.05814 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00098) (0.00098) $ (0.00098) $ All electric usage
BUSINESS ELECTRIC VEHICLE CUSTOMERS
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
TOU-PA-2-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.12600 $ 0.13600 $ 0.14100 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11552 $ 0.12552 $ 0.13052 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07891 $ 0.08891 $ 0.09391 $ 9pm - 4pm, every day WINTER MID-PEAK 0.10024 $ 0.11024 $ 0.11524 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08125 $ 0.09125 $ 0.09625 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.07047 $ 0.08047 $ 0.08547 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00099) (0.00099) $ (0.00099) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00219) (0.00219) $ (0.00219) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00220) (0.00220) $ (0.00220) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 12.02 $ 12.02 $ 12.02 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 2.72 $ 2.72 $ 2.72 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 2-50kV ($/kW)
$ (0.17) (0.17) $ (0.17) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 51-219kV ($/kW)
$ (0.37) (0.37) $ (0.37) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 220kV ($/kW)
$ (0.37) (0.37) $ (0.37) $ 4pm - 9pm, Monday - Friday
YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
TOU-PA-2-D5 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.24375 $ 0.25375 $ 0.25875 $ 5pm - 8pm, Monday - Friday SUMMER MID-PEAK 0.23034 $ 0.24034 $ 0.24534 $ 5pm - 8pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07441 $ 0.08441 $ 0.08941 $ 8pm - 5pm, every day WINTER MID-PEAK 0.10443 $ 0.11443 $ 0.11943 $ 5pm - 8pm, every day WINTER OFF-PEAK 0.08460 $ 0.09460 $ 0.09960 $ 8pm - 8am, every day WINTER SUPER OFF-PEAK 0.07329 $ 0.08329 $ 0.08829 $ 8am - 5pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00104) (0.00104) $ (0.00104) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00230) (0.00230) $ (0.00230) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00231) (0.00231) $ (0.00231) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 11.51 $ 11.51 $ 11.51 $ 5pm - 8pm, Monday - Friday WINTER MID-PEAK 2.14 $ 2.14 $ 2.14 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 2-50kV ($/kW)
$ (0.16) (0.16) $ (0.16) $ 5pm - 8pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 51-219kV ($/kW)
$ (0.33) (0.33) $ (0.33) $ 5pm - 8pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 220kV ($/kW)
$ (0.34) (0.34) $ (0.34) $ 5pm - 8pm, Monday - Friday
YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
AGRICULTURE CUSTOMERS
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
AGRICULTURE CUSTOMERS
TOU-PA-2-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.40681 $ 0.41681 $ 0.42181 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.11552 $ 0.12552 $ 0.13052 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07891 $ 0.08891 $ 0.09391 $ 9pm - 4pm, every day WINTER MID-PEAK 0.11492 $ 0.12492 $ 0.12992 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.09294 $ 0.10294 $ 0.10794 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.08043 $ 0.09043 $ 0.09543 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00164) (0.00164) $ (0.00164) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00357) (0.00357) $ (0.00357) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00358) (0.00358) $ (0.00358) $ All electric usage DEMAND CHARGE ($/KW) YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
TOU-PA-2-E5 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.67217 $ 0.68217 $ 0.68717 $ 5pm - 8pm, Monday - Friday SUMMER MID-PEAK 0.23034 $ 0.24034 $ 0.24534 $ 5pm - 8pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.07441 $ 0.08441 $ 0.08941 $ 8pm - 5pm, every day WINTER MID-PEAK 0.11540 $ 0.12540 $ 0.13040 $ 5pm - 8pm, every day WINTER OFF-PEAK 0.09331 $ 0.10331 $ 0.10831 $ 8pm - 8am, every day WINTER SUPER OFF-PEAK 0.08074 $ 0.09074 $ 0.09574 $ 8am - 5pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00164) (0.00164) $ (0.00164) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00358) (0.00358) $ (0.00358) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00358) (0.00358) $ (0.00358) $ All electric usage DEMAND CHARGE ($/KW) YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
TOU-PA-2-A Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.25915 $ 0.26915 $ 0.27415 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.12236 $ 0.13236 $ 0.13736 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08527 $ 0.09527 $ 0.10027 $ All other hours WINTER MID-PEAK 0.11396 $ 0.12396 $ 0.12896 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.07777 $ 0.08777 $ 0.09277 $ All other hours DEMAND CHARGE ($/KW) YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
TOU-PA-2-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.09394 $ 0.10394 $ 0.10894 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.08736 $ 0.09736 $ 0.10236 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.08527 $ 0.09527 $ 0.10027 $ All other hours WINTER MID-PEAK 0.11396 $ 0.12396 $ 0.12896 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.07777 $ 0.08777 $ 0.09277 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 8.52 $ 8.52 $ 8.52 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 2.61 $ 2.61 $ 2.61 $ 8am - 12pm & 6pm - 11pm, Monday - Friday
YEAR ROUND WIND MACHINE CREDIT
($/kW) $ (9.76) (9.76) $ (9.76) $ All electric usage
Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
AGRICULTURE CUSTOMERS
TOU-PA-3-D Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.11034 $ 0.12034 $ 0.12534 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10129 $ 0.11129 $ 0.11629 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06954 $ 0.07954 $ 0.08454 $ 9pm - 4pm, every day WINTER MID-PEAK 0.08697 $ 0.09697 $ 0.10197 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.08748 $ 0.09748 $ 0.10248 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04942 $ 0.05942 $ 0.06442 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00098) (0.00098) $ (0.00098) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00216) (0.00216) $ (0.00216) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00219) (0.00219) $ (0.00219) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 12.83 $ 12.83 $ 12.83 $ 4pm - 9pm, Monday - Friday WINTER MID-PEAK 2.76 $ 2.76 $ 2.76 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 2-50kV ($/kW)
$ (0.19) (0.19) $ (0.19) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 51-219kV ($/kW)
$ (0.45) (0.45) $ (0.45) $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 220kV ($/kW)
$ (0.45) (0.45) $ (0.45) $ 4pm - 9pm, Monday - Friday
TOU-PA-3-D5 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.20823 $ 0.21823 $ 0.22323 $ 5pm - 8pm, Monday - Friday SUMMER MID-PEAK 0.19681 $ 0.20681 $ 0.21181 $ 5pm - 8pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06583 $ 0.07583 $ 0.08083 $ 8pm - 5pm, every day WINTER MID-PEAK 0.08804 $ 0.09804 $ 0.10304 $ 5pm - 8pm, every day WINTER OFF-PEAK 0.08854 $ 0.09854 $ 0.10354 $ 8pm - 8am, every day WINTER SUPER OFF-PEAK 0.04989 $ 0.05989 $ 0.06489 $ 8am - 5pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00100) (0.00100) $ (0.00100) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00220) (0.00220) $ (0.00220) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00223) (0.00223) $ (0.00223) $ All electric usage DEMAND CHARGE ($/KW) SUMMER ON-PEAK 12.30 $ 12.30 $ 12.30 $ 5pm - 8pm, Monday - Friday WINTER MID-PEAK 2.86 $ 2.86 $ 2.86 $ 4pm - 9pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 2-50kV ($/kW)
$ (0.18) (0.18) $ (0.18) $ 5pm - 8pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 51-219kV ($/kW)
$ (0.44) (0.44) $ (0.44) $ 5pm - 8pm, Monday - Friday
SUMMER ON-PEAK AND WINTER MID-PEAK (WEEKDAYS) VOLTAGE DISCOUNT - DEMAND 220kV ($/kW)
$ (0.44) (0.44) $ (0.44) $ 5pm - 8pm, Monday - Friday
TOU-PA-3-E Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.34909 $ 0.35909 $ 0.36409 $ 4pm - 9pm, Monday - Friday SUMMER MID-PEAK 0.10129 $ 0.11129 $ 0.11629 $ 4pm - 9pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06954 $ 0.07954 $ 0.08454 $ 9pm - 4pm, every day WINTER MID-PEAK 0.12108 $ 0.13108 $ 0.13608 $ 4pm - 9pm, every day WINTER OFF-PEAK 0.09791 $ 0.10791 $ 0.11291 $ 9pm - 8am, every day WINTER SUPER OFF-PEAK 0.04022 $ 0.05022 $ 0.05522 $ 8am - 4pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00152) (0.00152) $ (0.00152) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00342) (0.00342) $ (0.00342) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00345) (0.00345) $ (0.00345) $ All electric usage Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
AGRICULTURE CUSTOMERS
TOU-PA-3-E5 Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.56802 $ 0.57802 $ 0.58302 $ 5pm - 8pm, Monday - Friday SUMMER MID-PEAK 0.19681 $ 0.20681 $ 0.21181 $ 5pm - 8pm, Saturday, Sunday, & holidays* SUMMER OFF-PEAK 0.06583 $ 0.07583 $ 0.08083 $ 8pm - 5pm, every day WINTER MID-PEAK 0.12634 $ 0.13634 $ 0.14134 $ 5pm - 8pm, every day WINTER OFF-PEAK 0.10210 $ 0.11210 $ 0.11710 $ 8pm - 8am, every day WINTER SUPER OFF-PEAK 0.04174 $ 0.05174 $ 0.05674 $ 8am - 5pm, every day
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 2-50kV ($/kWh) $ (0.00152) (0.00152) $ (0.00152) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 51-219kV ($/kWh) $ (0.00342) (0.00342) $ (0.00342) $ All electric usage
YEAR ROUND VOLTAGE DISCOUNT -
ENERGY 220kV ($/kWh) $ (0.00345) (0.00345) $ (0.00345) $ All electric usage TOU-PA-3-A Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.22617 $ 0.23617 $ 0.24117 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.10598 $ 0.11598 $ 0.12098 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07498 $ 0.08498 $ 0.08998 $ All other hours WINTER MID-PEAK 0.09901 $ 0.10901 $ 0.11401 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.07120 $ 0.08120 $ 0.08620 $ All other hours TOU-PA-3-B Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.08250 $ 0.09250 $ 0.09750 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 0.07670 $ 0.08670 $ 0.09170 $ 8am - 12pm & 6pm - 11pm, Monday - Friday SUMMER OFF-PEAK 0.07498 $ 0.08498 $ 0.08998 $ All other hours WINTER MID-PEAK 0.09901 $ 0.10901 $ 0.11401 $ 8am - 9pm, Monday - Friday WINTER OFF-PEAK 0.07120 $ 0.08120 $ 0.08620 $ All other hours DEMAND CHARGE ($/KW) SUMMER ON-PEAK 9.03 $ 9.03 $ 9.03 $ 12pm - 6pm, Monday - Friday SUMMER MID-PEAK 2.64 $ 2.64 $ 2.64 $ 8am - 12pm & 6pm - 11pm, Monday - Friday Effective: October 20, 2025
OCPA Rate Schedule Period Basic Choice Smart Choice
100% Renewable
Choice Time Period Definitions
Streetlighting
(LS-1, LS-2, DWL, and OL-1)
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.07614 $ 0.08614 $ 0.09114 $ All electric usage LS-3
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.07623 $ 0.08623 $ 0.09123 $ All electric usage AL-2-F
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.07623 $ 0.08623 $ 0.09123 $ All electric usage AL-2-GF Summer - June through September; Winter - October through May GENERATION CHARGE ($/KWH) SUMMER ON-PEAK 0.17096 $ 0.18096 $ 0.18596 $ 8am - 4pm, every day SUMMER OFF-PEAK 0.07623 $ 0.08623 $ 0.09123 $ All other hours WINTER ON-PEAK 0.11585 $ 0.12585 $ 0.13085 $ 8am - 4pm, every day WINTER OFF-PEAK 0.07623 $ 0.08623 $ 0.09123 $ All other hours TC-1
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.10561 $ 0.11561 $ 0.12061 $ All electric usage WTR
GENERATION CHARGE ($/KWH) YEAR-ROUND 0.12192 $ 0.13192 $ 0.13692 $ All electric usage *Applicable holidays for rate time periods are as follows: New Year's Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. When any holiday listed above falls on Sunday, the following Monday will be recognized as a holiday. No change will be made for holidays falling on Saturday.
STREETLIGHT CUSTOMERS
Effective: October 20, 2025
Wildfire Fund Non-Bypassable Charge
Competition Transition Charge
Rate Group WFC (All Vintages) CTC (All Vintages) GMS Factor (All Vintages) Domestic1 $ (0.00058) 0.00595 $ 0.009294
GS-12 $ (0.00041) 0.00595 $ 0.009294
TC-13 $ (0.00044) 0.00595 $ 0.009294
GS-24 $ (0.00043) 0.00595 $ 0.009294
TOU-GS-35 $ (0.00042) 0.00595 $ 0.009294
TOU-8-Sec6 $ (0.00041) 0.00595 $ 0.009294
TOU-8-Pri6 $ (0.00040) 0.00595 $ 0.009294
TOU-8-Sub6 $ (0.00038) 0.00595 $ 0.009294
Small AG7 $ (0.00042) 0.00595 $ 0.009294
Large AG8 $ (0.00042) 0.00595 $ 0.009294
St. Lighting9 $ (0.00053) 0.00595 $ 0.009294
2 Includes Schedules GS-1, TOU-GS-1, TOU-GS-1-RTP, AL-2 (On-Peak), LS-3 Option B (On- Peak), and TOU-EV-7. 3 Includes Schedules TC-1, Wi-Fi-1, and WTR.
4 Includes Schedules GS-2, TOU-EV-8, TOU-GS-2, and TOU-GS-2-RTP. 5 Includes Schedules TOU-GS-3 and TOU-GS-3-RTP.
6 Includes Schedules TOU-EV-9, TOU-8, TOU-8-RBU, and TOU-8-RTP. 7 Includes Schedules PA-1, PA-2, TOU-PA-2, and TOU-PA-2-RTP. 8 Includes Schedules TOU-PA-3 and TOU-PA-3-RTP.
9 Includes Schedules AL-2-(Off-Peak), DWL, LS-1, LS-2, LS-3, LS-3 Option B (Off-Peak), and OL-1.
The ongoing Competition Transition Charge (CTC) recovers the CPUC-approved market price limit for legacy electricity contracts (signed prior to 1998), as well as statutorily authorized costs that are related to restructuring of California’s electric industry prior to the energy crisis. These charges are assessed to all customers, including SCE-only customers, but are collected separately for CCA customers and go directly to SCE.
The Wildfire Fund Non-Bypassable Charge (WFC) supports the California Wildfire Fund. This charge is assessed to all customers, including SCE-only customers, but is collected separately for CCA customers. The funds go to the State of California for potential disbursement to IOUs, such as SCE, if a catastrophic event occurs. Customers on CARE and Medical Baseline Programs are currently exempt from these charges.
OCPA Rates in SCE Territory
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Surcharge
The Generation Municipal Surcharge (GMS) Factor recovers franchise fees paid by SCE to operate within certain municipal jurisdictions within California. This charge is assessed to all customers, including SCE-only customers, but is collected separately for CCA customers. The charge equals the product of the GMS factor and the SCE rates or charges that have been removed from the bill of a customer receiving CCA service. An exemption applies to CA political subdivision and certain cogeneration or nonutility generation facilities. It is the responsibility of the customer to self-identify for exemption.
Effective: October 20, 2025
Power Charge Indifference Adjustment
Rate Group PCIA Vintage
Domestic1 $ 2022 (0.01310)
GS-12 $ 2021 (0.00690)
TC-13 $ 2021 (0.00733)
GS-24 $ 2021 (0.00723)
TOU-GS-35 $ 2021 (0.00702)
TOU-8-Sec6 $ 2021 (0.00684)
TOU-8-Pri6 $ 2021 (0.00670)
TOU-8-Sub6 $ 2021 (0.00633)
Small AG7 $ 2021 (0.00708)
Large AG8 $ 2021 (0.00700)
St. Lighting9 $ 2021 (0.00884)
The Power Charge Indifference Adjustment (PCIA) is a fee collected by SCE and assessed to customers who receive their electric generation services from another provider. The PCIA is considered an "exit fee" assessed by SCE to cover costs for departing customers; resources acquired prior to a customer's change in service providers, and to ensure their current customers are “indifferent” to costs associated with the departed customers. SCE assigns customers a "PCIA Vintage" based on the date a customer’s respective community enrolled in alternative service; this date is reset upon reenrollment if a customer opts-out and later re-enrolls in OCPA service. The PCIA is charged on a per kWh basis based on net monthly usage, and is unaffected by time of use.
OCPA Rates in SCE Territory
OCPA Rate RIN - Basic Choice RIN - Smart Choice RIN - 100% Renewable TOU-GS-1-SEC-D USCA-XXOC-0038-0000 USCA-XXOC-0167-0000 USCA-XXOC-0166-0000 TOU-GS-1-PRI-D USCA-XXOC-0035-0000 USCA-XXOC-0161-0000 USCA-XXOC-0160-0000 TOU-GS-1-SUB-D USCA-XXOC-0041-0000 USCA-XXOC-0173-0000 USCA-XXOC-0172-0000 TOU-GS-1-SEC-E USCA-XXOC-0039-0000 USCA-XXOC-0169-0000 USCA-XXOC-0168-0000 TOU-GS-1-PRI-E USCA-XXOC-0036-0000 USCA-XXOC-0163-0000 USCA-XXOC-0162-0000 TOU-GS-1-SUB-E USCA-XXOC-0042-0000 USCA-XXOC-0175-0000 USCA-XXOC-0174-0000 TOU-GS-1-SEC-ES USCA-XXOC-0040-0000 USCA-XXOC-0171-0000 USCA-XXOC-0170-0000 TOU-GS-1-PRI-ES USCA-XXOC-0037-0000 USCA-XXOC-0165-0000 USCA-XXOC-0164-0000 TOU-GS-1-SUB-ES USCA-XXOC-0043-0000 USCA-XXOC-0177-0000 USCA-XXOC-0176-0000 TOU-GS-1-A USCA-XXOC-0033-0000 USCA-XXOC-0157-0000 USCA-XXOC-0156-0000 TOU-GS-1-B USCA-XXOC-0034-0000 USCA-XXOC-0159-0000 USCA-XXOC-0158-0000 TOU-GS-2-SEC-D USCA-XXOC-0048-0000 USCA-XXOC-0187-0000 USCA-XXOC-0186-0000 TOU-GS-2-PRI-D USCA-XXOC-0045-0000 USCA-XXOC-0181-0000 USCA-XXOC-0180-0000 TOU-GS-2-SUB-D USCA-XXOC-0051-0000 USCA-XXOC-0193-0000 USCA-XXOC-0192-0000 TOU-GS-2-SEC-E USCA-XXOC-0049-0000 USCA-XXOC-0189-0000 USCA-XXOC-0188-0000 TOU-GS-2-PRI-E USCA-XXOC-0046-0000 USCA-XXOC-0183-0000 USCA-XXOC-0182-0000 TOU-GS-2-SUB-E USCA-XXOC-0052-0000 USCA-XXOC-0195-0000 USCA-XXOC-0194-0000 TOU-GS-2-B USCA-XXOC-0044-0000 USCA-XXOC-0179-0000 USCA-XXOC-0178-0000 TOU-GS-2-SEC-R USCA-XXOC-0050-0000 USCA-XXOC-0191-0000 USCA-XXOC-0190-0000 TOU-GS-2-PRI-R USCA-XXOC-0047-0000 USCA-XXOC-0185-0000 USCA-XXOC-0184-0000 TOU-GS-2-SUB-R USCA-XXOC-0053-0000 USCA-XXOC-0197-0000 USCA-XXOC-0196-0000 TOU-GS-3-SEC-D USCA-XXOC-0058-0000 USCA-XXOC-0207-0000 USCA-XXOC-0206-0000 TOU-GS-3-PRI-D USCA-XXOC-0055-0000 USCA-XXOC-0201-0000 USCA-XXOC-0200-0000 TOU-GS-3-SUB-D USCA-XXOC-0061-0000 USCA-XXOC-0213-0000 USCA-XXOC-0212-0000 TOU-GS-3-SEC-E USCA-XXOC-0059-0000 USCA-XXOC-0209-0000 USCA-XXOC-0208-0000 TOU-GS-3-PRI-E USCA-XXOC-0056-0000 USCA-XXOC-0203-0000 USCA-XXOC-0202-0000 TOU-GS-3-SUB-E USCA-XXOC-0062-0000 USCA-XXOC-0215-0000 USCA-XXOC-0214-0000 TOU-GS-3-B USCA-XXOC-0054-0000 USCA-XXOC-0199-0000 USCA-XXOC-0198-0000 TOU-GS-3-SEC-R USCA-XXOC-0060-0000 USCA-XXOC-0211-0000 USCA-XXOC-0210-0000 TOU-GS-3-PRI-R USCA-XXOC-0057-0000 USCA-XXOC-0205-0000 USCA-XXOC-0204-0000 TOU-GS-3-SUB-R USCA-XXOC-0063-0000 USCA-XXOC-0217-0000 USCA-XXOC-0216-0000 TOU-8-SEC-D USCA-XXOC-0008-0000 USCA-XXOC-0107-0000 USCA-XXOC-0106-0000 TOU-8-PRI-D USCA-XXOC-0003-0000 USCA-XXOC-0097-0000 USCA-XXOC-0096-0000 TOU-8-SUB-D USCA-XXOC-0013-0000 USCA-XXOC-0117-0000 USCA-XXOC-0116-0000 TOU-8-SEC-E USCA-XXOC-0009-0000 USCA-XXOC-0109-0000 USCA-XXOC-0108-0000 TOU-8-PRI-E USCA-XXOC-0004-0000 USCA-XXOC-0099-0000 USCA-XXOC-0098-0000 TOU-8-SUB-E USCA-XXOC-0014-0000 USCA-XXOC-0119-0000 USCA-XXOC-0118-0000 TOU-8-SEC-B USCA-XXOC-0007-0000 USCA-XXOC-0105-0000 USCA-XXOC-0104-0000 Orange County Power Authority Rate Identification Number (RIN) Key The tables below show the corresponding Rate Identification Number (RIN) to Orange County Power Authority (OCPA) rate.
OCPA rates that are not time-dependent or Time-of-Use (TOU) do not have a corresponding RIN and are therefore excluded from this key. Your RIN can also be found below the "Details of your new charges" section on the generation portion of your utility bill.
Commercial Customers
TOU-8-PRI-B USCA-XXOC-0002-0000 USCA-XXOC-0095-0000 USCA-XXOC-0094-0000 TOU-8-SUB-B USCA-XXOC-0012-0000 USCA-XXOC-0115-0000 USCA-XXOC-0114-0000 TOU-8-SEC-R USCA-XXOC-0010-0000 USCA-XXOC-0111-0000 USCA-XXOC-0110-0000 TOU-8-PRI-R USCA-XXOC-0005-0000 USCA-XXOC-0101-0000 USCA-XXOC-0100-0000 TOU-8-SUB-R USCA-XXOC-0015-0000 USCA-XXOC-0121-0000 USCA-XXOC-0120-0000 TOU-8-SEC-RBU USCA-XXOC-0011-0000 USCA-XXOC-0113-0000 USCA-XXOC-0112-0000 TOU-8-PRI-RBU USCA-XXOC-0006-0000 USCA-XXOC-0103-0000 USCA-XXOC-0102-0000 TOU-8-SUB-RBU USCA-XXOC-0016-0000 USCA-XXOC-0123-0000 USCA-XXOC-0122-0000 TOU-EV-7-SEC USCA-XXOC-0025-0000 USCA-XXOC-0141-0000 USCA-XXOC-0140-0000 TOU-EV-7-PRI USCA-XXOC-0024-0000 USCA-XXOC-0139-0000 USCA-XXOC-0138-0000 TOU-EV-7-SUB USCA-XXOC-0026-0000 USCA-XXOC-0143-0000 USCA-XXOC-0142-0000 TOU-EV-8-SEC USCA-XXOC-0028-0000 USCA-XXOC-0147-0000 USCA-XXOC-0146-0000 TOU-EV-8-PRI USCA-XXOC-0027-0000 USCA-XXOC-0145-0000 USCA-XXOC-0144-0000 TOU-EV-8-SUB USCA-XXOC-0029-0000 USCA-XXOC-0149-0000 USCA-XXOC-0148-0000 TOU-EV-9-SEC USCA-XXOC-0031-0000 USCA-XXOC-0153-0000 USCA-XXOC-0152-0000 TOU-EV-9-PRI USCA-XXOC-0030-0000 USCA-XXOC-0151-0000 USCA-XXOC-0150-0000 TOU-EV-9-SUB USCA-XXOC-0032-0000 USCA-XXOC-0155-0000 USCA-XXOC-0154-0000 TOU-PA-2-SEC-D USCA-XXOC-0070-0000 USCA-XXOC-0231-0000 USCA-XXOC-0230-0000 TOU-PA-2-PRI-D USCA-XXOC-0066-0000 USCA-XXOC-0223-0000 USCA-XXOC-0222-0000 TOU-PA-2-SUB-D USCA-XXOC-0074-0000 USCA-XXOC-0239-0000 USCA-XXOC-0238-0000 TOU-PA-2-SEC-D5 USCA-XXOC-0071-0000 USCA-XXOC-0233-0000 USCA-XXOC-0232-0000 TOU-PA-2-PRI-D5 USCA-XXOC-0067-0000 USCA-XXOC-0225-0000 USCA-XXOC-0224-0000 TOU-PA-2-SUB-D5 USCA-XXOC-0075-0000 USCA-XXOC-0241-0000 USCA-XXOC-0240-0000 TOU-PA-2-SEC-E USCA-XXOC-0072-0000 USCA-XXOC-0235-0000 USCA-XXOC-0234-0000 TOU-PA-2-PRI-E USCA-XXOC-0068-0000 USCA-XXOC-0227-0000 USCA-XXOC-0226-0000 TOU-PA-2-SUB-E USCA-XXOC-0076-0000 USCA-XXOC-0243-0000 USCA-XXOC-0242-0000 TOU-PA-2-SEC-E5 USCA-XXOC-0073-0000 USCA-XXOC-0237-0000 USCA-XXOC-0236-0000 TOU-PA-2-PRI-E5 USCA-XXOC-0069-0000 USCA-XXOC-0229-0000 USCA-XXOC-0228-0000 TOU-PA-2-SUB-E5 USCA-XXOC-0077-0000 USCA-XXOC-0245-0000 USCA-XXOC-0244-0000 TOU-PA-2-A USCA-XXOC-0064-0000 USCA-XXOC-0219-0000 USCA-XXOC-0218-0000 TOU-PA-2-B USCA-XXOC-0065-0000 USCA-XXOC-0221-0000 USCA-XXOC-0220-0000 TOU-PA-3-SEC-D USCA-XXOC-0084-0000 USCA-XXOC-0259-0000 USCA-XXOC-0258-0000 TOU-PA-3-PRI-D USCA-XXOC-0080-0000 USCA-XXOC-0251-0000 USCA-XXOC-0250-0000 TOU-PA-3-SUB-D USCA-XXOC-0088-0000 USCA-XXOC-0267-0000 USCA-XXOC-0266-0000 TOU-PA-3-SEC-D5 USCA-XXOC-0085-0000 USCA-XXOC-0261-0000 USCA-XXOC-0260-0000 TOU-PA-3-PRI-D5 USCA-XXOC-0081-0000 USCA-XXOC-0253-0000 USCA-XXOC-0252-0000 TOU-PA-3-SUB-D5 USCA-XXOC-0089-0000 USCA-XXOC-0269-0000 USCA-XXOC-0268-0000 TOU-PA-3-SEC-E USCA-XXOC-0086-0000 USCA-XXOC-0263-0000 USCA-XXOC-0262-0000 TOU-PA-3-PRI-E USCA-XXOC-0082-0000 USCA-XXOC-0255-0000 USCA-XXOC-0254-0000 TOU-PA-3-SUB-E USCA-XXOC-0090-0000 USCA-XXOC-0271-0000 USCA-XXOC-0270-0000 TOU-PA-3-SEC-E5 USCA-XXOC-0087-0000 USCA-XXOC-0265-0000 USCA-XXOC-0264-0000 TOU-PA-3-PRI-E5 USCA-XXOC-0083-0000 USCA-XXOC-0257-0000 USCA-XXOC-0256-0000 TOU-PA-3-SUB-E5 USCA-XXOC-0091-0000 USCA-XXOC-0273-0000 USCA-XXOC-0272-0000 TOU-PA-3-A USCA-XXOC-0078-0000 USCA-XXOC-0247-0000 USCA-XXOC-0246-0000 TOU-PA-3-B USCA-XXOC-0079-0000 USCA-XXOC-0249-0000 USCA-XXOC-0248-0000 AL-2-GF USCA-XXOC-0001-0000 USCA-XXOC-0093-0000 USCA-XXOC-0092-0000 1 Orange County Power Authority
Policy Number 019: Reserve Policy
Purpose
OCPA will prudently manage its operations in a manner that supports its long-term financial independence and stability while providing sufficient financial capacity to meet short term obligations.
Adequate reserves will enable OCPA to satisfy working capital requirements, procure energy at competitive rates, adhere to loan covenants, obtain and maintain an investment grade credit rating, cover unanticipated expenditures, and support rate stability.
Reserves are defined as the Net Position plus funds held in the Rates Stabilization Fund. The Net Position represents the difference between OCPA’s assets and liabilities as defined by the Government Accounting Standards Board and consistent with Generally Accepted Accounting Principles.
The Reserve Policy outlines the appropriate types and target levels (minimum and maximum) of unrestricted/undesignated reserves as prescribed in the following policy.
The four most important purposes of a reserve policy are to:
1. Plan for contingencies. OCPA will maintain sufficient reserves to minimize rate increases due to market volatility (power supply shocks or maintain rate competitiveness), weather impacts on demands, economic downturns, emergencies (such as natural disasters), and regulatory changes.
2. Maintain good standing with rating agencies. OCPA will maintain sufficient reserves to obtain, maintain, or improve credit ratings.
3. Avoid interest expense. Having sufficient reserves avoids interest expense to cover short-term cash shortfalls using reserves instead of debt.
4. Ensure cash availability when revenue is unavailable. Reserves can be used to bridge times of the year that normally see temporary low levels of cash. Maintaining adequate reserves can balance intra-period differences in cash availability.
Policy
Reserve Target Levels
Starting FY2024/25, OCPA shall maintain a minimum reserve balance equal to 30% of total operating budget expenditures, with a goal of increasing the reserve to 50% of total operating budget expenditures. The maximum reserve is 75% of total operating budget expenditures.
Funding the Target Amount
Funding reserves will generally come from excess revenues over expenditures or one-time revenues.
Conditions for Use of Reserves
OCPA will strive to avoid the appropriation of reserve balance for recurring operating expenditures.
The reserve balance may be used to:
1. Provide revenues to make up for unanticipated revenue shortfall of spikes in power supply expenses.
2. Provide temporary resources in the event of an economic downturn while expenditure reductions and/or rate adjustments are implemented.
3. Provide resources to meet emergency expenditures.
Excess Reserves
If reserve funds exceed the maximum level, OCPA will consider enhancing program expenditures, capital improvements, paying down existing debt, offsetting other long-term liabilities, and reducing rates.
Reserves between Minimum and Maximum
No other action by OCPA will be required if reserves are between the minimum and maximum levels.
Periodic Review of Targets
If the risk factors behind the target are eliminated or new risk factors emerge as a result of changes in the industry, legislation, or economic conditions, the basis of the reserve will be reviewed, and the funding level may be adjusted accordingly.
Reporting
Reserve levels will be monitored during the fiscal year and reported in the annual budget review reports. The reserve target levels will be analyzed annually, and over/under reserve determination shall be made in conjunction with year-end financial results. These results will be reported to the Boards as part of the year-end financial report presentation.
Orange County Power Authority
Policy Number 021: Rate Development Policy
Purpose
This policy provides the framework for Orange County Power Authority’s (“OCPA”) Board of Directors and staff to ensure OCPA’s rate design, development and implementation process remains transparent, fiscally responsible and centered on the customer.
As a public agency, OCPA must, at minimum, set rates to recover costs associated with the purchase of power, operational costs, meeting financial metrics, and debt services. It is in the best interest of OCPA and its customers to design and implement rates that meet revenue requirements as well as targeted reserves, while maintaining rate competitiveness, stability, and long-term financial viability.
Background
OCPA customers receive electric delivery service under a wide variety of Southern California Edison’s (“SCE”) rate schedules that include Residential (D), Commercial and Industrial (GS), Agricultural and Pumping (PA), and Street Lighting and Traffic Control (LS and TC). In Spring 2022, OCPA commenced its commercial customer enrollment, serving GS, PA, LS and TC classes. Residential customers were enrolled in Fall 2022. Because of the timing differences in enrollments, OCPA’s residential customers are assigned the 2022 vintage for the purpose of calculating SCE Power Charge Indifference Adjustment (“PCIA”) charges and other surcharges, while non-residential customers are assigned to the 2021 vintage.1 OCPA advocates for ratepayers by providing a choice of electricity providers and shifting control of local energy supply decisions from profit-driven, incumbent utility into the hands of residents and businesses located in our service jurisdiction. This creates competition in rates that benefits customers, increases transparency, and ensures a better overall customer experience.
OCPA Primary Rate Setting Objectives
OCPA has set goals and priorities that shall be taken into account during the rate design process:
1. Local Control
Board discretion on rate-setting.
2. Cost Recovery
Rates are adequate to cover all expenses, debt services, and other financial obligations.
3. Stability
Rates shall enable the creation of a prudent rate stabilization reserve fund to mitigate significant swings in rates, cover unforeseen expenses, negotiate favorable terms with power suppliers, obtain and maintain an investment-grade credit rating, and achieve strategic goals. 1 Vintages assigned to customers in future mass enrollments, if any, may be different based on the timing of the enrollment.
4. Competitive
Rates shall allow OCPA to effectively retain and attract customers by offering superior electricity services with higher renewable content than the incumbent investor-owned utility.
5. Equity
Variations in rates among customers are based on justifiable differences in their usage characteristics and/or cost of service.
OCPA Rate Setting Timeline
Typically, SCE updates its annual Energy Resource Recovery Account (“ERRA") forecast for electric generation rates and PCIA changes, which becomes effective in January and is usually approved by the California Public Utilities Commission (“CPUC”) in December.
Following the approval of the ERRA, staff will present a proposed Rate Design for the year to the Board for review and approval. With frequent power market changes and evolving regulatory policies, SCE changes their rates multiple times a year, which may require staff to propose intra-year rate changes to the Board for review and approval.
Upon the Board’s approval of the annual OCPA Rate Design, staff will make necessary adjustments to OCPA rates as soon as practicable and as necessary during the year to maintain the approved OCPA Rate Design for all customers. Staff will place a report on the agenda detailing the adjustment and request ratification of the adjusted OCPA rates at the next regular board meeting.
The approved OCPA rates will be published on the OCPA website prior to their effective date, allowing customers to compare, plan, and gain a better understanding of their upcoming bills.
Joint Rate Comparison
As per the regulatory requirements, SCE and OCPA must collaborate to publish and post a Joint Rate Comparison on their respective websites for each rate change. This will enable customers to easily compare the rates and assess any potential changes in their bills.
Future Cost-Based Rate Design
OCPA may evaluate the viability of transitioning to a Cost-Based (Cost-of-Service) rate design, rather than a rate design directly tied to SCE rates, after it has established sufficient reserves in accordance with the OCPA Reserves Policy. The Cost-Based rate design is the prevailing method utilized by most utilities to calculate their retail rates and provides enhanced rate stability to customers.
ORANGE COUNTY POWER AUTHORITY
Policy Number 024: Rate Stabilization Fund Policy
Approved: 06/18/2024
This Rate Stabilization Fund Policy (Policy) establishes guidelines for managing and administering Rate Stabilization Fund (RSF) at Orange County Power Authority (OCPA).
OBJECTIVE
Establishing an RSF allows OCPA to defer revenues in years of strong financial results for use in future years when financial results are weaker or stressed. This strategy would enable OCPA to avoid substantial rate increases needed to address unanticipated spikes in energy costs or, conversely, to offset reductions in rate levels (and net revenues) due to uncontrollable events that negatively impact fiscal financial results. Examples include:
• Investor-owned utilities (IOUs) rate uncertainty, such as substantial increases in the Power Charge Indifference Adjustments (PCIA) and decreases in the generation rates. • Unexpected shocks in energy prices, such as significant increases in prices for renewable energy (PCC1) and Resource Adequacy (RA).
• Changes in member participation, including withdrawals. • Defaults on customer payments during global or local economic recessions. • Significant regulatory and legislative changes in the energy sector that affect IOUs rate, RA prices, etc.
• Reduced electricity demand due to rate affordability issues.
Using deferred revenues in future years would allow OCPA to minimize the near-term impact on rates and net revenues. Additionally, should OCPA decide to access the tax-exempt capital markets in the future, it would need to agree to several covenants. These covenants, required to protect and attract bond investors, would mandate that OCPA generates net revenues sufficient to cover debt service costs. The RSF could be utilized to meet these covenants if necessary.
ACCOUNTING
Deferring revenues into the Rate Stabilization Fund (RSF) would result in a reduction in the Orange County Power Authority's (OCPA) reported revenues for that fiscal year, with a corresponding increase in reported revenues in years when withdrawals from the RSF are made. By deferring revenues into the RSF before they are recognized as revenues, OCPA would effectively “bank” these funds for use in future fiscal years.
Withdrawals from the RSF will be considered in fiscal years where net revenues are projected to be negative or as necessary to satisfy any covenants, contractual obligations, or to maintain investment-grade credit ratings in the future.
REPORTING
Staff will notify the Board via the CEO Report after any transfers are made.
The Power Charge Indifference Adjustment (PCIA)
What is the PCIA?
The PCIA, or Power Charge Indifference Adjustment, is a fee charged by investor-owned utilities (IOUs) in California to all customers, including those who receive generation service from a Community Choice Aggregator (CCA) or Electric Service Provider (ESP). In the past, the PCIA has been known as an “exit fee” but this is a misnomer. The PCIA recovers the IOUs’ above-market costs for power contracts or resources that were acquired prior to a customer's departure to an alternative energy provider.
Due to the dynamics of inputs to the PCIA, the fee can vary dramatically from year to year. These variations create rate volatility for all customers. CalCCA believes structural changes are needed to decrease PCIA volatility and ensure the PCIA calculation more accurately reflects the full value of IOU energy resource portfolios so that it is properly recovered from customers equitably.
How is the PCIA Calculated?
The PCIA is set annually in the IOUs’ Energy Resource Recovery Account (ERRA) proceedings. It includes above-market costs related to power supply commitments that the IOUs made many years ago. Above-market means the cost of the resource is higher than the revenue the resource generates. These include Utility-Owned Generation (UOG) (e.g., nuclear, natural gas, hydroelectric plants) and long-term renewable energy contracts with third parties.
The PCIA is intended to leave all customers indifferent to taking up service with a CCA or other alternative.
Customers are assigned “vintages” based on the year they moved to CCA service and are responsible for the above-market costs incurred on their behalf before they switched service. Bundled customers, or customers who take up both generation and transmission and distribution (T&D) services from an IOU, are always assigned the current year as their vintage.
The PCIA is derived from the utility’s indifference amount, which is updated annually in each IOU’s ERRA proceeding. The indifference amount is the difference in the target year between the cost of the IOU’s supply portfolio and the market value of the portfolio.
A low indifference amount and subsequent PCIA savings can result from either the cost of the portfolio going down or the value going up. The portfolio value is calculated using Market Price Benchmarks (MPBs), which have experienced extreme variability in recent years.
PCIA Swings
When the current market value of IOU power portfolios is lower than what the utility originally paid, the PCIA goes positive, and departed customers pay the difference. If the value of IOU portfolios is higher than what the utility originally paid, the PCIA goes negative, and bundled IOU customers pay the difference.
Over the past decade, CCA customers experienced dramatic increases in the PCIA to the tune of hundreds of millions of dollars. More recently, in 2024 and 2025, IOU portfolio values increased to overtake portfolio costs. As value surpassed costs, IOU bundled customers were hit with significant PCIA increases in order to provide the value back to departed customers who were owed.
In recent years, the indifference amount has not only varied from positive to negative but also changed significantly in total magnitude, from over $2.5 billion to tens of thousands in PG&E’s case, as shown in the graph above. These dramatic swings in the PCIA have led the California Public Utilities Commission (CPUC) to reconsider the current PCIA methodology.
PCIA Changes Ahead?
In February 2025, the CPUC issued an Order Instituting Rulemaking (OIR) to evaluate potential changes to the methodology used to calculate the PCIA with the goals of improving utility ERRA cost forecasting, mitigating rate volatility, and ensuring indifference among bundled and departed customers.
The OIR separates potential changes into two tracks. Track one is currently considering modifications to MPB calculations. Beginning in 2026, track two will consider broader changes to the overall PCIA methodology.
In June 2025, the CPUC released a decision on track one which modifies the RA MPB and applies it to the 2025 and future ERRA calculations. The decision combines the RA MPB datasets in one RA MPB, expands the datasets scope in time, and reduces their risk of manipulation.
CalCCA requested rehearing of this decision on the grounds that applying the new RA MPB methodology to the 2025 revenue requirement constitutes unlawful retroactive ratemaking. The CPUC denied CalCCA’s request.
In December 2025, CalCCA filed a Petition for Writ of Review challenging the CPUC’s decision, arguing that the CPUC’s action violates the statutory prohibition against retroactive ratemaking, which protects rate stability and prevents after-the-fact changes to approved rates. The petition also asserts that the CPUC lacked adequate findings or evidence to change the existing methodology.
CalCCA’s Recommendations
CalCCA is recommending a number of structural changes to the PCIA, including those listed below.
Track one recommendations:
• Maintain consistent pricing between RPS
and RA
• Maximize representative transactions for
MPB calculation
• Mitigate risk in RA MPB manipulation
• Ensure seasonality in RA prices is well
reflected
Track two recommendations:
• Consider sunsetting the PCIA
• Allocate resources proportionally to unbundled
and bundled customers
• Revisit the Greenhouse Gas (GHG)-free
methodology
• Implement guidance for the RA slice-of-day
framework
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.4
--------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Board of Directors
From: Louis Ting, Director of Power Resources
Approved By: Joe Mosca, Chief Executive Officer
Subject: APPROVE 2026 OCPA PRODUCT OFFERING OPTIONS
Date: January 12, 2026
---------------------------------------------------------------------------------------------------------------------
STRATEGIC GOALS
☐ Enrich & Grow the OCPA Community:
☐ Prioritize Fiscal Sustainability & Affordability:
☐ Design & Deploy Community-Aligned Customer Programs:
☒ Energize Our Community with Renewable Energy:
☐ Raise Awareness of Community Energy & Advocate for Our Customers:
☐ Not Applicable:
RECOMMENDED ACTION
Approve the proposed renewable energy content for OCPA’s 2026 retail service offering options, in conjunction with the proposed 2026 OCPA generation rate stabilization approach (Item 8.3 on the Board of Directors Meeting Agenda for January 12, 2026). This will reflect the increased carbon-free or Greenhouse Gas (GHG)-free resources allocated to OCPA customers, as per the California Public Utilities Commission’s (Commission) decisions. It will also align OCPA’s renewable energy resource mix with the service offering selections of OCPA members (Members) and meet the compliance requirements of California’s upward trajectory in the Renewables Portfolio Standard (RPS) procurement mandate.
BACKGROUND
OCPA offers three distinct retail service offerings to its customers: 1) 100% Renewable Choice – a premium product with 100% RPS-eligible renewable energy resources; 2) Smart Choice –a renewable energy product positioned between Basic Choice and 100% Renewable Choice; and 3) Basic Choice – a renewable energy product that meets the RPS requirements. To ensure these service offerings align with the interim annual procurement mandates under California’s RPS program, to accept all allocations of carbon-free resources from Southern California Edison’s (SCE) and Pacific Gas & Electric’s (PG&E) as per the Commission’s decisions, and to align with Members’ current and proposed 2026 service offering elections, staff are bringing the proposed energy mix for OCPA’s product offerings for the Board of Directors’ consideration.
ANALYSIS AND DISCUSSION
OCPA is responsible for ensuring that its resource mix contains sufficient production from renewable energy resources to comply with California’s RPS program, which reflects an interim annual procurement mandate of 49% in 2026, increasing to 60% by 2030. In addition to supporting its baseline RPS compliance objectives, OCPA has developed two alternative service options that offer its Members and customers increasing levels of renewable energy content at specified rate premiums, which cover incremental renewable energy costs relative to OCPA’s Basic Choice service option.
Maintaining three distinct product offerings provides greater flexibility to OCPA’s customers, allowing each Member and their customers to select service options that best align with their unique preferences and priorities. Individual customers always have the choice to choose the plan that best suits their needs.
• Basic Choice offering provides customers with renewable energy content that is at least as high as California’s prevailing interim annual procurement mandate – 49% for 2026.
Therefore, the Basic Choice service offering will include a minimum of 49% renewable energy.
• 100% Renewable Choice is OCPA’s premium retail service offering, providing participating Members and customers with a 100% renewable energy supply and the lowest possible carbon emission rate.
• Smart Choice, OCPA’s third retail service offering, provides customers with renewable energy content set between Basic Choice and 100% Renewable Choice, along with a generation rate premium situated between the two. For 2026, as discussed in the proposed 2026 OCPA Generation Rate Stabilization Approach (Item 8.3), the Smart Choice service offering is proposed to include 60% renewable energy plus 40% GHG-Free energy, which ensures the delivery of an energy product that reflects a lower emission coefficient when compared to Basic Choice.
Based on SCE’s latest Power Content Label
OCPA 2026 Service Offerings
In summary, for 2026, OCPA’s retail service offering proposal is as follows:
• 100% Renewable Choice service offering will continue to provide participating customers with a 100% RPS-eligible renewable resource mix.
• Basic Choice will include a minimum 49% RPS-eligible renewable energy, which aligns with California’s interim annual RPS procurement mandate. • Smart Choice will include a minimum of 60% renewable energy plus 40% GHG-free energy.
OCPA staff regularly monitor and engages with regional energy markets to gather information related to product pricing and availability, mindful of the unprecedented volatilities in renewable energy prices that have occurred over the past few years. With the widespread adoption of above-RPS procurement targets – particularly among Community Choice Aggregators (CCA) – system-wide project delays due to transmission constraints, and prior short positions among some of California’s largest retail electricity sellers, supply was constrained at the same time that demand increased, tightening markets and driving prices higher. While this presents, and may continue to present, challenges for OCPA’s resource planning and procurement processes, staff believe that its projected renewable energy needs can be met in a manner that accommodates desired customer service levels across OCPA’s three unique service options.
FISCAL IMPACT
The fiscal impact assessment resulting from the proposed 2026 product offerings update will be incorporated in OCPA’s FY2025/26 Mid-Year Budget Update, which is scheduled for Board approval in the Spring of 2026.
ATTACHMENT
None
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 8.5
-------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Board of Directors
From: Lisette Chel Walker, Interim Board Clerk
Approved by: Joe Mosca, Chief Executive Officer
Subject: ADOPT THE 2026 BOARD OF DIRECTORS MEETING SCHEDULE Date: January 12, 2026
--------------------------------------------------------------------------------------------------------------------
RECOMMENDED ACTION
Adopt Resolution No. 2026-XX A Resolution of the Board of Directors of Orange County Power Authority Establishing Regular Meetings of the Board of Directors for February through December 2026.
BACKGROUND
The Ralph M. Brown Act (Cal. Gov. Code § 54950 et seq.) provides that the legislative body of each local agency shall provide, by ordinance, resolution, bylaws, or other rule, the time and place for holding its regular meetings. For the 2025 calendar year, the Board of Directors held their meetings predominantly on the 2nd Monday of each month, except when holidays required an adjustment, at Orange County Power Authority, 15310 Barranca Parkway, Suite 250, Irvine, CA 92618. The meeting in May was moved forward one week due to a conflict with the Cal-CCA conference.
After a review of holidays and meeting dates and times of the city councils of member agencies, staff recommend regular meetings continue to be held at 4:30 p.m., on the second Monday of each month at 15310 Barranca Parkway, Suite 250, Irvine, CA 92618.
These meeting dates are listed below:
Date Time Location
Monday, February 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, March 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, April 13, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, May 4, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Date Time Location
Monday, June 8, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, July 13, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
August 2026 - No Meeting Dark No Meeting
Monday, September 14, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, October 19, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, November 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, December 14, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
FISCAL IMPACT
None
ATTACHMENTS
Attachment A – Resolution No. 2026-XX: A Resolution of the Board of Directors of Orange County Power Authority Establishing Regular Meetings of the Board of Directors for 2026.
Attachment B – Spreadsheet with holidays and the represented member cities' governing board meetings.
Resolution No. 2026-XX
Date Adopted:
RESOLUTION NO. 2026-XX
A RESOLUTION OF THE BOARD OF DIRECTORS OF THE
ORANGE COUNTY POWER AUTHORITY ESTABLISHING
REGULAR MEETINGS OF THE BOARD OF DIRECTORS FOR
2026
A. Orange County Power Authority (“OCPA”) is a joint powers authority formed pursuant to the Joint Exercise of Powers Act (Cal. Gov. Code § 6500 et seq.), California Public Utilities Code § 366.2, and a Joint Powers Agreement effective on November 20, 2020.
B. The Ralph M. Brown Act (Cal. Gov. Code § 54950 et seq.) provides that the legislative body of each local agency shall provide, by ordinance, resolution, bylaws, or other rule, the time and place for holding its regular meetings.
C. The Board of Directors seeks to establish the time and meeting location for all regular meetings of the Board of Directors for the 2026 calendar year.
NOW, THEREFORE, BE IT RESOLVED by the Board of Directors of the Orange County Power Authority Power as follows:
Section 1. For the 2026 calendar year, regular meetings of the Board of Directors shall take place on the dates set forth below and shall begin at 4:30 p.m. All regular meetings shall take place at 15310 Barranca Parkway, Suite 250, Irvine, CA 92618. OCPA’s meetings may be held fully or partially by videoconference or teleconference as authorized by applicable law.
Date Time Location
Monday, February 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, March 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, April 13, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, May 4, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, June 8, 2026 4:30 p.m. 315310 Barranca Parkway, Suite 250, Irvine, CA 92618
Resolution No. 2026-XX
Date Adopted:
Date Time Location
Monday, July 13, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
August 2026 No Meeting Dark No Meeting
Monday, September 14, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, October 19, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, November 9, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Monday, December 14, 2026 4:30 p.m. 15310 Barranca Parkway, Suite 250, Irvine, CA 92618
Section 2. The Board of Directors shall have the power to change the time or location of any regular meetings by amending or replacing this resolution, or cancel such meetings, or call special meetings with proper notice. Special and adjourned meetings of the Board of Directors may be called and held in the manner authorized by the Ralph M. Brown Act (Cal. Gov. Code § 54950 et seq.), as may be amended from time to time.
Section 3. This resolution shall take effect immediately upon its adoption.
PASSED AND ADOPTED at a meeting of the Board of Directors of the Orange County Power Authority held on January 12, 2026.
Lisette Chel Walker
Interim Board Secretary
Orange County Power Authority
Thurs & Mon Jan. 1 & 19 New Year's & MLK Monday Jan. 12 Tuesday Jan. 13 & 27 Tuesday Jan. 13 & 27 Tuesday Jan. 6 & 20 Tuesday Jan. 6 & 20 Monday Feb. 16 President's Day Monday Feb. 9 Tuesday Feb. 10 & 24 Tuesday Feb. 10 & 24 Tuesday Feb. 3 & 17 Tuesday Feb. 3 & 17Tuesday Mar. 31 Cesar Chavez Monday Mar. 9 Tuesday Mar. 10 & 24 Tuesday Mar. 10 & 24 Tuesday Mar. 3 & 17 Tuesday Mar. 3 & 17Monday Apr. None Monday Apr. 13 Tuesday Apr. 14 & 28 Tuesday Apr. 14 & 28 Tuesday Apr. 7 & 21 Tuesday Apr. 7 & 21Monday May 25 Memorial Monday May. 4 Tuesday May 12 & 26 Tuesday May 12 & 26 Tuesday May 5 & 19 Tuesday May 5 & 19Friday Jun. 19 Juneteenth Monday Jun. 8 Tuesday Jun. 9 & 23 Tuesday Jun. 9 & 23 Tuesday Jun. 2 & 16 Tuesday Jun. 2 & 16Saturday Jul. 4 Independence Monday Jul. 13 Tuesday Jul. 14 & 28 Tuesday Jul. 14 & 28 Tuesday Jul. 7 & 21 Tuesday Jul. 7 & 21August DARK DARK Monday DARK Tuesday Aug. 11 & 25 Tuesday Aug. 11 & 25 Tuesday Aug. 4 & 18 Tuesday Aug. 4 & 18Monday Sep. 7 Labor Monday Sep. 14 Tuesday Sep. 8 & 22 Tuesday Sep. 8 & 22 Tuesday Sep. 1 & 15 Tuesday Sep. 1 & 15Monday Oct. 12 Columbus Monday Oct. 19 Tuesday Oct. 13 & 27 Tuesday Oct. 13 & 27 Tuesday Oct. 6 & 20 Tuesday Oct. 6 & 20Wed-Thu-Fri Nov. 11 & 26-27 Veterans & Thanksgiving Monday Nov. 9 Tuesday Nov. 10 & 24 Tuesday Nov. 10 & 24 Tuesday Nov. 3 & 17 Tuesday Nov. 3 & 17Friday Dec. 25 Christmas Monday Dec. 14 Tuesday Dec. 8 & 22 Tuesday Dec. 8 & 22 Tuesday Dec. 1 & 15 Tuesday Dec. 1 & 15
OCPA BOARD OF DIRECTORS
2026 Meeting Dates
Holidays
OCPA
(4:30 p.m.)
2nd Mondays
Buena Park
(5:00 p.m.)
2nd & 4th Tuesdays
Irvine
(4:00 p.m.)
2nd & 4th Tuesday
Fullerton
(5:30 p.m.)
1st & 3rd Tuesdays
Fountain Valley
(6:00 p.m.)
1st & 3rd Tuesdays
ORANGE COUNTY POWER AUTHORITY
Staff Report – Item 10
--------------------------------------------------------------------------------------------------------------------- To: Orange County Power Authority Board of Directors
From: Joe Mosca, Chief Executive Officer
Subject: CHIEF EXECUTIVE OFFICER’S REPORT
Date: January 12, 2026
--------------------------------------------------------------------------------------------------------------------- Revenue Deferral Transfer
As planned in the FY2025/26 Budget, OCPA will utilize the $45 million in previously deferred revenue from FY2023/24 - $15 million in FY2024/25 and $30 million in FY2025/26 - to help offset the anticipated revenue shortfall. This shortfall is primarily driven by the continuation of the 2024 rate design in 2025 and the City of Irvine’s shift from 100% Renewable Choice to Basic Choice. This strategic use of deferred revenue aligns with the Board-approved Rate Stabilization Policy and serves as a key financial tool to support long-term rate stability and affordability. By proactively reallocating these funds, OCPA strengthens its ability to manage financial risks, stabilize rates, and protect customers from market volatility.
Communications & External Affairs Updates
Communications
The OCPA digital holiday card was sent out this week to 520 elected officials, stakeholders, vendors, contractors, and community partners. It currently has a 45% open rate.
The OCPA opt-out page has been updated to provide more information to customers before they make their determination. Based on their reason for wanting to opt-out, language is provided to help educate them so they’re sure to make an informed decision: https://www.ocpower.org/opt-out/.
OCPA is working on updated customer enrollment letters that go out to new residents in member cities, letting them know they have been enrolled at their city’s default renewable energy plan. These notices are required by the California Public Utilities Commission and have been updated to simplify the language and terms and conditions, while updating the renewable energy content to reflect 2026 levels.
The University of California system published a cross-campus update for November and December, where the UCI ANTreprenuer Center was prominently highlighted for their OCPA Community Impact Award.
Community Engagement
In December, OCPA attended the Yalda Gala hosted by the Iranian American Chamber of Commerce where we accepted a community support award and recognition awards from Congressman Dave Min and Supervisor Katrina Foley.
Staff attended the Orange County People's Hearing on Offshore Oil and Gas Drilling. Three non-partisan groups (Surfrider Foundation, OC Coastkeeper, and Oceana) sponsored the event, where many of the speakers mentioned climate change and supporting renewables versus risking impacts to our OC coastal tourism, marine, and fishing businesses. We connected with representatives from each group and informed them about OCPA’s value proposition, which is to provide more renewable energy. OCPA also attended the Irvine Sustainability Commission meeting where they reviewed recent solid waste audit results, which highlighted measurable progress toward the city’s diversion goals, along with a continued need for public education to drive greater voluntary compliance.
External Affairs
In December, staff joined the Regulatory and Legislative team on their bi-annual meetings with OC Senators and Assemblymembers to provide an update on OCPA. In December, staff and I met with Tom Koutroulis and Senior Leadership of OC Waste and Recycling to discuss opportunities for future partnership. The meeting was initiated to learn more about OCWR’s progress and plans for the Doheny Desalination Plan, and share how OCPA can strategically partner on this project to provide the GHG free energy required for operations. We have previously spoken with the contractor on the desalination project and are working to connect with South Coast Water District, and will follow up with the City of Dana Point.
I attended the Orange County Board of Supervisors Holiday Open House alongside the External Affairs team, using the opportunity to engage directly with county leadership and staff. Throughout the event, we were able to make several introductions between OCPA leadership and key members of the Supervisors’ teams.
Staff attended the Association of California Cities-Orange County (ACCOC) Regional Holiday Mixer in Costa Mesa, which brought together elected officials and city staff from across the county.
Customer Programs
Community Power Plan: The Community Power Plan is now open for public comment on the OCPA website through December 25th. The document is available through a tool that makes commenting simple, and notes are being monitored by the Director of Communications and External Affairs.
o Community Power Plan pilot program: We are working on a direct-to-renter program that offers quick, plug-in electric replacements for gas equipment that do not require landlord approval. The aim is not only to help customers electrify, but also for these appliances to save customers money on running central heating and air. We are striving for launch of the new program immediately following presentation of the final CPP to the Board in February. Equitable Building Decarbonization Direct Install Grant: LA County is working through the CEC to get approval for formal launch of the program. Staff have attended numerous onboarding calls and are working on securing Orange County United Way as the outreach partner based on proposals from an earlier RFQ.
Energy Efficiency Kits: Of the original 1,500 inventory we have limited inventory remaining. The program has closed in the Marketplace but customers can complete the form linked on the OCPA website to receive the few remaining kits. Residential Battery Rebate Program: To-date, 48 applications have been approved for this program and one rebate has been processed.
Calpine Community Benefits Grant: Final awardee identification has taken place with the assistance of Calpine, the Community Advisory Committee, and Programs staff.
Announcement of the three selected projects will take place in early January 2026.
Human Resources Updates
Recruitment
External Affairs Manager: The position remains open. The first round of panel interviews will resume in the new year.
Board Clerk & Executive Assistant to the CEO: This position is now vacant, and recruitment will begin in the new year.
Data Analyst: Recruitment for this role will resume in the new year. Interns: Leva Rohani has concluded her term as the CEA Intern. The Regulatory and Legislative internship will be filled in the new year.
Events & Stakeholder Outreach
The OCPA team has attended the following events and community meetings since our last Board meeting.
City Event & Meetings Date Time
Orange County Orange County Board of Supervisors
Holiday Open House Wednesday, December 10, 2025 11:30 AM - 1:30 PM Orange County ACCOC Holiday Mixer Wednesday, December 10, 2025 5:30 PM - 8:30 PM Buena Park The Art Brown Metrolink Station
Sign Unveiling Wednesday, December 12, 2025 2:00 PM – 3:00 PM We are looking forward to many opportunities to engage with the community and key stakeholders, including:
City Event & Meetings Date Time
Orange County Future Leaders Conference – Black
Chamber of Commerce Thursday, January 15, 2026 11:00 AM – 1:30 PM Orange County OC Iranian Chamber New Year
Mixer Thursday, January 15, 2026 6:00 PM – 8:00 PM
Orange County Coffee Conversations with CA State
Senator Tony Strickland Thursday, January 23, 2026 8:30 AM - 10:00 AM Placentia The Centennial Gala Friday, January 24, 2026 5:30 PM - 8:30 PM Orange County Sustainable Campus Challenge Kick-Off Tuesday, January 27, 2026 4:00 PM – 6:00 PM Orange County ABAOC Lunar New Year Lunch Sunday, February 1, 2026 TBD Fountain
Valley Community Lunar New Year Event Sunday, February 1, 2026 TBD Irvine UCI Lunar New Year Events Sunday, February 8, 2026 TBD Attachments:
Attachment A – Non-Power Supply Contracts In Excess of $50,000 to Under $100,000 Attachment B – OCPA Contract Tracker as of January 1, 2026 Orange County Power Authority
Non Power Supply Contracts In Excess of $50,000 to Under $100,000 Item No Vendor Term Contract Amount Brief Service Description Remark 1 GB Endeavors, LLC 12/17/2025 - 12/16/2026 $50,000 Strategic Consulting and Analytical Support.
No. Vendor Start Date End Date NTE Amount Expenses recorded against contract
Amount for Work
Performed and
Invoiced but Not
Yet Paid
Remaining NTE
Amount
Notes Contract
Approved by the
Board?
Contract
Reported to the
Board?
RFP
to be Issued?
1 Best Best & Krieger 12/16/2020 See Notes See Notes 2,884,328.61 See Notes General Counsel, Financial & Power Procurement, Regulatory, Labor Related, and Special Legal Services. No NTE amount and contract end date. Costs are variable (time and materials).
Yes Yes RFP was issued on 2/24/2023 with one
proposal rec'd on 3/17/2023. Pending for
Board direction.
2 Calpine Energy Solutions 9/14/2021 9/13/2026 See Notes 6,665,183.05 See Notes Data Management & Call Center Services. NTE and Amount Paid depend on the number of active accounts during the month. Yes 3 Golden Communications 3/1/2024 2/28/2026 39,776.00 19,329.00 20,447.00 Digital Services - Strategic Marketing, Branding, Communications, and Public Education and Outreach Campaign/Program, Website Development Svc. Yes 4 Lakeview Business Center LLC (The Irvine Company) 2/19/2024 See Notes See Notes 307,043.52 See Notes New office lease 15310 Barranca Parkway, Irvine, CA 92618. The agreement was signed February 19, 2024 but the commencement date is approximately 22 weeks from that date. It is for 84 months (to end at the end of the month). The lease agreement does not have an NTE. The first 5 months are abated. Security deposit, 1st month rent and operating expense was paid in Apr-24.
Yes
5 Littler Mendelson P.C. 2/22/2024 12/31/2025 94,900.00 23,478.50 71,421.50 Labor and Employment Legal Services Yes 6 Maher Accountancy 1/1/2025 12/31/2025 280,500.00 280,500.00 - Accounting Service and Annual Financial Audit Support. Contract has been extended for 2025 with a 4.66% increase in the NTE amount ($280,500). Yes Yes 7 Newgen Strategies & Solutions 7/19/2023 6/30/2026 495,750.00 248,447.79 247,302.21 Rates Strategies, Budget and Projection Modeling, and FP&A Services. Yes 8 Orange County Printing Company/ R.R. Donneylley
the DOT Corp.
We Mail For You
8/1/2025 7/31/2027 260,000.00 84,012.29 175,987.71 Print House Services and Promotional Services. Three new contracts effective Aug 2025 to Jul 2027, include the option for the CEO to extend each agreement for up to 3 additional one-year terms, subject to satisfactory performance.
Yes
9 Pacific Energy Advisors, Inc. 1/1/2025 12/31/2025 588,000.00 549,130.16 38,869.84 Portfolio Management Services; amended with 10% increased NTE for additional back-office support and feasibility study for potential new members. A new contract for 2025 with a NTE of $588k has been approved by the board on 11/25/2024.
Yes Yes
10 Sorren CPAs P.C. 8/1/2025 7/31/2028 91,200.00 30,400.00 60,800.00 3-Year External Financial Audit Services. Yes 11 Reveille, Inc. 7/1/2023 6/30/2026 3,999,686.00 2,908,715.79 1,090,970.21 Strategic Marketing and Branding Material, PR and Social Media Support Yes 12 SDI Presence LLC 4/1/2024 3/31/2026 387,636.00 115,460.43 272,175.57 Managed IT Support Yes 13 Southern California Edison 3/28/2021 See Notes See Notes 1,711,147.69 See Notes CCA Service Agreement. Contract term from 3/28/2021 to CCA termination date. Billing provided by SCE is set forth in SCE’s community choice aggregation tariff, as stated in SCE’s Electric Rule 23 and SCE’s rate schedules.
Yes
14 The Energy Authority 4/1/2022 9/3/2026 770,960.00 696,427.45 74,532.55 Scheduling Coordinator, Day Ahead Load Forecasting, and CRR Management Services. Full Service from Commencement Date to 9/3/2026. Amendment to add the load forecast service for $12,160.
Yes Yes
15 The Energy Federation/ AM Conservation 7/1/2023 6/30/2026 480,000.00 450,039.25 29,960.75 Online marketplace services for residential energy efficient products and smart home devices Yes 16 Amperon 5/1/2024 5/11/2026 122,000.00 106,500.00 15,500.00 Amendment to the long- and short-term load forecast services agreement for risk management: extends the term through 5/11/2026 and adds an NTE of $62,000. The amendment also provides an option to extend the agreement for one additional year, bringing the total NTE to $187,100.
Yes
17 Gofarth & Marti, DBA GM Business interiors, a Corporation 5/1/2024 4/30/2026 275,000.00 270,299.54 4,700.46 Furniture for OCPA's new office. The Board approved the contract on 04/30/2024. Amendment to add NTE of $25K in Aug 2024. Yes Yes 18 The Energy Coalition 9/17/2024 9/17/2026 500,000.00 275,156.25 224,843.75 Develop the Community Power Plan, technical assistance, grant and program support for OCPA's customer programs Yes 19 Chapman and Cutler LLP 10/13/2025 10/12/2026 300,000.00 - 300,000.00 For prepayment and disclosure legal counsel, contingent upon transaction completion and payable from bond proceeds. Yes 20 PFM Financial Advisors and PFM Swap Advisors 10/13/2025 10/12/2026 325,000.00 - 325,000.00 For prepay municipal advisory and swap advisory services, contingent upon transaction completion and payable from bond proceeds Yes 21 GB Endeavors, LLC 12/17/2025 12/16/2026 50,000.00 - 50,000.00 Strategic Advisory Consulting Services Yes Orange County Power Authority Contracts
As of December 31, 2025