EDISON INTERNATIONAL (EIX) Business

BUSINESS

CORPORATE STRUCTURE, INDUSTRY AND OTHER INFORMATION

Edison International was incorporated in 1987 as the parent holding company of SCE, a California public utility incorporated in 1909. Edison International also owns Trio, a global energy advisory firm providing integrated sustainability and energy solutions to commercial, industrial and institutional customers.

The principal executive office of Edison International is located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, California 91770, and Edison International's telephone number is (626) 302-2222. The principal executive office of SCE is located at 2244 Walnut Grove Avenue, P.O. Box 800, Rosemead, California 91770, and SCE's telephone number is (626) 302-1212.

This is a combined Annual Report on Form 10-K for Edison International and SCE. Edison International and SCE make available at edisoninvestor.com: Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after Edison International and SCE electronically file such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's internet website at sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.

Subsidiaries of Edison International

SCE – Public Utility

SCE is an investor-owned public utility primarily engaged in the business of supplying and delivering electricity through SCE's electrical infrastructure to an approximately 50,000 square-mile area of southern California. SCE serves approximately 5 million customers in its service area. As of December 31, 2025, SCE's total number of customers by class were as follows:

CPUC and FERC rates decouple authorized revenue from the volume of electricity sales and the price of energy procured so that SCE has the opportunity to receive revenue equal to amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity sold does not have a direct impact on SCE's financial results. See "SCE—Overview of Ratemaking Process—CPUC" and "—FERC" for further information.

Trio – Energy Service Provider

Trio is a global energy advisory firm providing integrated sustainability and energy solutions to commercial, industrial and institutional customers. Trio aims to provide energy solutions that address cost, carbon and complex choices for its customers.

Regulation of Edison International as a Holding Company

As a public utility holding company, Edison International is subject to the Public Utility Holding Company Act. The Public Utility Holding Company Act primarily obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

Edison International is not a public utility and its capital structure is not regulated by the CPUC. The 1988 CPUC decision authorizing SCE to reorganize into a holding company structure, however, imposed certain obligations on Edison International and its affiliates. These obligations include a requirement that SCE's dividend policy continue to be established by the SCE Board of Directors as though SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's electricity service obligations, shall receive first priority from the Boards of Directors of Edison International and SCE. The CPUC has also promulgated Affiliate Transaction Rules, which, among other requirements, prohibit holding companies from (1) being used as a conduit to provide non-public information to a utility's affiliates and (2) causing or abetting a utility's violation of the rules, including providing preferential treatment to its affiliates.

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Human Capital

At December 31, 2025, Edison International had an aggregate of 13,725 employees (excluding interns and employees on leaves of absence), of which 13,235 were full-time employees of SCE or its subsidiaries. In addition to employees, SCE's workforce includes a significant number of contract workers who support SCE's operations. Among these contract workers are Safety Tier 1 Contractors. SCE estimates, based on contractors' self-reported hours worked and a 2,080-hour work year, that there were approximately 9,151 full-time equivalent Safety Tier 1 Contractors supporting SCE operations during 2025. All Safety Tier 1 Contractors engaged in decommissioning activities at San Onofre are managed by the DGC. In addition to Safety Tier 1 Contractors, SCE also uses other contract workers to support its transmission and distribution, vegetation management, information technology and customer service activities.

Approximately 4,600 of SCE's employees are represented by the International Brotherhood of Electrical Workers ("IBEW") under collective bargaining agreements that expire December 31, 2027. In addition, in June 2025, approximately 1,100 of SCE's employees agreed to be represented by the Engineers and Scientists of California Local 20, International Federation of Professional and Technical Engineers ("ESC 20"). As of February 11, 2026, negotiations between ESC 20 and SCE for a collective bargaining agreement are pending. A substantial number of SCE's contract workers are also unionized.

Edison International focuses on various human capital measures and objectives in managing its business, including measures and objectives related to safety, diversity, equity and inclusion and workforce continuity.

Safety

Safety is the first of Edison International’s core values. Edison International is committed to fostering and maintaining a safe environment for its employees, contract workers, customers, and the public. Over the past several years, Edison International has intensified its efforts to improve workforce safety, including an increased focus on, and investment in, maturing a culture of safety ownership among its workforce that empowers employees and contract workers to own their safety, support their team members' safety and contribute to a safe work environment.

Edison International takes efforts to eliminate fatalities and serious injuries, and reduce all injuries in our employee and contractor workforce. Edison International also continues to enhance its workforce safety culture. For instance, SCE uses safety culture assessments for both employee and contractors to measure progress toward improving safety culture. Additionally, all full-time employees are provided with regular safety-related training, particularly for those who work in proximity to high-voltage electrical equipment and other high hazard activities.

SCE has implemented a people and systems safety plan for high hazard organizations. This plan is driven by SCE’s Safety Management System (“SMS”) and safety culture improvement efforts. Foundational to the SMS is the safety risk management pillar that identifies and prioritizes risks and mitigations based on several factors, including worker and leader input. Examples of key risk mitigations targeted by the SMS include developing a multi-year training improvement plan and standardizing processes for safer high hazard work methods.

In 2025, SCE increased oversight of its contracted workforce through hiring of additional safety advisors. Similar to prior years, SCE implemented contractor initiatives to provide additional education on safe work practices, enhance risk awareness and better streamline understanding of SCE expectations. As part of SCE’s safety protocols and contractor safety efforts, it forms incident review teams to address all contractor serious injury incidents, and related corrective actions. The respective contractors are then required to perform a cause evaluation to determine causes and learnings for each incident. Incident review outcomes including any work practice changes, rule updates, and new tools are shared and communicated to SCE employees and contractors for their knowledge, awareness, and implementation. Additionally, to strengthen contractor safety performance, SCE engaged an independent consultant to conduct a comprehensive review and recommend enhancements to contractor safety programs.

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Edison International also uses various measures to assess safety performance, including, without limitation, fatalities and serious injury rates for employees and contract workers. The following represents data for 2025:

1EEI SIF Rate is calculated by multiplying the total number of 2025 EEI SIF incidents (classified by SCE on or before January 16, 2026) by 200,000 and then dividing by the total number of reported hours worked.

2DART Rate is calculated by multiplying the number of 2025 DARTs (reported to SCE on or before January 11, 2026 for Safety Tier 1 Contractors and classified as a DART by SCE on or before January 16, 2026 for employees) by 200,000 and then dividing by the total number of reported hours worked. The 2026 DART Rates may change based on information received by SCE after January 16, 2026, for Safety Tier 1 Contractors and after January 11, 2026 for employees.

3Represents SCE contractor safety data and data provided by the DGC for contractors that undertake a significant scope of decommissioning activities at San Onofre.

Diversity, Equity and Inclusion

Edison International believes that a merit-based work environment comprised of people with diverse skills, experiences and perspectives is an important driver of success. This merit-based inclusive approach supports a workforce that reflects the customers and communities it serves and enables Edison International to continue to earn public trust and drive better business outcomes. At Edison International, on average, employees in the same role regardless of race/ethnicity or gender identification receive equal pay for equal work. Similar to broader society, when looking at gender or race/ethnicity-specific groups across Edison International without regard to role, female employees and Black and Hispanic employees do not receive comparable pay to male and White employees, respectively, due to lower representation of female, Black and Hispanic employees in higher paying jobs. Edison International is committed to broad recruitment and use of merit-based hiring practices to attract and retain top talent.

The table below provides Edison International's employee diversity data1 as of December 31, 2025:

1Calculated using the guidelines SCE uses to calculate the diversity data it reports to the United States Equal Employment Opportunity Commission.

2Excludes interns and employees on a leave of absence.

3"Leaders" represents all non-executive manager and supervisor level employees.

4"Executives" represents all officers and all director level employees.

5Excludes employees of Trio's subsidiary Alfa Energy Ltd. Alfa Energy Ltd.’s workforce is based in the United Kingdom and does not track race/ethnicity data due to regulatory restrictions.

To support Edison International's inclusion efforts, Executives and Leaders are offered training and tools to enable all individuals to excel and to promote teams comprised of people with diverse skills, experiences and perspectives. Edison International uses various measures to assess success of its workforce development initiatives, including without limitation, monitoring hiring, promotion and turnover rates.

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Workforce Continuity

Edison International is committed to identifying and developing the talents of its workforce and takes a variety of steps to increase employee engagement and provide employees opportunities for growth. Employees are offered training opportunities, including an onboarding program, technical training, required ethics and compliance training and optional trainings to support career development. SCE estimates that over 99% of active SCE employees completed all assigned training required to be completed in 2025 as part of SCE's enterprise-wide training program. Employees may also be required to take additional trainings based on their job function.

Employees receive competitive compensation packages which include a wide selection of health plans, a 401(k) savings plan with a company match, wellness programs and initiatives, tuition reimbursement, competitive vacation/holiday program, professional development, volunteer programs, employee assistance program, and a philanthropy and matching contribution program.

Edison International uses various measures to assess employee engagement and satisfaction, including, without limitation, conducting regular employee engagement surveys and monitoring turnover. Edison International Parent and SCE's combined Turnover Rate was 6.7% and 7.9% in 2025 and 2024, respectively.

Executives engage in succession planning for leadership positions within the organization. Edison International's and SCE's Boards of Directors also engage in succession planning and talent development discussions for senior officers.

Edison International's Sustainability Report is available on its website. The report and any other information contained on, or connected to, this website are not deemed part of, and are not incorporated by reference into, this Annual Report on Form 10-K.

Insurance

Edison International maintains a property and casualty insurance program for itself and its subsidiaries and excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. These policies are subject to specific retentions, sub-limits and deductibles, which are comparable to those carried by other utility companies of similar size. Catastrophic events, such as hurricanes and storms, that have not impacted Edison International or its subsidiaries directly have had an impact, and can have future impacts, on insurance markets overall.

While SCE maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage experienced.

SCE also has separate insurance programs for nuclear property and liability, workers compensation and wildfires. For further information on nuclear and wildfire insurance, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies."

SCE

Regulation

CPUC

The CPUC has the authority to regulate, among other things, retail rates, utility distribution-level equipment and assets, energy purchases on behalf of retail customers, SCE capital structure, rate of return, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning funding and costs, and aspects of the transmission system planning, site identification and construction, including safety and environmental mitigation. The CPUC can assess penalties on any public utility that violates or fails to comply with its rules and requirements, of up to $100,000, for each offense, which could be assessed daily for a continuing violation. The CPUC's enforcement policy authorizes the staff of the CPUC to draft proposed Administrative Consent Orders and Administrative Enforcement Orders, both of which can include fines and serve as alternatives to issuance of a citation or formal investigation proceeding, for CPUC consideration and approval.

FERC

The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, rate of return, accounting practices, and licensing of hydroelectric projects. The FERC also has jurisdiction over a portion of the retail rates and associated rate design.

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CAISO

The CAISO operates a wholesale energy market primarily in California through which competing electricity generators offer their electricity output to market participants, including electricity retailers. SCE has placed its transmission system under the operational control of the CAISO.

Major transmission projects required for reliability, economic and other policy reasons are identified and approved through the CAISO's annual transmission planning process. Depending on the nature of the project identified, it may be assigned to SCE or set for competitive bid.

The CAISO is conducting transmission planning studies to identify transmission needed to meet a 25 million metric ton GHG emissions target by 2035 set by the CPUC for California's electricity sector to support California's target of reducing overall GHG emissions statewide.

NERC

The FERC assigned administrative responsibility to the NERC to establish and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential disruptions from cyber and physical security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets, including supervisory control and data acquisition systems for the electric grid. The reliability standards define the requirements for planning and operating the bulk power system. Compliance with these standards is mandatory. As of the date of this filing, the maximum penalty that may be levied for violating a NERC reliability or critical infrastructure protection standard is approximately $1.6 million per violation, per day.

OEIS

The OEIS, successor to the CPUC's Wildfire Safety Division, is responsible for, among other things, approving and overseeing compliance with WMPs. As part of overseeing WMP compliance, OEIS can issue notices of nonperformance and recommend that the Commission pursue an enforcement action against an electrical corporation for noncompliance with its approved WMP. Other OEIS tasks include conducting safety culture assessments, approving executive compensation structures, and issuing safety certifications.

NRC

The NRC has jurisdiction with respect to the safety of San Onofre and Palo Verde Nuclear Generating Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance assessment, and enforcement of its requirements. In June 2013, SCE decided to permanently retire and decommission San Onofre. The NRC regulates the decommissioning of San Onofre. For further information, see "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" in the MD&A.

Other Regulatory Agencies

The construction, planning and project site identification of SCE's transmission lines and substation facilities require compliance with various laws and approval of many governmental agencies in addition to the CPUC and FERC. These include various state regulatory agencies depending on the project location; the U.S. Environmental Protection Agency and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, the California Department of Fish and Wildlife, the California Coastal Commission, and the State Water Resources Control Board. In addition, to the extent that SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from the affected tribes and the Bureau of Indian Affairs are also necessary for the project to proceed.

Compliance with Government Regulations

SCE incurs significant costs to comply with government regulations. These costs, which include operation and maintenance expenses and capital expenses, include without limitation: costs incurred to maintain wildfire insurance coverage required by law; comply with environmental regulations, including licensing requirements, regulations governing California's renewable energy standards and regulations governing the decommissioning of San Onofre; land use and construction regulations; privacy and cybersecurity regulations; and Occupational Safety and Health Administration regulations. SCE also incurs operation and maintenance expenses and capital expenses to comply with requirements set forth in various regulatory decisions, including costs incurred to implement its approved capital projects and safety programs such as its WMPs.

Most costs incurred by SCE to comply with government regulations are authorized in its CPUC and FERC general rate cases and, are therefore, recovered through electric rates. To the extent SCE incurs costs to comply with government regulations above those that are authorized, or prior to obtaining authorization for recovery through rates (for instance

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certain costs incurred in line with SCE's obligations under its WMPs and tracked in wildfire mitigation-related memorandum accounts), SCE will seek recovery of such costs through electric rates to the extent they are eligible for recovery. There is no assurance that SCE will be allowed to fully recover these costs. For further information on wildfire mitigation and wildfire insurance costs, see "MD&A—Liquidity and Capital Resources—SCE—Regulatory Proceedings—Wildfire Related Regulatory Proceedings."

SCE earns a rate of return on its authorized capital expenditures included in its rate base. Approximately $1.6 billion of spending on wildfire risk mitigation capital expenditures are not included in rate base under the terms of AB 1054. Further, SCE expects that it will be required to exclude $2.9 billion of wildfire risk mitigation capital expenditures approved on or after January 1, 2026 under the terms of SB 254. For further information, see "—Southern California Wildfires— Recovery of Wildfire-Related Costs—California Wildfire Legislation—Excluded Capital Expenditures."

Overview of Ratemaking Process

CPUC

Revenue authorized by the CPUC through GRC proceedings is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investments in generation and distribution assets and general plant (also referred to as "rate base") on a forecast basis. Revenue is authorized through quadrennial GRC proceedings where the CPUC sets an annual revenue requirement for the test year which is made up of the operation and maintenance costs, depreciation, taxes and a return consistent with the authorized cost of capital (discussed below). In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Following the test year, the revenue requirements for the remaining three years will be set by a methodology established in the GRC proceeding, which has generally, among other items, included annual allowances for escalation in operation and maintenance costs and additional changes in capital-related investments.

SCE's 2025 GRC authorized revenue requirements for 2025, 2026, 2027 and 2028 of $9.7 billion, $10.2 billion, $10.7 billion and $11.2 billion, respectively, with adjustments to the post-test years' revenue requirements, allowing the application of an attrition index to operation and maintenance expenses, tied to the Consumer Price Index and capped at five percent each year, along with budget-based wildfire mitigation capital additions and zero escalation for all of SCE's non-wildfire related capital additions in the attrition years. For further discussion of the 2025 GRC, see "MD&A—Results of Operations—Impact of 2025 GRC."

Beginning with the 2029 GRC, SCE will be required to include affordability metrics in GRC applications where the revenue increase is estimated to exceed one percent of currently authorized revenues systemwide. The CPUC has defined affordability as the degree to which a representative household is able to pay for an essential utility service charge, given its socioeconomic status.

By May 15 in the year preceding each GRC application filing date, SCE is required to file a Risk Assessment and Mitigation Phase ("RAMP") application with the CPUC to provide information about SCE's assessment of its key safety risks and its proposed programs and spending for mitigating those risks. SCE plans to file its RAMP application for the 2029 GRC in May 2026. The information developed during the RAMP informs SCE's proposed projects and funding requests in the subsequent phase of the GRC.

The CPUC regulates SCE's cost of capital, including its capital structure and authorized rates of return. SCE's currently authorized capital structure is 43% long-term debt, 5% preferred equity and 52% common equity. SCE’s authorized capital structure is subject to certain exclusions, for example the waiver of certain expenses and debt related to the 2017/2018 Wildfire/Mudslide Events. For further information on the exclusion related to the 2017/2018 Wildfire/Mudslide Events, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends."

SCE's currently authorized cost of capital for 2026 consists of: cost of long-term debt of 4.71%, cost of preferred equity of 6.89%, and ROE of 10.03%. Based on these cost factors and the capital structure discussed above, SCE’s weighted average return on rate base will be 7.59% for 2026. The cost of capital adjustment mechanism set by the CPUC provides for an adjustment to SCE's authorized cost of capital. The cost of capital adjustment mechanism's benchmark beginning January 1, 2026, is the 12-month, October 1, 2024 through September 30, 2025, average Moody's Baa utility bond yield of 5.94%. If the difference between the benchmark and the average of the same index for the 12-month period from October 1, 2025 to September 30, 2026 exceeds 100-basis points, SCE's CPUC-authorized ROE will be adjusted for 2027 by 20% of the amount of the difference (up or down).

CPUC rates decouple authorized revenue from the volume of electricity sales so that SCE receives revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the volume of retail electricity sales.

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Cost-recovery balancing accounts track the difference between actual expenditures associated with the account, revenue authorized for recovery by the CPUC (authorized revenue requirement), and the actual revenues collected within customer rates to cover those specific expenditures. These balancing accounts are used to track and recover, among other things, SCE's decoupled costs of fuel and purchased power, as well as certain operation and maintenance expenses. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact earnings, such differences do impact cash flows and can change rapidly. SCE also has capital-related balancing accounts on which it earns a return, such as the grid hardening balancing account. Costs tracked in balancing accounts are not subject to after-the-fact reasonableness review unless the balancing accounts are one-way balancing accounts or otherwise subject to a cost cap. SCE also has memorandum accounts, which track costs above authorized levels eligible for cost recovery upon a future reasonableness review. To the extent SCE does not have a tracking mechanism, SCE cannot recover expenses that exceed authorized amounts. However, every subsequent GRC allows SCE to reflect its prior actual investment in plant as a part of the forecast for the next test year.

The 2025 GRC final decision authorized capital expenditures of approximately $1 billion during 2025 - 2028 to support 212 miles of the wildfire mitigation targeted undergrounding ("TUG") program, along with the deployment of 1,653 circuit miles of covered conductors in high fire risk areas. The final decision authorized a two-way Grid Hardening Balancing Account to track the difference between actual TUG costs and Rapid Earth Fault Current Limiter costs up to the approved mile limit and the authorized amounts, with spending in excess of 110% of authorized amounts subject to reasonableness review. SCE is also authorized to record incremental costs that exceed the approved scope in the existing Wildfire Mitigation Plan Memorandum Account, with cost recovery subject to reasonableness review.

SCE's cost-recovery mechanism for its fuel and purchased power-related costs is facilitated in three main balancing accounts, the ERRA, the PABA, and the new system generation balancing account ("NSGBA"). For all three accounts, SCE sets rates based on an annual forecast of the costs that it expects to incur during the subsequent year. In addition, the CPUC has established a "trigger" mechanism for the ERRA and the PABA. The trigger mechanism requires SCE to request an expeditious rate change if the sum of the ERRA balance and the bundled service customers' pro-rata share of the PABA balance exceeds 4% of SCE's prior year generation rate revenue and SCE does not expect the aggregate overcollection or undercollection to fall below 5% of SCE's prior year generation rate revenue within 120 days. For 2026, SCE estimates the 4% and 5% trigger amounts to be approximately $183 million and $229 million, respectively.

For 2025, the 4% and 5% trigger amounts were approximately $234 million and $292 million, respectively. As of December 31, 2025, the ERRA was overcollected by approximately $829 million, the PABA was undercollected by approximately $1.4 billion, and the NSGBA was overcollected by approximately $23 million. In December 2025, the CPUC approved SCE incorporating these year-end balances into customer rates in January 2026.

The majority of fuel and purchased power procurement-related costs eligible for recovery through cost-recovery rates are pre-approved by the CPUC through specific decisions and a procurement plan with predefined standards that establish the eligibility for cost-recovery. If such costs are subsequently found to be non-compliant with this procurement plan, then this could negatively impact SCE's earnings and cash flows. In addition, the CPUC retrospectively reviews outages associated with utility-owned generation and SCE's power procurement contract administration activities through the annual ERRA review proceeding. A CPUC finding that SCE was unreasonable or imprudent with respect to its utility-owned generation outages and contract administration activities, could negatively impact SCE's earnings and cash flows. The ERRA review proceeding is also used as a venue to review costs in various memorandum and balancing accounts including the Grid Hardening Balancing Account.

FERC

Transmission capital and operating costs that are prudently incurred, including a return on its net investment in transmission assets, are recovered through revenue authorized by the FERC. Since 2012, SCE has used a formula rate to determine SCE's FERC transmission revenue requirement, including its construction work in progress revenue requirement. Under operation of the formula rate, transmission revenue will be updated to actual cost of service annually. The transmission revenue requirement and rates are updated each December, to reflect a forecast of costs for the upcoming rate period, as well as a true up of the transmission revenue to actual costs incurred by SCE in the prior calendar year on its formula rate.

The FERC ROE is currently fixed at 10.3% and does not separately reflect any adders. The FERC ROE would only change if a different ROE is approved by the FERC in a new proceeding. For further information on the FERC formula rates, related transmission revenue requirements and rate changes, see "MD&A—Liquidity and Capital Resources—SCE—Regulatory Proceedings—2026 FERC Formula Rate Annual Update."

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Retail Rates Structure and Residential Rate Design

To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial, agricultural and street lighting) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate components are designed to recover the authorized revenue allocated to each customer class.

SCE has a two-tier residential rate structure. The first tier is priced below the average rate and is intended to cover the customer's essential electricity needs. The second tier is priced at 29% more than the first tier. SCE's current default rate is the time of use ("TOU") structure, which incorporates the two-tier structure through a baseline credit applied to approximately 300 kWh a month. Under a TOU rate structure, rates are based on the time of day and the season. TOU rates are typically lower early in the day, overnight, and on the weekends when energy resources are less in demand. As of December 31, 2025, approximately 60% of residential customers are on TOU rates. To recover fixed costs that SCE incurs to serve a residential customer regardless of the customer’s usage, SCE assesses both a minimum charge of $10 per month ($5 for low-income customers) and a fixed charge.

In May 2024, the CPUC authorized a residential class Basic Service Charge (i.e., fixed charge) with three levels dependent on participation in income-qualified programs. Customers enrolled in the California Alternative Rates for Energy (CARE) and Family Electric Rate Assistance (FERA) programs receive Basic Service Charges that are respectively 25% and 50% of the $24.15 fixed charge applicable to all other residential customers. SCE began including the new Basic Service Charge on residential customer bills in the fourth quarter of 2025. For information on residential rates for customers with renewable generation systems, see "—Competition" below.

Purchased Power and Fuel Supply

SCE obtains the power, energy, and local grid support needed to serve its customers primarily from purchases from external parties. SCE estimates that approximately 15% of power delivered to SCE's customers in 2025 came from SCE's own generating facilities.

Natural Gas Supply

SCE requires natural gas to fuel its Mountainview and peaker plants, which are generation units that operate in response to wholesale market signals related to power prices and reliability needs. The physical natural gas purchased by SCE is sourced in competitive interstate markets at trading points on the SoCalGas local distribution company system. SoCalGas is the primary provider of intrastate pipeline transportation service to the gas-fueled generation stations that SCE controls. In 2015 – 2016, SoCalGas experienced a significant natural gas fuel leak at its Aliso Canyon underground gas storage facility that resulted in reduced capacity and usage of the facility. Currently, Aliso Canyon is authorized to operate at up to 79% of its maximum capacity. CPUC has established a biennial assessment process to evaluate the reliability and cost impacts of minimizing or eliminating reliance on Aliso Canyon. To date, SCE has found that gas storage-use restrictions combined with SoCalGas pipeline maintenance constraints contributed to increased electricity costs for customers but did not impact grid reliability. However, there is no certainty that these restrictions or pipeline constraints will not impact grid reliability in the future. Price increases faced by customers would not affect SCE's earnings because SCE expects recovery of these costs through the ERRA balancing account or other CPUC approved procurement plans. However, these higher prices may impact cash flow due to the timing of those recoveries. For more information on cost-recovery mechanisms, see "—Overview of Ratemaking Process" above. SCE is actively monitoring legislative and regulatory processes that are addressing pipeline and electric grid operations impacted by the Aliso Canyon leak, including the CPUC’s biennial assessment process for considering changes to the facility's maximum inventory. SCE has also made additional procurement efforts to alleviate the impact of the partial closure of Aliso Canyon, including accelerating existing contracts for new capacity, procuring energy storage from third-parties, contracting for design, build, and transfer of utility-owned storage, procuring additional demand response and contracting for firm gas transportation capacity.

CAISO Wholesale Energy Market

The CAISO operates a wholesale energy market primarily in California through which competing electricity generators offer their electricity output to market participants, including electricity retailers. The CAISO schedules power in hourly increments with hourly prices through a day-ahead market in California and schedules power in fifteen-minute and five-minute increments with fifteen-minute and five-minute prices through two real-time markets that cover California and portions of ten neighboring states through the Western Energy Imbalance Market. Both markets optimize energy procurement, ancillary service procurement, unit commitment and congestion management. SCE participates in the day-ahead and real-time markets for the sale of its own generation and generation under contract and for purchases for its load requirements. In December 2023, the FERC approved an Extended Day-Ahead Market ("EDAM"), giving utilities outside the CAISO the option of joining a centralized day-ahead market run by the CAISO. The EDAM, which is currently scheduled to go-live in May 2026, gives utilities an opportunity to lock in energy prices a day in advance, and thereby substantially avoid volatility in the real-time energy market.

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The CPUC's Resource Adequacy program imposes resource adequacy requirements on load-serving entities like SCE that are designed to provide sufficient resources to the CAISO to ensure the safe and reliable operation of the grid in real time. All load-serving entities are responsible for meeting the system resource adequacy requirements for the load they serve, plus an additional amount that is referred to as a planning reserve margin. The CPUC has also adopted a central procurement structure in SCE's distribution service area for local resource adequacy that transfers the responsibility for procuring local resource adequacy from other local load-serving entities to SCE as a central procurement entity ("CPE") for its distribution service area. Under this structure, while SCE procures local resource adequacy to meet the local resource adequacy requirement for its distribution service area, other load-serving entities can also procure their own local resources. Load-serving entities ("LSE") that procure their own local resources can sell the capacity to the CPE, and utilize the resources.

Following state-wide rotating outages in August 2020 that impacted a significant number of SCE's customers, the CPUC has taken action towards ensuring reliable electric service in the event that extreme heat events occur during summer. The CPUC has issued decisions requiring at least an aggregate of 15,500 MW of additional net qualifying renewable or zero-emitting capacity to be procured collectively by all of the load-serving entities subject to the CPUC’s Integrated Resource Planning purview. The aggregate additional capacity is required by 2028, with 2,000 MW required by 2023, an additional 6,000 MW required by 2024, an additional 1,500 MW required by 2025, an additional 2,000 MW required by 2026, an additional 2,000 MW required by 2027, and an additional 2,000 MW of long-lead time resources, comprised of 1,000 MW of long-duration storage and 1,000 MW of firm zero-emitting resources required by 2028; 2,500 MW of the aggregate procurement requirement through 2025 must be through generation or generation paired with storage.

SCE's allocation of the requirements is 705 MW by 2023, 2,114 MW by 2024, 529 MW by 2025, 684 MW by 2026, 684 MW by 2027, and 705 MW of long-lead time resources, comprised of 353 MW of long-duration storage and 352 MW of firm zero-emitting resources by 2028, for a total of 5,421 MW; 880 MW of the aggregate procurement requirement through 2025 must be through generation or generation paired with storage.

As of December 31, 2025, SCE has executed sufficient long‑term contracts to meet all of these procurement requirements, including renewable and zero‑emitting resources, long‑duration storage and geothermal resources. In addition, SCE has executed contracts sufficient to meet its 880 MW procurement requirement for generation or generation paired with storage due in 2025, although certain projects are not expected to achieve commercial operation until 2026 or 2027. In September 2025, the CPUC established conditions under which delayed procurement may still be deemed compliant for up to three years after a required online date if the LSE has executed sufficient long‑term contracts and meets their month‑ahead system resource adequacy obligations during the delay. SCE expects to utilize this alternative compliance mechanism to address remaining delays in meeting applicable procurement requirements.

In February 2024, the CPUC adopted a decision approving SCE’s integrated resource plan identifying the resources needed to meet California’s greenhouse gas emissions and reliability targets and authorizing SCE to procure the resource needs identified in its plan. Additionally, the CPUC approved a process to request extensions of the 2028 procurement requirement for long-duration storage and firm zero-emitting resources to no later than 2031.

Competition

SCE faces retail competition in the sale of electricity to the extent that federal and California laws permit other sources to provide electricity and related services to retail customers within SCE's service area. While retail competition impacts customer rates it does not impact SCE's earnings activities because the volume of electricity sales is decoupled from authorized revenue. The increased retail competition is from governmental entities formed by cities, counties, and certain other public agencies to generate and/or purchase electricity for their local residents and businesses, known as CCAs. While California law provides only limited opportunities for customers in SCE's service area to choose to purchase power directly from an Electric Service Provider, a limited, phased-in expansion of customer choice ("Direct Access") for nonresidential customers was authorized beginning in 2009, and an additional limited expansion of Direct Access was authorized in 2018. When a customer who had previously taken bundled service from SCE converts to taking retail electricity service from an Electric Service Provider or a CCA, SCE remains that customer's transmission and distribution provider. Other forms of departing load include customer generation, and load that departs SCE service entirely to take electricity service from a publicly owned utility or a tribal utility.

California law requires bundled service customers to remain financially indifferent to departing load customers and to the mass return of departing load customers in the event of an Electric Service Provider or CCA's failure or other service termination. The CPUC has issued a series of decisions designed to avoid cost shifting in the context of departing load, including revising the power charge indifference adjustment methodology to effectively address potential cost shifts to bundled service customers.

Investor-owned utilities serve as the default providers of last resort in their respective service areas and can be significantly impacted by Electric Service Providers or CCAs failing or otherwise exiting the market. In March 2021, the CPUC initiated

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a rulemaking to examine the risks of catastrophic failures by Electric Service Providers or CCAs on investor-owned utilities and the need for any changes in the regulatory framework to increase consumer protections and financial security requirements, among other measures. In 2024, the CPUC issued a decision adopting changes to CCA financial security requirements, CCA financial reporting requirements, among others. As part of Phase 2 of this rulemaking, the CPUC will also examine under what requirements a CCA or Electric Service Provider may assume the provider of last resort obligation from an investor-owned electric utility in some or all of the utility’s service area.

As of year-end 2025, SCE had twelve CCAs serving customers in its service area that represented approximately 21% of SCE's total service load. One CCA expanded in SCE's service area in 2025. One expanded CCA has been approved by the CPUC to serve customers in SCE's service area in 2026. Based on recent load statistics, SCE anticipates that Direct Access and CCA load will be approximately 15% and 21% of its total service load by the end of 2026, respectively.

Customer-owned power generation and storage alternatives, such as rooftop solar facilities and battery systems, are increasingly installed by SCE's customers behind SCE's revenue meter as a result of technological developments, federal and state subsidies, and declining costs of such alternatives. Beginning in 2020, and subject to certain exceptions, most newly built homes in California are required to have solar installations.

Net Energy Metering

California legislation passed in 1995 encouraged private residential and commercial investment in renewable energy resources by requiring SCE and other investor-owned electric utilities to offer a NEM billing option to customers who install eligible power generation systems to supply all or part of their energy needs. NEM customers are interconnected to SCE's grid and credited for the net difference between the electricity SCE supplied to them through the grid and the electricity the customer exported to SCE over a 12-month period. SCE is required to credit the NEM customer for most of the power they sell back to SCE at the retail rate. Through the credit they receive, NEM customers effectively avoid paying certain grid-related costs. NEM customers are also exempted from some non-bypassable, standby and departing load charges and interconnection fees. Electric Service Providers and CCAs may, but are not required by law to, offer NEM rates.

In January 2016, the CPUC issued a decision adopting a new standard NEM tariff for customers with renewable generation systems. The changes that the CPUC decision made to the existing NEM tariff did not significantly impact the NEM subsidy. Specifically, the decision required customers that take service on SCE's NEM tariff after June 2017 to continue to be compensated at the retail rate, minus certain non-bypassable charges. NEM customers also continued to be exempted from standby and departing load charges but were required to pay a $75 interconnection fee and to select a time-of-use retail rate.

In August 2020, the CPUC initiated a rulemaking to develop a successor to the NEM tariffs. In December 2022, the CPUC issued a final decision adopting a Net Billing Tariff ("NBT") that decoupled export compensation from the retail rate, which lowers the subsidy compared to NEM. Under the final decision, the CPUC deferred consideration of whether to assess a grid participation charge to address the costs participating customers avoid by reducing the electricity they purchase from SCE and whether to adopt other mechanisms that would allow SCE to recover its cost of service and the costs of many public policy programs to another pending proceeding. The final decision also provides an enhanced subsidy for lower income customers and customers who pair rooftop solar with energy storage systems. The final decision does not apply to existing NEM customers until after they have completed twenty years on their existing NEM tariff, at which time they will move to the new, reduced NBT tariff. Non-utility parties' appeal of the CPUC's final decision is pending.

The effect of these types of competition on SCE generally is to reduce the amount of electricity purchased from SCE by retail customers. Customers who use alternative electricity sources typically continue to use and pay for SCE's transmission and distribution services; however, current NEM customers use, but do not pay the full cost for, those services. While changes in volume or rates generally do not impact SCE's earnings activities, decreased retail electricity sales by SCE has the effect of increasing utility rates because the costs of the distribution grid are not currently borne by all customers that benefit from its use. In November 2025, a Base Service Charge authorized by the CPUC was implemented for residential rates. The Base Service Charge recovers a portion of the fixed costs of providing service. See "Risk Factors—Risks Relating to Southern California Edison Company—Competitive and Market Risks."

In the area of transmission infrastructure, SCE has experienced increased competition from independent transmission providers under the FERC's transmission planning requirements rules, effective in 2011, that removed the incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities and mandated regional and interregional transmission planning. Regional entities, such as independent system operators, have processes for regional and interregional transmission planning and the competitive solicitation and selection of developers (including incumbent utilities) to build and own certain types of new transmission projects. The CAISO has held competitive solicitations pursuant to these rules and independent service providers were selected.

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