EDISON INTERNATIONAL (EIX) FY 2024 MD&A

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion related to the changes in financial condition for 2023 compared to 2022 is incorporated by reference to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in Edison International's and SCE's combined Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC in February 2024.

MANAGEMENT OVERVIEW

Highlights of Operating Results

Edison International is the ultimate parent holding company of SCE and Edison Energy, LLC, doing business as Trio. SCE is an investor-owned public utility primarily engaged in the business of supplying and delivering electricity to an approximately 50,000 square mile area across Southern, Central and Coastal California. Trio is a global energy advisory firm providing integrated sustainability and energy solutions to commercial, industrial and institutional customers. Trio's business activities are currently not material to report as a separate business segment.

Edison International's earnings are prepared in accordance with GAAP. Management uses core earnings (loss) internally for financial planning and for analysis of performance. Core earnings (loss) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the company's performance from period to period. Core earnings (loss) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (loss) are defined as earnings attributable to Edison International shareholders less non-core items. Non-core items include income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as write downs, asset impairments and other income and expense related to changes in law, outcomes in tax, regulatory or legal proceedings, and exit activities, including sale of certain assets and other activities that are no longer continuing.

Beginning July 1, 2023, SCE implemented a customer-funded wildfire self-insurance program. With the commencement of this program, Edison International and SCE no longer consider claims-related losses for wildfires to be representative of ongoing earnings and treat such costs as non-core items.

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1Charges of $4 million and $6 million related to claims from wildfires ignited prior to July 1, 2023 were included in core earnings in 2023 and 2022, respectively. Core earnings in periods before the third quarter of 2023 have not been recast to exclude these charges.

2SCE and Edison International Parent and Other non-core items are tax-effected at an estimated statutory rate of approximately 28%; customer revenues (claims) for EIS insurance contract are tax-effected at the federal statutory rate of 21%.

Edison International's 2024 earnings increased $87 million, driven by an increase in SCE's earnings of $145 million, offset by an increase in Edison International Parent and Other loss of $58 million. SCE's higher net income consisted of $97 million of higher core earnings and $48 million of lower non-core loss. Edison International Parent and Other's higher loss consisted of $22 million of higher core loss and $36 million of lower non-core earnings.

The increase in SCE's core earnings was primarily due to higher revenue authorized in Track 4 and an increase in the authorized rate of return resulting from the cost of capital adjustment mechanism, partially offset by higher interest expense.

The increase in Edison International Parent and Other's core loss was primarily due to higher interest expense.

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Consolidated non-core items for 2024 and 2023 for Edison International included:

•Charges of $493 million ($355 million after-tax) recorded in 2024 and $634 million ($457 million after-tax) recorded in 2023 for 2017/2018 Wildfire/Mudslide Events claims and related legal expenses, net of expected FERC recoveries. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further information.

•Charges of $162 million ($117 million after-tax) recorded in 2024 and $34 million ($25 million after-tax) recorded in 2023 for wildfire claims and related legal expenses, net of expected insurance and regulatory recoveries, related to the Other Wildfire Events. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further information.

•Charges of $146 million ($105 million after-tax) recorded in 2024 and $213 million ($153 million after-tax) recorded in 2023 from the amortization of SCE's contributions to the Wildfire Insurance Fund. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.

•Severance costs of $50 million ($36 million after-tax), net of expected FERC recovery, recorded in 2024 due to current and probable reductions in workforce. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.

•A charge of $30 million ($21 million after-tax) recorded in 2023 for a disallowance related to the 2021 NDCTP. See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" for more information.

•A charge of $17 million ($12 million after-tax) recorded in 2023 related to customer cancellations of certain ECS data services.

•Insurance recovery of $10 million ($7 million after-tax) recorded in 2023, related to settlement of an employment litigation matter. SCE and Edison International settled the matter following an atypical jury award.

•Expected wildfire claims of $4 million ($3 million after-tax) insured by EIS recorded in 2024 and net earnings of $42 million ($33 million after-tax) recorded in 2023, related to customer revenues for an EIS insurance contract offset by expected wildfire claims insured by EIS. See "Notes to Consolidated Financial Statements— Note 12. Commitments and Contingencies"

See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations.

Electricity Industry Trends

The electric power industry is undergoing urgent and fundamental changes to how energy infrastructure is planned and built, driven by: state government actions to reduce GHG emissions; new sources of demand, such as electric vehicles, data centers, and building electrification; and technological innovations that support clean energy adoption, such as distributed generation and energy storage. These factors, coupled with the increasing impacts of climate change, are altering the way in which electricity is generated and delivered. The impacts of climate change are apparent and accelerating. In 2024, the Earth experienced its hottest year on record. This spike in temperature is making extreme weather events commonplace. In California alone, climate-related disasters have cost the state tens of billions of dollars since 2018, with the 2025 wildfires being particularly devastating. Climate change is expected to have far-reaching effects on society, necessitating industry-wide solutions to enhance grid resilience and support a clean, reliable and affordable grid.

California is committed to reducing its GHG emissions, improving local air quality and supporting continued economic growth. The state codified into law goals to reduce GHG emissions by 40% from 1990 levels by 2030 and 85% from the same baseline by 2045, as well as to be carbon neutral by 2045. State and local air quality plans also call for substantial improvements including reducing smog-causing nitrogen oxides 90% below 2010 levels by 2032 in the most polluted areas of the state.

While these policy goals cannot be achieved by the electric sector alone, the electric grid is a critical enabler of the adoption of energy technologies that support California's GHG reduction objectives. California has set RPS targets which require California retail sellers of electricity to provide 60% of power from renewable resources by 2030. California also requires sellers of electricity to deliver 100% of retail sales from carbon-free sources by 2045, including interim targets of 90% by 2035 and 95% by 2040. In 2024, approximately 46% of SCE's customer deliveries came from carbon-free resources. SCE continues to make progress towards meeting its long-term RPS and carbon-free power goals and interim targets. In addition, Edison International is committed to achieving net-zero GHG emissions by 2045, in alignment with economy-wide climate actions planned by California. This commitment covers the power SCE delivers to customers and Edison International's enterprise-wide operations. To further support these goals, Edison International and SCE are investing in building a more resilient grid to reduce climate- and weather-related vulnerabilities. Since 2018, SCE has been

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adapting to climate change through system hardening to reduce wildfire risk. In its 2025 GRC, SCE proposed climate adaptation investments to address wildfire and physical risks that could occur by 2030.

Edison International believes that California's 2045 goals can be achieved most economically through emissions reductions enabled by clean electricity to serve 100% of retail sales, electrifying approximately 90% of light-duty vehicles, 90% of medium-duty vehicles, 54% of heavy-duty vehicles, 80% of buses and 95% of buildings. Additionally, reducing emissions to near zero in the electric sector hinges on developing clean firm resources to replace natural gas. Clean firm resources, such as next-generation geothermal, small modular reactors, natural gas with carbon capture and storage, and clean hydrogen, produce constant power through any weather conditions or season with little or no greenhouse gas emissions. By 2045, electricity demand is projected to increase by at least 80% as compared to 2022 per Edison International's analysis. In SCE’s service area, the increase in electricity demand is materializing sooner than expected. SCE’s most recent 10-year load growth forecast has increased by 35% compared to its 2022 distribution system plan. The key drivers of this increase are commercial developments, transportation electrification, and new residential housing. California has demonstrated strong long-term support of transportation electrification as shown by the approval of SCE's Charge Ready programs and 2022 legislation banning sales of new gas vehicles by 2035. However, Edison International believes that more state policy support, along with public and private investment, is needed to enable California to reach its 2030 and 2045 GHG reduction targets. Additional policy and regulatory support is also needed to de-risk the development of clean firm resources, adjust planning processes to enable proactive grid build-out, and streamline permitting processes. The current federal administration has declared a national emergency on energy, stressing the need for a reliable, diversified, and affordable supply of energy. The integrity and expansion of energy infrastructure is an immediate and pressing priority.

Edison International's vision is to lead the transformation of the electric power industry and the company is focused on opportunities in delivering clean energy, advancing electrification, building a modernized and more reliable grid, and enabling customers' technology choices. SCE's ongoing focus to drive operational and service excellence is intended to allow it to achieve these objectives safely while controlling costs and customer rates. SCE expects its bundled system average rate will rise at or below a 2.6% compound annual growth rate from 2024 through 2028, which is near the projected rate of local inflation. This projected rate growth incorporates the requested increases in SCE’s 2025 GRC, and also assumes a full recovery of costs associated with the 2017/2018 Wildfire/Mudslide Events (See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" for further information, including TKM Settlement). Partially offsetting these increases are historical costs rolling out of rates and rising electricity consumption. SCE projects that, even as electricity bills increase over time, total energy costs for the average SCE household will be reduced by approximately 40% by 2045 due to the efficiency of electrified technologies among other drivers.

SCE’s investments in the grid, utility owned storage capacity, and contracts for substantial new clean energy resources are key enablers of reliable economy-wide electrification. See "—Capital Program," "Liquidity and Capital Resources—Capital Investment Plan," and "Business—SCE—Purchased Power and Fuel Supply—CAISO Wholesale Energy Market" for further details. SCE also continues to implement its transportation electrification programs. As of December 31, 2024, SCE had completed construction at 386 sites to support 6,520 charge ports under its suite of light-duty Charge Ready programs, and 99 sites to support the electrification of 2,251 medium and heavy-duty vehicles through its Charge Ready Transport program. Subject to regulatory approval, SCE plans to invest approximately $13 billion in infrastructure replacement between 2023 and 2028 to ensure the grid is reliable, resilient, and ready for widespread electrification. This represents approximately 30% of the capital plan for that same time period, as discussed in "—Capital Program."

Changes in the electric power industry are impacting customers and jurisdictions outside California as well. Many other states and countries are also pursuing climate change and GHG reduction objectives, and large commercial and industrial customers are continuing to pursue cost reduction and sustainability goals. Trio is a global energy advisory firm providing integrated sustainability and energy solutions to commercial, industrial and institutional customers who may be impacted by these changes.

To better engage in this broader transformation and provide a view of developments outside of SCE, Edison International has also made several investments in emerging companies in areas related to the technology and business model changes that are driving industry transformation and may make additional investments in the future. These investments are not financially material to Edison International.

2025 General Rate Case

SCE filed its 2025 GRC application with the CPUC in May 2023, for the four-year period of 2025 – 2028. In its application, SCE requested that the CPUC authorize a test year 2025 revenue requirement of approximately $10.3 billion. This represents a $1.9 billion, or 23%, increase over the approximately $8.4 billion 2024 revenue requirement adopted in Track 4, prior to adjustments for updated operations and maintenance escalation rates, the CPUC's decisions to adopt SCE's 2023 - 2025 cost of capital, and the expanded use of customer-funded self-insurance for wildfire-related claims.

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In February 2024, intervenors to the 2025 GRC proceeding, including Cal Advocates and The Utility Reform Network ("TURN"), submitted testimony in response to SCE's application. Cal Advocates and TURN recommended reductions to SCE's requests for load growth investments, infrastructure replacement, targeted undergrounding of conductors, and other areas of SCE's application.

Cal Advocates in its testimony proposed a test year 2025 revenue requirement of approximately $9.3 billion, representing an increase of approximately 11% over the 2024 revenue requirement adopted in Track 4, before the adjustments described above. While TURN did not calculate a test year 2025 revenue requirement in connection with its proposals in its testimony, SCE estimates that TURN's proposals would result in a test year 2025 revenue requirement of approximately 12% over the 2024 revenue requirement adopted in Track 4, before the adjustments described above.

In June 2024, following amendments and other revisions to rebuttal testimony, SCE updated its 2025 revenue requirement request to $10.5 billion, and proposed post-test year revenue requirement increases of approximately $670 million, $750 million and $730 million in 2026, 2027, and 2028, respectively. The updated 2025 revenue requirement included a $220 million increase associated with the cost of capital adjustment authorized by the CPUC in a separate proceeding, which was subsequently modified by a CPUC decision in October 2024, as discussed in "—Cost of Capital."

In July 2024, the CPUC issued a decision approving SCE's request in the 2025 GRC to extend the customer-funded wildfire self-insurance through the 2025 GRC period.

In October 2024, the CPUC approved the establishment of a memorandum account to track changes in the revenue requirement between January 1, 2025, and the implementation date of the final decision. While SCE and certain parties have entered into stipulations to resolve certain contested areas in the 2025 GRC, SCE cannot predict the revenue requirement the CPUC will ultimately authorize or forecast the timing of a final decision. SCE expects to recognize revenue based on the 2024 authorized revenue requirement, adjusted to reflect the 2025 CPUC-authorized ROE as discussed in "—Cost of Capital," until a GRC decision is issued.

Cost of Capital

The cost of capital adjustment mechanism set by the CPUC provides for an adjustment to SCE's authorized cost of capital that, when triggered, will impact SCE's results of operations and cash flows. In 2023, the cost of capital adjustment mechanism was triggered and resulted in an increase to SCE's CPUC-authorized ROE from 10.05% to 10.75% effective January 1, 2024. The resulting increase to SCE's 2024 GRC-related revenue requirement was $201 million. The cost of capital adjustment mechanism was not triggered in 2024. In October 2024, the CPUC issued a decision modifying the cost of capital adjustment mechanism that changed the mechanism's adjustment ratio from 50% to 20%. This modification was also applied to the increase that was most recently triggered in 2023, effective on January 1, 2025. As a result, SCE's 2025 CPUC-authorized ROE was adjusted to 10.33%. The decision reduces SCE's updated 2025 GRC-related revenue requirement by approximately $117 million. For further information, see "—2025 General Rate Case." For additional information on cost of capital and the ratemaking process, see "Business—SCE—Overview of Ratemaking Process—CPUC."

SCE expects to file its regularly scheduled cost of capital application in March 2025 for rates effective for 2026 – 2028.

Capital Program

Capital Expenditures

Total capital expenditures (including accruals) were $5.7 billion in 2024 and $5.4 billion in 2023.

In connection with the 2025 GRC, SCE forecasts capital expenditures of $26.6 billion to $31.5 billion for 2025 – 2028. In the absence of a 2025 GRC decision, SCE has developed, and is executing against, a capital expenditure plan that is expected to allow SCE to meet what is ultimately authorized in the 2025 GRC decision while minimizing the associated risk of unauthorized spending.

The table below reflects forecast capital expenditures for 2025 – 2028 based on planned CPUC jurisdictional spending and current management expectations of FERC-jurisdictional spending. CPUC jurisdictional spending includes amounts requested in the 2025 GRC, and other approved non-GRC CPUC capital spending. The forecast CPUC jurisdictional capital spending will be dependent upon amounts approved in the 2025 GRC. Forecasted expenditures for FERC capital projects are subject to change due to factors such as timeliness of permitting, licensing, regulatory approvals, contractor bids, supply chain issues and other operational considerations.

Based on management's judgment of potential capital spending variability informed by historical precedent of previously authorized amounts, potential permitting delays, and other operational considerations, a range case was prepared reflecting reductions to GRC capital expenditures, CPUC non-GRC capital expenditures, and FERC capital expenditures.

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The following table sets forth a summary of capital expenditures for 2024 actual spend and a forecast for 2025 – 2028 on the basis described above:

*Not applicable

In addition to the amounts presented in the table above, SCE expects to make additional CPUC capital investments, the recovery of which will be subject to future regulatory approval. This includes non-GRC programs including additional spending on an enterprise resource planning ("ERP") software implementation, an advanced metering infrastructure program and other potential investments in the grid supporting restoration, reliability, resilience and readiness. SCE expects the total expenditures of these programs to be at least $3 billion, some of which will be incurred beyond 2028. In the first half of 2025, SCE intends to file an application with the CPUC for approval of the ERP implementation and expects to include approximately $1 billion of capital expenditures through 2029.

In May 2023, the CAISO released its 2022 – 2023 Transmission Plan based on the CPUC's projections that more than 40 gigawatts of new resources need to be added in California by 2032. As the incumbent transmission owner for a portion of these transmission projects, SCE expects to construct projects requiring capital investment of at least $2.0 billion, most of which will be incurred beyond 2028. In May 2024, the CAISO released its 2023 – 2024 Transmission Plan which identified additional transmission projects expected to be constructed by SCE by 2030 with anticipated capital expenditures of approximately $80 million.

In addition to projects awarded to incumbent transmission owners, the CAISO also identified projects eligible for competitive solicitation. In May 2024, SCE, in association with Lotus Infrastructure Global Operations, LLC, was selected as the approved project sponsor for a 30-mile overhead transmission line project connecting San Diego and Orange Counties. The project is expected to be in-service in 2032 and SCE expects to place approximately $244 million into its transmission rate base in 2032.

Rate Base

SCE's year-end rate base was $45.7 billion at December 31, 2024, compared to $42.7 billion at December 31, 2023.

Reflected below is SCE's weighted average annual rate base for 2024 – 2028, encompassing GRC capital expenditures as incorporated in the requests in the 2025 GRC application, approved non-GRC projects or programs, and FERC capital expenditures.

*Not applicable

Southern California Wildfires and Mudslides

Unprecedented weather conditions in California due to climate change have contributed to wildfires, including those where SCE's equipment has been alleged to be associated with the fire's ignition, that have caused loss of life and substantial damage in SCE's service area, including as recently as January 2025.

SCE continues to implement its WMP to reduce the risk of SCE equipment contributing to the ignition of wildfires. Further to the investments SCE is making as part of its WMP, SCE also uses its PSPS program to proactively de-energize power

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lines as a last resort to mitigate the risk of significant wildfires during extreme weather events. In addition, California has increased its investment in wildfire prevention and fire suppression capabilities. Yet, the potential for catastrophic wildfire activity in SCE's service area still exists.

Eaton Fire

In January 2025, several wind-driven wildfires impacted portions of SCE's service area, causing loss of life, substantial damage and service outages for SCE customers. One of the largest of these wildfires, the Eaton Fire, ignited in SCE's service area in Los Angeles County and spread under conditions of an extreme Santa Ana windstorm.

According to preliminary information provided by CAL FIRE, the Eaton Fire burned approximately 14,000 acres; destroyed approximately 6,018 single residence structures, 3,146 other minor structures, 96 multiple residences and 158 mixed commercial/residential and nonresidential commercial structures; damaged approximately 750 residential structures, 260 other minor structures, 28 multiple residences and 35 mixed commercial/residential and nonresidential commercial structures and resulted in 17 confirmed civilian fatalities and 9 confirmed fire personnel injuries/illnesses. In addition, fire authorities have estimated suppression costs at approximately $100 million.

The Los Angeles County Fire Department is leading the investigation into the origin and cause of the Eaton Fire, with the assistance of CAL FIRE, and has identified a preliminary area of origin of the fire. SCE has transmission facilities in the preliminary area of origin. As part of its investigation, the Los Angeles County Fire Department has requested that SCE preserve in-place its equipment in the preliminary area of origin. The SED is also conducting an investigation with respect to the Eaton Fire.

Multiple lawsuits related to the Eaton Fire have been initiated against SCE and Edison International. SCE’s ongoing internal review into the facts and circumstances of the Eaton Fire is complex and will require significant time. SCE's review includes ongoing inspections of its facilities and records and of third-party information, including analysis of concerning images and videos that suggest a possible link to SCE's transmission facilities in the preliminary area of origin. As of February 27, 2025, based on the information it has reviewed, SCE has not determined whether its equipment was associated with the ignition of the Eaton Fire.

SCE has $1.0 billion of customer-funded self-insurance coverage available for wildfires ignited between January 1, 2025 and December 31, 2025, subject to a shareholder contribution of up to $12.5 million. If SCE incurs losses in excess of $1.0 billion for claims for third-party damages related to the Eaton Fire, SCE will be reimbursed for such losses from the Wildfire Insurance Fund, subject to approval of the fund administrator and the Wildfire Insurance Fund’s claims-paying capacity, initially approximately $21 billion for all three participating utilities. PG&E is seeking reimbursement from the Wildfire Insurance Fund for losses related to the 2021 Dixie Fire and has disclosed that, as of December 31, 2024, it had recorded aggregate recoveries from the Wildfire Insurance Fund of $925 million, of which it had received $169 million. Until the fund administrator determines that the fund will be terminated, it is expected to reimburse eligible claims on a first come, first served basis, subject to the fund administrator's review.

A utility that has received reimbursement of eligible claims from the Wildfire Insurance Fund would file an application with the CPUC for review of its costs and expenses after it has resolved all or, if authorized by the CPUC, substantially all third-party damage claims related to a wildfire, or upon earlier request of the fund administrator. A utility that held a valid safety certification at the time of the relevant wildfire, like SCE did at the time of the Eaton Fire, will be presumed to have acted prudently unless a party in the proceeding creates "serious doubt" as to the reasonableness of the utility's conduct, in which case the utility will have the burden of dispelling that doubt and proving its conduct was prudent. The prudency standard does not necessitate perfect conduct and AB 1054 requires that the CPUC find that a utility is prudent if it determines that the utility's conduct related to the relevant ignition was consistent with actions of a reasonable utility. SCE believes that the CPUC's determination regarding the reasonableness of a utility's ignition-related conduct should be based on an evaluation of the reasonableness of the utility’s overall policies, systems, and practices. The CPUC has not applied the AB 1054 prudency framework to a wildfire cost-recovery proceeding.

SCE believes that it is a reasonable operator of its electric system. Neither SCE nor any fire agency has determined the cause of the Eaton Fire, including whether SCE’s transmission equipment was associated with its ignition. If it is determined that SCE’s transmission equipment was associated with the ignition of the Eaton Fire, based on the information it has reviewed as of February 27, 2025, SCE believes that it would be able to make a good faith showing that its conduct with respect to its transmission facilities in the preliminary area of origin was consistent with the actions of a reasonable utility.

The CPUC will determine the prudency of a utility’s ignition-related conduct in a formal proceeding. If the CPUC finds that a utility’s conduct was not prudent, it may nevertheless allow cost recovery in full or in part taking into account factors both within and beyond the utility's control that may have exacerbated the costs and expenses, including humidity, temperature and winds. A utility that held a safety certification at the time of the ignition will be required to reimburse the

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fund only for amounts disallowed by the CPUC up to the AB 1054 Liability Cap in the year that the disallowance occurs, unless the fund administrator finds that the utility's actions or inactions relative to the ignition of the fire constitute conscious or willful disregard of the rights and safety of others, in which case the utility will be required to reimburse the fund for all amounts withdrawn. The AB 1054 Liability Cap is a cap on the aggregate requirement to reimburse the Wildfire Insurance Fund over a trailing three calendar year period and is equal to 20% of the equity portion of the utility's transmission and distribution rate base, excluding general plant and intangibles, in the year of the applicable prudency determination. Utilities will be able to seek recovery of prudently incurred uninsured wildfire costs not covered by the Wildfire Insurance Fund, assessed under the prudency standard clarified under AB 1054, through electric rates.

2017/2018 Wildfire/Mudslide Events

Multiple lawsuits and investigations related to the 2017/2018 Wildfire/Mudslide Events have been initiated against SCE and Edison International. SCE has previously entered into settlements with a number of local public entities, subrogation and individual plaintiffs in the TKM and Woolsey Fire litigations and under the SED Agreement. As of February 20, 2025, in addition to the outstanding claims of approximately 290 of the approximately 15,000 initial individual plaintiffs, there were alleged and potential claims of certain public entity plaintiffs, including CAL OES, outstanding.

In 2024, SCE recorded estimated losses of $490 million for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. As a result, SCE also recorded expected recoveries through FERC electric rates of $27 million against the charge, and the resulting net charge to earnings was $463 million ($333 million after-tax).

Through December 31, 2024, SCE has recorded estimated losses of $9.9 billion, recoveries from insurance of $2.0 billion, all of which have been collected, and expected recoveries through FERC electric rates of $440 million, $376 million of which has been collected subject to refund, related to the 2017/2018 Wildfire/Mudslide Events claims. The cumulative after-tax net charges to earnings recorded through December 31, 2024, have been $5.4 billion.

As of December 31, 2024, SCE had paid $9.5 billion under executed settlements and had $86 million to be paid under executed settlements, including $57 million to be paid under the SED Agreement, related to the 2017/2018 Wildfire/Mudslide Events. After giving effect to all payment obligations under settlements entered into through December 31, 2024, Edison International's and SCE's best estimate of expected losses for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events was $340 million.

Estimated losses for the 2017/2018 Wildfire/Mudslide Events litigation are based on a number of assumptions and are subject to change as additional information becomes available. Actual losses incurred may be higher or lower than estimated based on several factors, including the uncertainty in estimating damages that have been or may be alleged. Edison International and SCE may incur a material loss in excess of amounts accrued in connection with the remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events.

CPUC-Jurisdictional Rate Recovery

In August 2023, SCE filed an application to seek CPUC-jurisdictional rate recovery of prudently incurred losses related to the Thomas Fire, the Koenigstein Fire and the Montecito Mudslides. SCE also sought recovery of approximately $65 million in restoration costs in the proceeding. In January 2025, the CPUC approved the TKM Settlement Agreement and closed the proceeding. Parties to the proceeding may file an application for rehearing through March 10, 2025. Under the TKM Settlement Agreement, SCE is authorized to recover 60%, or approximately $1.6 billion, of approximately $2.7 billion of losses, consisting of approximately $1.3 billion of uninsured claims paid as of May 31, 2024, and $0.3 billion of associated costs, composed of legal and financing costs incurred as of May 31, 2024, and estimated ongoing financing costs. SCE is also authorized to recover 60% of claims paid and related costs incurred after May 31, 2024, other than for $125 million of uninsured claims and related financing costs which SCE waived its right to seek recovery of under the SED Agreement. SCE will record a regulatory asset for recoveries permitted under the TKM Settlement Agreement in the first quarter of 2025 and will request approval from the CPUC to finance the amounts authorized under the TKM Settlement Agreement through the issuance of securitized bonds.

Under the TKM Settlement Agreement, SCE is also authorized to recover approximately $55 million of approximately $65 million in restoration costs incurred. Further, SCE will use shareholder funds to offset $50 million of wildfire mitigation expenses recorded in memorandum accounts between 2024 and 2028. Under the TKM Settlement Agreement, SCE is allowed to permanently exclude from SCE's CPUC regulatory capital structure any after-tax charges to equity associated with the costs disallowed or funded by shareholders in the TKM Settlement Agreement and the debt issued to finance those costs (For further details about SCE's CPUC authorized capital structure, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends"). In October 2024, SCE filed an application to seek CPUC-jurisdictional rate recovery of $5.4 billion of prudently incurred losses related to the Woolsey Fire, consisting of approximately $4.4 billion of uninsured claims paid as of August 31, 2024, and $1.0 billion of associated costs, composed of legal and financing costs incurred as of August 31, 2024, and estimated ongoing financing

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costs. SCE is also seeking recovery of approximately $84 million in restoration costs in the proceeding. SCE will not record a regulatory asset for recoveries related to the Woolsey Fire in connection with the approval of the TKM Settlement Agreement. SCE will continue to evaluate the facts and circumstances of the Woolsey Fire cost recovery proceeding in determining if and when a regulatory asset may be recorded.

Other Wildfire Events

In addition to the 2017/2018 Wildfire/Mudslide Events, several other wildfires significantly impacted portions of SCE's service area prior to 2025, including the 2017 Creek Fire, the 2019 Saddle Ridge Fire, the 2020 Bobcat Fire, the 2020 Silverado Fire, the 2022 Coastal Fire and the 2022 Fairview Fire.

In 2024, SCE recorded estimated losses of $253 million for claims related to the Other Wildfire Events. As a result, SCE also recorded expected recoveries from insurance of $96 million and expected recoveries through electric rates of $9 million against the charge, and the resulting net charge to earnings was $148 million ($106 million after-tax).

Through December 31, 2024, SCE has recorded total estimated losses of $1.1 billion, expected recoveries from insurance and third parties of $718 million and expected recoveries through electric rates of $177 million related to the Other Wildfire Events claims. The cumulative after-tax net charges to earnings recorded through December 31, 2024, have been $175 million.

As of December 31, 2024, SCE had paid or is obligated to pay approximately $576 million under executed settlements related to the Other Wildfire Events and Edison International's and SCE's estimated losses for remaining alleged and potential claims (established at the low end of the estimated range of reasonably possible losses) related to the Other Wildfire Events was $563 million. As of the same date, SCE had assets for expected recoveries through insurance and third parties of $434 million and through electric rates of $149 million on its consolidated balance sheets related to the Other Wildfire Events.

Edison International and SCE may incur material losses in excess of the amounts accrued for certain of the Other Wildfire Events. Edison International and SCE expect that additional losses incurred in connection with any such fire, other than for the Creek Fire, will be covered by insurance, subject to self-insured retentions and co-insurance, and expect that any such additional losses after expected recoveries from insurance and through electric rates will not be material. For information on the Creek Fire, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" in this report.

In light of the prudency standard the CPUC is required to apply under AB 1054 to utilities holding a safety certification at the time a wildfire ignited after July 12, 2019, SCE has concluded, at this time, that both uninsured CPUC-jurisdictional and uninsured FERC-jurisdictional wildfire-related costs related to the Other Wildfire Events that ignited after July 2019 for which it has deferred as regulatory assets are probable of recovery through electric rates. SCE will continue to evaluate the probability of recovery based on available evidence, including regulatory decisions, including any CPUC decisions illustrating the interpretation and/or application of the prudency standard under AB 1054, and, for each applicable fire, evidence that could cast serious doubt as to the reasonableness of SCE's conduct relative to that fire.

For further information on Southern California Wildfires and Mudslides, see "Risk Factors," "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Business—Southern California Wildfires" and "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" in this report.

RESULTS OF OPERATIONS

SCE

The table below shows SCE's consolidated statements of income for 2024, 2023 and 2022. In general, expenses SCE is authorized to pass through directly to customers (such as purchased power and fuel expenses, flow-through taxes, as well as costs incurred for various programs and activities, such as public purpose programs and vegetation management activities) and the corresponding amount of revenues collected to recover those pass-through costs do not impact net income.

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Years ended December 31, 2024, 2023 and 2022

The following table is a summary of SCE's results of operations for the periods indicated:

2024 vs 2023

Operating Revenue

Higher operating revenue of $1,272 million is primarily due to:

•An increase in CPUC-related revenues of $617 million primarily due to higher revenue authorized in Track 4 and an increase in the authorized rate of return resulting from the cost of capital adjustment mechanism. See "Management Overview—Cost of Capital" for more information.

•An increase in operating revenues of $51 million primarily due to recognition of previously unrecognized return on rate base related to emergency restoration related capital expenditures.

•A net increase in revenues of $604 million related to higher expenses that are passed through to customers. The increase in pass-through revenues is primarily offset by increases in the following:

◦Operation and maintenance expense of $809 million

◦Depreciation and amortization expense of $111 million

◦Interest expense of $66 million

◦Property and other taxes of $28 million

These pass-through increases were offset by the decreases in the following:

◦Purchased power and fuel expense of $277 million

◦Income tax expense of $134 million

Purchased Power and Fuel

A decrease in purchased power and fuel costs of $277 million, primarily due to lower purchased power and gas prices, partially offset by an increase in purchased power volume and higher losses in hedging activities (offset in "Operating Revenue" above).

Operation and Maintenance

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An increase in operation and maintenance expense of $993 million is primarily due to:

•A net increase in expense of $809 million related to operating expenses that are passed through to customers and offset in "Operating Revenue" above. The increase is mainly driven by:

◦$462 million due to higher previously deferred wildfire mitigation, vegetation management, and emergency restoration costs authorized for recovery in 2024 than in 2023. See "Liquidity and Capital Resources—SCE—Regulatory Proceedings" for more information

◦$301 million higher vegetation management expenses

◦$196 million higher public purpose program expenses

◦$144 million higher uncollectible accounts expense

◦$116 million higher transmission access charges

These increases are partially offset by:

◦$209 million previously deferred wildfire insurance premium authorized for recovery in 2023

◦$195 million lower insurance costs due to SCE's expanded use of customer-funded self-insurance since July 2023

•$90 million higher expenses primarily related to plant maintenance

•$62 million higher wildfire mitigation expenses

•Severance costs of $53 million recorded in 2024 due to current and probable reductions in workforce

•$25 million higher expenses related to IT software maintenance and capital-related expense

•The 2023 recognition of a $30 million disallowance related to the 2021 NDCTP

•The 2023 recognition of $17 million related to customer cancellations of certain ECS data services

Wildfire-related Claims, Net of Insurance Recoveries

Charges for wildfire-related claims, net of insurance recoveries, were $647 million and $665 million in 2024 and 2023, respectively, related to the 2017/2018 Wildfire/Mudslide Events and Other Wildfire Events. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

Wildfire Insurance Fund Expense

A decrease in wildfire insurance fund amortization expense of $67 million due to the change in the estimated life of the Wildfire Insurance Fund in the beginning of 2024, which increased the amortization period of SCE's Wildfire Insurance Fund contributions assets. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.

Depreciation and Amortization

An increase in depreciation and amortization expense of $232 million due to an increase of $121 million primarily driven by higher plant balances and $111 million of pass-through costs (offset in "Operating Revenue" above). The pass-through costs are mainly related to emergency restoration and wildfire mitigation activities.

Property and Other Taxes

An increase in property and other taxes of $54 million due to an increase of $26 million primarily related to higher assessed property values and $28 million of pass-through costs (offset in "Operating Revenue" above).

Interest Expense

An increase in interest expense of $219 million due to an increase of $153 million primarily related to higher interest rates on long-term debt and balancing account overcollections, and additional long-term borrowings, and $66 million of pass-through costs mainly related to emergency restoration activities and AB 1054 Excluded Capital Expenditures financed through securitization (offset in "Operating Revenue" above).

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Preference Stock Dividend Requirements

An increase in preference stock dividend requirements of $52 million primarily due to additional preference stock outstanding.

Income Taxes

A decrease in income tax expense of $64 million, primarily due to $97 million higher flow-through tax benefits that are passed through to customers, partially offset by an increase in tax expense on pre-tax income. See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for a reconciliation of the federal statutory rate to the effective income tax rate.

2023 vs 2022

Operating Revenue

An increase in operating revenue of $897 million is primarily due to:

•A net decrease in revenues of $1,231 million related to lower expenses that are passed through to customers. The decrease in pass-through revenues are offset by decreases in the following:

◦Purchased power and fuel expense of $889 million

◦Operation and maintenance expense of $482 million

◦Wildfire-related claims, net of insurance recoveries of $37 million

These pass-through decreases are partially offset by increases in the following:

◦Income tax expense of $43 million

◦Interest expense of $39 million

◦Property and other taxes of $38 million

◦Other income, net, of $37 million

◦Depreciation and amortization expense of $17 million

•An increase in CPUC-related revenues of $320 million primarily due to the escalation mechanism set forth in the 2021 GRC decision.

Purchased Power and Fuel

A decrease in purchased power and fuel costs of $889 million, primarily lower prices and volumes for both purchased power and gas, partially offset by hedging activities (offset in "Operating Revenue" above).

Operation and Maintenance

A decrease in operation and maintenance expense of $588 million is primarily due to:

•A net decrease in expense of $482 million related to the operating expenses that are passed through to customers and offset in "Operating Revenue" above. The decrease is mainly driven by:

◦$463 million due to lower previously deferred wildfire mitigation and emergency restoration costs authorized for recovery in 2023 than in 2022

◦$218 million lower insurance costs due to SCE's expanded use of customer-funded self-insurance since July 2023

◦$79 million lower uncollectible accounts expense primarily due to the recognition of $109 million previously deferred uncollectible accounts expense in 2022

◦$56 million lower transmission access charges

The decreases are partially offset by:

◦$209 million previously deferred wildfire insurance premium authorized for recovery in 2023

◦$125 million higher public purpose program expenses

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•The 2022 charges of $95 million related to the CPUC's decision on SCE's Upstream Lighting Program, consisting of $76 million in disallowed costs and $19 million in fines

•$40 million lower uncollectible accounts expense due to expense recognized in 2022 not subject to cost recovery

•The 2023 recognition of a $30 million probable disallowance related to the 2021 NDCTP

Wildfire-related Claims, Net of Insurance Recoveries

Charges for wildfire-related claims, net of insurance recoveries, were $665 million and $1.3 billion in 2023 and 2022, respectively, related to the 2017/2018 Wildfire/Mudslide Events and Other Wildfire Events.

Depreciation and Amortization

An increase in depreciation and amortization expense of $74 million due to an increase of $57 million primarily driven by higher plant balances and $17 million of pass-through costs (offset in "Operating Revenue" above).

Property and Other Taxes

An increase in property and other taxes of $69 million due to an increase of $31 million primarily related to higher assessed property values and $38 million of pass-through costs (offset in "Operating Revenue" above).

Impairment, net of other operating income

Impairments were recorded in 2022, of which $17 million related to disallowed capital expenditure and $47 million related to a settlement agreement between SCE and TURN in the CSRP proceeding.

Interest Expense

An increase in interest expense of $351 million due to an increase of $312 million primarily related to higher interest rates on long-term debt and balancing account overcollections and additional long-term borrowings, and $39 million of pass-through costs primarily related to AB 1054 Excluded Capital Expenditures financed through securitization (offset in "Operating Revenue" above).

Other income, net

An increase in other income, net of $160 million primarily due to higher interest rates applied to balancing account undercollections and increased equity allowance for funds used during construction, partially offset by lower net periodic benefit income related to the non-service cost components for SCE's pension and PBOP.

Preference Stock Dividend Requirements

An increase in preference stock dividend requirements of $16 million primarily due to dividends paid on Series E preference stock at a higher rate.

Income Taxes

An increase in tax expense of $293 million in 2023 compared to a tax benefit recorded in 2022, primarily due to higher taxable income and $42 million lower flow-through tax benefits that are passed through to customers.

Edison International Parent and Other

Results of operations for Edison International Parent and Other include amounts from other subsidiaries that are not reportable segments, as well as intercompany eliminations.

Loss from Operations

The following table summarizes the results of Edison International Parent and Other:

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The net loss attributable to common shareholders from operations of Edison International Parent and Other increased $58 million in 2024 compared to 2023 primarily due to lack of earnings from an EIS insurance contract and higher interest expense.

The net loss attributable to common shareholders from operations of Edison International Parent and Other increased $42 million in 2023 compared to 2022 primarily due to higher interest expense, partially offset by gains on preferred stock repurchases of $16 million.

LIQUIDITY AND CAPITAL RESOURCES

SCE

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is dependent upon its operating cash flow and access to the bank and capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest obligations, dividend payments to and equity contributions from Edison International, obligations to preference shareholders, and the outcome of tax, regulatory and legal matters.

In the next 12 months, SCE expects to fund its cash requirements through operating cash flows, and capital market and bank financings. SCE also has availability under its credit facility to fund cash requirements. SCE expects to issue additional debt for general corporate purposes, and to securitize the recovery of 2017/2018 Wildfire/Mudslide Events as permitted by the TKM Settlement Agreement subject to the filing and approval of a securitization financing order.

SCE issued securitized bonds in the amounts of $775 million and $533 million in 2023 and 2022, respectively, to finance the required AB 1054 Excluded Capital Expenditures and related financing costs. For more information, see "Notes to Consolidated Financial Statements––Note 5. Debt and Credit Agreements."

The following table summarizes SCE's current long-term issuer credit ratings and outlook from the major credit rating agencies, and SCE's credit rating outlook as of February 20, 2025:

SCE's credit ratings may be affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner, or the Wildfire Insurance Fund is materially depleted, or a persistent increase in the frequency of severe wildfires in California leads the credit rating agencies to believe the Wildfire Insurance Fund is at risk of a material depletion. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, bond financings or other borrowings. In addition, some of SCE's power procurement contracts and environmental remediation obligations would require SCE to pay related liabilities or post additional collateral if SCE's credit rating were to fall below investment grade. For further details, see "—Margin and Collateral Deposits."

For restrictions on SCE's ability to pay dividends, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends."

Available Liquidity

At December 31, 2024, SCE had cash on hand of $78 million and approximately $2.1 billion available to borrow on its $3.4 billion revolving credit facility. The credit facility is available for borrowing needs until May 2028. The aggregate maximum principal amount under the SCE revolving credit facility may be increased up to $4.0 billion, provided that additional lender commitments are obtained. SCE also had standby letters of credit with total capacity of $625 million, and the unused amount was $507 million as of December 31, 2024. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

At December 31, 2024, SCE had $1.3 billion outstanding commercial paper, net of discount, at a weighted average interest rate of 4.95% supported by the revolving credit facility. In January 2025, SCE issued $850 million and $650 million of first and refunding mortgage bonds due in 2035 and 2055, respectively. The proceeds were used to repay commercial paper borrowings outstanding as of December 31, 2024 and for general corporate purposes.

SCE may finance balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper, its credit facilities or other borrowings, subject to availability in the capital markets. As necessary, SCE will utilize its available liquidity, capital market financings, other borrowings or parent company equity

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contributions in order to meet its obligations as they become due, including costs related to wildfire events. For further information, see "Management Overview—Southern California Wildfires and Mudslides."

Debt Covenant

SCE's credit facilities and term loan require a debt to total capitalization ratio as defined in the applicable agreements of less than or equal to 0.65 to 1. At December 31, 2024, SCE's debt to total capitalization ratio was 0.58 to 1.

At December 31, 2024, SCE was in compliance with all financial covenants that affect access to capital.

Regulatory Proceedings

Wildfire Related Regulatory Proceedings

In response to the increase in wildfire activity and faster progression of and increase in damage from wildfires across SCE's service area and throughout California, SCE has incurred wildfire mitigation and wildfire and drought restoration related spending at levels significantly exceeding amounts authorized in SCE's GRCs. For regulatory proceedings related to the 2017/2018 Wildfire/Mudslide Events, see "Management Overview—Southern California Wildfires and Mudslides."

2021 GRC Wildfire Mitigation Memorandum Account Balances

In June 2022, SCE filed an application with the CPUC requesting reasonableness review of the incremental costs incurred in 2021 related to non-WCCP wildfire mitigation and vegetation management activities, requesting a total revenue requirement of approximately $327 million plus an ongoing capital-related revenue requirement. In March 2024, the CPUC issued a decision fully authorizing SCE's requested revenue requirement. The revenue requirement is being recovered in rates over 12 months starting June 1, 2024.

In October 2023, SCE requested authority to recover a revenue requirement of $384 million, including interest associated with 2022 operations and maintenance and capital expenditures above levels authorized in wildfire mitigation accounts and the vegetation management balancing account. In July 2024, the CPUC approved SCE's request for interim rate recovery of $210 million of this revenue requirement, subject to refund. The revenue requirement for interim rate recovery is being recovered in rates over 17 months starting October 1, 2024. A final decision for the total authorized revenue requirement is expected in the second quarter of 2025 according to the CPUC adopted schedule.

2020 Emergency Wildfire Restoration

SCE filed a catastrophic event memorandum account application in 2022, primarily related to restoration efforts related to multiple 2020 wildfires. In May 2024, the CPUC issued a decision approving the recovery of SCE's capital request of $312 million and operation and maintenance expenses of $200 million, resulting in a revenue requirement of $191 million plus its ongoing capital-related revenue requirement. The revenue requirement is being recovered in rates over a 12-month period starting October 1, 2024.

Multi-year Wildfire Mitigation and Catastrophic Events Filing ("WMCE Filing")

In April 2024, SCE filed its WMCE Filing, seeking to recover incremental operating and maintenance expenses of $320 million and incremental capital expenditures of $702 million, primarily associated with 2019 – 2023 WCCP capital expenditures recorded in the wildfire risk mitigation balancing account, 2023 operations and maintenance and capital expenditures incremental to amounts authorized in wildfire mitigation accounts and the vegetation management balancing account, storm-related costs associated with certain 2020 – 2022 events recorded in the catastrophic event memorandum account, and certain wildfire liability insurance premium expenses recorded in the wildfire expense memorandum account, which were denied without prejudice in a previous decision. In July 2024, the CPUC adopted a schedule with a proposed decision expected in the third quarter of 2025.

ERRA Trigger Application

SCE recovers its fuel and purchased power-related costs through various balancing accounts, primarily the ERRA and the PABA. SCE sets rates based on an annual forecast of the costs that it expects to incur during the subsequent year. The aggregate overcollection in the ERRA and the eligible portion of the PABA at April 30, 2024 resulted in SCE triggering an established mechanism, which required SCE to file an expedited application for the CPUC's approval to reduce bundled service generation rates (see "Business—SCE—Overview of Ratemaking Process" for further information about the trigger

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mechanism). The CPUC approved this application in August 2024, resulting in a $742 million reduction in the revenue requirement, returned through rates over a 12-month period starting October 1, 2024.

2025 FERC Formula Rate Annual Update

In November 2024, SCE filed its 2025 annual transmission revenue requirement update with the FERC, with rates effective January 1, 2025. The update reflects a 2025 transmission revenue requirement of $1.3 billion, which is a $220 million, or 20% increase from the 2024 annual rates. The increase is primarily due to 2024 rates including a return of prior year overcollections.

Capital Investment Plan

Major Transmission Projects

A summary of SCE's most significant transmission and substation construction projects is presented below. The timing of the projects below is subject to timely receipt of permitting, licensing, and regulatory approvals.

1Direct expenditures include direct labor, land, and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecast discussed in "Management Overview—Capital Program."

2Direct expenditures were adjusted for inflation with no change to the scope of the project.

3In June 2023, SCE filed an amended application for a certificate of public convenience and necessity ("CPCN") with technical design modifications and engineering refinements to the proposed project that decreases project costs and reduces GHG emissions. Accordingly, the direct expenditures of the project are estimated to be reduced from $486 million to $472 million. SCE is unable to predict the final project costs for the Alberhill System Project.

Riverside Transmission Reliability Project

The Riverside Transmission Reliability Project is a joint project between SCE and Riverside Public Utilities ("RPU"), the municipal utility department of the City of Riverside. While RPU will be responsible for constructing some of the project's facilities within Riverside, SCE's portion of the project consists of constructing upgrades to its system, including a new 230 kV substation; certain interconnection and telecommunication facilities and overhead transmission lines in the cities of Riverside, Jurupa Valley and Norco and in portions of unincorporated Riverside County. In May 2022, the Riverside City Council ("RCC") voted to investigate alternatives to the CPUC approved project. Consequently, SCE suspended all major activities on the project. In January 2023, the RCC voted to establish a working group to pursue funding for additional undergrounding. In October 2023, the City of Norco filed a petition for modification ("PFM") to modify the CPUC decision approving the project and reopen the record to reconsider full undergrounding. In November 2023, SCE filed a response opposing the PFM. In March 2024, the CPUC denied the PFM. In May 2024, the RCC voted to move forward with the original scope of the project and SCE restarted its work on the project. In July 2024, SCE initiated construction bid solicitations with awards expected in the first half of 2025.

Alberhill System Project

The Alberhill System Project consists of constructing a new 500 kV substation, two 500 kV transmission lines to connect the proposed substation to the existing Serrano-Valley 500 kV transmission line, telecommunication equipment, and subtransmission lines in western Riverside County. The project was designed to meet long-term forecasted electrical demand in the proposed Alberhill System Project area and to increase electrical system reliability and resiliency. In April 2018 and July 2018, the CPUC issued a proposed decision and an alternate proposed decision, both denying SCE's ability to construct the Alberhill System Project based on a perceived lack of need. SCE filed comments on both proposed decisions requesting that the CPUC grant the CPCN for the Alberhill System Project. In August 2018, the CPUC issued a decision that did not deny or approve the Alberhill System Project but directed SCE to submit supplemental information on the Alberhill System Project, including, but not limited to, a load forecast and cost benefit analysis of several alternatives to the proposed project. In January 2020, SCE submitted a supplemental analysis to the CPUC for the Alberhill System Project including several alternatives to the proposed project as well as an update to the original project cost. In June 2023, SCE filed an amended CPCN with technical design modifications and engineering refinements to the proposed project that decrease project costs and reduce GHG emissions. In June 2024, the CPUC issued an addendum to its 2017 Final

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Environmental Impact Report, concluding its California Environmental Quality Act review. The project is now seeking final CPUC approval to begin construction. SCE is expecting the final CPUC decision in the second half of 2025.

Approximately 48% of the Alberhill System Project costs spent to date would be subject to recovery through CPUC revenue and 52% through FERC revenue. In October 2017, SCE obtained approval from the FERC for abandoned plant treatment for the Alberhill System Project, which allows SCE to seek recovery of 100% of all prudently incurred costs after the approval date and 50% of prudently incurred costs prior to the approval date. As of December 31, 2024, SCE had incurred approximately $69 million of capital expenditures, which excludes land costs that may be recovered through sale to a third party and includes overhead costs, of which approximately $48 million may not be recoverable if the project is cancelled.

Eldorado-Lugo-Mohave Upgrade Project

The Eldorado-Lugo-Mohave Upgrade Project will increase capacity on existing transmission lines to allow additional renewable energy to flow from Nevada to southern California. The project would modify SCE's existing Eldorado, Lugo, and Mohave electrical substations to accommodate the increased power flows from Nevada to southern California; increase the power flow through the existing 500 kV transmission lines by constructing two new capacitors along the lines; raise transmission tower heights to meet ground clearance requirements; and install fiber optics on the transmission lines to provide communications between existing SCE substations. In August 2020, the CPUC approved the CPCN for the project.

Construction for the project began in November 2020. The total costs for the Eldorado-Lugo-Mohave Upgrade Project are expected to exceed amounts currently approved in the CPCN granted by the CPUC due to delays in regulatory approvals, contractor performance issues, supply chain constraints, COVID-19 impacts, and the availability of CAISO outage windows. In May 2023, SCE filed a PFM of the decision that approved the project to increase the maximum reasonable and prudent cost for the project, which increased the direct expenditures from $247 million to $319 million. SCE expects the project to be in service in 2025, subject to the completion of environmental agency review of the mitigation work. Additional work after the in-service date is required to mitigate the impact of the project on nearby natural gas transmission lines. SCE's current estimate of the additional work is $64 million. SCE anticipates filing a second PFM or amending the existing PFM to address the additional costs of the mitigation work once the scope and cost of this work is finalized.

Utility Owned Storage Projects

In October 2021, SCE contracted with Ameresco, Inc. ("Ameresco") for the construction of utility owned energy storage projects at three sites in SCE's service area with an aggregate capacity of 537.5 MW, consisting of a 225 MW project, a 200 MW project, and a 112.5 MW project, and an in-service date of August 1, 2022. The 200 MW and 112.5 MW projects went in-service during the third quarter of 2024, and Ameresco has advised SCE that it currently expects the 225 MW project to be in-service by the first quarter of 2025. SCE believes that there is risk of delay beyond Ameresco's projected in-service date.

In April 2022, SCE received a force majeure event notice from Ameresco in which Ameresco asserted that both manufacturing delays related to COVID-19 shut-downs in China and new shipping restrictions imposed by Chinese governmental authorities were then impacting the supply of batteries from China necessary for timely completion of the projects. Ameresco subsequently supplemented its force majeure notice noting additional supply chain issues related to COVID-19. Permitting delays and engineering issues and certain changes requested by SCE also impacted the projects in 2022. In January 2023, SCE received a force majeure event notice from Ameresco in which Ameresco asserted that severe winter storms in Southern California had impacted the timely completion of the projects.

In April 2023, Ameresco discovered damage to some of the equipment at the 225 MW project. Ameresco has sent SCE a notice of potential force majeure event and has concluded that the damage was caused by soil heave and that the soil heave was caused by extreme rainstorms at the project site in the winter of 2022 – 2023. Ameresco is performing corrective action in response to the damage discovered in 2023.

SCE is continuing to evaluate the force majeure event notices and is awaiting additional information from Ameresco on the underlying events. If there is a valid force majeure event under the contracts with Ameresco, subject to certain conditions, the project schedules and any related triggers of liquidated damages may be extended, and the contract prices may be increased to account for the impact of the force majeure event.

SCE currently expects these storage projects to result in $1.0 billion of capital expenditures of which approximately $800 million has been incurred, as of December 31, 2024. SCE also expects to receive in aggregate approximately $380 million of tax credits available under the IRA for all three projects, which will accrue to the benefit of its customers (see "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information). Because Ameresco did not achieve an in-service date of August 1, 2022, SCE is entitled to liquidated damages under the terms of the contracts subject to any relief Ameresco may be entitled to under the contracts, including any relief for any valid force majeure

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events. Once triggered, delay-related liquidated damages accrue daily for up to 60 days up to a maximum of $89 million in aggregate for all three projects.

Ameresco has obtained surety bonds to secure its obligations to complete the construction of the projects, and is also required to obtain surety bonds or letters of credit after completion of the projects to secure its performance obligations, including its warranty obligations. If Ameresco is unable to fulfill its obligations and the amounts available under any surety bonds or letters of credit are insufficient or the issuer of any such surety bonds or letters of credit disputes coverage or otherwise does not perform or pay for the performance of Ameresco’s obligations, SCE will incur additional costs beyond its contractual obligations.

In December 2021, the CPUC approved recovery of the capital expenditures and establishment of a balancing account for the associated revenue requirement, which have been reflected in rates beginning in the first quarter of 2022. Authorized revenue requirements have been and will continue to be included in the annual ERRA review proceeding and can only be disallowed upon a finding that SCE failed to prudently administer the contracts.

Decommissioning of San Onofre

The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning, and the management of spent nuclear fuel. SCE is the operating agent of San Onofre and has engaged the DGC to undertake a significant scope of decommissioning activities for Units 1, 2, and 3 at San Onofre. The decommissioning of San Onofre is expected to take many years. SCE funds decommissioning costs, including costs associated with storing spent nuclear fuel, with assets that are currently held in nuclear decommissioning trusts.

Under federal law, the U.S. Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE has not met its contractual obligation to accept spent nuclear fuel. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Two Independent Spent Fuel Storage Installations ("ISFSI") store nuclear fuel onsite at San Onofre. The first stores nuclear fuel from all three Units ("ISFSI 1") and the second stores nuclear fuel from Units 2 and 3 ("ISFSI 2").

SCE's Coastal Development Permits, the principal discretionary permits required for maintaining the ISFSIs onsite, currently extend through 2035.

Decommissioning of San Onofre Unit 1 began in 1999 and the transfer of spent nuclear fuel from Unit 1 to dry cask storage in ISFSI 1 was completed in 2005. Major decommissioning work for Unit 1 has been completed except for certain underground work.

Decommissioning of San Onofre Units 2 and 3 began in June 2013 and the transfer of spent nuclear fuel from San Onofre Units 2 and 3 to dry cask storage in the two ISFSIs was completed in August 2020. In August 2020, SCE commenced, and is currently conducting, major decommissioning activities in accordance with the terms of the Coastal Developmental Permit for decommissioning San Onofre Units 2 and 3.

SCE's share of the San Onofre Units 2 and 3 decommissioning costs recorded for the years ended December 31, 2024 and 2023 were $218 million (in 2024 dollars) and $226 million (in 2023 dollars), respectively. The CPUC conducts a reasonableness review of recorded decommissioning costs in NDCTPs, which are submitted every three years.

SCE filed the 2021 NDCTP with the CPUC in February 2022 to request reasonableness review of approximately $570 million (SCE share in 2022 dollars) of recorded San Onofre Units 2 and 3 decommissioning costs incurred during the period 2018 to 2020, and subsequently agreed to a $30 million disallowance under a settlement with the relevant intervenors. In the third quarter of 2024, the CPUC approved the 2021 NDCTP, as modified by the settlement agreement, and SCE made a contribution accordingly to the non-qualified nuclear decommissioning trust to effectuate the disallowance.

SCE filed its 2024 NDCTP in December 2024. In the 2024 NDCTP, SCE requests reasonableness review of approximately $538 million (SCE share in 2024 dollars) of recorded San Onofre Units 2 and 3 decommissioning costs incurred during the period 2021 to 2023. SCE also requests approval of an updated decommissioning cost estimate for decommissioning activities to be completed at San Onofre Units 2 and 3 of $3.0 billion, of which $2.3 billion is SCE's share (in 2024 dollars). The decommissioning cost estimate includes costs through the expected decommissioning completion date, currently estimated to be in 2056.

Decommissioning cost estimates are subject to a number of uncertainties including the cost and timing of nuclear waste disposal, the time it will take to obtain required permits, cost of removal of property, site remediation costs, as well as a number of other assumptions and estimates, including when the federal government will provide for either interim or permanent off-site storage of spent nuclear fuel enabling the removal and transport of spent fuel canisters from the San

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Onofre site, as to which there can be no assurance. Cost estimates are subject to change as decommissioning proceeds and such changes may be material.

SCE had nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.1 billion at December 31, 2024 and $2.2 billion at December 31, 2023. Based upon the resolution of a number of uncertainties, including the uncertainties of decommissioning discussed above, the financial performance of the nuclear decommissioning trust fund investments, as well as the resolution of a number of other assumptions and estimates, additional contributions to the nuclear decommissioning trust's funds may be required. If additional contributions to the nuclear decommissioning trust funds become necessary, SCE will seek recovery of additional contributions to the decommissioning trust through electric rates and any such recovery will be subject to a reasonableness review by the CPUC. Cost increases resulting from contractual disputes, delays in performance by the contractor, elevated levels of inflation, or permitting delays, among other things, could cause SCE to materially overrun the decommissioning cost estimate and could materially impact the sufficiency of trust funds.

In December 2024, the CPUC approved disbursements from SCE's nuclear decommissioning trusts to cover forecasted 2025 decommissioning costs for San Onofre Units 2 and 3, of which SCE's share is approximately $245 million in 2025 dollars.

Margin and Collateral Deposits

Certain derivative instruments, power and energy procurement contracts, and other contractual arrangements contain collateral requirements. In addition, certain environmental remediation obligations require financial assurance that may be in the form of collateral postings. Future collateral requirements may differ from the requirements at December 31, 2024 due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations, and the impact of SCE's credit ratings falling below investment grade.

The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would have been required as of December 31, 2024, if SCE's credit rating had been downgraded to below investment grade as of that date. The table below also provides the potential collateral that could be required due to adverse changes in wholesale power and natural gas prices over the remaining lives of existing power and fuel derivative contracts.

In addition to amounts shown in the table, power and fuel contract counterparties may also institute new collateral requirements, applicable to future transactions to allow SCE to continue trading in power and fuel contracts at the time of a downgrade or upon significant increases in market prices. Furthermore, SCE may also be required to post up to $50 million in collateral in connection with its environmental remediation obligations, within 120 days of the end of the fiscal year in which a downgrade below investment grade occurs.

1Net collateral provided to counterparties and other brokers consisted of $128 million in letters of credit and surety bonds and $81 million of cash collateral.

2Represents potential collateral requirements for accounts payable and mark-to-market valuation at December 31, 2024. Requirement varies throughout the period and is generally lower at the end of the month.

3Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2024 due to adverse market price movements over the remaining lives of the existing power and fuel derivative contracts using a 95% confidence level.

Edison International Parent and Other

In the next 12 months, Edison International Parent expects to fund its net cash requirements through cash on hand, dividends from SCE, and capital market and bank financings. Edison International Parent may finance its ongoing cash requirements, including dividends, working capital requirements, payment of obligations, and capital investments, including capital contributions to subsidiaries, with short-term or other financings, subject to availability in the bank and capital markets.

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At December 31, 2024, Edison International Parent had cash on hand of $115 million and $1.1 billion available to borrow on its $1.5 billion revolving credit facility. The credit facility is available for borrowing needs until May 2028. The aggregate maximum principal amount under the Edison International Parent revolving credit facility may be increased up to $2.0 billion, provided that additional lender commitments are obtained. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

At December 31, 2024, Edison International Parent had $444 million outstanding commercial paper, net of discount, at a weighted-average interest rate of 4.86% supported by the revolving credit facility.

Edison International Parent has $800 million of debt maturities arising in the next 12 months. Edison International expects to issue debt to refinance these maturities.

On February 27, 2025, Edison International declared a dividend of $0.8275 per share to be paid on April 30, 2025. Edison International Parent and Other's liquidity and its ability to pay operating expenses and pay dividends to common shareholders are dependent on access to the bank and capital markets, dividends from SCE, realization of tax benefits and its ability to meet California law requirements for the declaration of dividends. Prior to declaring dividends, the Edison International Board of Directors evaluates available information, including when applicable, information pertaining to wildfire events, to ensure that the California law requirements for the declarations are met. For information on the California law requirements on the declaration of dividends, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends." Edison International intends to maintain its target payout ratio of 45% – 55% of SCE's core earnings, subject to the factors identified above.

Edison International's ability to declare and pay common dividends may be restricted under the terms of its Series A and Series B Preferred Stock. For further information see "Notes to Consolidated Financial Statements—Note 14. Equity."

Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio as defined in the applicable agreements of less than or equal to 0.70 to 1. At December 31, 2024, Edison International's consolidated debt to total capitalization ratio was 0.65 to 1.

At December 31, 2024, Edison International Parent was in compliance with all financial covenants that affect access to capital.

The following table summarizes Edison International Parent's current long-term issuer credit ratings and outlook from the major credit rating agencies, and Edison International Parent's credit rating outlook as of February 20, 2025:

Edison International Parent's credit ratings may be affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner, or the Wildfire Insurance Fund is materially depleted, or a persistent increase in the frequency of severe wildfires in California leads the credit rating agencies to believe the Wildfire Insurance Fund is at risk of a material depletion. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, note financings or other borrowings.

Edison International Income Taxes

Net Operating Loss and Tax Credit Carryforwards

Edison International has approximately $3.6 billion of tax effected net operating losses and tax credit carryforwards at December 31, 2024 (after excluding $107 million of Capistrano Wind attributes and offsetting $397 million of unrecognized tax benefits), which are available to offset future consolidated tax liabilities.

See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information regarding taxes payable to Capistrano Wind.

Inflation Reduction Act of 2022

The IRA imposes a 15% corporate alternative minimum tax ("CAMT") on adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a specified 3-year period. The CAMT was effective beginning January 1, 2023. Based on the current interpretation of the law and historical financial data, Edison International estimates that it will exceed the $1.0 billion threshold and be subject to CAMT on its consolidated federal tax returns beginning in 2026. SCE expects to be subject to CAMT on its stand-alone Federal return beginning in 2026.

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The law also includes significant extensions, expansions, and enhancements of numerous energy-related investment tax credits, as well as creating new credits applicable to electricity production which may apply to SCE's capital expenditures. Under the IRA, as of December 31, 2024, SCE generated investment tax credits of approximately $231 million related to two utility owned storage projects, which will be recognized and returned to customers, as the credits are utilized.

Historical Cash Flows

SCE

Net Cash Provided by Operating Activities

The following table summarizes major categories of net cash provided by operating activities as provided in more detail in SCE's consolidated statements of cash flows for 2024, 2023, and 2022:

1Non-cash items include depreciation and amortization, allowance for equity during construction, impairment and other income, Wildfire Insurance Fund amortization expense, deferred income taxes, and other.

2Changes in working capital items include receivables, accrued unbilled revenue, inventory, amortization of prepaid expenses, accounts payable, tax receivables and payables, derivative assets and liabilities, and other current assets and liabilities.

3The amount in 2024 represents payments of $779 million for 2017/2018 Wildfire/Mudslide Events and $361 million for Other Wildfire Events, partially offset by an increase in wildfire estimated losses of $743 million. The amount in 2023 represents payments of $1.0 billion for 2017/2018 Wildfire/Mudslide Events and $190 million for Other Wildfire Events, partially offset by an increase in wildfire estimated losses of $814 million.

4Includes nuclear decommissioning trusts. See “Nuclear Decommissioning Activities” below for further information. The amount in 2024 also includes cash received from customers to fund certain construction projects and cash received for a state incentive program to pass on to customers. The amount in 2023 also includes outflow from the increases in wildfire insurance receivables.

Net cash provided by operating activities was impacted by the following:

Net income and non-cash items increased in 2024 by $231 million primarily due to higher revenue authorized in Track 4 and an increase in the authorized rate of return resulting from the cost of capital adjustment mechanism, partially offset by higher interest expense.

The net outflows in cash resulting from working capital were $221 million and $762 million in 2024 and 2023, respectively. Net cash outflows for both 2024 and 2023 were primarily due to increases in unbilled revenue and power procurement related receivables. The higher outflow in 2023 was also due to payments of power purchase contracts that had high gas prices from December 2022, as well as an increase in customer receivables due to various customer protection programs in place.

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Net cash provided by regulatory assets and liabilities, including changes in net over or undercollections recorded in balancing accounts, was $1,219 million and $576 million in 2024 and 2023, respectively. SCE has a number of balancing and memorandum accounts, which impact cash flows based on differences between timing of collection through rates and incurring expenditures. Cash inflows in 2024 and 2023 were both due to recovery of prior year undercollections. The higher inflow in 2024 compared to 2023 was driven by higher prior year undercollections implemented into rates in 2024, higher sales volume due to hotter weather in 2024, and higher overcollection from funds collected for customer-funded wildfire self-insurance in 2024.

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for 2024, 2023, and 2022. Issuances of debt is discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

Net Cash Used in Investing Activities

Cash flows used in investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Cash used in capital expenditures were $5.7 billion, $5.4 billion, and $5.8 billion for 2024, 2023, and 2022, respectively, primarily related to transmission, distribution and generation investments. SCE had a net redemption of nuclear decommissioning trust investments of $121 million, $180 million, and $123 million in 2024, 2023, and 2022, respectively. See "Nuclear Decommissioning Activities" below for further discussion.

Nuclear Decommissioning Activities

SCE's consolidated statements of cash flows include nuclear decommissioning activities, which are reflected in the following line items:

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Net cash used in operating activities relates to interest and dividends less administrative expenses, taxes and SCE's decommissioning costs. Investing activities represent the purchase and sale of investments within the nuclear decommissioning trusts, including the reinvestment of earnings from nuclear decommissioning trust investments.

Funds for decommissioning costs are requested from the nuclear decommissioning trusts one month in advance. Decommissioning disbursements are funded from sales of investments of the nuclear decommissioning trusts. The net cash impact reflects timing of decommissioning payments ($222 million, $229 million, and 189 million in 2024, 2023, and 2022, respectively) and reimbursements to SCE from the nuclear decommissioning trust ($214 million, $222 million, and $201 million in 2024, 2023, and 2022, respectively). The net cash outflow in 2024 also primarily includes $19 million of tax benefits received and a $30 million disallowance under the 2021 NDCTP (For further details, see "—Decommissioning of San Onofre), both contributed by SCE to the decommissioning trust.

Edison International Parent and Other

The table below sets forth condensed historical cash flow from operations for Edison International Parent and Other, including intercompany eliminations.

Net Cash Used in Operating Activities

Net cash used in operating activities increased by $89 million in 2024 compared to 2023, primarily due to cash outflows of $318 million in 2024 and $280 million in 2023 for interest and operating costs. Additionally, there was $51 million cash outflow in 2024 related to a California state income tax payment.

Net Cash Provided by Financing Activities

Net cash provided by financing activities was as follows:

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Contractual Obligations and Contingencies

Contractual Obligations

SCE and Edison International Parent and Other have various contractual obligations, which are recorded as liabilities in the consolidated financial statements. Other items, such as certain purchase commitments and other executory contracts, are not recognized as liabilities in the consolidated financial statements but are required to be disclosed in the footnotes to the financial statements.

For details on long-term debt, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

Certain power purchase agreements which SCE entered into with independent power producers are treated as operating or finance leases. In addition, SCE has other operating lease obligations primarily related to vehicles, office space and other equipment. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" and "—Note 13. Leases."

SCE also has other purchase obligations primarily related to maintaining reliability and expanding SCE's transmission and distribution system and nuclear fuel supply contracts. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

Edison International Parent and Other and SCE have estimated contributions to the pension and PBOP plans. These amounts represent estimates that are based on assumptions that are subject to change. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.

Edison International and SCE have a total net liability recorded for uncertain tax positions. Edison International and SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the tax authorities. See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information.

For details on derivative obligations and asset retirement obligations, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 1. Summary of Significant Accounting Policies," respectively.

Contingencies

Edison International's and SCE's material contingencies are discussed in "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies."

Off-Balance Sheet Arrangements

SCE has variable interests in power purchase contracts with variable interest entities. See "Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."

MARKET RISK EXPOSURES

Edison International's and SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Derivative instruments are used to manage market risks including market risks to SCE's customers. For further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 4. Fair Value Measurements."

Interest Rate Risk

Edison International and SCE are exposed to changes in interest rates primarily as a result of financing, investing and borrowing activities used for liquidity purposes, and to fund business operations and capital investments. The nature and amount of Edison International's and SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. Fluctuations in interest rates can affect earnings and cash flows. Changes in interest rates may impact SCE's authorized rate of return for the period beyond 2025 through a CPUC cost of capital proceeding, see "Management Overview—Cost of Capital" and "Business—SCE—Overview of Ratemaking

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Process" for further discussion. The following table summarizes the increase or decrease to the fair value of long-term debt including the current portion, if the market interest rates were changed while leaving all other assumptions the same:

Commodity Price Risk

SCE and its customers are exposed to the risk of a change in the market price of natural gas, electric power and transmission congestion. Due to regulatory mechanisms, exposure to commodity prices is not expected to impact earnings but may impact timing of cash flows. SCE's hedging program is designed to reduce exposure to variability in market prices related to SCE's purchases and sales of electric power and natural gas. As part of this program, SCE enters into energy options, swaps, forward arrangements, and congestion revenue rights ("CRRs"). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. Therefore, SCE expects recovery of its related hedging costs, as well as procurement costs, through the ERRA balancing account or CPUC-approved procurement plans. For more details of the ERRA balancing account, see "Business—SCE—Overview of Ratemaking Process."

Fair Value of Derivative Instruments

The fair value of derivative instruments is included in the consolidated balance sheets unless subject to an exception under the applicable accounting guidance. Realized gains and losses from derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, accordingly, changes in the fair value of derivative instruments have no impact on earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment. For further discussion on fair value measurements and the fair value hierarchy, see "Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net asset of $212 million and $91 million at December 31, 2024 and 2023, respectively.

The following table summarizes the increase or decrease to the fair values of the net asset of derivative instruments included in the consolidated balance sheets, if the electricity prices or gas prices were changed while leaving all other assumptions constant:

Investment Price Risk

Edison International and SCE are subject to investment price risk due to securities held as investments in the nuclear decommissioning trust and various pension and other post-retirement benefit plan trusts.

Nuclear Decommissioning Trust

As of December 31, 2024, SCE's nuclear decommissioning trust investments include equity investments of $1.6 billion and fixed income investments of $2.6 billion. These investments are exposed to price fluctuations in equity markets and changes in interest rates. SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust. These policies restrict the trust from holding alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. Due to regulatory mechanisms, investment earnings and realized and unrealized gains and losses increase or decrease the trust assets and the related regulatory asset or liability, and do not materially affect earnings. For further discussion on the

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nuclear decommissioning trust investments, see "Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 10. Investments."

PBOP and Pension Plan Assets

The PBOP Plan and the Southern California Edison Company Retirement Plan Trust assets include investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. These investments are exposed to price fluctuations in equity markets and changes in interest rates. The investment of plan assets is overseen by a fiduciary investment committee. Risk is managed through diversification among multiple asset classes, managers, styles, and securities. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for additional information regarding investment strategy of plan assets.

Contributions related to SCE employees made to SCE pension plan are anticipated to be recovered through CPUC-approved regulatory mechanisms.

Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of set-off. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio of counterparties based on credit ratings and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. Based on SCE's policies and risk exposures related to credit, SCE does not anticipate a material adverse effect on their financial statements as a result of counterparty nonperformance. At December 31, 2024, SCE's power and gas trading counterparty credit risk exposure was $110 million, 99.8% of which was associated with entities with an investment grade rating of A or higher. SCE assigns a credit rating to counterparties based on the lowest of a counterparty's S&P's, Moody's, and Fitch's rating.

For more information related to credit risks, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments."

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

The accounting policies described below are considered critical to obtaining an understanding of Edison International's and SCE's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing the consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or, the use of alternative estimates, could have a material impact on Edison International's and SCE's results of operations or financial position. For more information on Edison International's and SCE's accounting policies, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

Accounting for Contingencies

Nature of Estimates Required. Edison International and SCE record loss contingencies when management determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. Gain contingencies are recognized in the financial statements when they are realized.

Key Assumptions and Approach Used. The determination of an accrual for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, Edison International and SCE may consider the following factors, among others: the nature of the litigation, claim or assessment, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. Edison International and SCE provide disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred.

Effect if Different Assumptions Used. Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded on the consolidated financial statements. For a discussion of contingencies, guarantees, and indemnities, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

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Application to Wildfires

As discussed in "Management Overview," wildfires in SCE's service area have caused loss of life, substantial damage to both residential and business properties, and service outages for SCE customers.

The extent of legal liability for wildfire-related damages in actions against utilities depends on a number of factors, including whether the utility substantially caused or contributed to the damages and whether parties seeking recovery of damages will be required to show negligence in addition to causation. Final determinations of legal liability for wildfire events, including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes and settlements may be reached before determinations of legal liability are ever made.

Edison International and SCE have incurred material losses in connection with several wildfires. Estimated losses for wildfire litigation are based on a number of assumptions and are subject to change as additional information becomes available. Actual losses incurred may be higher or lower than estimated based on several factors, including the uncertainty in estimating damages that have been or may be alleged. For instance, SCE will receive additional information with respect to damages claimed as the claims mediation and trial processes progress. Other factors that can cause actual losses incurred to be higher or lower than estimated include the ability to reach settlements and the outcomes of settlements reached through the ongoing claims mediation and trial processes, uncertainties related to the sufficiency of insurance held by plaintiffs, uncertainties related to the litigation processes, including whether plaintiffs will ultimately pursue claims, uncertainty as to the legal and factual determinations to be made during litigation, including uncertainty as to the contributing causes of certain wildfires, and the uncertainty as to how these factors impact future settlements.

For more information related to the loss contingencies of the wildfires, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

Rate Regulated Enterprises

Nature of Estimate Required. SCE follows the accounting principles for rate-regulated enterprises which are required for entities whose rates are set by regulators at levels intended to recover the estimated costs of providing service, plus a return on net investment, or rate base. Regulators may also impose penalties or grant incentives. Due to timing and other differences in the collection of revenue, these accounting principles allow a cost that would otherwise be charged as an expense by an unregulated entity to be capitalized as a regulatory asset if it is probable that such cost is recoverable through future rates; conversely the accounting principles require creation of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and refundable to customers. In addition, SCE recognizes revenue and regulatory assets from alternative revenue programs, which enables the utility to adjust future rates in response to past activities or completed events, if certain criteria are met.

Accounting principles for rate-regulated enterprises also require recognition of an impairment loss if it becomes probable that the regulated utility will abandon a plant investment or the cost of a recently completed plant will be disallowed for ratemaking purposes, and a reasonable estimate of the amount of the disallowance can be made.

Key Assumptions and Approach Used. SCE's management assesses at the end of each reporting period whether regulatory assets are probable of future recovery by considering factors such as the current regulatory environment, the issuance of rate orders on recovery of the specific or a similar incurred cost to SCE or other rate-regulated entities, and other factors that would indicate that the regulator will treat an incurred cost as allowable for ratemaking purposes. Using these factors, management has determined that existing regulatory assets are probable of future recovery or settlement, and regulatory liabilities are properly identified. This determination reflects the current regulatory climate and is subject to change in the future. SCE also considers whether any plant investments are probable of abandonment or disallowance.

Effect if Different Assumptions Used. Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and plant investments, the recognition of incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penalties. If future recovery of costs ceases to be probable, all or part of the regulatory assets and/or plant investments would have to be written off against current period earnings, and additional regulatory liabilities would have to be recognized. At December 31, 2024, the consolidated balance sheets included regulatory assets of $11.6 billion and regulatory liabilities of $11.5 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported.

Application to Southern California Wildfires

Application to pre-AB 1054 fires

Regulatory recovery of SCE's losses realized in connection with the 2017/2018 Wildfire/Mudslide Events in excess of available insurance is subject to approval by regulators. Under accounting standards for rate-regulated enterprises, SCE defers costs as regulatory assets in the period it concludes that such costs are probable of future recovery in electric rates.

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SCE utilizes objectively determinable evidence to form its view on probability of future recovery. The only directly comparable precedent, in which a California investor-owned utility sought recovery for uninsured wildfire claims related costs and the CPUC made a prudency determination, is SDG&E's requests for cost recovery related to 2007 wildfire activity. The FERC allowed recovery of all FERC-jurisdictional wildfire claims related costs, while the CPUC rejected recovery of all CPUC-jurisdictional wildfire claims related costs based on a determination that SDG&E did not meet the CPUC's prudency standard.

In January 2025, the CPUC approved the TKM Settlement Agreement and closed the proceeding. However, the CPUC did not make a determination regarding SCE's prudency when it approved the TKM Settlement Agreement. Therefore, notwithstanding CPUC approval of the TKM Settlement Agreement, SCE believes that the CPUC's interpretation and application of the prudency standard to SDG&E continues to create substantial uncertainty regarding how that standard will be applied to an investor-owned utility in wildfire cost-recovery proceedings for fires ignited prior to July 12, 2019. Consequently, SCE is unable to estimate the uninsured CPUC-jurisdictional claims related costs related to the Woolsey Fire or Creek Fire, both pre-AB 1054 events, that are probable of future recovery, and will not record a regulatory asset for recoveries related to the Woolsey Fire or Creek Fire in connection with the approval of the TKM Settlement Agreement. SCE will continue to evaluate the facts and circumstances of the pre-AB 1054 cost recovery proceeding to determine if and when a regulatory asset for pre-AB 1054 events may be recorded.

Through the operation of its FERC Formula Rate, and based upon the precedent established in SDG&E's recovery of FERC-jurisdictional wildfire-related costs, SCE believes it is probable it will recover its FERC-jurisdictional wildfire and mudslide related costs and has recorded total expected recoveries within the FERC balancing account.

Application to post-AB-1054 Other Wildfire Events

Management judgment is required to assess the probability of recovery of SCE's losses realized, in excess of available insurance, in connection with wildfires ignited after the adoption of AB 1054 in July 2019.

The CPUC and FERC may not allow SCE to recover uninsured losses through electric rates if it is determined that such losses were not reasonably or prudently incurred. On July 12, 2019, AB 1054 clarified that the CPUC must allow recovery of costs and expenses arising from a covered wildfire if the utility's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available at that time. Further, utilities with a valid safety certification at the time of the relevant wildfire will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates "serious doubt" as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to dispel that doubt and prove its conduct was prudent. The serious doubt standard in AB 1054 is modeled after the FERC cost recovery standard. SCE evaluates the probability of recovery of costs related to the Other Wildfire Events that ignited after the adoption of AB 1054 in the context of the prudency standard laid out by AB 1054 above, including how the FERC applies the serious doubt standard. SCE’s evaluation also relies on its status as a holder of a valid safety certification, facts and other evidence known to date related to the ignition, and any regulatory decisions illustrating the interpretation and/or application of the prudency framework under AB 1054, which as of December 31, 2024, has not been applied by the CPUC to an actual cost recovery application filed by any California investor-owned utility. SCE also considers which costs are eligible for recovery based on precedent from other CPUC cost recovery proceedings. Management's assessment of the probability of recovery may change, related to changes in any of these factors in the future.

See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" for further discussion of regulatory assets recorded for wildfire as of December 31, 2024.

Income Taxes

Nature of Estimates Required. As part of the process of preparing its consolidated financial statements, Edison International and SCE are required to estimate income taxes for each jurisdiction in which they operate. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within Edison International's and SCE's consolidated balance sheets, including net operating loss and tax credit carryforwards. Certain estimates and assumptions are required to determine whether deferred tax assets can and will be utilized in future periods. Based on currently enacted tax laws, Edison International expects to generate sufficient taxable income to fully utilize all loss and credit carryovers set to expire beyond 2024.

Edison International and SCE take certain tax positions they believe are in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the Internal Revenue Service, state tax authorities and the courts. Edison International and SCE determine uncertain tax positions in accordance with the authoritative guidance.

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Key Assumptions and Approach Used. In determining whether it is more likely than not that all or some portion of net operating loss and tax credit carryforwards can be utilized, management analyzes the trend of GAAP earnings and then estimates the impact of future taxable income, reversing temporary differences and available prudent and feasible tax planning strategies based on currently enacted tax laws.

Accounting for tax obligations requires management judgment. Edison International's and SCE's management use judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing uncertain tax positions Edison International and SCE consider, among others, the following factors: the facts and circumstances of the position, regulations, rulings, case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax positions. Edison International and SCE evaluate uncertain tax positions at the end of each reporting period and make adjustments when warranted based on changes in fact or law.

Effect if Different Assumptions Used. Should a change in facts or circumstances, including a change in enacted tax legislation, lead to a change in judgment about the ultimate realizability of a deferred tax asset, Edison International and SCE would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.

Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue, and expenses recorded in the financial statements. Edison International and SCE continue to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. For a discussion of current and deferred taxes, net operating losses and tax credit carryforwards, accounting for uncertainty in income taxes, unrecognized tax benefits, and tax disputes, see "Notes to Consolidated Financial Statements—Note 8. Income Taxes."

Nuclear Decommissioning – Asset Retirement Obligation

Key Assumptions and Approach Used. San Onofre Units 1, 2, and 3 decommissioning cost estimates are updated in each NDCTP and when there are material changes to the timing or amount of estimated future cash flows. Palo Verde decommissioning cost estimates are updated by the operating agent, Arizona Public Services, every three years and when there are material changes to the timing or amount of estimated future cash flows. SCE estimates that it will spend approximately $7.6 billion, undiscounted through 2098, to decommission its nuclear facilities.

The current ARO estimates for San Onofre and Palo Verde are based on:

•Decommissioning Costs. The estimated costs for labor, material, equipment and other, and low-level radioactive waste costs are included in each of the NRC decommissioning stages: license termination, site restoration and spent fuel storage. The liability to decommission SCE's nuclear power facilities is based on a 2024 decommissioning study, filed as part of the 2024 NDCTP, for San Onofre Unit 1, 2, and 3 and a 2023 decommissioning study for Palo Verde.

•Escalation Rates. Annual escalation rates are used to convert the decommissioning cost estimates in base year dollars to decommissioning cost estimates in future-year dollars. Escalation rates are primarily used for labor, material, equipment, and low-level radioactive waste burial costs. SCE's current estimates are based upon SCE's decommissioning cost methodology used for ratemaking purposes. Average escalation rates range from 2.1% to 7.5% (depending on the cost element) annually.

•Timing. Initial decommissioning activities at San Onofre Unit 1 started in 1999 and at Units 2 and 3 in 2013. Cost estimates for San Onofre Units are currently based on completion of decommissioning activities by 2056. Cost estimates for Palo Verde are based on an assumption that decommissioning will commence promptly after the current NRC operating licenses expire. The Palo Verde 1, 2, and 3 operating licenses currently expire in 2045, 2046, and 2047, respectively.

•Spent Fuel Dry Storage Costs. Cost estimates, including the impact of escalations, are based on an assumption that the U.S. Department of Energy will begin to take spent fuel from the nuclear industry in 2034 and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2054 and 2097, respectively.

•Changes in Decommissioning Technology, Regulation and Economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.

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See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" for further discussion of the plans for decommissioning of San Onofre.

Effect if Different Assumptions Used. The ARO for decommissioning SCE's nuclear facilities was $2.1 billion as of December 31, 2024, based on the most recent decommissioning studies performed and the subsequent cost estimate updates. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material effect on the recorded liability.

The following table illustrates the increase to the ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:

The increase in the ARO liability driven by an increase in the escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. As of December 31, 2024, the regulatory liability for recoveries in excess of ARO liabilities was $1.7 billion.

Pensions and Postretirement Benefits Other than Pensions

Nature of Estimate Required. Authoritative accounting guidance requires companies to recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Edison International and SCE have a fiscal year-end measurement date for all of their postretirement plans.

Key Assumptions of Approach Used. Pension and other postretirement benefit obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense, and the discount rate is important to liability measurement. Other assumptions, which require management judgment, include the rate of compensation increases, and rates of retirement, turnover and termination. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated periodically and updated to reflect actual experience, as appropriate.

As of December 31, 2024, Edison International's and SCE's pension plans had a $3.6 billion and $3.3 billion projected benefit obligation, respectively, and total 2024 expense for these plans was $27 million and $24 million, respectively. As of December 31, 2024, the accumulated benefit obligation for Edison International's and SCE's PBOP plans were $741 million and $737 million, respectively, and there were no expenses for Edison International's and SCE's PBOP plans for 2024. The majority of annual contributions made to SCE's pension and PBOP plan are anticipated to be recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the related annual expense.

Pension expense is recorded for SCE based on the amount funded to the trusts, as calculated using an actuarial method required for ratemaking purposes, in which the impact of market volatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pension expense calculated in accordance with ratemaking methods and pension expense calculated in accordance with authoritative accounting guidance for pension is accumulated as a regulatory asset or liability, and is expected, over time, to be recovered from or returned to customers. As of December 31, 2024, this cumulative difference amounted to $132 million, meaning that the ratemaking method has recognized less in expense than the accounting method since implementation of authoritative guidance for employers' accounting for pensions in 1987, which was offset by a regulatory liability for the current funding level of SCE's pension plan.

Edison International and SCE used the following critical assumptions to determine expense for pension and PBOP for 2024:

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*Not applicable to pension plans.

1The discount rate enables Edison International and SCE to state expected future cash flows at a present value on the measurement date. Edison International and SCE select its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows by matching the timing and amount of expected future benefit payments to the corresponding yields from the Willis Towers Watson RATE: Link 10th – 90th percentile yield curve model on the measurement date.

2To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 5% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized returns on the pension plan assets were 5.6%, 5.2% and 6.6% for the one-year, five-year and ten-year periods ended December 31, 2024, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 3.5%, 1.8% and 4.3% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.

3The health care cost trend rate gradually declines to 5.00% for 2029 and beyond.

As of December 31, 2024, Edison International and SCE had unrecognized net pension gains of $138 million and $120 million, respectively, and unrecognized PBOP gains of $1.5 billion. The unrecognized pension and PBOP gains primarily consisted of the cumulative impact of the increased discount rates on the respective benefit obligations and the cumulative difference between the expected and actual rate of return on plan assets. Of these deferred gains, $133 million of SCE's pension gains and $1.5 billion of SCE's PBOP gains are recorded as regulatory liabilities, respectively, and are expected to be amortized to expense over the expected future service of the employees (subject to regulatory adjustment) or refunded to ratepayers at the termination or completion of the plan.

Edison International's and SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans have no plan assets.

Effect if Different Assumptions Used. Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or the assumptions and judgments used by management underlying these estimates, could have a material effect on the recorded expenses and liabilities.

The following table summarizes the increase or decrease to projected benefit obligation for pension and the accumulated benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:

A one percentage point increase in the expected rate of return on pension plan assets would decrease Edison International's and SCE's current year expense by $35 million and $33 million, respectively, and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease both Edison International's and SCE's current year expense by $23 million.

Contributions to the Wildfire Insurance Fund

Nature of Estimates Required. At December 31, 2024, Edison International and SCE have a $1.9 billion long-term asset and a $138 million current asset reflected as "Wildfire Insurance Fund contributions" in the consolidated balance sheets for the initial $2.4 billion contribution made during 2019 and the present value of annual contributions SCE committed to make to the Wildfire Insurance Fund, reduced by amortization. At December 31, 2024, a long-term liability of $363 million has been reflected in "Other deferred credits and other long-term liabilities" for the present value of unpaid contributions. Contributions were discounted to the present value using US treasury interest rates at the date SCE committed to participate in the Wildfire Insurance Fund.

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Management concluded it would be most appropriate to account for the contributions to the Wildfire Insurance Fund similar to prepaid insurance, ratably allocating the expense to periods based on an estimated period of coverage.

Key Assumptions and Approach Used. The Wildfire Insurance Fund does not have a defined life. Instead, the Wildfire Insurance Fund will terminate when the administrator determines that the fund has been exhausted. Management reassesses the period of coverage of the fund at least annually in the first quarter each year and adjustments are applied on a prospective basis. The determination of the correct period in which to record an expense in relation to contributions to the Wildfire Insurance Fund depends, among other factors, on management's assessment of: the future occurrence and magnitude of wildfires; the involvement of SCE, or other electrical corporations which could access the Wildfire Insurance Fund, in the ignition of those fires; the probable future outcomes of CPUC cost recovery proceedings for wildfire claims, which may require reimbursement of the fund by electrical corporations; and the use of the contributions by the administrator of the Wildfire Insurance Fund. Further information regarding these factors may become available due to the actions of the fund administrator, or other entities, which could require management to reassess the period of coverage.

Edison International and SCE assess the Wildfire Insurance Fund contribution asset for impairment each reporting period. An impairment will be recorded if the Wildfire Insurance Fund contribution asset exceeds SCE's ability to benefit from the remaining coverage provided by the Wildfire Insurance Fund.

In January 2024, Edison International and SCE used Monte Carlo simulations for the annual assessment to estimate the period of coverage of the fund. This assessment was based on ten years (2014 – 2023) of historical data from wildfires caused by electrical utility equipment to estimate expected loss, resulting in an estimated fund life of 20 years from the date SCE committed to participate in the Wildfire Insurance Fund. The details of the operation of the Wildfire Insurance Fund and estimates related to claims by SCE, PG&E, and SDG&E against the fund have been applied to the expected loss simulations to estimate the period of coverage of the fund. The most sensitive inputs to the estimated period of coverage are the expected frequency of wildfire events caused by investor-owned utility electrical equipment and the estimated costs associated with those forecasted events. These inputs are most affected by the historical data used in estimating expected losses. Using a 17-year period (2007 – 2023) of historical data would further increase the period of coverage. There were fires in the service area of SCE, PG&E and SDG&E since the inception of the Wildfire Insurance Fund, including fires for which the cause is unknown, which may in the future be determined to be covered by the Wildfire Insurance Fund and have not been reflected or estimated at this time. As of the date of this filing, SCE is continuing to perform its annual assessment for 2025 to reassess its estimate of the life of the Wildfire Insurance Fund.

Effect if Different Assumptions Used. Changes in the estimated life of the insurance fund, including impairment of the fund, could have a material impact on the expense recognition.

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

RISK FACTORS

RISKS RELATING TO EDISON INTERNATIONAL

Edison International's liquidity and ability to pay dividends depends on its ability to borrow funds, access to bank and capital markets, monetization of tax benefits held by Edison International, and SCE's ability to pay dividends and tax allocation payments to Edison International. Edison International is a holding company and, as such, it has no material operations of its own. Edison International's ability to meet its financial obligations, make investments, and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of SCE and SCE's ability to make upstream distributions. If SCE does not make upstream distributions to Edison International and Edison International is unable to access the bank and capital markets on reasonable terms, Edison International may be unable to continue to pay dividends to its shareholders or meet its financial obligations.

Prior to paying dividends to Edison International, SCE has financial and regulatory obligations that must be satisfied, including, among others, debt service and preference stock dividends. Further, Edison International and SCE cannot pay dividends if California law requirements for the declaration of dividends are not met. For information on CPUC and California law requirements related to the declaration of dividends, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends." SCE may also owe tax-allocation payments to Edison International under applicable tax-allocation agreements.

Edison International's ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including its levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. In addition, the factors affecting

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SCE's business will impact Edison International's ability to obtain financing. Edison International's inability to borrow funds from time to time could have a material effect on Edison International's liquidity and operations.

See "Risks Relating to Southern California Edison Company" below for further discussion.

RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY

Regulatory and Legislative Risks

SCE's financial results depend upon its ability to recover its costs and to earn a reasonable rate of return on capital investments in a timely manner from its customers through regulated rates.

SCE's ongoing financial results depend on its ability to recover its costs from its customers, including the costs of electricity purchased for its customers, through the rates it charges its customers as approved by the CPUC and FERC. SCE's financial results also depend on its ability to earn a reasonable return on capital, including long-term debt and equity. SCE's ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time lag between when costs are incurred and when those costs are recovered in customers' rates and differences between the forecast or authorized costs embedded in rates (which are set on a prospective basis) and the amount of actual costs incurred.

The CPUC or the FERC may not allow SCE to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, SCE may incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, SCE has incurred, and expects to further incur, wildfire mitigation expenses before it is clear whether such costs will be recoverable from customers. Also, the CPUC may deny recovery of costs incurred by SCE, including uninsured wildfire-related costs, if the CPUC determines that SCE was not prudent. For further information on recovery of uninsured wildfire-related costs see "Business—Southern California Wildfires—Recovery of Wildfire-Related Costs" and "Management Overview—Southern California Wildfires and Mudslides" in the MD&A. In addition, while SCE supports California's environmental goals, it may be prevented from fully executing on its strategy to support such goals by regulatory delay or lack of approval of cost-recovery for the costs of such strategic actions and electrification programs from the relevant regulatory agencies, including as a result of customer affordability concerns. For example, the CPUC issued a decision denying SCE’s Building Electrification Program Application, citing, among other things, a desire to avoid increasing rates.

SCE's CPUC authorized return on investment is established by multiplying an authorized rate of return, determined by the CPUC in standalone cost of capital proceedings, by SCE's authorized CPUC rate base. SCE's CPUC-authorized cost of capital is subject to potential adjustment should interest rates move substantially in years between cost of capital proceedings. SCE's authorized return on its transmission assets is established by multiplying an authorized rate of return, determined by the FERC, by SCE's transmission rate base. For further information see "Business—SCE—Overview of Ratemaking Process."

SCE's capital investment plan, increasing procurement of renewable power and energy storage, inflation, commodity price volatility, increasing self-generation, load departures to CCAs or Electric Service Providers, and increasing environmental regulations, among other things, collectively place continuing upward pressure on customer rates. As customer rates increase, the CPUC may face greater pressure to approve lesser amounts in SCE’s ratemaking or cost recovery proceedings. To relieve some of this upward rate pressure, the CPUC may authorize lower revenues, or increase the period over which SCE is allowed to recover amounts, or disallow the recovery of SCE’s cost which could impact SCE’s ability to recover its operating costs timely or at all. If SCE is unable to obtain a sufficient rate increase or modify its rate design to recover its costs and an adequate return on capital in rates in a timely manner, its financial condition and results of operations could be materially affected.

SCE is subject to extensive regulation and the risk of adverse regulatory and legislative decisions, delays in regulatory or legislative decisions, and changes in applicable regulations or legislation.

SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. Among other things, the CPUC regulates SCE's retail rates and capital structure, and the FERC regulates SCE's wholesale rates and capital structure. The NRC regulates the decommissioning of San Onofre in addition to the local and state agencies that require permits. The construction, planning, siting and operation of SCE's power plants, energy storage projects, and transmission lines in California are also subject to regulation by the CPUC and other local, state and federal agencies.

SCE must periodically apply for licenses and permits from these various regulatory authorities, including environmental regulatory authorities, and must abide by their respective rules, regulations and orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose fines, penalties or disallowances on SCE, SCE may be prevented from executing its strategy and its

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business could be materially affected. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by opponents and such delay or defeat could have a material effect on SCE's business.

The Wildfire Insurance Fund and other provisions of AB 1054 may not be sufficient or effectively mitigate the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are a substantial cause, which could have a detrimental effect on SCE's business and financial condition. The effectiveness of AB 1054 to mitigate the wildfire-related risk faced by SCE is conditioned in part on the performance of OEIS and various entities formed under AB 1054 and related legislation to, among other things, administer the Wildfire Insurance Fund, approve WMPs, issue safety certifications, oversee and enforce compliance with wildfire safety standards, and develop metrics to reduce risk and measure compliance with risk reduction.

In addition, CPUC approval is required to recover the costs SCE is incurring to strengthen its wildfire mitigation and prevention efforts described in SCE's WMPs. See "Business—Southern California Wildfires" and "Liquidity and Capital Resources—SCE—Regulatory Proceedings—Wildfire Related Regulatory Proceedings" in the MD&A.

In addition, existing regulations may be revised or re-interpreted and new laws and regulations may be adopted or become applicable to SCE, or its facilities or operations, in a manner that may have a detrimental effect on SCE's business or result in significant additional costs. In addition, regulations adopted via the public initiative or legislative process may apply to SCE, or its facilities or operations, in a manner that may have a detrimental effect on SCE's business or result in significant additional costs.

SCE's energy procurement activities are subject to regulatory and market risks, including availability, that could materially affect its financial condition and liquidity.

SCE obtains energy, capacity, environmental credits and ancillary services needed to serve its customers from its own generating plants and through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover, through the rates it is allowed to charge its customers, reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility primarily resulting from changes in commodity prices, including as a result of gas supply constraints. Additionally, significant and prolonged gas use restrictions may adversely impact the reliability of the electric grid if critical generation resources are limited in their operations. For further information, see "Business—SCE—Purchased Power and Fuel Supply." SCE is also subject to the risks of unfavorable or untimely CPUC decisions about the compliance with SCE's energy procurement plan and the reasonableness of certain procurement-related costs.

SCE may not be able to hedge its risk for commodities on economic terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could materially affect SCE's liquidity and results of operations, see "Market Risk Exposures" in the MD&A.

Operating Risks

Damage claims against SCE for wildfire-related losses may materially affect SCE's financial condition and results of operations.

Prolonged drought conditions and shifting weather patterns in California resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by years of historic drought and lack of adequate clearing of hazardous fuels by responsible parties have increased the duration of the wildfire season and the risk of severe wildfire events.

Severe wildfires and urban development in and near high fire risk areas in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment. Catastrophic wildfires can occur in SCE's service area even if SCE effectively implements its WMPs. California courts have previously found utilities to be strictly liable for property damage, regardless of fault, by applying the theory of inverse condemnation when a utility's facilities were determined to be a substantial cause of a wildfire that caused the property damage. An inability to recover uninsured wildfire-related costs could materially affect SCE's business, financial condition and results of operations. For example, if SCE is unable to, or believes that it may be unable to, recover damages related to catastrophic wildfires through insurance, the Wildfire Insurance Fund (which is only available for fires ignited after July 12, 2019) or electric rates, or access the bank and capital markets on reasonable terms, SCE may not have sufficient cash or equity to pay dividends or may be restricted from declaring such dividends because it does not meet CPUC or California law requirements related to the declaration of dividends. For information on the California law requirements on the declaration of dividends, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends." Also see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

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Edison International's and SCE's costs of accessing capital markets has increased due to the risks associated with wildfires in Southern California. Edison International's and SCE's access to the bank and capital markets could also be constrained and/or the costs of accessing those markets could increase further as a result of wildfire risk, including if Edison International's and/or SCE's credit ratings are downgraded or placed on negative watch due to concerns about Edison International and/or SCE's financial health as a result of wildfires.

SCE's insurance coverage for wildfires may not be sufficient.

SCE may not be able to recover uninsured losses (including amounts paid for self-insured retention and co-insurance) in electric rates. Additionally, SCE’s contractors may experience coverage reductions and/or increased wildfire insurance costs in future years. For losses associated with claims occurring before the authorization of SCE’s CPUC-authorized customer-funded self-insurance program, no assurance can be given that losses will not exceed the limits of SCE's or its contractors' insurance coverage. Losses which are not fully insured or cannot be recovered from contractors, through the Wildfire Insurance Fund or electric rates, including any such losses that exceed funds available through the Wildfire Insurance Fund and are ultimately not authorized to be recovered through rates, could materially affect Edison International's and SCE's financial condition and results of operations. For more information on wildfire insurance risk, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

SCE may not effectively implement its wildfire mitigation plans.

SCE will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement its WMPs. For example, SCE may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to permitting delays, sourcing, engaging, and retaining effectively trained contract workers or procuring materials it needs to fulfill its mitigation obligations under the WMPs. In addition, if SCE does not have an approved WMP, SCE will not be issued a safety certification from the CPUC and will consequently not benefit from the presumption of prudency or the AB 1054 Liability Cap.

The CPUC may assess penalties on SCE if it finds that SCE has failed to substantially comply with its WMP. In addition, SCE may be subject to mandated changes to, or restrictions on, its operational wildfire mitigation practices or be subject to regulatory fines and penalties or claims for damages and reputational harm if SCE does not execute its wildfire mitigation practices in compliance with applicable rules and regulations. SCE's wildfire mitigation practices include PSPS and using fast-curve settings. In addition, SCE has been and may be further subject to regulatory fines and penalties or claims for damages and reputational harm if it is determined that SCE has placed excessive or unreasonable reliance on PSPS or has failed to maintain compliance with notification and post event reporting requirements related to PSPS. For information regarding SCE’s PSPS activities and related fines, see "Business—Southern California Wildfires—Public Safety Power Shutoff."

SCE establishes the criteria under which it implements PSPS in its service area. To the extent SCE's criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires during high wind events, SCE does not fully implement PSPS when criteria are met due to other overriding conditions or SCE's regulators or others mandate changes to, or restrictions on, its criteria or other operational PSPS practices, SCE will face a higher likelihood of catastrophic wildfires in its service area during high wind events. Similarly, if SCE is prohibited by the CPUC from implementing its desired fast-curve settings, SCE will face a higher likelihood of catastrophic wildfires in its service area.

For more information on AB 1054, see "Business—Southern California Wildfires—Recovery of Wildfire-Related Costs—2019 Wildfire Legislation."

SCE will not benefit from all of the features of AB 1054 if the Wildfire Insurance Fund is exhausted.

Catastrophic wildfires could rapidly exhaust the Wildfire Insurance Fund and SCE will not be reimbursed by the Wildfire Insurance Fund or benefit from the AB 1054 Liability Cap if the fund has been exhausted as a result of damage claims previously incurred by SCE or the other participating utilities. AB 1054 does not have a mechanism for adding to or replenishing the Wildfire Insurance Fund.

For more information on AB 1054, see "Business—Southern California Wildfires and Mudslides—Recovery of Wildfire-Related Costs—2019 Wildfire Legislation."

Climate change exacerbated weather-related incidents and other natural disasters have and could continue to materially affect SCE's financial condition and results of operations.

Weather-related incidents, including storms and events caused, or exacerbated, by climate change, such as wildfires, flooding and debris flows, and other natural disasters such as earthquakes can disrupt the generation and transmission of

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electricity, and can seriously damage the infrastructure necessary to deliver power to SCE's customers. The impacts of climate change continue to evolve and remain dynamic and unpredictable.

Climate change has caused, and exacerbated, extreme weather events and wildfires in southern California, and wildfires could cause, among other things, public safety issues, property damage and operational issues. In addition, the risk of flooding and debris flows occurring as a result of rain may be heightened. For example, the Eaton Fire that ignited in Los Angeles County in January 2025 resulted in loss of life, property damage and loss of service and subsequent extreme weather events such as increased rain or flooding could further impact the affected areas. For more information on liabilities related to wildfire events, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

Extreme heat events have and can continue to lead to prolonged widespread outages due to, among other things, state-wide capacity supply shortages or equipment failure. Extreme weather events can also lead to use of PSPS. Weather-related events, such as debris flows, flooding and melting of a significantly higher than normal snowpack, and earthquakes can cause over-topping or failure at an SCE dam resulting in a rapid release of water that could cause public safety issues, property damage and operational issues.

Weather-related incidents and other natural disasters can lead to lost revenue and increased expense, including higher maintenance and repair costs, which SCE may not be able to recover from its customers. These incidents can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers on a timely basis or if fire-related losses are found to be the result of utility practices and/or the failure of electric and other utility equipment. In addition, these occurrences could lead to significant claims for damages, including for loss of life and property damage. These occurrences could materially affect SCE's business, financial condition and results of operations, and the inability to restore power to SCE's customers could also materially damage the business reputation of SCE and Edison International.

For additional information related to climate related risks, see "Business—Environmental Considerations—Environmental Risks."

The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to SCE's workforce and the general public.

Electricity poses hazards for SCE's workforce and the general public should they come in contact with electrical current or equipment, including through energized downed power lines or if equipment malfunctions. In addition, the risks associated with the operation of transmission and distribution assets and power generation and storage facilities include public and workforce safety issues and the risk of utility assets causing or contributing to wildfires.

Injuries and property damage caused by such events can subject SCE to liability that, despite the existence of insurance coverage, can be significant. In addition, SCE may be held responsible for the actions of its contractors and from time to time, SCE is named as a party in legal proceedings involving claims related to its contractors and their employees. No assurance can be given that future losses will not exceed the limits of SCE's or its contractors' insurance coverage. Litigation and other legal processes are subject to inherent uncertainties, including, costs of litigation, unpredictable court or jury decisions, and the differing laws and sentiments regarding damage awards in regions where SCE operates.

The CPUC has increased its focus on public safety with an emphasis on heightened compliance with construction and operating standards and the potential for penalties being imposed on utilities. Additionally, the CPUC has delegated to its staff the authority to issue citations to electric utilities, which can impose fines of up to $100,000 per violation per day (capped at a maximum of $8 million), pursuant to the CPUC's jurisdiction for violations of safety rules found in statutes, regulations, and the CPUC's General Orders. The CPUC also can issue fines greater than $8 million outside of the citation program. Such penalties and liabilities could be significant and materially affect SCE's liquidity and results of operations.

SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage the risks inherent in constructing, operating, and maintaining its facilities and workforce.

SCE's infrastructure is aging and could pose a risk to system reliability if not sufficiently maintained and expanded to meet load growth and electrification needs. In addition, as described above, natural disasters such as wildfires in SCE's service area can cause significant public safety issues, property damage and operational issues. SCE is engaged in a significant and ongoing infrastructure investment program. This investment program, which includes transmission projects and constructing utility owned storage to mitigate possible state-wide capacity shortages in 2025 and later years, has inherent operational risks and elevates the need for effective execution in SCE's activities. For example, utility owned storage facilities utilize lithium-ion battery technology that in certain circumstances can and have caused a thermal event that can ignite nearby materials, including other lithium-ion cells particularly when deployed in indoor facilities. SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage these risks as well as the risks inherent in constructing, operating, and maintaining its facilities, the operation of which can be hazardous and

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important for system reliability. SCE's inherent operating risks include such matters as the risks of human performance, availability of skilled workforce and workforce capabilities, contractor management, data and records accuracy, public opposition to infrastructure projects, delays, environmental remediation and mitigation costs, difficulty in estimating costs or in recovering costs that are above original estimates, system limitations and degradation, maintaining physical security of workforce and assets, maintaining cybersecurity of data and assets, and delays and interruptions in necessary supplies, including key components necessary for the timely construction of utility owned storage. For example, SCE's financial condition may be materially affected as a result of safety incidents, delays, permitting violations and violations of regulatory requirements, among other things, caused by SCE's failure to appropriately manage its contractor workforce or from contractual violations by SCE's contractors and the inability for SCE to recover through contractual indemnities or insurance held by the contractor. SCE's financial condition may also be materially affected as a result of data or records inaccuracies, for example, inaccurate records could lead to missing or delayed compliance with SCE's policies and regulatory requirements, and could contribute to safety incidents.

SCE's financial condition and results of operations could also be materially affected if SCE is unable to attract, train and retain a qualified workforce, and provide safe working conditions for its workforce, including its operations and management personnel. Constrained labor market in California and nationally and SCE's relations with its unionized workforce also impact SCE's ability to maintain its workforce. For example, the increased electrification efforts in California and nationally have led to greater competition for certain skilled workers.

There are inherent risks associated with owning and decommissioning nuclear power generation facilities and obtaining cost reimbursement, including, among other things, insufficiency of nuclear decommissioning trust funds, costs exceeding current estimates, execution risks, potential harmful effects on the environment and human health and the hazards of storage, handling and disposal of radioactive materials. Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.

SCE funds decommissioning costs with assets that are currently held in nuclear decommissioning trusts. Based upon the financial performance of the nuclear decommissioning trust fund investments, as well as the resolution of a number of other uncertainties, assumptions and estimates, additional contributions to the nuclear decommissioning trust's funds may be required. If additional contributions to the nuclear decommissioning trust funds become necessary, recovery of any such additional funds through electric rates is subject to the CPUC's review and approval.

The costs of decommissioning San Onofre are subject to reasonableness reviews by the CPUC. These costs may not be recoverable through regulatory processes or otherwise unless SCE can establish that the costs were reasonably incurred. In addition, SCE faces inherent execution risks including such matters as the risks of human performance, workforce capabilities, public opposition, permitting delays, and governmental approvals. Decommissioning costs ultimately incurred could exceed the current estimates and cost increases resulting from contractual disputes, delays in performance by DCG, elevated levels of inflation, or permitting delays, among other things, could cause SCE to materially overrun current decommissioning cost estimates and could materially impact the sufficiency of trust funds. See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" in the MD&A.

Even though San Onofre is being decommissioned, the presence of spent nuclear fuel still poses a potential risk of a nuclear incident. Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $16.3 billion for Palo Verde and $560 million for San Onofre. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available of $500 million per site. In the case of San Onofre, the balance is covered by a U.S. Government indemnity. In the case of Palo Verde, the balance is covered by a loss sharing program among nuclear reactor licensees. There is no assurance that the CPUC would allow SCE to recover the required contribution made pursuant to this loss sharing program in the case of one or more nuclear incidents with claims that exceeded $500 million at a nuclear reactor which is participating in the program. If this public liability limit of $16.3 billion is insufficient, federal law contemplates that additional funds may be appropriated by Congress. There can be no assurance of SCE's ability to recover uninsured costs in the event the additional federal appropriations are insufficient. For more information on nuclear insurance risk, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Nuclear Insurance."

SCE's distribution of water and propane gas on Catalina Island involves inherent risks of damage to private property and the environment and injury to employees and the general public.

SCE owns and operates the water distribution system that serves Catalina Island, California and a propane gas distribution system that serves the City of Avalon on Catalina Island, California. Production, storage, treatment and distribution of water for human use and the transportation, storage, distribution and use of gas can be hazardous, and can cause damage to private property and the environment and injury to employees and the general public if equipment fails or does not perform as anticipated. For example, the risks of operating a water distribution system include the potential for burst pipes and water contamination and the risks of operating gas distribution system include the potential for gas leaks, fire or explosion. The risks related to SCE's operation of its water and gas distribution systems may be exacerbated due to aging

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infrastructure. SCE has, in the past, requested that the CPUC allow SCE to include certain water system costs in electric rates and may make similar requests for the water and gas systems in the future. If such requests are denied, significant costs may not be recoverable from customers. In addition, SCE may have to pay fines, penalties and remediation costs if it does not comply with laws and regulations in the operation of the water and gas distribution systems. An inability to recover costs associated with any such damages or injuries or any fines, penalties or remediation costs, from insurance or through electric rates, could materially affect SCE's business, financial condition and results of operations.

Financing Risks

As a capital-intensive company, SCE relies on access to the bank and capital markets. If SCE were unable to access these markets or the cost of financing were to substantially increase, its liquidity and operations could be materially affected.

SCE regularly accesses the bank and capital markets to finance its activities and is expected to do so by its regulators as part of its obligation to serve its customers. SCE needs substantial capital for its ongoing infrastructure investment program and for financing wildfire related losses. SCE's ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, increases in interest rates and credit spreads due to inflationary pressures, and other market conditions. In addition, the actions of other California investor-owned utilities and legal, regulatory and legislative decisions impacting investor-owned utilities can affect market conditions and therefore, SCE's ability to obtain financing. SCE's inability to obtain additional capital from time to time could have a material effect on SCE's liquidity and operations.

Competitive and Market Risks

If SCE is unable to operate efficiently and to effectively and timely respond to the changes that the electricity industry is undergoing, as a result of increased load requirements, competition, technological advances, and changes to the regulatory environment, SCE's business model, financial condition and results of operations could be materially impacted.

SCE’s ability to efficiently operate and implement process changes has a direct impact on its ability to execute its strategy, its customer rates and affordability of electricity. Even if SCE’s costs are recoverable, the necessary costs of operations and investments supporting safety, reliability, resilience and being ready to meet California’s clean energy goals will negatively impact the affordability of SCE’s customer rates, may cause reputational harm and cause increased load departures.

Customers and third parties are increasingly deploying DERs, such as solar generation, energy storage, energy efficiency and demand response technologies. California's environmental policy objectives are accelerating the pace and scope of industry change. This change will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity and increase the grid's capacity to interconnect DERs. In addition, enabling California's clean energy economy goals will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options and electric vehicle infrastructure. If SCE is unable to operate efficiently and adapt to these changes, its business model, its ability to execute on its strategy, and ultimately its financial condition and results of operations could be materially impacted.

Customer-owned generation and load departures to CCAs or Electric Service Providers each reduce the amount of electricity that customers purchase from utilities and have the effect of increasing utility rates unless customer rates are designed to allocate the costs of the distribution grid across all customers that benefit from its use. For example, some customers in California who generate their own power are not currently required to pay all transmission and distribution charges and non-bypassable charges, subject to limitations, which results in increased costs for other customers. If there are not updates in regulations to further support the need for customers pay their share of transmission and distribution costs and non-bypassable charges, for example through a higher fixed charge, and the demand for electricity reduces so significantly that SCE is no longer effectively able to recover such costs from its customers, SCE's business, financial condition and results of operations will be materially impacted.

In addition, the FERC has opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities.

For more information. See "Business—SCE—Competition."

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RISKS RELATING TO EDISON INTERNATIONAL AND SOUTHERN CALIFORNIA EDISON COMPANY

Cybersecurity and Physical Security Risks

Successful attacks on SCE information and operational technology systems and infrastructure could have a material impact on SCE's operations or financial condition

Edison International and SCE systems, assets and personnel are targets for physical and cyber attacks. Regulators such as NERC and U.S. Government agencies, including the Departments of Defense, Homeland Security, and Energy, have increasingly stressed that threat sources continue to seek to identify and exploit vulnerabilities in the U.S. national electric grid and other critical energy infrastructures, and that such attacks and disruptions, both physical and cyber, are highly sophisticated and dynamic. Several U.S. Government agencies have highlighted the increasing risks related to physical and cybersecurity attacks, including ransomware attacks, related to the electric sector, including its supply chain, and that the risks may escalate during periods of heightened geopolitical tensions.

SCE requires the uninterrupted use of sophisticated information and operational technology systems and infrastructure to monitor and operate the electric grid. In the regular course of SCE’s business, it also handles a range of sensitive infrastructure, security, employee, customer, and business systems information. If SCE's information technology and operational technology systems' security were to be compromised by physical or electronic means or a critical system or technology failure were to occur without timely recovery, including failure of new technology to be implemented as designed, SCE could be unable to fulfill critical business functions and/or sensitive information could be misappropriated or compromised. Such events could result in violations of privacy and other laws, material financial loss to SCE and/or to its customers, loss of confidence in SCE's security risk management, customer dissatisfaction, and significant litigation and/or regulatory exposure, all of which could materially affect Edison International’s and SCE's financial condition, operations, and the business reputation of Edison International and SCE.

SCE's security program cannot prevent all attacks or incidents

SCE's systems have experienced, and will continue to face, cyber and physical security events involving malicious code, unauthorized access attempts, vandalism and other illicit activities. No security program can completely shield its systems, infrastructure, and data from attacks, intrusions, or other catastrophic events that could result in their failure or reduced functionality. There is no guarantee that SCE's security program, including prevention, detection, mitigation, and remediation of risks, will prevent all future cyber and physical security incidents that could materially impact its operations or financial condition.

SCE is not able to anticipate and prevent all physical and cyber attacks or information security breaches, and its investments in security resources, talent, and business practices may not be effective against all threat actors, particularly nation-state actors. Voluntary cybersecurity guidelines and practices cannot be applied to all businesses equally due to system capability, complexity, and resources for implementation. SCE's security tools and controls, including those supporting configuration management, identity and access management, network segmentation, and boundary defenses, may not fully protect against unauthorized access from internal and external threats. SCE's current security controls and defenses may also not protect against insider threats, including deliberate and unintentional actions (e.g., human error) and other emerging cybersecurity risks created by artificial intelligence, quantum computing, cyber skills shortages, and regulatory constraints.

SCE's security program is prioritized based on known risks, available resources, and regulatory requirements, and therefore all SCE assets are not equally protected. For example, not all of SCE's information technology assets are inventoried, which could result in unmitigated vulnerabilities or slow the detection, investigation, and recovery of an incident. Known vulnerabilities in SCE's information technology and operational technology environments may not be remediated before an adversary could discover or exploit them. Attackers can also exploit new, unknown vulnerabilities (e.g., zero day) and vulnerabilities where a patch or other remediation measure is not yet available.

SCE's transition to a more network-connected grid and increased deployment of new technologies increases the number of systems adversaries can target

SCE's operations require the continuous availability and deployment of critical information and operational technology systems, sensitive customer and employee data and infrastructure information, all of which are targets for malicious actors. New cyber and physical threats arise as SCE moves to an increasingly digital electric grid. For example, SCE's grid modernization efforts and the transition to a more connected grid, including the integration of new technologies and increased networking of operational technology assets such as substations, increases the threat surface and potential vulnerabilities that an adversary can target. As new systems are developed or procured by SCE, software development practices may not comprehensively prevent the introduction of new software vulnerabilities. Additionally, certain existing or legacy information technology, operational technology, and communications infrastructure use less secure protocols or configurations.

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Vendors and other third parties may be used to target and attack SCE

SCE interacts with a wide array of third parties and depends on vendors to provide it with products and services. Malicious actors may attack vendors to disrupt the services they provide to SCE, or to use those vendors as a conduit to attack SCE. SCE system data and architecture are also disclosed, either voluntarily or by mandate, to third parties and the public by regulators, employees, contractors, and vendors. This system data may be used by malicious actors to understand SCE’s systems to prepare for a cyber or physical attack.

The products and services provided by SCE's vendors may contain vulnerabilities or otherwise not adhere to SCE's enterprise cybersecurity standards (e.g., lack of encryption). Additionally, SCE's operational technology vendors have increasingly been targeted by threat actors. A compromise of equipment and/or exfiltration of SCE data, whether by physical or by electronic means, could result in loss or changes to confidential or sensitive information and interruption of business processes. For example, compromises to widely-used products and services may affect the supply chains of many industries, including companies in SCE’s supply chain. While SCE vendors have experienced cybersecurity incidents, such incidents have not, to SCE's knowledge, resulted in a material impact to SCE to date.

Global and Regional Risks

Edison International's and SCE's financial condition and results of operations could be materially impacted by catastrophic, macroeconomic and geopolitical events that cause significant disruption to workforces, supply chains, economies, or societies on a regional, statewide, national or global basis.

Edison International and SCE could be materially and adversely impacted by catastrophic, macroeconomic and geopolitical events, such as the effects of increased inflationary pressures and interest rates, potential economic downturns or recessions, geopolitical pressures, and pandemics and regional health emergencies. For example, the global spread of COVID-19, which was declared a pandemic by the World Health Organization in March 2020, created significant uncertainty, volatility and disruption globally that resulted in, among other things, disruption to supply chains, economies, and workforce and impacted the operations of Edison International and SCE. Additionally, the geopolitical developments involving the Russia-Ukraine conflict, China and the Middle East, could cause delays and disruptions in the supply chain and the availability and timely delivery of services, materials and components used in SCE’s operations. Political changes following the United States presidential election could lead to changes in economic conditions or economic uncertainties in the United States and globally, including impacts to infrastructure investments, tariffs, taxes, and energy, environmental and social policies.

Many of the risks and uncertainties identified in this Form 10-K have, and will be, exacerbated by the impacts of a catastrophic event and the actions taken by governmental entities, businesses, individuals and others in response to such an event. In addition, impacts of international conflict, recession, pandemic or similar events on SCE's customers and third parties could also result in SCE facing, among other things, significant reductions in demand for electricity and payment delays and/or defaults from customers which could result in significant under-collections. Edison International and SCE access to the bank and capital markets and/or the costs of accessing those markets could be constrained and could also face payment delays and/or defaults from insurers and other counterparties. These impacts, among others, could materially and adversely impact Edison International's and SCE's business, operations, cash flows, liquidity and financial results.

Edison International's and SCE's business activities are concentrated in one industry and in one region.

Substantially all of Edison International's and all of SCE's business activities are concentrated in the electric utility industry. Edison International's principal subsidiary, SCE, serves customers only in southern and central California. As a result, Edison International's and SCE's future performance may be affected by events and economic factors unique to California or by regional regulation, legislation or judicial decisions. For example, California courts have applied strict liability to investor-owned utilities in wildfire and other litigation matters. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."