EX-99.1 2 eixmay2020businessupdate.htm EXHIBIT 99.1 BUSINESS UPDATE PRESENTATION MAY 1, 2020
Exhibit 99.1 Business Update May 1, 2020

Forward-Looking Statements Statements contained in this presentation about future performance, including, without limitation, operating results, capital expenditures, rate base growth, dividend policy, financial outlook, and other statements that are not purely historical, are forward-looking statements. These forward-looking statements reflect our current expectations; however, such statements involve risks and uncertainties. Actual results could differ materially from current expectations. These forward-looking statements represent our expectations only as of the date of this presentation, and Edison International assumes no duty to update them to reflect new information, events or circumstances. Important factors that could cause different results include, but are not limited to the: • ability of SCE to recover its costs through regulated rates, including costs related to uninsured wildfire-related and mudslide-related liabilities, costs incurred to mitigate the risk of utility equipment causing future wildfires, costs incurred to implement SCE's new customer service system and costs incurred as a result of the COVID-19 pandemic; • ability of SCE to implement its Wildfire Mitigation Plan, including effectively implementing Public Safety Power Shut-Offs when appropriate; • ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire-related claims, and to recover the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses from customers or other parties; • risks associated with California Assembly Bill 1054 (“AB 1054”) effectively mitigating the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are alleged to be a substantial cause, including SCE's ability to maintain a valid safety certification, SCE's ability to recover uninsured wildfire-related costs from the insurance fund established under AB 1054 (“Wildfire Insurance Fund”), the longevity of the Wildfire Insurance Fund, and the CPUC's interpretation of and actions under AB 1054, including their interpretation of the new prudency standard established under AB 1054; • decisions and other actions by the California Public Utilities Commission, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and other regulatory and legislative authorities, including decisions and actions related to determinations of authorized rates of return or return on equity, the recoverability of wildfire-related and mudslide-related costs, issuance of SCE's wildfire safety certification, wildfire mitigation efforts, and delays in regulatory and legislative actions; • ability of Edison International or SCE to borrow funds and access bank and capital markets on reasonable terms; • risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting, governmental approvals, on-site storage of spent nuclear fuel, delays, contractual disputes, and cost overruns; • pandemics, such as COVID-19, and other events that cause regional, statewide, national or global disruption,, which could impact, among other things, Edison International's and SCE's business, operations, cash flows, liquidity and/or financial results; • extreme weather-related incidents and other natural disasters (including earthquakes and events caused, or exacerbated, by climate change, such as wildfires), which could cause, among other things, public safety issues, property damage and operational issues; • physical security of Edison International's and SCE's critical assets and personnel and the cybersecurity of Edison International's and SCE's critical information technology systems for grid control, and business, employee and customer data; • risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure for other electricity providers such as Community Choice Aggregators (“CCA,” which are cities, counties, and certain other public agencies with the authority to generate and/or purchase electricity for their local residents and businesses) and Electric Service Providers (entities that offer electric power and ancillary services to retail customers, other than electrical corporations (like SCE) and CCAs); • risks inherent in SCE's transmission and distribution infrastructure investment program, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable acceptance of power delivery), changes in the California Independent System Operator’s transmission plans, and governmental approvals; and • risks associated with the operation of transmission and distribution assets and power generating facilities, including public and employee safety issues, the risk of utility assets causing or contributing to wildfires, failure, availability, efficiency, and output of equipment and facilities, and availability and cost of spare parts. Other important factors are discussed under the headings “Forward-Looking Statements”, “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s Form 10-K and other reports filed with the Securities and Exchange Commission, which are available on our website: www.edisoninvestor.com. These filings also provide additional information on historical and other factual data contained in this presentation. May 1, 2020 1

Table of Contents Updated (U) or New (N) from February 2020 Page Business Update EIX Shareholder Value 3 EIX Summary, SCE Regulatory Framework, SCE Long-Term Growth Drivers 4-6 U SCE Capital Expenditures and Rate Base Forecast 7-9 Commitment to Sustainability: California Mandates, SCE’s Pathway 2045, SCE Investments 10-12 COVID-19 Pandemic Summaries 13-14 N Wildfire Risk and Mitigation Summaries, 2019 Wildfire Legislation Update, AB 1054 Wildfire Fund 15-18 SCE Key Regulatory Proceedings 19 U SCE 2021 General Rate Case Overview and Timeline; CalPA Testimony Summary; FMA Update Summary 20-25 N.U SCE CPUC 2020 Cost of Capital 26 U SCE Distribution and Transmission Capital Expenditure Detail 27-30 U Operational Excellence 31 Edison Energy Group Summary 32 2020 EIX Core Earnings Guidance 33 Annual Dividends Per Share 34 Appendix Commitment to Sustainability: Transparency, Strong Corporate Governance 36-37 SCE Historical Rate Base and Capital Expenditures 38-39 Power Grid of the Future 40 SCE Customer Demand Trends, Bundled Revenue Requirement, SAR Historical Growth, Rate and Bills Comparison 41-44 U SCE CCA Overview, Residential Rate Reform and Other 45-48 U First Quarter 2020 Earnings and Liquidity Summary, Results of Operations, Non-GAAP Reconciliations 49-56 N,U May 1, 2020 2

EIX Strategy Should Produce Long-Term Value Sustained Earnings and Dividend Electric-Led Clean Energy Future Growth Led by SCE SCE Rate Base Growth Drives Earnings EIX Vision • 7-8% average annual rate base growth • Lead transformation of the electric power through 2023 industry • SCE earnings expected to track rate base • Focus on clean energy, efficient growth over the long term electrification, grid of the future and customer choice Constructive Regulatory Structure SCE Electric-Led Clean Energy Strategy • Decoupling of electricity sales • Addressing wildfire risk • Balancing accounts • Cleaning the power system • Forward-looking ratemaking • Strengthening and modernizing the grid • Prudency standard shifting burden of proof • Achieving operational and service from utility for wildfire-related proceedings excellence • Helping customers make cleaner energy Sustainable Dividend Growth choices • Target payout ratio of 45-55% of SCE Edison Energy Strategy earnings • Partnering with global market leaders to align energy investments with strategic goals • Empowering organizational vision, mitigating risk, and achieving long-term sustainability and cost saving targets for clients May 1, 2020 3

About Edison International Vision is to lead the transformation of the electric power industry, focusing on opportunities in clean energy, efficient electrification, grid of the future, and customer choice About Southern California Edison One of the nation’s largest electric utilities •15 million residents •5 million customer •50,000 square-mile in service territory accounts service area Significant infrastructure investment •118,000 miles of •3,200 MW owned generation distribution/transmission lines Above average rate base growth driven by • Safety and reliability  Infrastructure replacement  Wildfire mitigation • California’s low carbon objectives  Grid modernization  Transportation electrification  Energy storage Limited Generation Exposure • Own less than 20% of its power • Majority of future needs via generation competitive solicitations About Edison Energy • An independent advisory and services company with advanced analytic capabilities to design optimal energy portfolio solutions for large-scale commercial and industrial customers May 1, 2020 4

SCE Decoupled Regulatory Framework Regulatory Mechanism Key Benefits Decoupling of Revenues from • Earnings not affected by variability of retail electricity sales Sales • Differences between amounts collected and authorized levels either billed or refunded • Promotes energy conservation • Stabilizes revenues during economic cycles Major Balancing Accounts • Cost-recovery related balancing accounts represented more • Sales than 55% of costs • Fuel and Purchased power • Trigger mechanism for fuel and purchased power adjustments • Energy efficiency at 5% variance level • Pension expense Advanced Long-Term • Upfront contract approvals and prudency standards provide Procurement Planning greater certainty of cost recovery (subject to compliance- related reasonableness review) Forward-looking Ratemaking • Forward and test year GRC with four-year rate cycle • Separate cost of capital mechanism May 1, 2020 5

SCE Long-Term Growth Drivers Description Timeframe/Regulatory Process Sustained level of infrastructure investment • Ongoing - current and future GRCs Infrastructure required until equilibrium replacement rates Replacement achieved and then maintained Utility investment and operational practices • 2018 – Filed Grid Safety & Resiliency application, CPUC that mitigate wildfire risk and bolster fire approved $526 million of total costs (capital: $407 million) Wildfire Prevention prevention and response activities • 2019 & 2020 – Filed Wildfire Mitigation Plans • Ongoing – future GRCs and Mitigation • First ~$1.6 billion fire risk mitigation capital spend will be securitized per AB 1054 Utility investment to build and support the • 2018 & 2019 – Medium- and Heavy-Duty (MD/HD) Vehicle expansion of transportation electrification in Transportation Electrification (TE) program approved, Electrification of passenger and light-, medium- and heavy- totaling $356 million; Charge Ready 2 application filed, Transportation and duty vehicles and support electrification of requesting $760 million; Charge Ready Bridge Funding other sectors of the economy approved totaling $22 million Other Sectors • 2020-2030 – Potential investments to support electrification in other sectors of the economy Future transmission investment to meet 60% • 2017-2022 – Multiple projects approved by CAISO in renewables mandate in 2030, 100% clean permitting and/or construction Transmission energy by 2045 and to support reliability • 2023-2045 – Future needs largely driven by CAISO planning process SCE-owned investment opportunities under • Today – Most commitments via contracts; over 690 MW existing CPUC proceedings procured Energy Storage • 2020-2023 – procurement target of 580 MW by 2020 as utility-owned or procured; additional reliability proceeding ongoing Accelerate circuit upgrades, automation, • 2018-2020 – Approximately $590 million of capital spending communication, and analytics capabilities at approved in 2018 GRC decision Grid Modernization locations to integrate distributed energy • 2021-2023 – Approximately $750 million of capital spending resources requested in 2021 GRC application • 2025 – CPUC target to complete grid modernization but may take longer May 1, 2020 6

SCE Capital Expenditure Forecast ($ billions) $19.4 - $21.2 billion capital program Distribution for 2020-2023 Transmission • This capital forecast includes: Generation 1  2018 GRC approved CPUC capital spend Wildire mitigation-related spend for 2019-2020 $5.4 $5.4 $5.4  2021 GRC requested CPUC capital spend $5.0 for 2021-2023 $4.8  Non-GRC capital programs including Charge Ready Pilot, Medium- and Heavy- Duty (MD/HD) Transportation Electrification and 2019-2020 wildfire mitigation-related programs  FERC forecasted capital spend • Long term growth drivers include:  Infrastructure Replacement  Wildfire Mitigation  Transportation Electrification  Transmission Infrastructure • Authorized/Actual may differ from forecast; 2019 (Actual) 2020 2021 2022 2023 previously authorized amounts in the last Range three GRC cycles were 89%, 92% and 92%2 of 3 $4.8 $4.9 $4.9 $4.8 Case capital requested, respectively 1. In accordance with Assembly Bill 1054, ~$1.6 billion of wildfire mitigation-related spend shall not earn an equity return. See “SCE Wildfire Capital Forecast” slide for further information on wildfire-related capital spend 2. Approval percentage for the 2018 GRC excludes Grid Modernization and project approvals that were deferred to the next General Rate Case for timing reasons 3. The low end of the range for 2021-2023 reflects a 10% reduction on the total capital forecast using management judgment based on historical experience of previously authorized amounts and potential for permitting delays and other operational considerations. The low end of the range for 2020 reflects a 10% reduction applied only to FERC capital spending and non-GRC programs May 1, 2020 7

SCE Rate Base Forecast ($ billions) $41.0 $38.2 $35.9 $33.4 $30.8 $28.5 Range Case 1 2018 2019 2020 2021 2022 2023 CAGR Range Case 2 $28.5 $30.8 $33.3 $35.1 $37.0 $39.2 6.6% 1. Morongo Transmission holds an option to invest up to $400 million in the West of Devers Transmission Project, or half of the estimated cost of the transmission facilities only, at the in-service date, estimated to be 2021. In the table above, the rate base has been reduced to reflect this option. Capital forecast includes 100% of the project spend 2. Rate base forecast range case reflects capital expenditure forecast range case Note: Weighted-average year basis. FERC based on latest forecast and represents approximately 20% of total rate base throughout the forecast period. CPUC excludes the ~$1.6 billion of SCE’s fire risk mitigation capital expenditures in accordance with Assembly Bill 1054. CPUC also excludes the “rate-base offset” adjustment related to the 2015 GRC write-off of the regulatory asset for 2012-2014 incremental tax repairs and rate base associated with projects or programs that have not yet been approved. May 1, 2020 8

SCE Wildfire Capital Forecast ($ billions) 1 All Other Wildfire-Related Mitigation $4.4 Billion Capital Request for 2020-2023 1 Spend • Under AB 1054, ~$1.6 billion of SCE’s fire risk capital Wildfire-Related Mitigation Spend - expenditures per CPUC-approved Wildfire Mitigation Plan AB1054 shall not earn an equity return $1.4  SCE assumes all CPUC-jurisdictional wildfire-related mitigation spend generally incurred after AB 1054 $1.1 passage will be eligible to meet the requirement until the ~$1.6 billion has been incurred $1.0  Spending recovered from ratepayers through a $0.9 securitizable dedicated-rate component • Main wildfire-related programs include: $0.7 $1.4  Covered Conductor Program (total capital request of $0.2 $3.2 billion) – Risk-prioritized replacement of more $0.8 $1.1 than 6,000 miles of bare conductor to covered $0.9 conductor by 2023  Preventative Maintenance Program (total capital $0.5 request of approximately $310 million) – Enhanced inspection program within High Fire Risk Areas $0.2 (HFRAs) designed to proactively detect and timely remediate potential in-service failures​ 2019 Actual 2020 2021 2022 2023 1. Includes FERC wildfire mitigation-related spending of $4 million, $5 million, $4 million and $4 million for 2020-2023, respectively; inclusive of overheads Note: Totals may not foot due to rounding. Forecast based on 2018 GRC request levels. May 1, 2020 9

Commitment to Sustainability: California Mandates • SCE emissions from delivered power declined 42% between 2005 and 2018, and in 2018, SCE delivered power with only half the GHG emissions per unit of electricity as the estimated U.S. average • California law requires SCE to deliver on some of the most aggressive clean energy mandates in the industry: • By 2020 – 33% of power from Renewables Portfolio Standard (“RPS”)-eligible resources • By 2030 – 60% of power from RPS-eligible resources • By 2045 – 100% carbon-free power State Carbon Emissions Reduction Pathway 2017 California’s GHG Annual million metric tons (MMT) Emissions by Sector 450 Residential Commercial Industrial Commercial and 400 Agriculture Transportation Electricity Residential 350 12% Transportation Electrical 300 41% 40% by 2030 Power [260 MMT] 250 15% 200 Carbon Neutrality Agriculture by 2045 8% 150 [108 MMT] 80% by 2050 100 [86 MMT] Industrial 24% 50 0 2015 2020 2025 2030 2035 2040 2045 2050 SCE sees itself as a catalyst for achieving California’s economy-wide GHG emissions reduction goals, including carbon neutrality by 2045, and a 40% and 80% reduction from 1990 levels by 2030 and 2050, respectively – through economy-wide electrification Source: Data for both charts from California Air Resources Board; California GHG Emissions data as of 2017. May 1, 2020 10

Commitment to Sustainability: SCE’s Pathway 2045 Pathway 2045 outlines our blueprint for how California can achieve carbon neutrality by 2045. This analysis updates and extends SCE’s November 2017 Pathway 2030 and continues to show electric-led path to be most efficient and cost-effective way to meet state carbon reduction and other environmental goals • 100% of grid sales with carbon- • 75% of light-duty vehicles need free electricity to be electric • 80 GW of utility-scale clean • 66% of medium-duty vehicles generation need to be electric • 30 GW of utility-scale energy • 33% of heavy-duty vehicles storage need to be electric • 33% of space and water • Until there is an alternative, heating to be electrified by natural gas generation capacity 2030 provides a crucial role for • 70% of space and water reliability and affordability heating to be electrified by • 40% of natural gas that remains 2045 will be decarbonized through • Building electrification will the addition of biomethane and increase load significantly by hydrogen 2045 – representing 15% of the total load Achieve carbon neutrality by 2045 through powering 100% of grid sales with carbon-free electricity, electrifying the transportation and building sectors, and using low-carbon fuels for technologies that are not yet viable for electrification May 1, 2020 11

Commitment to Sustainability: SCE Investments Clean Energy Efficient Electrification • Reduced GHG emissions from • Approved and proposed delivered power by 42% between investments of over $1 billion to 2005 and 2018 expand electrification across Southern California’s economy • 46% carbon-free power delivered in 2018, which had only half the • Award-winning Charge Ready GHG emissions per unit of pilot and bridge funding electricity of the US average program are successfully supporting the installation of  Targeting carbon neutrality by approximately 2,800 EV charge 2045 in line with state goals ports for light-duty vehicles • #1 utility nationally for energy • Charge Ready Transport, the storage in 2017 and 2018* largest truck and transit charging • Named national leader in solar initiative in the nation, will install for past decade* infrastructure for at least 870 customer sites by 2024 • Award-winning hybrid enhanced gas turbine project, combining battery storage with natural gas generation *According to the Smart Electric Power Alliance (SEPA) rankings, based on a survey of more than 400 utilities nationally. May 1, 2020 12

Focus on Operations During COVID-19 Pandemic • Safety of workers and communities is our first priority; procedures in place to protect workers that align with guidance from the World Health Organization and Center for Disease Control • About 2/3 of all employees have been teleworking since March 16; approximately 4,500 SCE Employees workers continue to work at SCE facilities or in the field • Field and facilities workers have additional guidelines and enhanced personal protection equipment • Temporarily suspending service disconnections and waiving late fees • Providing monthly bill discounts/one-time bill relief to certain income-qualified programs; Customers and working closely with the CPUC Communities • Pledged $1 million to local non-profits to assist our communities • Prioritizing public safety and wildfire mitigation work to protect our communities while mitigating impacts of essential outages on customers • Wildfire mitigation work remains a top priority and focused on meeting all compliance targets Wildfire outlined in SCE’s 2020-2022 Wildfire Mitigation Plan (WMP); identified as essential work by Prevention and government agencies; continue activities that minimize the impact of PSPS on our communities Mitigation • Currently on track for 61 of 69 WMP activities through Q1 2020 and action plans in place for all off track activities • Currently no material supply chain disruptions Supply Chain • Continue monitoring our supply chain; receiving feedback from over 100 critical contractors on pandemic impact to their companies Pandemic response grounded in best-in-class emergency management protocols; evaluating additional impact/timing scenarios and mitigations as pandemic progresses May 1, 2020 13

Regulatory Mechanisms Provide Revenue Certainty • Earnings not affected by variability of retail electricity sales Revenue • Long-standing regulatory mechanism that annually adjusts rates to collect/refund variance Decoupling from authorized revenue requirement • Base Revenue Requirement Balancing Account (BRRBA) allows collection of authorized revenue requirement and cost recovery regardless of change in demand/volumes • Activated Catastrophic Event Memorandum Account (CEMA) for COVID-19 related costs Recovery • CPUC approved resolution for a COVID-19 Pandemic Protections Memorandum Account where Mechanisms we will record non-payment and non-recovery of billed amounts and later seek recovery in our annual Energy Resource Recovery Account or other proceedings • Exploring additional potential mechanisms to mitigate or manage customer rate impacts 6% Decline in System Load During Stay-at-Home Order Vs. Prior Year1 System Load by Segment Total SCE Residential Non-Residential 20201 vs. 2019 (6%) 14% (16%) 20201 vs. 5-year average (11%) 10% (18%) Load and payment impacts may shift as impact of pandemic develops but California’s regulatory construct has established mechanisms for recovery of IOU revenue requirement 1. Data based on period starting March 16, 2020 through April 19, 2020 Note: Information is not weather adjusted. Customer class and system load represent all SCE retail customers (bundled as well as Direct Access and CCA). The load impact by customer class is estimated using interval load data from representative samples of customers in each rate group. These estimates are not derived from SCE billing files therefore they don’t necessarily match what the customers were billed. May 1, 2020 14

2019 Wildfire Mitigation Actions  Inspections: EOI inspections conducted on all distribution and transmission circuits in 2019; large volume of findings constrained bandwidth for other programs in 2019; transitioning to more risk-prioritized approach using technology and enhanced aerial inspections  Resources: added significant resources to manage accelerated pace of inspections, vegetation management, and infrastructure hardening programs; competition from statewide activities constrains pace of growth  Execution: achieved target volumes of major programs and completed majority of 2019 Wildfire Mitigation Plan (WMP) activities; rapid scaling of programs resulted in opportunities to improve efficiency going forward  In 2019, SCE met or exceeded its goals for the vast majority of activities identified in its plan, substantially completed the remaining activities, and greatly exceeded its plan in some areas  Public Safety Power Shutoff (PSPS): rapid deployment of situational awareness tools and capabilities helped to better target outages during high risk conditions; continuing to identify ways to better manage energized/de- energized lines during severe wind conditions while maintaining risk mitigation needs and reducing customer impact  During peak fire season (October 2019), only ~2% of SCE customers were affected by PSPS  Ignitions: ignition cause analysis of 2019 events validated programs and informed further plan updates; as more mitigations are deployed, we expect to reduce the scope and impact of PSPS, but PSPS will have to remain available as a tool to mitigate wildfire risk during severe weather and high Fire Potential Index events  Found over 40 instances of damage to system assets in post-PSPS patrols  Technology: meaningful benefits from field deployment of mobile technology and enhanced data analytics advanced prioritization capabilities, and detection of system issues; increasing adoption of new technologies planned for 2020 and beyond SCE continues to drive process improvements, but has not fundamentally changed the approach to wildfire mitigation in 2020 and beyond May 1, 2020 15

Mitigating Catastrophic Wildfire Risk 2019 Deployment 2020-22 Wildfire Mitigation Plan Covered Conductor: installed well in excess 4,000 additional circuit miles by Jan 1, 2023 Infrastructure of 2019 WMP target of 96 circuit miles 2020: 700-1,000 / 2021: 1,400 / 2022: 1,600 Hardening Undergrounding: leverage risk analysis to Approximately 17 miles of undergrounding under identify opportunities consideration in 2021-22 Inspections: EOI inspections conducted on all Risk-informed ground & aerial inspection program distribution and transmission circuits in 2019 covering ~50% of HFRA structures annually Vegetation Management: expand line Continue expanded line clearances; focus on clearances standards to 12 feet; removed hazard tree assessments and timely removal; Enhanced ~5,900 hazard trees (below initial target of expand brush clearing at base of poles to 200,000- Operational 7,500); and conducted over 80,000 instances 300,000 per year Practices of clearing brush around poles incremental to existing regulatory requirements PSPS: de-energization based on circuit- Same de-energization approach with new circuit- specific wind speed thresholds specific mitigation plans and customer care programs to reduce customer impacts Weather Stations: over 350 installed 375-475 weather stations per year Situational HD Cameras: approximately 90 installed Deployment complete as coverage in high fire risk Awareness areas effectively maximized 2020-2022 Wildfire Mitigation Plan continues the same foundational strategy with increased focus on risk-prioritization of activities and PSPS impact mitigations May 1, 2020 16

2019 Wildfire Legislation Update Summary of Assembly Bill 1054 and Assembly Bill 111 Safety • Creates Wildfire Safety Division1 to provide additional wildfire safety oversight Oversight • Annual safety certifications issued by Wildfire Safety Division1 require: 1) an approved wildfire mitigation plan; 2) utility to be in and good safety standing; 3) established board safety committee with relevant safety experience; 4) board-level reporting to the Certification CPUC on safety issues; 5) approved executive compensation structure that promotes safety, ensures public safety and utility financial stability; 6) compensation limits on executive officer contracts; and 7) implementation of, and reporting to the CPUC on wildfire mitigation plans, safety culture assessments and board safety committee recommendations Cost • Provided a utility is “safety certified” and elects to participate in the wildfire “insurance” fund (described below), establishes a Recovery FERC-like prudence standard to guide recovery of costs arising from catastrophic wildfires occurring after bill enactment Standard • Prudence is based on reasonable utility conduct with potential for full or partial recovery, considering factors within and beyond a utility’s control • FERC-like standard assumes utility is prudent, unless intervenors create serious doubt, shifting burden to the utility to prove prudence Wildfire • Establishes a wildfire fund to help wildfire victims and affected communities recover and rebuild more quickly Fund • Wildfire “insurance” fund is an insurance-like fund that more broadly socializes wildfire costs; utilities’ participation is voluntary • Fund includes a $10.5 billion ratepayer contribution through a 15-year extension of the Department of Water Resources bond charge; wildfire insurance fund also includes $10.5 billion contribution from utility shareholders • All three IOUs have elected to participate. PG&E must emerge from bankruptcy by June 30, 2020 to participate  SCE’s shareholders initially contributed approximately $2.4 billion on September 10 and expect to contribute approximately $95 million annually on January 1 for 10 years2 Mitigation • First $1.6 billion of SCE’s fire risk mitigation capital expenditures as approved in wildfire mitigation plans shall not earn an equity CapEx return, but can be recovered from ratepayers through a securitizable dedicated rate component2 Liability Cap • While fund remains solvent, wildfire cost disallowances capped over each trailing 3-year period to 20% of T&D equity rate base • Must be safety certified and not found to be acting with willful or conscious disregard of the safety of others 1. Wildfire Safety Division created within CPUC until duties transferred to newly formed Office of Energy Infrastructure Safety on or after July 2021 2. Excluded from measurement of regulatory capital structure May 1, 2020 17

Assembly Bill 1054 Wildfire Fund Mechanics1 IOUs contribute $10.5 B Customers contribute non-bypassable charge • PG&E: $4.8 B initial + $193 M annually for 10 years • $0.9 B per year charge for 15 years ($0.5 B w/o PG&E) (conditional on exiting bankruptcy by June 30, 2020) • California Department of Water Resources (DWR) can • SCE: $2.4 B initial + $95 M annually for 10 years issue ≤$10.5 B of bonds to reimburse state for initial • SDG&E: $0.3 B initial + $13 M annually for 10 years $2 B contribution and to capitalize fund Wildfire Fund • “Covered Wildfire” means any wildfire ignited on or after July 12, 2019, caused by an electrical corporation as determined by the governmental agency responsible for determining causation, in excess of annual utility retention (expected to be ~$1 B) • Size of fund if all 3 IOUs contribute equal to $21.0-24.0 B2; if only SCE & SDG&E contribute fund is $9.6-11.2 B2 • Funds invested / managed by administrator selected by California Catastrophe Response Council • Fund reimbursed if imprudent (see below right), but does not have a separate replenishment mechanism If found imprudent, IOU reimburses Wildfire Fund up to 3-year rolling cap Fund payment of “eligible claims”3 • Liability cap of 20% of T&D Equity Rate Base • Pay out claims to claimants on a first come, first CPUC (~$3.0 B for SCE as of 2020) unless found to served basis subject to fund administrator prudency have acted with conscious or willful disregard approval determination • Valid safety certification is required • Subrogation claims settled at ≤40% approved of operations • Liability cap lapses when fund is exhausted unless exceptional facts and circumstances; (serious doubt higher amounts may be approved by fund standard) administrator If found prudent, IOU does not reimburse Wildfire Fund 1. This summary is based on Edison International’s interpretation of Assembly Bill 1054 2. Range based on whether customer charge finances DWR bonds or is contributed directly to Wildfire Fund • Valid safety certification is required 3. “Eligible claims” means claims for third-party damages from covered wildfires less annual utility retention (larger of $1.0 B or required insurance layer per fund administrator) May 1, 2020 18

SCE Key Regulatory Proceedings Proceeding Description Next Steps Key CPUC Proceedings 2021 General Rate Case Set CPUC base revenue requirement, capital Application filed August 30, 2019; Scoping Memo issued in October 2019; (A. 19-08-013) expenditures and rate base for 2021-2024 CalPA filed testimony on April 10, 2020, other intervenors to file in May 2020; 2024 revenue requirement request to be filed May 2022 Application for Approval of Requesting to a waiver to SCE’s authorized Proposed decision issued April 1, 2020; Awaiting CPUC approval Waiver of Capital Structure capital structure calculation for wildfire Rule (A. 19-02-017) liabilities reserve Grid Safety and Resiliency Requesting $526 million of total cost for Final Decision approving settlement issued April 16, 2020 Program (GSRP) 2018-2020 (per settlement); focused on grid (A. 18-09-002) hardening and enhanced vegetation management Application for Recovery of Requesting recovery of $505 million in Application filed July 31, 2019; Scoping Memo issued in December 2019; WEMA costs (A. 19-07-020) insurance premiums and other associated Hearings expected in June 2020 costs tracked in the WEMA Application for Recovery of Requesting recovery of $138 million in costs Application filed July 31, 2019; Scoping memo issued on December 6, CEMA costs tracked in the CEMA for drought-related work 2019; Proposed decision expected in mid-2021 (A. 19-07-021) and for work related to 2017 fires 2020 Wildfire Mitigation Plan Evaluating and approving the 2020-2022 Filed February 7, 2020; Approval expected June 2020 wildfire mitigation plan Charge Ready Program Implementation program for charger Pilot report filed in May 2018; Charge Ready Bridge Funding approved in (A.14-10-014; A.18-06-015) installations and market education December 2018; expecting proposed decision in first half of 2020 Power Charge Indifference Review, revise, and consider alternatives to Final Phase 1 Decision adopted on October 11, 2018; Final Phase 2 Adjustment (PCIA) OIR the PCIA Decision on benchmark refinement/true-up was approved on October (R.17-06-026) 10, 2019; Final decision on portfolio optimization scheduled for Q3 2020 Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates New replacement rate became effective, subject to refund, on 11/12/19; partial settlement reduced request to 11.97%; parties agreed to settlement in principal in April 2020 (details to be filed no later than July 1, 2020) May 1, 2020 19

SCE 2021 General Rate Case Overview Filed August 30, 2019, request balances the need to advance California’s ambitious decarbonization policy goals and address emergent wildfire public safety risks, while continuing to provide safe, reliable, and affordable service to customers • 2021 GRC Application (A. 19-08-013) addresses major portion of CPUC-jurisdictional revenue requirement for 2021-2023  Includes operating costs and capital investment requests  Excludes CPUC jurisdictional costs such as fuel and purchased power, cost of capital and other discrete SCE capital projects (such as Charge Ready 2 – SCE’s transportation electrification infrastructure program)  Excludes FERC-jurisdictional transmission revenue requirement • Requests 2021 revenue requirement of $7.554 billion1  $1.109 billion increase over 2020 authorized revenue requirement, a 11.4% increase over total rates2  Requests increases of $423 million for 2022 and $514 million for 2023 • Multi-track schedule proposed to approve 2021-2023 revenue requirement and reasonableness of additional 2018-2020 recorded incremental amounts associated with the Fire Mitigation memorandum accounts (FMA)3 (See “SCE 2021 General Rate Case Timeline” for more information) • On January 16, 2020, the CPUC modified the Rate Case Plan to add a third attrition year to each of the large Investor Owned Utilities rate case cycles – In mid-April, a Ruling was issued requiring SCE to file its RAMP and propose a revenue requirement for 2024 in May 2022 in a new Track 4 1. Includes all updates to the GRC revenue requirement filed with the CPUC as of February 20, 2020 2. 11.4% includes the impact of lower anticipated 2021 kWh sales and recoveries of non-wildfire memo accounts 3. Includes Wildfire Mitigation Plan Memo Account, Fire Hazard Prevention Memo Account, Grid Safety and Resiliency Program Memo Account and Fire Risk Mitigation Memo Account May 1, 2020 20

SCE 2021 General Rate Case Timeline • Track 1 includes approval of the 2021-2023 GRC revenue requirement. Track 2 includes reasonableness of additional 2018-2019 recorded incremental amounts associated with the Fire Mitigation memorandum accounts1 Estimated 2019 2020 2021 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 GRC Intervenor Evidentiary Final Track 2 Application Testimony Hearings Decision Final Decision Track 2 Filing Rebuttal Proposed Track 2 2018-2019 Decision Proposed FMA Update Decision • Track 3 includes approval of 2020 recorded incremental amounts associated with the Fire Mitigation memorandum accounts1 and 2018-2020 Grid Safety and Resiliency Program (GSRP) costs above settlement amount Estimated 2021 2022 Q1 Q2 Q3 Q4 Q1 Q2 Intervenor 2020 FMA Rebuttal Evidentiary Proposed Final Testimony Update Hearings Decision Decision 1. Includes Wildfire Mitigation Plan Memo Account, Fire Hazard Prevention Memo Account, Grid Safety and Resiliency Program Memo Account and Fire Risk Mitigation Memo Account Note: Actual schedule to be set by CPUC in a future regulatory order. The schedule is subject to change over the course of the proceeding. May 1, 2020 21

SCE 2021 General Rate Case Timeline (cont.) • In mid-April, the Assigned Commissioner and ALJs in the 2021 GRC issued a Ruling requiring SCE to file its RAMP and propose a revenue requirement for 2024 in May 2022 in a new Track 4 of the rate case proceeding Estimated 2022 2023 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Track 4 Filing – Rebuttal Final RAMP and Decision Testimony Intervenor Evidentiary Proposed (2024 Request) Testimony Hearings Decision Note: The schedule is subject to change over the course of the proceeding. May 1, 2020 22

SCE 2021 GRC Update – Intervenor Testimony California Public Advocates (CalPA) submitted testimony on April 10, 2020 – Key elements • Proposed 2021 revenue requirement of $6.9 billion, a $651 million reduction from SCE’s request of $7.6 billion o Proposed subsequent 3.5% attrition year increases of $242 million and $250 million in 2022 and 2023, respectively compared to SCE’s requested increases of $424 million and $513 million in 2022 and 2023, respectively • Proposed approving ~90% of SCE’s capital expenditures request; reduction was primarily in wildfire covered conductor program reducing the number of miles and T&D grid operations (e.g. Load Growth, Grid Modernization) • With respect to wildfire mitigation activities overall, CalPA generally approves the work activities proposed but takes issue with the pace and level of funding requested • Proposed SCE’s wildfire insurance premium costs should be shared (75% customer funded / 25% shareholder funded) • Similar to CalPA’s 2018 GRC testimony, current filing recommends reductions to incentive compensation programs arguing for continued shareholder funding TURN and other intervenors will submit testimony on May 5, 2020; SCE rebuttal testimony is due June 12, 2020 SCE Rate Base Forecast Comparison to CalPA – 2021-2023 ($ billions) 2019 2020 2021 2022 2023 4-year CAGR SCE’s Rate Base Forecast1 $30.8 $33.4 $35.9 $38.2 $41.0 7.5% SCE’s Rate Base Forecast at CalPA n/a n/a $35.7 $37.0 $38.4 6.1% Recommended Capital Spending Levels2 Difference n/a n/a ($0.2) ($1.2) ($2.6) 1. Rate base forecast includes CPUC GRC 2019-2020 authorized and 2021-2023 request, and latest Non-GRC and FERC estimates 2. Figures assume CPUC GRC rate base attrition year increases for 2022 and 2023 of 3.5%, consistent with CalPA’s attrition mechanism proposal May 1, 2020 23

Fire Memorandum Account Update Summary • On March 5, 2020, SCE filed its 2018-2019 Fire Memorandum Account (FMA) Update which initiated Track 2 of the 2021 GRC proceeding  Covers three separate memorandum accounts including: Wildfire Mitigation Plan MA (WMPMA), Fire Hazard Prevention MA (FHPMA), and Fire Risk Mitigation MA (FRMMA)  Seeks reasonableness review of $508.6 million of incremental O&M and $301.9 million of incremental capital expenditures incurred for wildfire mitigation activities through December 31, 2019  Seeks approval of the associated revenue requirement of $500.1 million; lower than the overall reasonableness review request due to capital recovery over asset life, flow-through tax impacts and the exclusion of capital expenditures not eligible for an equity return per AB 1054 • Grid Safety and Resiliency Program (GSRP), Wildfire Expense Memorandum Account (WEMA) and Catastrophic Event Memorandum Account (CEMA) cost recovery applications have also been filed with the CPUC; GSRP was approved in April 2020 • SCE has requested cost recovery on approximately $1 billion of wildfire-related costs across multiple proceedings • As we incur costs in 2020, we will continue to track costs in the associated memorandum accounts  The 2020 FMA update is due on March 2, 2021 SCE has requested reasonableness review and, where appropriate, cost recovery for all incremental wildfire mitigation costs for 2018 and 2019 May 1, 2020 24

Wildfire-Related CPUC Cost Recovery Filings ($ millions; inception to December 31, 2019) Total Incremental Incremental Application Mechanism for Memorandum Account Capital Spent O&M Spent Request1,2 Recovery Anticipated Timeline 2018-2019 FMA Update Breakdown: WMPMA $302 $304 FMA Update PD expected in Q1 2021 FHPMA 0 198 FMA Update PD expected in Q1 2021 FRMMA 0 8 FMA Update PD expected in Q1 2021 Total FMA Update $302 $509 $500 Other Wildfire-related Memorandum Accounts: GSRPMA $390 $37 N/A GSRP Settlement CPUC approved in April 2020 WEMA (Insurance costs only) 0 341 5053 WEMA Application Hearings expected in June 2020 CEMA (Filed)4 57 79 88 CEMA Application PD expected in March 2021 Sub-total $447 $457 $593 Grand Total $749 $966 $1,093 1. All revenue requirements include interest that have accrued to the account through December 31, 2019. Additionally, WEMA and CEMA applications also include forecast interest that SCE expects to accrue prior to getting cost recovery 2. Capital revenue requirement recorded in Memorandum Accounts mainly represents depreciation expense, taxes, and return. $204 million of the $302 million of the WMPMA capital expenditures are excluded from the cost recovery request because they are not eligible for an equity return per AB 1054 and will be evaluated separately for cost recovery through a dedicated-rate component (excludes overheads). Additionally, $218 million of the $390 million GSRPMA capital expenditures are not eligible for an equity return per AB 1054 (excluding overheads) 3. WEMA Application request represents expected incremental costs incurred through the end of the current contracted period (June 2020). The requested recovery includes $478 million for insurance premium expense, $12 million for forecast financing costs (at a commercial paper rate), and $10 million for forecast memorandum account interest, plus $5 million for FF&U. “Incremental O&M Spent” only represents a portion of the requested incremental costs accrued through December 31, 2019 4. CEMA Application filed on July 31, 2019 only covers certain events including 2017-2018 Drought, 2017 Pier Firestorm, 2017 Canyon 1 & Canyon 2 Firestorms, 2017 Thomas Firestorm and 2017 Creek & Rye Firestorm. Additionally, costs may have been accrued in this memorandum account post the application filing date May 1, 2020 25

CPUC 2020 Cost of Capital CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate 6.0 Moving Average (10/1/19 – 4/29/20) = 3.72% 100 basis point +/- Deadband 5.5 5.0 Starting Value – 4.50% 4.5 Rate (%) 4.0 3.5 3.0 2.5 10/1/19 1/1/20 4/1/20 7/1/20 10/1/20 1/1/21 4/1/21 7/1/21 10/1/21 1/1/22 4/1/22 7/1/22 10/1/22 CPUC Cost of Capital approved for 2020-2023 CPUC Authorized • ROE adjustment based on 12-month average of Capital Moody’s Baa utility bond rates, measured from Structure 2020-2023 October 1 to September 30 Common Equity 52% 10.30% • If index exceeds 100 bps deadband from starting index Preferred 5% 5.70% value, authorized ROE changes by half the difference Long-term Debt 43% 4.74% • Starting index value based on trailing 12 months of Moody’s Baa index as of September 30, 2019 – reset at Weighted Average Cost of Capital 7.68% 4.50% May 1, 2020 26

SCE Distribution System Investments Distribution Trends • Capital expenditures for certain programs deferred over 2020 – 2023 Capital Spending Forecast 2 - next five years to support reallocation of distribution for Distribution $17.5 billion resources to wildfire mitigation1; historical program funding levels will be reinstated in subsequent GRC periods in order to resume trajectory towards New Service equilibrium replacement rate Load Connections Growth • Distribution grid requires upgrades to circuit capacity, Other automation, and control systems to support various grid resiliency and reliability objectives, as well as increased use of distributed energy resources Wildfire Infrastructure 2020-2023 Capital Spending Drivers Replacement • Automation of distribution circuits • Pole replacements • Load growth upgrades General Plant • Cable and overhead conductor replacements • Preventive and breakdown maintenance • Circuit breaker, transformer bank and relay replacements/upgrades • New Service Connections 1. Deferrals required with infrastructure replacement, load growth and grid modernization programs 2. Other includes, among other things, grid modernization, emergency management, customer requested system modifications, and transportation electrification programs Note: Forecast based on 2021 GRC request levels. May 1, 2020 27

SCE Transportation Electrification (TE) Proposals • Proposals advance the vision of SCE’s Pathway 2045, which is an integrated approach to reduce GHG emissions and air pollution by taking action in three California economic sectors: electricity, transportation, and buildings • These programs accelerate electrification of the transportation sector, supporting SCE’s vision of more than 7 million light-duty passenger vehicles and transitioning to zero-emission trucks and transit  Additional studies launched to increase adoption, such as electrification of the Interstate 5 corridor Medium- and Heavy-Duty (MD/HD) Vehicle Charge Ready Bridge Funding and 2 Transportation Electrification Program $356 million Total Cost1 (in nominal dollars); approved Charge Ready “Bridge” Funding - $22 million Total Cost May 2018 (in 2014 dollars); approved December 2018 • 5-year program • Additional approved capital spend of $12 million; O&M of $10 million; bridge funding must be subtracted from • Approved capital spend of $242 million; O&M of $115 any authorized Charge Ready 2 funding million • Included in capital spend and rate base forecasts • Included in capital spend and rate base forecasts • SCE to install over 1,400 chargers, including 24% in multi- unit dwellings Charge Ready Pilot Charge Ready 2 – $760 million Total Cost1 (in 2018 Charge Ready Pilot - $22 million Total Cost1 (in 2014 dollars); filed June 2018 (pending CPUC approval) dollars); approved January 2016 • 4-year program, providing over 50,000 chargers • Approved capital spend of $12 million; O&M of $10 million • $561 million in capital spend; O&M of $199 million • Supports approximately 1,300 chargers • Not included in capital spend or rate base forecasts • Included in capital spend and rate base forecasts 1. Total Cost includes both O&M and capital spend May 1, 2020 28

SCE Energy Storage SCE 2020 Storage Portfolio CPUC Energy Storage Program Requirements: 350 *Up to • 1,325 MW target statewide contracted by 2020, and 300 80% of installed by 2024 (580 MW SCE share); ownership allowed 310 MW to be up to 290 MW for SCE 250 shifted between • SCE has procured over 690 MW of energy storage T&D 200 (includes 60 MW of utility owned storage), with over 600 MW of which being eligible to count towards CPUC targets MW *85 MW 150 185 excess may  SCE has exceeded the 580 MW target set by AB 2514 offset T&D 100 targets SCE Procurement to Meet System Reliability Needs: • Although the AB 2514 target has been met, SCE 50 85 anticipates energy storage being a key resource to meet 0 reliability objectives for years to come Transmission Distribution Customer • Most recently, the CPUC directed SCE to procure 1,185 MW of incremental system resource capacity to come Eligible storage to be included Currently above online between August 1, 2021 and August 1, 2023. SCE in 2020 Storage compliance targets Plan (Filing date 3/1/2020) launched its System Reliability RFO to meet this need, 2020 Cumulative *Storage that is permitted to where energy storage is an eligible resource Procurement Target count in different categories • SCE will begin submitting System Reliability RFO contracts due to flex counting rules for CPUC approval in April/May 2020 May 1, 2020 29

SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost4 (as of March 31, 2020) Date West of Devers1,2 $840 million $311 million 2021 Mesa Substation1 $646 million $249 million 2022 Alberhill System3 $486 million $445 million — 3 Riverside Transmission Reliability1 $584 million $573 million 2026 Eldorado-Lugo-Mohave Upgrade $246 million $150 million 2021 FERC Cost of Capital 11.2% ROE from January 1, 2018 to November 12, 2019: • ROE = Base (plus incentives) of 10.7% + CAISO Participation  Application for FERC Formula recovery mechanism post November 12, 2019 was filed April 11, 2019; settlement discussions ongoing • Requesting Base ROE of 11.97% + CAISO Participation + Incentive Projects  Requested 50 bp CAISO adder; approved, but application for rehearing requested by CPUC 1. CPUC approved 2. Morongo Transmission holds an option to invest up to $400 million, or half of the estimated cost of the transmission facilities only, at the in-service date. If the option is exercised, SCE’s rate base would be offset by that amount 3. In January 2020, SCE supplemented the existing CPUC record with additional analysis as it relates to the Project need which included alternative projects with lower costs as well as an update to the original project cost that is not reflected in the table above. SCE is unable to predict the timing of a final CPUC decision, the corresponding in-service date, and what the final project costs will be for the Alberhill project 4. Total Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval. SCE regularly evaluates the cost and schedule based on permitting processes, given that SCE continues to see delays in securing project approvals May 1, 2020 30

SCE Operational Excellence Defining Excellence Measuring Excellence Top Quartile • Employee and public safety • Safety metrics • Reliability • System performance and reliability (SAIDI and SAIFI) • Customer service • Customer satisfaction • Cost efficiency calculation based on Optimize internal voice-of-customer surveys • Capital productivity • O&M cost per customer • Purchased power cost • Reduce system average rate • Digitization growth with O&M / High performing, continuous purchased power cost reductions improvement culture Ongoing Operational Excellence Efforts May 1, 2020 31

Edison Energy Summary About Edison Energy Edison Energy’s Service Offerings • Edison Energy provides independent, expert advice and services to help large corporate and institutional clients better understand and navigate the choices and risks of managing energy. Edison Renewables & Supply enables decision-makers in organizations to deliver Solutions on their strategic, financial and sustainability goals Sustainability • Optimized energy management is delivered through advanced analytics of the customer’s energy portfolio in alignment with their goals and We Transform strategic objectives, leveraging Edison Energy’s the Business market experience and independence to provide customized advisory solutions of Managing Energy • Edison Energy serves many large-scale and multinational customers, including 12 of the Fortune 50 • Edison Energy continues to see strong and growing Demand client interest and is gaining insights from its work Installations for these customers that are increasingly relevant to Solutions Edison International’s clean energy, electrification and sustainability efforts May 1, 2020 32

2020 EIX Core Earnings Guidance 2020 Assumption Additional Notes CPUC Rate Base $26.8 billion Return on Equity (ROE) 10.30% 2020 Cost of Capital Final Decision Capital Structure 52% equity 2020 Cost of Capital Final Decision FERC Rate Base $6.6 billion ~20% of total 2020 rate base forecast Informed by MISO ruling; in line with CPUC 2020 Cost of ROE 10.30% Capital Final Decision Recorded capital structure; 2020 average estimated equity layer; includes charges such as the AB 1054 wildfire insurance Capital Structure 47% equity fund contributions, wildfire-related claims associated with the 2017/2018 wildfire events and the SONGS asset impairment Other Items Expect more volatility across and within categories as we Variances to Rate Base manage within the guidance range; categories include SCE Math ($0.55) – ($0.85) per share Variances, SB 901/AB 1054, EIX Parent and Other and Share Count Dilution 2020 Includes $0.2 billion of remaining 2019 ATM program and Equity Market $0.6 billion of additional 2020 equity needs; $91 million of Activities $0.8 billion of EIX equity issuances equity needs issued through March 31, 2020; evaluating market for timing of remaining equity issuance Based on the timing of 2020 equity Weighted Average issuances, the 2020 weighted average 2019 – 339.7 million shares Share Count share count is subject to change Wildfire Insurance Fund Expense Excluded from core guidance Amortization expense will be a non-core item EIX reaffirms 2020 Core EPS guidance range of $4.32 - $4.62 May 1, 2020 33

EIX Annual Dividends Per Share Sixteen Consecutive Years of Dividend Growth $2.551 $2.42 $2.45 $2.17 $1.92 $1.67 $1.42 $1.35 $1.28 $1.30 $1.22 $1.24 $1.26 $1.16 $1.08 $1.00 $0.80 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Expect dividend growth within target payout ratio of 45-55% of SCE’s earnings 1. 2020 dividend annualized based on December 12, 2019 declaration May 1, 2020 34

Appendix May 1, 2020 35

Commitment to Sustainability: Transparency Oversight Strategic Alignment • Board and Nom/Gov Committee: • ESG priority assessment conducted in 2018, with input from internal and external stakeholders, identifying 19 priority topics  Full board has responsibility for • Reaffirmed corporate strategy; many identified topics related to EIX’s clean strategic oversight of ESG issues energy vision  Nominating/Governance • ESG priority assessment used as input into corporate strategy updates, ESG Committee reviews ESG trends commitments/actions, and reporting and disclosure and ensures oversight of relevant issues by board and committees 19 Priority Topics Identified in ESG Assessment Transition to a clean energy Customers, communities, Operations and governance • CEO/Senior Management: future and employees  Top management committee, Climate change & GHG Safety & health Cyber & physical security including CEO and direct reports, emissions oversees ESG program Grid modernization & Affordability & access Environmental footprint innovation Governance, transparency & Reporting and Disclosure Local air quality Community development compliance • Annual sustainability report framed Renewable energy & Infrastructure reliability & Customer relations around corporate strategy and ESG distributed energy resources resilience materiality assessment • Piloted the EEI disclosure template in Service & product innovation Diversity & inclusion Public policy engagement 2017; updated annually Employee engagement & Transportation electrification Water use & management • Link to Edison’s sustainability disclosures: workforce development www.edison.com/sustainability Business Model Sustainability is central to EIX’s strategy to lead the transformation of the electric power industry May 1, 2020 36

Commitment to Sustainability: Strong Governance 7 of 11 Directors are Corporate Independent Board Key Areas of diverse in terms of Governance Committees Oversight 10 of 11 Directors are race/ethnicity, gender Independent (91%) Highlights and/or LGBTQ identification (64%) Independent Board Audit and Finance Strategy and Corporate Chair Goals Regular Independent Compensation and Employee, Contractor Director Executive Executive Personnel and Public Safety Average Age Average Tenure Sessions 60.5 Years 4.4 Years Director Orientation Nominating/Corporate Key Enterprise Risks, and Continuing Governance including Wildfires and Education Cybersecurity Experience, Skills & Attributes Annual Board and Safety and Operations Executive Committee Evaluations Compensation • Safety and Operations Director Retirement at Succession and Talent • Strategic Planning and Capital Markets Age 72 Planning • Risk Management Majority Voting in Diversity and Inclusion • Legal, Regulatory and Public Policy Director Elections • Cybersecurity and Technology 10% Threshold for Other ESG Issues and • Engineering and Science Shareholders to Call Trends Special Meetings • Workforce/Talent Management • Environmental and Sustainability Shareholders May Act by Written Consent • Utility Industry • Financial Expertise Annual Say on Pay Vote • Corporate Governance Proxy Access with • SCE/California Utility Customer Standard Terms May 1, 2020 37

SCE Historical Rate Base and Core Earnings ($ billions, except per share data) $32.6 $29.6 $27.8 $25.9 $24.6 2015 2016 2017 2018 2019 Core EPS $4.20 $4.22 $4.58 $4.42 $5.01 Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2015, rate base excludes the “rate-base offset” adjustment related to the 2015 GRC write-off of the regulatory asset for 2012-2014 incremental tax repairs. 2019 rate base excludes $0.3 billion of SCE’s fire risk mitigation capital expenditures in accordance with Assembly Bill 1054. May 1, 2020 38

SCE Historical Capital Expenditures ($ billions) $4.8 $4.4 $3.9 $3.8 $3.5 2015 2016 2017 2018 2019 May 1, 2020 39

Distribution Power Grid of the Future Current State Future State One-Way Electricity Flow Variable, Two-Way Electricity Flow • System designed to distribute electricity • Distribution system at the center of the from large central generating stations power grid • Voltage centrally monitored and • System designed to manage fluctuating maintained resources and customer demand • Increasing integration of distributed • Digital monitoring and control devices and energy resources advanced communications systems to • Limited situational awareness and improve safety and reliability, and integrate visualization tools for power grid DERs operators • Improved data management and power grid operations and cyber risk mitigation Renewable Generation Mandates • Integrated utility distribution with Cross-Subsidized Residential Solar distributed energy resources planning Limited Electric Vehicle Charging Maximize Distributed Resources and Infrastructure Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency May 1, 2020 40

SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) 2015 2016 2017 2018 2019 Residential 30,093 29,579 30,221 29,865 28,985 Commercial 42,396 42,189 42,514 42,369 41,602 Industrial 7,623 7,162 6,659 6,786 6,442 Public authorities 4,795 4,715 4,711 4,510 4,365 Agricultural and other 1,950 1,803 1,498 1,745 1,541 Subtotal 86,857 85,448 85,602 85,276 82,935 Resale 1,080 1,794 1,568 1,867 1,719 Total Kilowatt-Hour Sales 87,937 87,242 87,170 87,143 84,654 Customers Residential 4,393,150 4,417,340 4,447,706 4,477,508 4,499,464 Commercial 561,475 565,222 569,222 572,313 575,254 Industrial 10,811 10,445 10,274 10,078 9,525 Public authorities 46,436 46,133 46,410 46,059 46,012 Agricultural 21,306 21,233 21,045 20,872 20,687 Railroads and railways 130 133 137 131 132 Interdepartmental 22 22 24 24 24 Total Number of Customers 5,033,330 5,060,528 5,094,818 5,126,985 5,151,098 Number of New Connections 31,653 38,076 39,621 39,633 39,308 Area Peak Demand (MW) 23,079 23,091 23,508 23,766 22,009 Note: See Edison International Financial and Statistical Reports for further information. May 1, 2020 41

SCE Bundled Revenue Requirement 2020 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 4,351 8.0 Fuel & Purchased Power (46%) Distribution – poles, wires, substations, service centers 3,698 6.8 Distribution (39%) Generation – owned generation investment and O&M 594 1.1 Generation (6%) Transmission (7%) Transmission – greater than 220kV 683 1.3 Other (2%) Other – CPUC and legislative public purpose programs, 197 0.3 system reliability investments, nuclear decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $9,523 ÷ Bundled kWh (millions) 54,528 = Bundled Systemwide Average Rate (¢/kWh) 17.5¢ SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 16.0 15.9 17.5 Note: Rates in effect as of April 13, 2020. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services from SCE. May 1, 2020 42

System Average Rate Historical Growth ¢/kWh Comparative System Rates reduced due to the implementation of Average Rates1 1) the SONGS Revised Settlement, including % Delta to SCE CAGR NEIL insurance benefits, 2) lower fuel & SCE 17.5¢ -- 30-yr 20-yr 10-yr purchased power costs, and 3) a lower 2015 (‘90-’20) (‘00-’20) (‘10-’20) GRC revenue requirement that includes 23% SCE System Average Rate 2.1% 3.0% 2.0% PG&E 21.6¢ flow-through tax benefits Los Angeles Area Inflation 2.5% 2.5% 2.1% SDG&E 24.0¢ 37% Rates include California Climate Credit 22.0¢ Higher gas price forecast post-Katrina Delay in 2012 GRC leads leads to higher rates with subsequent to shorter ramp-up of 19.9¢ 20.0¢ Energy Crisis and refund of over collection rate increase return to normal 18.0¢ 17.5¢ 16.0¢ 14.0¢ 12.0¢ 10.0¢ 8.0¢ 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 SCE’s system average rate has grown less than inflation over the last 30 years 1. SCE Advice 3972-E-A effective April 13, PG&E Advice 5769-E effective March 1, SDG&E Advice 3514-E effective April 1 May 1, 2020 43

SCE Rates and Bills Comparison 2019 Average Residential Bills ($ per Month) KeyKey Factors Factors $126 26% • Average monthly residential bills are lower Lower than the national average as higher rate $93 levels are more than offset by lower usage • SCE’s residential customer usage is lower than the national average due to mild climate and higher energy efficiency appliance and building standards • SCE’s residential rates are above national US Average SCE average due, in part, to a cleaner fuel mix, 2019 Average Residential Rates high cost of living, and lower system load (¢/kWh) factor 24% 16.2 Higher 13.1 US Average SCE SCE’s average residential rates are above national average, but residential bills are below national average due to lower usage Source: EIA's Form 861M (formerly Form 826) Data Monthly Electric Utility Sales and Revenue Data 2019. https://www.eia.gov/electricity/data/eia861m/index.html. May 1, 2020 44

Community Choice Aggregator (CCA) Overview • Assembly Bill 1171 permits cities and counties, and Joint Powers Authorities (JPAs) to act as CCAs to purchase and sell electricity on behalf of the utility customers within their jurisdiction • An Order Instituting Rulemaking (OIR R.17-06-026) was opened on June 29, 2017 to review, revise, and consider alternatives to the “Power Charge Indifference Adjustment” or PCIA  The PCIA allocates a proportional share of above-market costs of SCE’s energy procurement portfolio to departing load customers to ensure remaining bundled service customers are indifferent  October 11, 2018 Commission decision changes PCIA methodology and has substantially addressed the historical subsidy to departing load that materialized when renewables market prices declined over the past 4 years o Decision also established a Phase 2, which is addressing utility portfolio optimization, PCIA “pre-payment” options for entities and individual departing load customers, and implementation of the Investor-Owned Utility Community Choice Aggregator “true-up” process for Resource Adequacy (RA) and Renewable (IOU) (CCA) Energy Credits (RECs) costs o A Phase 2 final decision on the benchmark and true-up process was approved on October 10, 2019, with the other Phase 2 activities to continue into 2020 • On February 8, 2018, the Commission approved Resolution E-4907 requiring CCAs to demonstrate compliance with annual Resource Adequacy (RA) requirements prior to commencing operations • Existing Direct Access and CCA load was 26% of SCE’s total load at the end of 2019 Approximately 34% of SCE’s bundled service load could be part of a CCA or Direct Access by the end of 2020 May 1, 2020 45

Residential Rate Design OIR Decision • CPUC Order Instituting Ratemaking R. 12-06-013 comprehensively reviewed residential rate structure, including a future transition to Time of Use (TOU) rates  In March 2018, SCE began to migrate 400,000 residential customers to TOU rate structures  Remaining eligible residential customers to be migrated between October 2020 and end of Q1 2022 Non-CARE1, Unbundled Rates January 2014 January 2020 Fixed Charge: Fixed Charge: (Single-Family) $0.94/month (Single-Family) $0.94/month (Multi-Family) $0.73/month (Multi-Family) $0.73/month Minimum Bill: Minimum Bill: $1.79/month $10.52/month 2.19 1.20 2.10 2.30 1.25 1.00 1.00 (3%) (11%) (16%) (22%) (37%) (51% of system usage) (60% of system usage) Tiered Rate Level Tiered Rate Level (Relative to Tier 1 Rate) (Relative to Tier 1 Rate) Tier 1: Tier 2: Tier 3: Tier 4: Tier 1: Tier 2: SUE: 100% 101-130% 131-200% >200% 100% 101-400% >400% Usage Level (Rate Ratio / % of Baseline) Usage Level (Rate Ratio / % of Baseline) 1. SCE’s California Alternate Rates for Energy (CARE) program is an income-qualifying program that reduces energy bills for eligible customers by about 33% May 1, 2020 46

Impacts of Abundant Solar Energy (Duck Curve) New Time-of-Use (TOU) Periods • On March 1, 2019, SCE changed its basic TOU pricing period definition for the first time in over 30 years • Abundant mid-day renewable energy lowers prices from 8am-4pm (October - June) • Highest cost period is now 4pm-9pm, all-days1 Season Previous New On-Peak Summer Weekdays: 12-6pm Weekdays: 4-9pm Mid-Peak Summer Weekdays: 8am-12pm; 6pm-11pm Weekends: 4-9pm Winter Weekdays: 8am-9pm Weekdays and Weekends: 4-9pm Off-Peak Summer Weekdays: 11pm-8am Weekdays and Weekends: All except Weekends: All 4-9pm Winter Weekdays: 9pm-8am Weekdays and Weekends: 9pm-8am Weekends: All Super Off-Peak Winter N/A Weekdays and Weekends: 8am-4pm 1. TOU pricing periods defined for non-residential customers per CPUC Decision D.18-07-006. Similar residential TOU definitions were filed by SCE in A.17-12-012 May 1, 2020 47

SCE Net Energy Metering Monthly Residential Solar SCE Net Metering Statistics (March 2020) Installations and MW Installed • 351,832 combined residential and non-residential projects – 2,922 MW installed 7000 40 • 99.9 % solar projects • 344,104 residential (7.6% of all residential customers) – 1,896 MW 35 6000 • 7,728 non-residential – 1026 MW • Approximately 5,102,029 MWh/year generated 30 5000 Key Dates 25 July 1, 2017 • 4000 Official start of NEM successor tariff; customers are subject to:  Mandatory TOU rate MW Installed 20  Non-bypassable charges 3000  Application fees 15 July 31, 2017 • Residential customers who meet this deadline are grandfathered for 2000 current TOU periods for maximum of 5 years (10 for non-residential) Number of Solar Residential Solar Residential of Number Installations 10 September 9, 2017 • Smart Inverters required on all solar installations 1000 5 July 25, 2018 • Smart Inverters with Reactive Power Priority required on all solar installations 0 0 2014 2015 2016 2017 2018 2019 2020 Near Term Outlook • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 Installations MW rate structure has helped reduce the per customer cost shift; further efforts to reduce the shift through new TOU pricing periods • Commission to revisit NEM Successor Tariff by July 2020 to evaluate the existing NEM tariffs and consider the development and adoption of successor tariffs May 1, 2020 48

First Quarter Earnings Summary Key SCE EPS Drivers4 Q1 Q1 Variance 2020 2019 Higher revenue $ 0.42 - CPUC revenue 0.37 Basic Earnings Per Share (EPS)1 - FERC revenue 0.05 SCE $ 0.60 $ 0.90 $ (0.30) Higher O&M (0.28) Higher depreciation (0.01) EIX Parent & Other (0.10) (0.05) (0.05) Higher interest expense (0.03) Basic EPS $ 0.50 $ 0.85 $ (0.35) Income taxes 0.02 Less: Non-core Items Results prior to impact from share dilution $ 0.12 Impact from share dilution (0.08) 2,3 SCE $ (0.12) $ 0.22 $ (0.34) Total core drivers $ 0.04 2,3 EIX Parent & Other3 (0.01) — (0.01) Non-core items (0.34) Total $ (0.30) Total Non-core $ (0.13) $ 0.22 $ (0.35) Key EIX EPS Drivers4 Core Earnings Per Share (EPS) EIX parent and other — Higher interest expense and corporate expenses $ (0.05) SCE $ 0.72 $ 0.68 $ 0.04 Impact from share dilution 0.01 EIX Parent & Other (0.09) (0.05) (0.04) Total core drivers $ (0.04) Non-core items3 (0.01) Core EPS $ 0.63 $ 0.63 $ — Total $ (0.05) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Amortization of Wildfire Insurance Fund expenses, impact from changes in the allocation of deferred tax re-measurement between customers and shareholders and gain from sale of San Onofre nuclear fuel in 2019 3. Re-measurement of uncertain tax positions related to the 2010 – 2012 California state tax filings 4. 2020 EPS drivers are reported based on prior year weighted-average share count of 326 million (2020 YTD weighted-average shares outstanding is 363 million) Note: Diluted earnings were $0.50 and $0.85 per share for the three months ended March 31, 2020 and 2019, respectively. May 1, 2020 49

Pension Well-Funded at Year End 2019 Postretirement Benefits Other Than Pensions Pension Benefits are 96% Funded (PBOP) are 119% Funded with Resilient Asset with Resilient Asset Allocation1 Allocation2 Total Plan Assets: $3.8 billion Represented PBOP Trust: $1.4 billion Global Equity 10% Alternatives/ Opportunistic 5% U.S. Equity 23% Fixed Income 85% Fixed Income 48% International Non-Represented PBOP Trust: $1.1 billion Equity 17% Fixed Alternatives/ Income 29% Opportunistic Global Equity 12% 58% Alternatives/ Opportunistic 13% Regulatory balancing account in place for variances in benefit plan funding costs 1. Information relates to qualified plans 2. PBOP is comprised of multiple trusts that vary in funding levels from approximately 80% to fully funded May 1, 2020 50

Strong EIX and SCE Liquidity Profiles ($ billions) Liquidity Profile1 Financing Activities • Targeting EIX long-term FFO/debt ratio of 15-17% $6.4 • EIX financing activities:  $800 million 364-day term loan to enhance financial flexibility drawn on March 25th $4.0  $400 million senior note offering closed April 3rd  $400 million senior notes repaid on April 15th  No long-term debt maturities remain in 2020 or 2021 $2.3 • SCE financing activities:  $2.3 billion of first mortgage bonds issued across three offerings in the YTD period  $800 million 364-day revolver and $475 million 364- day term loan to fund AB 1054 wildfire mitigation 2 EIX SCE Total capital spending  st Cash on hand $373 million tax-exempt bonds purchased on April 1 Unused 1-Year Credit Facility (AB 1054) (plan to re-market subject to market conditions) Unused 5-Year Credit Facility (General)  No long-term debt maturities at SCE for remainder of 2020; $1 billion of long-term debt maturities in 2021 EIX and SCE have taken proactive steps to enhance liquidity YTD; EIX term loan increased financing flexibility for remaining equity planned for 2020 1. As of April 15, 2020 2. Expected to be repaid with proceeds from securitization of dedicated-rate component Note: Totals may not foot due to rounding. May 1, 2020 51

SCE Annual Results of Operations ($ millions) • Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards 2019 2018 Earnings Cost-Recovery Total Earnings Cost-Recovery Total Activities Activities Consolidated Activities Activities Consolidated Operating revenue $6,678 $5,628 $12,306 $6,560 $6,051 $12,611 Purchased power and fuel — 4,839 4,839 — 5,406 5,406 Operation and maintenance 2,073 863 2,936 1,972 730 2,702 Wildfire-related claims, net of recoveries 255 — 255 2,669 — 2,669 Wildfire insurance fund expense 152 — 152 Depreciation and amortization 1,727 1 1,728 1,867 — 1,867 Property and other taxes 396 — 396 392 — 392 Impairment and other charges 159 — 159 (12) — (12) Other operating income (4) — (4) (7) — (7) Total operating expenses 4,758 5,703 10,461 6,881 6,136 13,017 Operating (loss) income 1,920 (75) 1,845 (321) (85) (406) Interest expense (738) (1) (739) (671) (2) (673) Other income and expenses 119 76 195 107 87 194 (Loss) income before income taxes 1,301 — 1,301 (885) — (885) Income tax (benefit) expense (229) — (229) (696) — (696) Net (loss) income 1,530 — 1,530 (189) — (189) Preferred and preference stock dividend 121 — 121 121 — 121 requirements Net (loss) income available for common stock $1,409 — $1,409 ($310) — ($310) Less: Non-core items (293) (1,750) Core Earnings $1,702 $1,440 Note: See Use of Non-GAAP Financial Measures. May 1, 2020 52

Earnings Per Share Non-GAAP Reconciliations Reconciliation of EIX Basic Earnings Per Share Guidance to EIX Core Earnings Per Share Guidance EPS Attributable to Edison International 2020 Low High Basic EIX EPS $4.19 $4.49 Total Non-Core Items1 (0.13) (0.13) Core EIX EPS $4.32 $4.62 1. EPS is calculated on the assumed weighted-average share count for 2020 of 369.5 million which was originally provided on February 27, 2020. May 1, 2020 53

Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q1 Q1 Earnings Attributable to Edison International 2020 2019 SCE $219 $293 EIX Parent & Other (36) (15) Basic Earnings $183 $278 Non-Core Items SCE1,2,3 ($42) 72 EIX Parent & Other3 (3) — Total Non-Core ($45) $72 Core Earnings SCE $261 $221 EIX Parent & Other (33) (15) Core Earnings $228 $206 1. Includes amortization of Wildfire Insurance Fund expenses of $84 million ($60 million after-tax) for the quarter ending March 31, 2020 2. Includes income tax benefits of $69 million recorded in 2019 related to changes in the allocation of deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019 to provide guidance on the implementation of Tax Reform 3. Includes income tax benefit of $18 million and income tax expense of $3 million for SCE and Edison International Parent and Other, respectively, recorded in 2020 due to re- measurement of uncertain tax positions related to the 2010 – 2012 California state tax filings currently under audit May 1, 2020 54

EIX Core EPS Non-GAAP Reconciliations Reconciliation of Edison International Basic Earnings Per Share to Edison International Core Earnings Per Share Earnings Per Share Attributable to Edison International 2019 2018 2017 Basic EPS 3.78 ($1.30) $1.73 Non-Core Items (*) SCE Impairment and other 2018 GRC decision – Impairment of utility property, plant and equipment (0.38) — — Implementation of Revised San Onofre Settlement Agreement 0.03 0.03 (1.38) Wildfire-related claims, net of recoveries (0.48) (5.60) — Amortization of Wildfire Insurance Fund expenses (0.34) — — Re-measurement of deferred taxes as a result of Tax Reform 0.27 — (0.10) Settlement of 1994 – 2006 California tax audits — 0.20 — Edison International Parent and Other Edison Energy Group’s goodwill impairment (0.06) — — Sale of SoCore Energy and other — (0.14) 0.04 Settlement of 1994 – 2006 California tax audits — (0.04) — Re-measurement of deferred taxes as a result of Tax Reform — — (1.33) Discontinued operations Settlement of 1994 – 2006 California tax audits — 0.10 — Impact of share dilution (*) 0.04 — — Less: Total Non-Core Items (0.92) (5.45) (2.77) Core EPS $4.70 $4.15 $4.50 (*) 2019 EPS drivers are reported at a consistent share count of 325.8 million (weighted-average shares outstanding is 359.7 million and 339.7 million for fourth quarter and full year 2019, respectively) Note: See Use of Non-GAAP Financial Measures. May 1, 2020 55

Use of Non-GAAP Financial Measures Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) 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 (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) 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. A reconciliation of Non-GAAP information to GAAP information is included either on the slide where the information appears or on another slide referenced in this presentation. EIX Investor Relations Contact Sam Ramraj, Vice President (626) 302-2540 sam.ramraj@edisonintl.com Allison Bahen, Principal Manager (626) 302-5493 allison.bahen@edisonintl.com May 1, 2020 56