Exhibit 99.1 Business Update February 28, 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 and costs incurred to implement SCE's new customer service system; • ability of SCE to implement its WMP, 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 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 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 CPUC, the FERC, the NRC 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; • 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 CCAs and Electric Service Providers; • 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 CAISO'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. February 28, 2020 1
Table of Contents Updated (U) or New (N) from October 2019 Page Business Update EIX Shareholder Value 3 U EIX Summary, SCE Long-Term Growth Drivers 4-5 U SCE Capital Expenditures and Rate Base Forecast 6-8 U Commitment to Sustainability: California Mandates, SCE’s Pathway 2045, SCE Investments 9-11 N,U Wildfire Risk and Mitigation Summaries, 2019 Wildfire Legislation Update, AB 1054 Wildfire Fund 12-15 N,U SCE Key Regulatory Proceedings 16 U SCE 2021 General Rate Case Overview and Timeline 17-18 U SCE CPUC 2020 Cost of Capital 19 N SCE Distribution and Transmission Capital Expenditure Detail 20-23 U Operational Excellence 24 Edison Energy Group Summary 25 U 2020 EIX Core Earnings Guidance 26-27 N Annual Dividends Per Share 28 U Appendix Commitment to Sustainability: Transparency, Strong Corporate Governance 30-31 N SCE Regulatory Framework 32 SCE Historical Rate Base and Capital Expenditures 33-34 U Power Grid of the Future 35 SCE Customer Demand Trends, Bundled Revenue Requirement, SAR Historical Growth, Rate and Bills Comparison 36-39 U SCE CCA Overview, Residential Rate Reform and Other 40-43 U Fourth Quarter and Full Year 2019 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 44-51 N,U February 28, 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 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 February 28, 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 February 28, 2020 4
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, requesting that mitigate wildfire risk and bolster fire $582 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 720 MW existing CPUC proceedings procured Energy Storage • 2020-2023 – $69 million of capital spending forecasted; 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 $750 million of capital spending resources requested in 2021 GRC application • 2025 – CPUC target to complete grid modernization but may take longer February 28, 2020 5
SCE Capital Expenditure Forecast ($ 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, ~$1.6 billion of wildfire mitigation-related spend shall not earn an equity return. See “SCE Wildfire Capital Forecast” slide for further information on wildfire-related capital spend 2. Approval percentage for the 2018 GRC excludes Grid Modernization and project approvals that were deferred to the next General Rate Case for timing reasons 3. The low end of the range for 2021-2023 reflects a 10% reduction on the total capital forecast using management judgment based on historical experience of previously authorized amounts and potential for permitting delays and other operational considerations. The low end of the range for 2020 reflects a 10% reduction applied only to FERC capital spending and non-GRC programs February 28, 2020 6
SCE Rate Base Forecast ($ 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 ~$1.6 billion of SCE’s fire risk mitigation capital expenditures in accordance with Assembly Bill 1054. CPUC also excludes the “rate-base offset” adjustment related to the 2015 GRC write-off of the regulatory asset for 2012-2014 incremental tax repairs and rate base associated with projects or programs that have not yet been approved, except for GS&RP spend incurred before August 1, 2019. February 28, 2020 7
SCE Wildfire Capital Forecast ($ 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. February 28, 2020 8
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. February 28, 2020 9
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 February 28, 2020 10
Commitment to Sustainability: SCE Investments Clean Energy Efficient Electrification • Reduced GHG emissions from • Approved and proposed delivered power by 42% since 2005 investments of over $1 billion to expand electrification across • 46% carbon-free power delivered Southern California’s economy in 2018, which had only half the GHG emissions per unit of • Award-winning Charge Ready electricity of the US average pilot and bridge funding program are successfully Targeting carbon neutrality by supporting the installation of 2045 in line with state goals approximately 2,800 EV charge • #1 utility nationally for energy ports for light-duty vehicles storage in 2017 and 2018* • Charge Ready Transport, the • Named national leader in solar largest truck and transit charging for past decade* initiative in the nation, will install infrastructure for at least 870 • Award-winning hybrid enhanced customer sites by 2024 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. February 28, 2020 11
2019 Wildfire Mitigation Actions Inspections: completed overhead inspections of 100% of T&D assets in HFRA; 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 Met or exceeded targets in 54 of the 58 programs (our covered conductor, HD cameras and weather station programs all exceeded targets) 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 February 28, 2020 12
Mitigating Catastrophic Wildfire Risk 2019 Actuals 2020-22 Wildfire Mitigation Plan Covered Conductor: 372 circuit miles 4,000 additional circuit miles by Jan 1, 2023 Infrastructure completed 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: All HFRA distribution and Risk-informed ground & aerial inspection program transmission structures inspected covering ~50% of HFRA structures annually Vegetation Management: expand line Continue expanded line clearances; focus on Enhanced clearances to 12 feet; removed ~5,900 hazard hazard tree assessments and timely removal; Operational tree removals (below target of 7,500); and expand brush clearing at base of poles to 200,000- Practices clear brush at base of >100,000 poles 300,000 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: 357 installed 375-475 weather stations per year Situational HD Cameras: 91 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 February 28, 2020 13
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 issues5) 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 February 28, 2020 14
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) February 28, 2020 15
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 intervenor testimony to be filed in April/May 2020; 2024 year expected to be added in late 2020 Application for Approval of Requesting to a waiver to SCE’s authorized Awaiting proposed decision Waiver of Capital Structure capital structure calculation for wildfire Rule (A. 19-02-017) liabilities reserve Grid Safety and Resiliency Requesting $582 million of total cost for Settlement filed for in July 2019; awaiting CPUC approval Program (GSRP) 2018-2020; focused on grid hardening and (A. 18-09-002) enhanced vegetation management Application for Recovery of Requesting recovery $505 million in insurance Application filed July 31, 2019; Scoping Memo issued in December 2019; WEMA costs (A. 19-07-020) premiums and other associated costs tracked Proposed Decision expected in August 2020 in the WEMA Application for Recovery of Requesting recovery $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 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 Replacement rate filed on October 27, 2017 and a settlement covering 1/1/18 through 11/11/19 was approved by FERC; New replacement rate became effective, subject to refund, on 11/12/19; partial settlement reduced request to 11.97%; settlement discussions continuing February 28, 2020 16
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 – The Assigned Commissioner and ALJs in the 2021 GRC will work with parties to allow time in the schedule for SCE to propose a revenue requirement for 2024 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 February 28, 2020 17
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. February 28, 2020 18
CPUC 2020 Cost of Capital CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate 6.0 Moving Average (10/1/19 – 2/24/20) = 3.66% 100 basis point +/- Deadband 5.5 5.0 Starting Value – 4.50% 4.5 Rate (%) 4.0 3.5 3.0 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 of each year – Weighted Average Cost of Capital 7.68% 4.50% at September 2019 February 28, 2020 19
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. February 28, 2020 20
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 at least 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 February 28, 2020 21
SCE Energy Storage CPUC Energy Storage Program Requirements: SCE 2018 Storage Portfolio • 1,325 MW target statewide by 2024 (580 MW SCE share); 350 ownership allowed up to 290 MW for SCE 300 *Up to • SCE has flexibility to transfer across 3 approved categories 310 80% of 250 MW to be SCE Procurement Activities to Meet CPUC Requirements: shifted between • SCE has procured over 720 MW of energy storage 200 T&D (includes 60 MW of utility owned storage), ~600 MW of MW *85 MW 150 185 which is eligible to count towards CPUC targets excess may offset T&D SCE has exceeded the 580 MW target set by AB 2514 100 targets • SCE will file its 2020 Energy Storage and Investment Plan 50 85 (ESP&IP) on March 2, 2020 0 SCE Procurement to Meet System Reliability Needs: Transmission Distribution Customer • CPUC has directed SCE to procure 1,185 MW of Eligible storage to be included incremental system resource capacity to come online Currently above in 2020 Storage compliance targets between August 1, 2021 and August 1, 2023. SCE has Plan (Filing date 3/1/2020) 2020 Cumulative begun the procurement process *Storage that is permitted to Procurement Target count in different categories • SCE concurrently launched a separate track to procure due to flex counting rules utility owned energy storage systems February 28, 2020 22
SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost5 (as of December 31, 2019) Date West of Devers1,2 $840 million $356 million 2021 Mesa Substation1 $646 million $273 million 2022 Alberhill System3 $486 million $445 million — 3 Riverside Transmission Reliability4 $451 million $440 million 2024 Eldorado-Lugo-Mohave Upgrade $246 million $153 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. While the Riverside Transmission Reliability Project total cost is currently $451 million, the CPUC issued a proposed decision, which if adopted, would increase the project cost to $584 million 5. 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 February 28, 2020 23
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 February 28, 2020 24
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 February 28, 2020 25
2020 EIX Core Earnings Guidance 2020 Core Earnings Per Share Guidance – Building from SCE Rate Base on 2019 Weighted Average Shares $0.20 ($0.10) $5.17 ($0.41) • Interest related to • Financial, ($0.39) debt issued for operating and fund contribution: • Operating $4.47 other: expenses and ($0.09) • $0.32 other: Previously issued • Additional • Energy efficiency: ($0.14) 2019 shares: disallowed ($0.30) $0.02 • Interest expense: executive • • Incremental ($0.27) 2020 Equity Plan: compensation: ($0.09) wildfire ($0.01) mitigation costs not in Regulatory Assets: ($0.14) SCE 2020 EPS from SCE SB 901/AB 1054 EIX Parent Share Count Dilution EIX 2020 Core EPS Rate Base Forecast Variances Impacts & Other Midpoint Guidance EIX 2020 Core EPS guidance range of $4.32 - $4.62 Note: See Earnings Per Share Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. All tax-affected information on this slide is based on our current combined statutory tax rate of approximately 28%. Totals may not foot due to rounding. February 28, 2020 26
2020 EIX Core Earnings Guidance (cont.) Key Assumptions 2020 Assumption Additional Notes Total Rate Base $33.4 billion Based on rate base forecast 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 Capital Final ROE 10.30% Decision Recorded capital structure; 2020 average estimated equity layer; includes charges such as the AB 1054 wildfire insurance fund contributions, wildfire- Capital Structure 47% equity related claims associated with the 2017/2018 wildfire events and the SONGS asset impairment Other Items Equity Market $0.8 billion of EIX equity Includes $0.2 billion of remaining 2019 ATM program and $0.6 billion of Activities issuances additional 2020 equity needs Weighted Average 2019 – 339.7 million shares Share Count 2020 – 369.5 million shares Wildfire Insurance Excluded from core Fund Expense guidance Amortization expense will be a non-core item February 28, 2020 27
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 February 28, 2020 28
Appendix February 28, 2020 29
Commitment to Sustainability: Transparency Oversight Strategic Alignment • Board and Nom/Gov Committee: • ESG materiality 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 materiality assessment used as input into corporate strategy updates, Committee reviews ESG trends ESG commitments/actions, and reporting and disclosure and ensures oversight of relevant issues by board and committees 19 Priority Topics Identified in ESG Materiality Assessment • CEO/Senior Management: Transition to a clean energy Customers, communities, Operations and governance future and employees Top management committee, including CEO and direct reports, Business model Affordability & access Cyber & physical security oversees ESG program Climate change & GHG Community development Environmental footprint emissions Grid modernization & Governance, transparency & Reporting and Disclosure Customer relations innovation compliance • Annual sustainability report framed Infrastructure reliability & Local air quality Diversity & inclusion around corporate strategy and ESG resilience materiality assessment Renewable energy & Employee engagement & Public policy engagement • Piloted the EEI disclosure template in distributed energy resources workforce development 2017; updated annually • Link to Edison’s sustainability disclosures: Service & product innovation Safety & health Water use & management www.edison.com/sustainability Transportation electrification Sustainability is central to EIX’s strategy to lead the transformation of the electric power industry February 28, 2020 30
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 February 28, 2020 31
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 three-year rate cycle • Separate cost of capital mechanism February 28, 2020 32
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 $0.3 billion of SCE’s fire risk mitigation capital expenditures in accordance with Assembly Bill 1054. February 28, 2020 33
SCE Historical Capital Expenditures ($ billions) $4.8 $4.4 $3.9 $3.8 $3.5 2015 2016 2017 2018 2019 February 28, 2020 34
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 February 28, 2020 35
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. February 28, 2020 36
SCE Bundled Revenue Requirement 2020 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 4,503 7.6 Fuel & Purchased Power (54%) Distribution – poles, wires, substations, service centers 3,920 6.6 Distribution (40%) Generation – owned generation investment and O&M 737 1.2 Generation (8%) Transmission (7%) Transmission – greater than 220kV 731 1.3 Other (-9%) Other – CPUC and legislative public purpose programs, (146) (0.3) system reliability investments, nuclear decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $9,745 ÷ Bundled kWh (millions) 59,396 = Bundled Systemwide Average Rate (¢/kWh) 16.4¢ SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 16.0 15.9 16.4 Note: Rates in effect as of January 1, 2020. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services from SCE. February 28, 2020 37
System Average Rate Historical Growth ¢/kWh Comparative System Rates reduced due to the implementation of Average Rates 1) the SONGS Revised Settlement, including % Delta to SCE CAGR NEIL insurance benefits, 2) lower fuel & SCE 16.4¢ -- 30-yr 20-yr 10-yr purchased power costs, and 3) a lower 2015 (‘90-’20) (‘00-’20) (‘10-’20) GRC revenue requirement that includes 1 31% SCE System Average Rate 1.8% 2.7% 1.4% PG&E 21.5¢ flow-through tax benefits Los Angeles Area Inflation 2.5% 2.5% 2.1% SDG&E 24.1¢1 47% Rates include California Climate Credit 22.0¢ Higher gas price forecast post-Katrina Delay in 2012 GRC leads leads to higher rates with subsequent to shorter ramp-up of 19.9¢ 20.0¢ Energy Crisis and refund of over collection rate increase return to normal 18.0¢ 16.4¢ 16.0¢ 14.0¢ 12.0¢ 10.0¢ 8.0¢ 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 SCE’s system average rate has grown less than inflation over the last 30 years 1. PG&E Advice 5727-E effective January 1, SDG&E Advice 3487-E effective January 1 February 28, 2020 38
SCE Rates and Bills Comparison 2018-19 Average Residential Bills ($ per Month) KeyKey Factors Factors $127 28% • Average monthly residential bills are lower Lower than the national average as higher rate $92 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 US Average SCE • SCE’s residential rates are above national average due, in part, to a cleaner fuel mix, 2018-19 Average Residential Rates high cost of living, and lower system load (¢/kWh) factor 27% 16.4 ₵ Higher 12.9 ₵ 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 for 12-Months Ending October 2019. https://www.eia.gov/electricity/data/eia861m/index.html. February 28, 2020 39
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 February 28, 2020 40
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 Awaiting decision on residential fixed charge proposal, estimated Q2 2020. 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% February 28, 2020 41
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 February 28, 2020 42
SCE Net Energy Metering Monthly Residential Solar SCE Net Metering Statistics (12/19) Installations and MW Installed • 339,730 combined residential and non-residential projects – 2,830 MW installed • 99.8 % solar projects 7000 40 • 332,180 residential (7.4% of all residential customers) – 1,825 MW • 7,550 non-residential – 1005 MW 35 • Approximately 4,944,708 MWh/year generated 6000 30 Key Dates 5000 July 1, 2017 • Official start of NEM successor tariff; customers are subject to: 25 Mandatory TOU rate 4000 Non-bypassable charges MW Installed 20 Application fees 3000 July 31, 2017 15 • Residential customers who meet this deadline are grandfathered for current TOU periods for maximum of 5 years (10 for non-residential) 2000 September 9, 2017 Number of Solar Residential Solar Residential of Number Installations 10 • Smart Inverters required on all solar installations July 25, 2018 1000 5 • Smart Inverters with Reactive Power Priority required on all solar installations Near Term Outlook 0 0 • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 2013 2014 2015 2016 2017 2018 2019 rate structure has helped reduce the per customer cost shift; further efforts to reduce the shift through new TOU pricing periods Installations MW • Commission to revisit NEM Successor Tariff by July 2020 to evaluate the existing NEM tariffs and consider the development and adoption of successor tariffs February 28, 2020 43 CONFIDENTIAL - DRAFT
Fourth Quarter Earnings Summary Key SCE EPS Drivers3 Q4 Q4 Variance 2019 2018 Higher revenue4 $ 0.32 - CPUC revenue 0.19 Basic Earnings Per Share (EPS)1 - FERC and other operating revenue 0.13 SCE $ 0.54 $ (4.38) $ 4.92 Higher O&M (0.03) Wildfire-related self-insured retention (0.05) EIX Parent & Other (0.14) (0.11) (0.03) Lower depreciation 0.03 Discontinued Operations2 — 0.10 (0.10) Higher net financing costs (0.03) Income taxes4 (0.07) Basic EPS $ 0.40 $ (4.39) $ 4.79 Other — Less: Non-core Items - Property and other taxes (0.01) - Other operating income (0.01) SCE2 $ (0.54) $ (5.39) $ 4.85 - Other income and expenses 0.02 EIX Parent & Other2 (0.05) (0.04) (0.01) Results prior to impact from share dilution $ 0.17 Impact from share dilution (0.10) Discontinued Operations2 — 0.10 (0.10) Total core drivers $ 0.07 Non-core items2 4.85 Total Non-core $ (0.59) $ (5.33) $ 4.74 Total $ 4.92 Core Earnings Per Share (EPS) Key EIX EPS Drivers3 EIX parent and other — Higher interest expense and SCE $ 1.08 $ 1.01 $ 0.07 corporate expenses $ (0.07) EEG — 2018 goodwill impairment and other 0.05 EIX Parent & Other (0.09) (0.07) (0.02) Total core drivers $ (0.02) Core EPS $ 0.99 $ 0.94 $ 0.05 Non-core items2 (0.01) Total $ (0.03) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. See EIX Core EPS non-GAAP reconciliation in Appendix 3. 2019 EPS drivers are reported at a consistent share count of 325.8 million (2019 QTD weighted-average shares outstanding is 359.7 million) 4. Includes $(0.11) of tax expenses charged to customers Note: Diluted earnings were $0.40 and ($4.39) per share for the three months ended December 31, 2019 and 2018, respectively. February 28, 2020 44
Full-Year 2019 Earnings Summary Key SCE EPS Drivers3 2019 2018 Variance Test Year 2018 GRC true-up4 $ 0.20 Higher revenue5 0.87 Basic Earnings Per Share (EPS)1 - CPUC revenue 0.51 - 2018 FERC Formula Rate settlement6 0.13 SCE $ 4.15 $ (0.95) $ 5.10 - FERC and other operating revenue 0.23 Higher O&M (0.29) EIX Parent & Other (0.37) (0.45) 0.08 Wildfire-related self-insured retention (0.05) Lower depreciation 0.07 Discontinued Operations2 — 0.10 (0.10) Higher net financing costs (0.15) Basic EPS $ 3.78 $ (1.30) $ 5.08 Income taxes5,6 0.14 Other 0.01 Less: Non-core Items Property and other taxes (0.02) Other operating income (0.01) SCE2 $ (0.86) $ (5.37) $ 4.51 Other income and expenses 0.04 Results prior to impact from share dilution $ 0.80 EIX Parent & Other2 (0.06) (0.18) 0.12 Impact from share dilution (0.21) Total core drivers $ 0.59 2 Discontinued Operations — 0.10 (0.10) Non-core items2 4.51 Total $ 5.10 Total Non-core $ (0.92) $ (5.45) $ 4.53 Key EIX EPS Drivers3 Core Earnings Per Share (EPS) EIX parent and other — Higher interest expense and corporate expenses $ (0.13) SCE $ 5.01 $ 4.42 $ 0.59 EEG — 2018 goodwill impairment, lower corporate expenses and lower losses at the competitive business 0.08 EIX Parent & Other (0.31) (0.27) (0.04) Impact from share dilution 0.01 Core EPS $ 4.70 $ 4.15 $ 0.55 Total core drivers $ (0.04) Non-core items2 0.12 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix Total $ 0.08 2. See EIX Core EPS non-GAAP reconciliation in Appendix 3. 2019 EPS drivers are reported at a consistent share count of 325.8 million (2019 YTD weighted-average shares outstanding is 339.7 million) 4. Test Year 2018 GRC true-up of $0.20 includes revenue of $(0.34), O&M of $0.06, depreciation of $0.24, interest expense of $(0.01), property and other taxes of $0.01 and income taxes of $0.24 5. Includes $0.08 of tax benefits refunded to customers 6. Includes tax benefits related to the settlement (offset in taxes) Note: Diluted earnings were $3.77 and $(1.30) per share for the twelve months ended December 31, 2019 and 2018, respectively. February 28, 2020 45
SCE Annual Results of Operations ($ 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 $1,440 Note: See Use of Non-GAAP Financial Measures. February 28, 2020 46
Updated SCE Wildfire-Related Charges ($ millions) For the year ended December 31, 2019 and December 31, 2018, the income statements and balance sheets include the estimated losses/accrued liabilities (established at the lower end of the reasonably estimated range of expected losses), net of expected recoveries from insurance and FERC customers, related to the 2017/2018 Wildfire/Mudslide Events (as defined in the 10-Ks filed on February 27, 2020 and February 28, 2019) as follows: Income Statement Impacts 2019 2018 Total Charge for wildfire-related claims $232 $4,669 $4,901 Expected insurance recoveries - (2,000) (2,000) Expected revenue from FERC customers (14) (135) (149) Total pre-tax charge $218 $2,534 $2,752 Income tax benefit (61) (709) (770) Total after-tax charge $157 $1,825 $1,982 Total after-tax charge (per share) $0.46 $5.60 Claims Rollforward 2019 Wildfire-related claims (Balance as of December 31, 2018) $4,669 Incremental accrued losses in 2019 232 Payments (public entity’s settlement) (360) Wildfire-related claims (Balance as of December 31, 2019) $4,541 Note: See Use of Non-GAAP Financial Measures. February 28, 2020 47
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 Midpoint High SCE $4.84 EIX Parent & Other (0.38) Basic EPS1 $4.32 $4.47 $4.62 Non-Core Items SCE — — — EIX Parent & Other — — — Total Non-Core1 — — — Core EPS SCE $4.84 EIX Parent & Other (0.38) Core EPS1 $4.32 $4.47 $4.62 1. EPS is calculated on the assumed weighted-average share count for 2020 of 369.5 million. Please see 2020 EIX Core Earnings Guidance slide for more information February 28, 2020 48
Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q4 Q4 Earnings Attributable to Edison International 2019 2018 2019 2018 SCE $194 ($1,429) $1,409 $(310) EIX Parent & Other (51) (35) (125) (147) Discontinued Operations1 — 34 — 34 Basic Earnings $143 ($1,430) $1,284 ($423) Non-Core Items SCE1,2,3,4 ($194) (1,757) $(293) (1,750) EIX Parent & Other1,5 (18) (12) (18) (58) Discontinued Operations1 — 34 — 34 Total Non-Core ($212) ($1,735) ($311) (1,774) Core Earnings SCE $388 $328 $1,702 $1,440 EIX Parent & Other (33) (23) (107) (89) Core Earnings $355 $305 $1,595 $1,351 1. Includes income tax benefit of $34 million, income tax benefit of $66 million and income tax expense of $12 million in 2018 related to the settlement of the 1994 ‒ 2006 California tax audit for discontinued operations, SCE and EIX parent and other, respectively 2. Includes wildfire-related claims, net of recoveries of $218 million ($157 million after-tax) and $2,534 million ($1,825 million after-tax) in the fourth quarter of 2018 and 2019, respectively 3. Includes amortization of SCE’s Wildfire Insurance Fund expenses of $85 million ($61 million after-tax) and $152 million ($109 million after-tax) for the quarter and year-ended December 31, 2019, respectively 4. Includes an impairment charge of $171 million ($123 million after-tax) recorded in second quarter of 2019 for SCE related to the disallowed historical capital expenditures in SCE’s 2018 GRC final decision. The fourth quarter 2019 includes an additional $19 million income tax benefits ($88 million in full year 2019) related to changes in allocation of deferred tax re- measurement between customers and shareholders and impact from the approval of the Revised San Onofre Settlement Agreement 5. Includes goodwill impairment at Edison Energy Group of $25 million ($18 million after-tax) in the fourth quarter 2019 and loss on sale of SoCore Energy of $56 million ($46 million after- tax) in April 2018 February 28, 2020 49
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. February 28, 2020 50
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 internally for financial planning and for analysis of performance. Core earnings 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 are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison International shareholders less 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: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. 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 February 28, 2020 51
