EX-99.1 2 eixjuly2019businessupdat.htm 8-K BUSINESS UPDATE 07/26/19
Exhibit 99.1 Business Update July 26, 2019

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 and capital spending incurred prior to formal regulatory approval; • 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 a substantial cause, including the ability of SCE and SDG&E to raise the funds required to make initial contributions to the insurance fund under AB 1054, SCE's ability to maintain a valid safety certification, SCE's ability to recover uninsured wildfire-related costs from the wildfire fund established under AB 1054, and the CPUC's interpretation of and actions under AB 1054; • actions, or inaction, of the state of California with respect to achieving a timely and comprehensive solution mitigating the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are a substantial cause; • decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including decisions and actions related to determinations of authorized rates of return or return on equity, the GS&RP application, the recoverability of wildfire-related and mudslide-related costs, and delays in regulatory actions; • ability of Edison International or SCE to borrow funds and access the bank and capital markets on reasonable terms; • actions by credit rating agencies to downgrade Edison International or SCE's credit ratings or to place those ratings on negative watch or outlook; • 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; • 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. July 26, 2019 1

Table of Contents Updated (U) or New (N) from Page May 2019 Business Update EIX Shareholder Value 3 SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U California’s GHG Emissions Overview, SCE’s Clean Power and Electrification Pathway 7-8 2019 Wildfire Legislation Update 9 N 2018 General Rate Case Decision 10 N CPUC and FERC Cost of Capital Summary 11 U Capital Expenditures and Rate Base History and Forecast 12-14 U Mitigating Catastrophic Wildfire Risk, Wildfire Mitigation Summary 15-16 N,U Key Regulatory Proceedings 17 U CPUC Cost of Capital (2013-2019) 18 U Distribution and Transmission Capital Expenditure Detail 19-22 U Operational Excellence 23 EIX Responding to Industry Change, Edison Energy Group Summary 24-25 U 2019 EIX Core Earnings Guidance 26 N Annual Dividends Per Share 27 Appendix SCE Historical Capital Expenditures 29 Credit Ratings Summary 30 U Power Grid of the Future 31 EIX’s 2018 Sustainability Report Highlights 32 N SCE Customer Demand Trends, Bundled Revenue Requirement, System Average Rate Historical Growth 33-35 U CCA Overview, Residential Rate Reform and Other, SCE Rates and Bills Comparison 36-40 U Second Quarter and YTD 2019 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 41-47 N,U July 26, 2019 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 • 8.4% average annual rate base • Lead transformation of the electric growth through 2020 power industry • SCE earnings should track rate base • Focus on clean energy, efficient growth over the long term electrification, grid of the future and customers’ technology choice Constructive Regulatory Structure Wires-Focused SCE Strategy • Decoupling of electricity sales • Infrastructure replacement – safety • Balancing accounts and reliability • Forward-looking ratemaking • Grid modernization – California’s low- Sustainable Dividend Growth carbon goals • Target payout ratio of 45-55% of SCE • Grid resiliency and safety earnings • Operational excellence Edison Energy Strategy • Services for large commercial and industrial customers July 26, 2019 3

SCE Highlights One of the nation’s largest electric utilities • 15 million residents in service territory • 5 million customer accounts • 50,000 square-mile service area Significant infrastructure investment • 1.4 million power poles • 724,000 transformers • 118,000 miles of distribution/transmission lines • 3,200 MW owned generation Above average rate base growth driven by • Safety and reliability • California’s low-carbon objectives ➢ Grid modernization ➢ Transportation electrification ➢ Electric vehicle charging ➢ Energy storage Limited Generation Exposure • Own less than 20% of its power generation • Future needs via competitive solicitations July 26, 2019 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 Replacement rates achieved and then maintained • 2018-2020 – Approximately $590 million of capital Accelerate circuit upgrades, automation, spending in 2018 GRC decision communication, and analytics capabilities • 2025 – CPUC target to complete grid modernization but Grid Modernization at optimal locations to integrate distributed may take longer energy resources • 2017-2022 – Multiple projects approved by CAISO in Future transmission needs to meet 60% permitting and/or construction renewables mandate in 2030, 100% clean Transmission • 2023-2045 – Future needs largely driven by CAISO energy by 2045 and to support reliability planning process • Today – Most commitments via contracts; over 720 MW procured SCE-owned investment opportunities under • 2019-2020 - $29 million of capital spending forecasted; Energy Storage existing CPUC proceedings procurement target of 580 MW by 2020 as utility-owned or procured Utility investment in programs to build and • 2018 – Medium- and Heavy-Duty (MD/HD) Vehicle Electrification of support the expansion of transportation Transportation Electrification (TE) program approved, electrification in passenger and light-, totaling $356 million; Charge Ready 2 application filed, Transportation and medium- and heavy-duty vehicles and requesting $760 million; Charge Ready Bridge Funding Other Sectors potentially to support electrification of approved totaling $22 million other sectors of the economy • 2019-2030 – Potential investments to support electrification in other sectors of the economy Utility investment and operational practices • 2018 – Filed Grid Safety & Resiliency application, Wildfire Prevention that mitigate increasing wildfire risk and requesting $582 million of total costs (capital: $407 million) and Mitigation bolster fire prevention activities • 2019 – Filed Wildfire Mitigation Plan • Ongoing – future GRCs • First ~$1.6 billion fire risk mitigation capital spend will not be added to rate base per AB 1054 July 26, 2019 5

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 59% 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 July 26, 2019 6

California’s GHG Emissions Overview • On October 7, 2015, Governor Brown signed SB 350, which requires a doubling of energy efficiency in existing buildings for California by 2030 • On September 8, 2016, Governor Brown signed SB 32, which requires statewide GHG emissions to be reduced to 40% below the 1990 level by 2030; Governor Order set a 2050 target of 80% below 1990 levels • On July 24, 2017, Governor Brown signed AB 398, which extends cap-and-trade to 2030 • On January 26, 2018, Governor Brown released an Executive Order calling for 5 million zero emission vehicles by 2030 • On September 10, 2018, Governor Brown signed SB 100, which requires that 60% of energy sales to customers come from renewable power by 2030 and sets a 100% clean electricity goal for the state, and issued an executive order establishing a new target to achieve carbon neutrality, both by 2045 California GHG Emissions by Sector Commercial and Residential 12% Electrical Transportation Power 41% 16% Agriculture 8% Industrial 23% SCE is taking a leading role to ensure that transportation and building electrification plays a major part in reducing GHG and criteria pollutant emissions in California Source: Data for both charts from California Air Resources Board; California GHG Emissions data as of 2016. July 26, 2019 7

SCE’s Clean Power and Electrification Pathway Electric Power Company Roles • Emissions targets met through • Accelerate electrification of the • Electrify nearly one-third of optimization of renewables transportation sector residential and commercial • Implementation of upcoming ➢ At least 7 million light-duty space and water heaters IRP filing electric vehicles on • Joint utility study by E3 shows • 80% carbon-free electricity by California roads that electrifying homes is 2030 and 100% by 2045 ➢ 15% of medium-duty already cost-effective for most supported by energy storage vehicles electrified homeowners and developers • 2018 SCE renewable resources ➢ 6% of heavy-duty vehicles • Senate Bill 1477 allocates $200 portfolio = 36.3% electrified million over 4 years for pilots % Portfolio Breakdown • Joint utility study launched to • Continuation of company study transportation programs and earnings Solar 37% electrification of the I-5 incentive mechanism Wind 37% corridor Geothermal 22% Small Hydro 2% Biomass 2% July 26, 2019 8

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 • Initial safety certification issued by CPUC Executive Director within 30 days of IOU request requires: 1) an approved wildfire mitigation and plan; 2) utility to be in good safety standing; 3) established board safety committee with relevant safety experience; and 4) board-level Certification reporting to the CPUC on safety issues • Subsequent annual safety certifications issued by Wildfire Safety Division1 also require: 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 FERC-like Recovery 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 • Liquidity fund immediately established against which utilities may draw to pay wildfire claims; if utility found to be prudent, customers reimburse fund draw; if utility found imprudent, shareholders reimburse fund draw • Wildfire “insurance” fund is an insurance-like fund that more broadly socializes wildfire costs; utilities participation is voluntary • Both fund options include a $10.5 billion ratepayer contribution through the financing of a 15-year extension of the Department of Water Resources bond charge; wildfire insurance fund also includes $10.5 billion contribution from utility shareholders • Insurance-like fund created only if both SCE and SDG&E elect to participate within 15 days of bill enactment. SCE and SDG&E have elected to participate ➢ SCE’s shareholders to initially contribute approximately $2.4 billion by September 10 and 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 July 26, 2019 9

SCE 2018 General Rate Case Decision On May 16, 2019, the CPUC issued a final decision which is focused on SCE’s safety and reliability investments in infrastructure replacement and grid modernization, while mitigating customer rate impacts through lower operating costs • 2018 base revenue requirement decision of $5.116 billion ➢ Additional $335 million increase in 2019 and a $412 million increase in 2020 ➢ 95% of requested O&M expenses were adopted ➢ Results in an approximately 5% reduction to current bundled customer rates and bills • 2018 CPUC-jurisdictional capital spending authorization of $2.9 billion1 ➢ Authorization is 92% of SCE’s request excluding Grid Modernization and project approvals that were deferred to the next case for timing reasons2 ➢ Grid Modernization capital spending authorization was approximately 35% of request ($ billions) SCE Tax Update Testimony Decision Year 2/16/18 (Table III-1) 5/16/19 Difference to Request ($/%) Base Revenue Requirement 2018 $5.534 $5.116 ($0.418)/(7.5%) 2019 $5.965 $5.451 ($0.514)/(8.6%) 2020 $6.468 $5.863 ($0.605)/(9.4%) CPUC Rate Base3 2018 $22.939 $22.336 ($0.603)/(2.6%) 2019 $25.181 $24.236 ($0.945)/(3.8%) 2020 $27.445 $26.156 ($1.289)/(4.7%) 1. Excludes capitalized overheads and customer contributions 2. Project approvals referenced include the Cerritos Channel Project Transmission Line Relocation project and Customer Service Re-Platform (CSRP) program 3. Net of “rate-base offset” for the 2015 GRC decision July 26, 2019 10

CPUC and FERC Cost of Capital Summary CPUC Cost of Capital FERC Rate Case Component % Cost Weighted Cost Breakdown of Return on Equity (ROE) Cost Conventional ROE 10.60% Conventional ROE 11.12% Wildfire Risk ROE1 6.00% Wildfire Risk ROE1 6.00% Common Equity 52.0% 16.60% 8.63% Requested ROE + 17.12% Long-Term Debt 43.0% 4.74% 2.04% CAISO adder + 0.50% Preferred Equity 5.0% 5.70% 0.29% Incentive Projects Varies Total 100.0% 10.96% • Litigated proceeding, separate from GRC, • New Rate Case filed on April 11th filed on April 22nd • FERC accepted the new formula rate, • Request for three-year period starting subject to refund, on June 11th; new January 1, 2020 formula rate becomes effective • SCE, PG&E, SDG&E, and November 12, 2019 SoCalGas concurrently filed applications; • Current open proceeding was filed on applications were consolidated into one proceeding October 27, 2017 prior to wildfires; settlement discussions are ongoing2 • Proposed trigger mechanism for adjusting the cost of capital between • Capital structure at FERC is based on proceedings (similar to current recorded level vs. CPUC “authorized” mechanism) approach 1. SCE is evaluating its request for the Wildfire Risk ROE based upon the passage of Assembly Bill 1054 2. On October 27, 2017, SCE filed an application for its 2018 FERC formula recovery mechanism which includes a requested base ROE of 10.3% + CAISO Participation (50 basis points) + weighted average of individual project incentives July 26, 2019 11

SCE Historical Rate Base and Core Earnings ($ billions, except per share data) $29.6 $27.8 $25.9 $24.6 $23.3 $21.1 2013 2014 2015 2016 2017 2018 Core $4.22 EPS $3.88 $4.68 $4.20 $4.58 $4.42 Note: Recorded rate base, year-end basis. See SCE Core EPS Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures. Since 2013, rate base excludes SONGS. July 26, 2019 12

SCE Capital Expenditure Forecast ($ billions) Long Term Investment Drivers Distribution Wildfire mitigation-related spend Transmission Wildfire mitigation-related spend range Transportation Electrification Generation $4.9 • Approved $356 million ($242 million of capital spending) $4.6 $4.7 medium- and heavy-duty vehicle transportation $4.4 electrification program (included in forecast) • Requested $760 million ($561 million of capital spending) Charge Ready 2 application which focuses on charging infrastructure for light-duty vehicles (excluded from forecast) Wildfire Mitigation-Related Spend • Grid Safety and Resiliency Program (GS&RP): $582 million request ($407 million of capital spending) – focused on investment and operational practices that address increasing wildfire risk and bolster fire prevention and suppression activities • Wildfire Mitigation Plan (WMP) filed February 2019 and SCE expects to file its 2020 WMP by early 2020 • CPUC has authorized tracking of costs related to the GS&RP and WMP through memorandum accounts 2018 2019 2020 • 2019 includes approximately $390 million of wildfire Prior Forecast $4.4 $4.5 $4.7-4.9 mitigation-related spend, 2020 includes range of $500 to $700 million Delta ‒ $0.1 ‒ • 2020 spend will be largely used towards ~$1.6 billion fire risk spend without an equity return per AB 1054; seeking clarity on 2019 spend July 26, 2019 13

SCE Rate Base Forecast ($ billions) $33.4 $30.7 $28.5 2018 2019 2020 Prior Forecast $28.5 $30.7 $33.2 Delta $0.0 $0.0 $0.2 Note: : Weighted-average year basis. FERC based on latest forecast. CPUC excludes the “rate-base offset” adjustment related to the 2015 GRC write off of the regulatory asset for 2012-2014 incremental tax repairs. Figures do not include wildfire mitigation-related dollars. July 26, 2019 14

Mitigating Catastrophic Wildfire Risk • SCE’s comprehensive risk mitigation program focuses on three key areas: ➢ Grid hardening: Increase the use of fire-resistant poles, composite cross-arms and covered conductor in high fire risk areas; evaluate design approaches and next-generation engineering technology to further enhance public safety ➢ Increased situational awareness capabilities: Expand meteorological monitoring and forecasting capabilities by installing additional weather stations and high-definition cameras to help SCE and fire agencies to better prepare, mitigate, and respond to reported fires ➢ Enhanced operational practices: Restrict certain types of work in High Fire Risk Areas (HFRAs) during elevated fire risk conditions; reduce fire risk via a Public Safety Power Shutoff in HFRAs during elevated weather conditions; increase tree trimming and removal to further mitigate safety risks posed by trees or debris • Filed annual compliance plan (Wildfire Mitigation Plan) detailing the near- and longer-term actions that SCE is taking to significantly reduce the risk of fire ignitions and increase emergency response and grid resiliency against future impacts of climate change • Excluding the fire risk investments that will not earn an equity return per AB 1054, SCE’s programs (both O&M and capital) are expected to be recovered through different avenues: ➢ Capital amounts approved in the 2018 GRC subject to management discretion ➢ Grid Safety and Resiliency Program application: $582 million of total costs ($407 million of capital) ➢ SB 901 memorandum account which will be reviewed for approval during the 2021 GRC proceeding SCE plans to spend approximately $390 million in 2019 and $500-$700 million in 2020 with continued investments beyond our forecast period July 26, 2019 15

Wildfire Mitigation Summary Increased Situational Grid Hardening Enhanced Operational Practices Awareness Capabilities • 200+ circuit miles of covered • In-house team of fire weather • Completed Enhanced Overhead conductor installed with hundreds experts staffing our 24/7 Inspections of 400,000+ T&D more miles in queue Situational Awareness Center structures in HFRA • 9,000+ faster-acting fuses • 355+ installed weather stations • Deploying helicopters/drones to installed with a target of 450 installations by perform aerial inspections of our • 1,600+ protective devices end of 2019 and 850 by end of facilities in HFRA programmed with more sensitive 2020 • 2,000+ Circuit Breaker/Recloser (fast curve) settings (includes • 80+ installed HD cameras with a Blocking devices remotely set to automatic reclosers and circuit target of 160 installations providing not automatically re-energize lines breakers) 90% coverage by end of 2019 during high fire risk conditions • Developed enhanced Fire Potential • Enhanced Vegetation Index (FPI) to measure wildfire Management potential at the circuit level ➢ Increasing trim distances to keep • 2 supercomputers being installed power lines clear to run advanced weather models to ➢ Performing inspections/removal improve forecast resolution of hazard trees that pose risk • Refined Public Safety Power Shutoff (PSPS) protocol and communication July 26, 2019 16

SCE Key Regulatory Proceedings Proceeding Description Next Steps Key CPUC Proceedings 2020 Cost of Capital Sets CPUC cost of capital and capital structure Application filed April 22, 2019; Scoping Memo issued July 2, 2019; (A. 19-04-014) for 2020-2022 Intervenor and supplemental testimony due August 1, 2019; Rebuttal testimony due August 16, 2019; Hearings will be the first week of September Grid Safety and Resiliency Requesting $582 million of total cost for Application filed in September 2018; memorandum account approved Program (GS&RP) 2018-2020; focused on grid hardening and in January 2019; Intervenor testimony filed April 23; Reply testimony (A. 18-09-002) enhanced vegetation management filed May 31; Hearings scheduled for July 2019 postponed due to settlement discussions SB 901 Proceedings: The CPUC has opened two rulemakings The Wildfire Mitigation Plan (WMP) was filed on February 6, 2019; Wildfire Mitigation Plan OIR responsive to SB 901 (one for the evaluation approved on May 30 (R. 18-10-007) of wildfire mitigation plans and another for the development of a customer harm Stress Test OIR threshold methodology) Proposals for consideration in the Stress Test proceeding were filed on (R. 19-01-006) February 11, 2019; Decision on methodology approved June 27 Charge Ready Program Implementation program for charger Pilot report filed in May 2018; Charge Ready 2 application filed in June (A.14-10-014; A.18-06-015) installations and market education 2018; Scoping Memo issued October 2018; Charge Ready Bridge Funding approved in December 2018; proceeding ongoing Distribution Resources Plan Power grid investments to integrate Demo projects will be concluded due to significant delays in project (DRP) OIR (R.14-08-013) distributed energy resources schedules; No contracts will be executed in the solicitation for deferral projects due to lack of viable bids; Filing annual Grid Needs Assessment and Distribution Deferral Opportunities Reports on August 15 Power Charge Indifference Review, revise, and consider alternatives to Final Decision adopted on October 11, 2018; initiates second phase on Adjustment (PCIA) OIR the PCIA utility portfolio optimization and cost reduction; workshops on Phase 2 (R.17-06-026) underway Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates Replacement rate filed on October 27, 2017 and in effect subject to refund; proceeding ongoing and settlement discussions are continuing; new replacement rate accepted June 11 subject to refund and new settlement process is underway July 26, 2019 17

CPUC Cost of Capital (2013-2019) 7 CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/18 – 07/25/19) = 4.68% 100 basis point +/- Deadband 6 5 Rate Rate (%) Starting Value – 5.00% 4 ROE fixed at 10.45% ROE fixed at 10.30% for 2017, independent for 2018, independent of trigger mechanism of trigger mechanism 3 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 10/1/18 10/1/19 Settlement Two year settlement approved for 2018-2019 Terms (2018- • ROE adjustment based on 12-month average of CPUC Authorized 2019) Moody’s Baa utility bond rates, measured from Capital October 1 to September 30 Structure 2017 2018-2019 • If index exceeds 100 bps deadband from starting index Common Equity 48% 10.45% 10.30% value, authorized ROE changes by half the difference Preferred 9% 5.79% 5.82% • Starting index value based on trailing 12 months of Long-term Debt 43% 5.49% 4.98% Moody’s Baa index as of September 30 of each year – Weighted Average Cost of Capital 7.90% 7.61% 5.00% July 26, 2019 18

SCE Distribution System Investments Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing a large 2019 – 2020 Capital Spending Forecast for Distribution excluding Wildfire1 portion of total distribution capital spend, but not $6.4 Billion yet reaching equilibrium replacement rate ➢ Includes pole loading replacement program and overhead conductor replacements Load New Service Growth Connections • Distribution grid requires upgrades to circuit Other capacity, automation, and control systems to support reliability as use of distributed energy resources increases 2019-2020 Capital Spending Drivers Infrastructure • Automation of distribution circuits General Plant Replacement • Cable and conductor replacements • 4kV cutovers/removals • Pole replacements • Distribution preventive maintenance • Overhead conductor replacements • Circuit breaker and transformer bank replacements/upgrades 1. Other includes grid modernization, GRC energy storage, charge ready pilot programs, mobile home pilot programs and transportation electrification programs July 26, 2019 19

SCE Transportation Electrification (TE) Proposals • Proposals build on SCE’s Clean Power and Electrification Pathway, 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 placing at least 7 million light-duty passenger vehicles on the roads and transitioning to zero-emission trucks and transit ➢ Additional studies launched to increase adoption, such as electrification of the I-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 at least 1,000 chargers, including 20% in Charge Ready Pilot multi-unit dwellings 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 1,280 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 July 26, 2019 20

SCE Energy Storage CPUC Energy Storage Program Requirements: • Storage Rulemaking (R.10-12-007) established 1,325 MW target SCE 2018 Storage Portfolio for IOUs by 2024 (580 MW SCE share; spread as biennial targets during 2014-20); ownership allowed up to 290 MW for SCE 350 • Flexibility to transfer across categories, expanded in Storage 300 Rulemaking (R.15-03-011)* *Up to 80% 310 of MW to • Decision (D. 17-04-039) added AB 2868 opportunity for 250 be shifted programs and investments of an additional 500 MW of between distribution-level energy storage systems, distributed equally 200 T&D among the IOUs (166 MW SCE share; spread as biennial targets, MW *85 MW 2018 and onward; no more than 25% can be customer 185 150 excess may programs) offset T&D SCE Procurement Activities to Meet CPUC Requirements: 100 targets • SCE has procured over 720 MW of energy storage (includes 60 50 85 MW of utility owned storage), ~600 MW of which is eligible to count towards CPUC targets 0 • SCE recently submitted its 2018 Local Capacity Requirements Transmission Distribution Customer RFP (2018 LCR RFP) and its second Aliso Canyon Energy Storage RFO (ACES 2 RFO) for approval. Upon Commission approval of these energy storage resources, SCE will have exceeded the 580 MW target set by AB 2514 Eligible storage to be included in Currently above 2020 Storage compliance Plan targets (Filing date 3/1/2020) • SCE filed its 2018 Energy Storage and Investment Plan 2020 Cumulative (ESP&IP) on March 1, 2018; the AB 2514 track was approved *Storage that is permitted to Procurement Target by D.18-10-036 on October 25, 2018, however, the count in different categories due to flex counting rules Commission rejected SCE’s AB 2868 proposals in D.19-06-032 July 26, 2019 21

SCE Large Transmission Projects Summary of Large Transmission Projects Remaining Investment Estimated In-Service Project Name Total Cost5 (as of June 30, 2019) Date West of Devers1,2 $848 million $525 million 2021 Mesa Substation1 $646 million $345 million 2022 Alberhill System3 $486 million $447 million — 3 Riverside Transmission Reliability4 $451 million $441 million 2024 Eldorado-Lugo-Mohave Upgrade $257 million $192 million 2021 FERC Cost of Capital 11.5% ROE in 20196 (subject to refund): • ROE = Requested Base of 10.3% + CAISO Participation + weighted average of individual project incentives ➢ Application for 2018 and 2019 FERC Formula recovery mechanism filed on October 27, 2017 and April 11, 2019, respectively ➢ Requested 50 bp CAISO adder; approved, but application for rehearing requested by CPUC ➢ ROE and 2018 Transmission Revenue Requirement is accepted and suspended pending settlement discussions 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 August 2018, the CPUC approved the revised alternate decision which left the proceeding open and directed SCE to supplement the existing record with additional analysis as it relates to the Project need and alternatives. Potential revisions to the Project have not been reflected in the total cost of the Project or estimated in service date 4. Riverside Transmission Reliability Project total cost is currently estimated to be $451 million, however costs could increase depending on the final route alternative selected 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 6. SCE’s April 11, 2019 filing to revise its return on equity is pending review with the FERC and is not reflected in the stated figure July 26, 2019 22

SCE Operational Excellence Defining Excellence Measuring Excellence Top Quartile • Employee and public safety • Safety metrics • Reliability • System performance and reliability (SAIDI, SAIFI, • Customer service MAIFI) • Cost efficiency • Customer satisfaction Optimize calculation based on internal voice-of-customer • Capital productivity surveys • Purchased power cost • O&M cost per customer • Digitization • Reduce system rate growth High performing, continuous with O&M / purchased improvement culture Ongoing power cost reductions Operational Excellence Efforts July 26, 2019 23

Responding to Industry Change Long-Term Industry Trends Strategy • The technology landscape is evolving at SCE Strategy an unprecedented pace, with innovation • Clean the power system by accelerating driving advances in cost and capabilities of the de-carbonization of electricity supply distributed energy resources • Help customers make cleaner energy • Customer expectations are changing with choices to support electrification and increasing choices and alternatives, a leverage flexible energy demand growing priority of sustainability • Strengthen and modernize the grid by objectives, and flattening demand replacing aging infrastructure and • The regulatory environment for utilities is deploying technology complex, increasingly supportive of new • Achieve operational and service excellence forms of competition but unable to keep with top tier performance in safety, pace with new business models reliability, affordability, and customer • Policies both in California and globally are satisfaction setting aggressive greenhouse gas reduction targets Beyond SCE • Position Edison Energy as an independent energy advisor and integrator for large commercial and industrial customers July 26, 2019 24

Edison Energy Summary Edison Energy • Energy is a significant risk large commercial and industrial customers face. Edison Energy creates competitive advantage for market leaders by Renewables & Supply quantifying this risk and designing the portfolio solution to protect shareholder value threatened Sustainability Solutions by complex energy policies, technological advancements, and new products. • Optimized portfolio solutions based on robust Managed analytics of the customer’s energy portfolio in alignment with their goals and strategic Portfolio objectives Solution • Implementation of solutions through existing service lines or brokering with third parties • Edison International investment $84 million as of June 30, 2019 Demand Installations Solutions The Opportunity: Trusted Advisor and Solution Integrator July 26, 2019 25

2019 EIX Core Earnings Guidance 2019 Core Earnings Per Share Guidance – Key Assumptions Building from SCE Rate Base Total Rate Base $30.7 billion $0.20 ($0.33) • FERC comprises ~20% of total $0.41 ($0.18) CPUC $4.62 $4.71 • HoldCo Return on Equity 10.3% • Financing operating • Previously (ROE) and other: expenses: disclosed Capital Structure2 48% equity $0.32 1 cent per equity program: • Z-factor share per FERC $1.5 billion advice month • WF fund letter • HoldCo ROE3 10.5% with incentives initial approval: debt issued: contribution: $0.04 $1 billion in • Last approved FERC ROE; settlement discussions regarding 2019 $2.4 billion current 11.5% request continue and is subject to refund • Energy due 9/10 efficiency: • EEG: target financed • Revenues will be adjusted to reflect FERC ROE decision for $0.05 breakeven run rate by 50/50 with 2018 and 2019 (retroactive to January 1, 2018) year-end SCE debt and 1 2019 EIX equity Capital Structure Recorded capital structure; 44% 2019 average estimated equity SCE 2019 EPS SCE Test Year EIX Parent Equity EIX 2019 Core Other Items from Rate Variances 2018 GRC & Other Program / EPS Midpoint Capital Market $4.9 billion of EIX/SCE debt and Base Forecast True-Up WF Fund Guidance Activities equity issuances in addition to SCE’s normal course debt financing Financing of rate base EIX 2019 Core EPS guidance range of $4.61 - $4.81 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%. Guidance update reflects incremental financing activity only. Totals may not foot due to rounding. 1. For modeling purposes, SCE debt and EIX equity (based on 7/22/19 price of $69.68) issued on contribution due date (9/10/19); actual dilutive impact to vary based on capital mix, pricing, and timing 2. On February 28, 2019, SCE filed an application with the CPUC for a waiver of compliance with this equity ratio requirement, describing that while the wildfire-related charge accrued in the fourth quarter of 2018 caused its equity ratio to fall below 47% on a spot basis as of December 31, 2018, SCE remains in compliance with the 48% equity ratio over the applicable 37- month average basis. While the CPUC reviews the waiver application, SCE is considered in compliance with the capital structure rules 3. SCE’s April 11, 2019 filing to revise its ROE is pending review with the FERC and not reflected in guidance assumptions JulJulyy 26,25, 2019 26

EIX Annual Dividends Per Share Fifteen Consecutive Years of Dividend Growth 1 $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 Target dividend growth within target payout ratio of 45-55% of SCE’s earnings 1. 2019 dividend annualized based on December 6, 2018 declaration July 26, 2019 27

Appendix July 26, 2019 28

SCE Historical Capital Expenditures ($ billions) $4.4 $4.0 $3.9 $3.8 $3.5 2014 2015 2016 2017 2018 July 26, 2019 29

Credit Ratings Summary S&P Moody’s Fitch Date of Report July 26, 2019 July 12, 2019 July 18, 2019 Edison International Corporate / Outlook BBB/Stable Baa3/Negative BBB-/Negative Senior Unsecured BBB- Baa3 BBB- Commercial Paper A-2 P-3 F3 Southern California Edison Corporate / Outlook BBB/Stable Baa2/Negative BBB-/Negative First Mortgage Bonds A- A3 BBB+ Senior Unsecured BBB Baa2 BBB Preferred Securities BB+ Ba1 BB+ Commercial Paper A-2 P-2 F3 We expect Moody’s and Fitch to re-assess ratings because of our election to participate in the wildfire insurance fund July 26, 2019 30

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 plants power grid • Voltage centrally maintained • System designed to manage fluctuating • Increasing integration of distributed resources and customer demand energy resources • Digital monitoring and control devices and • Limited situational awareness and advanced communications systems to visualization tools for power grid improve safety and reliability, and integrate operators DERs • Improved data management and power Renewable Generation Mandates grid operations and cyber risk mitigation Subsidized Residential Solar • Integrated utility distribution with distributed energy resources planning Limited Electric Vehicle Charging Infrastructure Maximize Distributed Resources and Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency July 26, 2019 31

EIX’s 2018 Sustainability Report Highlights “At Edison International, we are leading the transformation of the electric power industry toward a clean energy future by focusing on opportunities in clean energy, efficient electrification, the grid of the future, and customer choice. As we pursue this vision, sustainability remains at the core of who we are and what we do.” – Pedro Pizarro, Edison International CEO * Edison Energy is not the same company as Southern California Edison, the utility, and Edison Energy is not regulated by the California Public Utilities Commission ** Cumulative duration (in minutes) of sustained repair outages, lasting longer than five minutes, experienced by the average customer in a year (including major event days) *** In February 2019, the EIX board approved a $3 million donation to the Edison International Wildfire Assistance Fund to enhance community resiliency and wildfire prevention and mitigation. This affects the 2019 data year and is not reflected here July 26, 2019 32

SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) 2014 2015 2016 2017 2018 Residential 30,027 30,093 29,579 30,221 29,865 Commercial 42,004 42,396 42,189 42,514 42,369 Industrial 8,392 7,623 7,162 6,659 6,786 Public authorities 4,975 4,795 4,715 4,711 4,510 Agricultural and other 2,019 1,950 1,803 1,498 1,745 Subtotal 87,416 86,857 85,448 85,602 85,276 Resale 1,308 1,080 1,794 1,568 1,867 Total Kilowatt-Hour Sales 88,725 87,937 87,242 87,170 87,143 Customers Residential 4,368,897 4,393,150 4,417,340 4,447,706 4,477,508 Commercial 557,957 561,475 565,222 569,222 572,313 Industrial 10,782 10,811 10,445 10,274 10,078 Public authorities 46,234 46,436 46,133 46,410 46,059 Agricultural 21,404 21,306 21,233 21,045 20,872 Railroads and railways 105 130 133 137 131 Interdepartmental 22 22 22 24 24 Total Number of Customers 5,005,401 5,033,330 5,060,528 5,094,818 5,126,985 Number of New Connections 29,879 31,653 38,076 39,621 39,633 Area Peak Demand (MW) 23,055 23,079 23,091 23,508 23,766 Note: See Edison International Financial and Statistical Reports for 2017 for further information. July 26, 2019 33

SCE Bundled Revenue Requirement 2019 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond 4,268 7.2 Fuel & Purchased Power Charge (44%) Distribution – poles, wires, substations, service 3,680 6.2 centers; Edison SmartConnect® Distribution Generation – owned generation investment and O&M 830 1.2 (38%) Generation (8%) Transmission – greater than 220kV 789 1.5 Transmission (8%) Other – CPUC and legislative public purpose 185 0.1 Other (2%) programs, system reliability investments, nuclear decommissioning, and prior-year over collections Total Bundled Revenue Requirement ($millions) $9,753  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 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 16.0 16.4 Note: Rates in effect as of June 1, 2019. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services from SCE. July 26, 2019 34

System Average Rate Historical Growth ¢/kWh Comparative System Rates reduced due to the implementation of Average Rates 1) the SONGS Revised Settlement, including CAGR % Delta to SCE NEIL insurance benefits, 2) lower fuel & 29-yr 20-yr 10-yr SCE 16.4¢ -- purchased power costs, and 3) a lower 2015 (‘90-’19) (‘99-’19) (‘09-'19) GRC revenue requirement that includes SCE System Average Rate 1.8% 2.7% 1.4% PG&E 20.7¢1 26% flow-through tax benefits Los Angeles Area Inflation 2.4% 2.5% 2.0% SDG&E 25.1¢1 53% Higher gas price forecast post-Katrina Delay in 2012 GRC leads 22.0¢ leads to higher rates with subsequent to shorter ramp-up of Energy Crisis and refund of over collection rate increase 20.0¢ return to normal 19.5¢ 18.0¢ 16.4¢ 16.0¢ 14.0¢ 12.0¢ 9.7¢ 10.0¢ 8.0¢ 1990 1991 1993 1995 1998 2000 2003 2005 2008 2010 2012 2013 2015 2017 1992 1994 1996 1997 1999 2001 2002 2004 2006 2007 2009 2011 2014 2016 2018 2019 SCE’s system average rate has grown less than inflation over the last 29 years 1. PG&E Advice 5573-E-A, SDG&E Advice 3377-E July 26, 2019 35

Community Choice Aggregator (CCA) Overview • Assembly Bill 1171 permits cities and counties, and Joint Powers Agencies (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 will address utility portfolio optimization, PCIA “pre-payment” options for entities and Investor-Owned Utility Community Choice Aggregator individual departing load customers, and implementation of the (IOU) (CCA) “true-up” process for Resource Adequacy and Renewable Energy Credits costs • 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 is expected to be ~35% of SCE’s total load by the end of 2019 Approximately 40% of SCE’s bundled service load could be part of a CCA or Direct Access by the end of 2020 July 26, 2019 36

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 beginning October 2020 • July 2015 CPUC Decision D. 15-07-001 includes: ➢ Transition to 2 tiered rate structure, coupled with Super-User Electric (SUE) Surcharge1 ➢ “Super User Electric Surcharge” for usage 400% above baseline (~3% of all usage) ➢ Minimum bills of approximately $10/month (applied to delivery revenue only) Non-CARE 2, Unbundled Rates January 2014 2019 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: $10.54/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 Level Tiered Rate Tiered Rate Level Level Tiered Rate (Relative to Tier Tier Rate) 1 to (Relative (Relative to Tier Tier Rate) 1 to (Relative 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 (% of Baseline) Usage Level (% of Baseline) 1. Completed in 2019 2. SCE’s California Alternate Rates for Energy (CARE) program is an income-qualifying program that reduces energy bills for eligible customers by about 30% July 26, 2019 37

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 • 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 July 26, 2019 38

SCE Net Energy Metering Monthly Residential Solar SCE Net Metering Statistics (6/19) Installations and MW Installed • 315,756 combined residential and non-residential projects – 2,649 MW installed 7000 40 • 99.8 % solar projects • 308,576 residential (6.9% of all residential customers) – 1,686 MW 35 • 7,180 non-residential – 964 MW 6000 • Approximately 4,631,727 MWh/year generated 30 Key Dates 5000 July 1, 2017 25 • Official start of NEM successor tariff; customers are subject to: ➢ Mandatory TOU rate 4000 MW Installed MW ➢ Non-bypassable charges 20 ➢ Application fees July 31, 2017 3000 • Residential customers who meet this deadline are grandfathered for 15 current TOU periods for maximum of 5 years (10 for non-residential) Number of Solar Residential Residential Solar of Installations Number September 9, 2017 2000 • Smart Inverters required on all solar installations 10 July 25, 2018 • Smart Inverters with Reactive Power Priority required on all solar 1000 installations 5 Near Term Outlook • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 0 0 rate structure has helped reduce the per customer cost shift; further efforts to reduce the shift through new TOU pricing periods 2013 2014 2015 2016 2017 2018 2019 • Commission to revisit NEM Successor Tariff by July 2020 where Installations MW increased customer/demand charges and market priced export compensation rates will be explored July 26, 2019 39

SCE Rates and Bills Comparison 2018 Average Residential Rates (¢/kWh) KeyKey Factors Factors 28% 16.4 ₵ Higher • SCE’s residential rates are above national 12.8 ₵ average due, in part, to a cleaner fuel mix, high cost of living, and lower system load factor • 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 2018 Average Residential Bills • Average monthly residential bills are lower ($ per Month) than the national average as higher rate levels are more than offset by lower usage 29% $134 Lower $95 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 2018. https://www.eia.gov/electricity/data/eia861m/index.html. July 26, 2019 40

Second Quarter Earnings Summary Q2 Q2 Key SCE EPS Drivers3 2019 2018 Variance Test Year 2018 GRC true-up $ 0.20 Basic Earnings Per Share (EPS)1 Higher revenue 0.34 - CPUC revenue 0.28 SCE $ 1.28 $ 0.91 $ 0.37 - FERC and other operating revenue 0.06 EIX Parent & Other (0.08) (0.06) (0.02) Lower O&M 0.14 Basic EPS $ 1.20 $ 0.85 $ 0.35 Lower depreciation 0.07 Higher net financing costs (0.01) Less: Non-core Items Other income and expenses 0.01 SCE2 $ (0.38) $ — $ (0.38) Total core drivers $ 0.75 Non-core items 2 (0.38) EIX Parent & Other — — — Total $ 0.37 Total Non-core $ (0.38) $ — $ (0.38) Core Earnings Per Share (EPS) Key EIX EPS Drivers EIX parent and other — Higher interest expense $ (0.03) SCE $ 1.66 $ 0.91 $ 0.75 EEG — Lower corporate expenses 0.01 EIX Parent & Other (0.08) (0.06) (0.02) Total core drivers $ (0.02) Core EPS $ 1.58 $ 0.85 $ 0.73 Total $ (0.02) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Impact of 2018 GRC final decision related to impairment of utility property, plant and equipment 3. Adjusted to exclude Test Year 2018 GRC true-up Note: Diluted earnings were $1.20 and $0.84 per share for the three months ended June 30, 2019 and 2018, respectively. July 26, 2019 41

Year to Date Earnings Summary YTD YTD Key SCE EPS Drivers4 2019 2018 Variance Test Year 2018 GRC true-up $ 0.20 Basic Earnings Per Share (EPS)1 Higher revenue 0.43 - CPUC revenue 0.34 SCE $ 2.18 $ 1.79 $ 0.39 - FERC and other operating revenue 0.09 EIX Parent & Other (0.13) (0.27) 0.14 Higher O&M (0.04) Lower depreciation 0.03 Basic EPS $ 2.05 $ 1.52 $ 0.53 Higher net financing costs (0.09) Less: Non-core Items Income taxes 0.02 Total core drivers $ 0.55 2 SCE $ (0.16) $ — $ (0.16) Non-core items2 (0.16) Total EIX Parent & Other3 — (0.13) 0.13 $ 0.39 Total Non-core $ (0.16) $ (0.13) $ (0.03) Key EIX EPS Drivers Core Earnings Per Share (EPS) EIX parent and other — Higher interest expense $ (0.02) EEG — Lower losses at the competitive business and lower SCE $ 2.34 $ 1.79 $ 0.55 corporate expenses 0.03 Total core drivers $ 0.01 EIX Parent & Other (0.13) (0.14) 0.01 Non-core items3 0.13 Core EPS $ 2.21 $ 1.65 $ 0.56 Total $ 0.14 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Impact of 2018 GRC final decision related to impairment of utility property, plant and equipment, changes in the allocation of deferred tax re-measurement between customers, shareholders and gain from sale of nuclear fuel as a result of Revised San Onofre Settlement Agreement 3. Loss on sale of SoCore Energy 4. Adjusted to exclude Test Year 2018 GRC true-up Note: Diluted earnings were $2.05 and $1.51 per share for the six months ended June 30, 2019 and 2018, respectively. July 26, 2019 42

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 2018 2017 Earnings Cost-Recovery Total Earnings Cost-Recovery Total Activities Activities Consolidated Activities Activities Consolidated Operating revenue $6,560 $6,051 $12,611 $6,611 $5,643 $12,254 Purchased power and fuel — 5,406 5,406 — 4,873 4,873 Operation and maintenance 1,972 730 2,702 1,898 824 2,722 Wildfire-related claims, net of recoveries 2,669 — 2,669 ― ― ― Depreciation and amortization 1,867 — 1,867 2,032 — 2,032 Property and other taxes 392 — 392 372 — 372 Impairment and other charges (12) — (12) 716 — 716 Other operating income (7) — (7) (8) — (8) Total operating expenses 6,881 6,136 13,017 5,010 5,697 10,707 Operating (loss) income (321) (85) (406) 1,601 (54) 1,547 Interest expense (671) (2) (673) (588) (1) (589) Other income and expenses 107 87 194 93 55 148 (Loss) income before income taxes (885) — (885) 1,106 — 1,106 Income tax (benefit) expense (696) — (696) (30) — (30) Net (loss) income (189) — (189) 1,136 — 1,136 Preferred and preference stock dividend 121 — 121 124 — 124 requirements Net (loss) income available for common stock ($310) — ($310) $1,012 — $1,012 Less: Non-core items (1,750) (481) Core Earnings $1,440 $1,493 Note: See Use of Non-GAAP Financial Measures. July 26, 2019 43

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 2019 Low Midpoint High SCE $4.88 EIX Parent & Other (0.32) Basic EPS1 $4.46 $4.56 $4.66 Non-Core Items SCE2,3 (0.15) (0.15) (0.15) EIX Parent & Other — — — Total Non-Core1 (0.15) (0.15) (0.15) Core EPS SCE $5.03 EIX Parent & Other (0.32) Core EPS1 $4.61 $4.71 $4.81 1. EPS is calculated on the assumed weighted-average share count for 2019. Please see 2019 EIX Core Earnings Guidance slide for more information. 2. Includes $0.22 per share of non-core items recorded for the three months ended March 31, 2019 and $(0.37) per share related to the impairment of utility property, plant and equipment due to the receipt of the 2018 GRC final decision in May 2019 3. Includes $(0.01) as a result of share count dilution July 26, 2019 44

Earnings Non-GAAP Reconciliations ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Q2 Q2 YTD YTD Earnings Attributable to Edison International 2019 2018 2019 2018 SCE $419 $297 $712 $583 EIX Parent & Other (27) (21) (42) (89) Basic Earnings $392 $276 $670 $494 Non-Core Items SCE 1 ($123) — ($51) — EIX Parent & Other 2 — 2 — (42) Total Non-Core ($123) $2 ($51) ($42) Core Earnings SCE $542 $297 $763 $583 EIX Parent & Other (27) (23) (42) (47) Core Earnings $515 $274 $721 $536 1. Includes an impairment charge of $170 million ($123 million after-tax) recorded in 2019 for SCE related to disallowed historical capital expenditures in SCE's 2018 GRC final decision in the second quarter of 2019. The six months ended June 30, 2019, includes income tax benefits of $69 million recorded in 2019 for SCE 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 2. Includes Loss of $63 million ($46 million after-tax) recorded in 2018 for Edison International Parent and Other related to sale of SoCore Energy in April 2018 July 26, 2019 45

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 2018 2017 Basic EPS ($1.30) $1.73 Non-Core Items SCE Wildfire-related claims, net of recoveries (5.60) — Settlement of 1994 – 2006 California tax audits 0.20 — Write down, impairment and other as a result of Revised San 0.03 (1.38) Onofre Settlement Agreement Re-measurement of deferred taxes as a result of Tax Reform — (0.10) Edison International Parent and Other Settlement of 1994 – 2006 California tax audits (0.04) — Re-measurement of deferred taxes as a result of Tax Reform — (1.33) Sale of SoCore Energy and other (0.14) 0.04 Discontinued operations Settlement of 1994 – 2006 California tax audits 0.10 — Less: Total Non-Core Items (5.45) (2.77) Core EPS $4.15 $4.50 Note: See Use of Non-GAAP Financial Measures. July 26, 2019 46

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 July 26, 2019 47