EX-99.1 2 eixmay2018businessupdate.htm EXHIBIT 99.1 EIX BUSINESS UPDATE PRESENTATION DATED MAY 2, 2018
Business Update May 2018 Exhibit 99.1

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 in a timely manner from its customers through regulated rates, including costs related to uninsured wildfire-related and mudslide-related liabilities, spending on grid modernization and other capital spending incurred prior to explicit regulatory approval; • ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire- related and mudslide-related exposure, and to recover the costs of such insurance or, in the absence of insurance, the ability to recover uninsured losses; • decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of authorized rates of return or return on equity, the 2018 GRC, the recoverability of wildfire-related and mudslide-related costs, and delays in regulatory actions; • ability of EIX or SCE to borrow funds and access the 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, and cost overruns; • extreme weather-related incidents and other natural disasters, including earthquakes and events caused, or exacerbated, by climate change, such as wildfires; • risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure due to Community Choice Aggregators (CCAs); and • 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. 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. Forward-Looking Statements 1May 2, 2018

Page Updated (U) or New (N) from February 2018 Business Update EIX Shareholder Value 3 SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U California Wildfire Risk Mitigation 7 Capital Expenditures and Rate Base History and Forecast 8-10 2018 General Rate Case 11 Key Regulatory Proceedings 12 U CPUC Cost of Capital 13 U 2018 Financial Assumptions 14 Distribution and Transmission Capital Expenditure Detail 15-19 U Operational Excellence 20 EIX Responding to Industry Change 21 Edison Energy Group Summary 22 U Annual Dividends Per Share 23 Appendix 2018 General Rate Case Overview 25 Historical Capital Expenditures 26 Capital Expenditure and Rate Base Detailed Forecast 27 Power Grid of the Future, Grid Modernization 28-31 SCE Customer Demand Trends 32 California Energy Policy 33 U SCE Bundled Revenue Requirement, System Average Rate Historical Growth 34-35 U CCA Overview, Residential Rate Reform and Other 36-39 N,U SCE Rates and Bills Comparison 40 U First Quarter 2018 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 41-45 N,U Table of Contents 2May 2, 2018

EIX Strategy Should Produce Superior Value Sustained Earnings and Dividend Growth Led by SCE Electric-Led Clean Energy Future SCE Rate Base Growth Drives Earnings • 9.7% average annual rate base growth through 2020 at request level • SCE earnings should track rate base growth Constructive Regulatory Structure • Decoupling of electricity sales • Balancing accounts • Forward-looking ratemaking Sustainable Dividend Growth • Target dividend growth at higher than industry average within target payout ratio of 45-55% of SCE earnings EIX Vision • Lead transformation of the electric power industry • Focus on clean energy, efficient electrification, grid of the future and customers’ technology choice Wires-Focused SCE Strategy • Infrastructure replacement – safety and reliability • Grid modernization – California’s low- carbon goals • Operational excellence Edison Energy Strategy • Services for large commercial and industrial customers 3May 2, 2018

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 • 725,000 transformers • 118,000 miles of distribution and transmission lines • 3,200 MW owned generation Above average rate base growth driven by • Safety and reliability • California’s low-carbon objectives  Grid modernization  Electric vehicle charging  Energy storage  Transportation electrification Limited Generation Exposure • Own less than 20% of its power generation • Future needs via competitive solicitations SCE Highlights 4May 2, 2018

SCE Long-Term Growth Drivers Description Timeframe/Regulatory Process Sustained level of infrastructure investment required until equilibrium replacement rates achieved and then maintained • Ongoing - current and future GRCs Accelerate circuit upgrades, automation, communication, and analytics capabilities at optimal locations to integrate distributed energy resources • Today – Grid modernization capital expenditures included in traditional spend • 2019-2020 – $1.3 billion capital request in 2018 GRC application • 2025 – CPUC target to complete grid modernization but may take longer Future transmission needs to meet 50% renewables mandate in 2030 and to support reliability • 2017-2022 – Multiple projects approved by CAISO in permitting and/or construction • 2021-2030 – Future needs largely driven by CAISO planning process SCE-owned investment opportunities under existing CPUC proceedings • Today – Most investments via contracts • $49 million of capital spending forecasted for 2018-2020 • SCE’s storage portfolio – procurement target of 580 MW by 2020 • Energy Storage and Distribution Deferral Application (A.) 17-12-002 - seeks contract approval of 10 MW of distribution connected storage Utility investment in programs to build and support the expansion of transportation electrification in passenger and light-, medium- and heavy-duty vehicles and potentially to support electrification of other sectors of the economy • 2016 – Charge Ready Phase I approved • 2017 – Transportation Electrification plan filed January 20; 5 priority projects approved, totaling $16 million; proposed decision issued on standard review projects • 2018-2030 – Future Charge Ready Phase II and other transportation electrification investments; potential investments to support electrification of other sectors of the economy Infrastructure Reliability Grid Modernization Electrification of Transportation and Other Sectors Energy Storage Transmission 5May 2, 2018

SCE Decoupled Regulatory Framework 6 Regulatory Mechanism Key Benefits Decoupling of Revenues from Sales • Earnings not affected by variability of retail electricity sales • Differences between amounts collected and authorized levels either billed or refunded • Promotes energy conservation • Stabilizes revenues during economic cycles Major Balancing Accounts • Sales • Fuel and Purchased power • Energy efficiency • Pension expense • Cost-recovery related balancing accounts represented more than 53% of costs • Trigger mechanism for fuel and purchased power adjustments at 5% variance level Advanced Long-Term Procurement Planning • Upfront contract approvals and prudency standards provide 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 May 2, 2018

California Wildfire Campaign 7 Prevention and mitigation Hardening the infrastructure Allocation of risk and liability • Effective fire suppression resources • Effective vegetation management policies • Hazardous fuels reduction • Zoning regulations for residential and commercial development in high fire risk areas • Stronger building codes in high fire risk areas • Partnering with state agencies on improved standards for climate resilient infrastructure • Assessing the design and operation of the system  Inspecting and upgrading poles  Undergrounding electric lines  Operating differently under Red Flag warnings  Preemptively de-energize lines in high fire risk areas during severe wind events • Policies around allocation of financial risks, including fire suppression costs and damages • Reforming the application of inverse condemnation with strict liability to utilities • Addressing the high cost of fire suppression, the costs which exceed state budgets annually • Addressing increasingly high premiums for wildfire insurance coverage May 2, 2018

SCE Historical Rate Base and Core Earnings Rate Base Core Earnings 6% 2% 2012– 2017 CAGR ($ billions, except per share data) 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. $4.20$4.68$4.10 $3.88 Core EPS $4.22 $21.0 $21.1 $23.3 $24.6 $25.9 $27.8 2012 2013 2014 2015 2016 2017 $4.58 8May 2, 2018

SCE Capital Expenditure Forecast 1. Includes 2018 – 2020 capital expenditures of $105 million for Mobile Home Park, $49 million for Energy Storage, $10 million for Transportation Electrification, and $4 million for Charge Ready 2. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures 3. 2018 spending at budget levels; 2019-2020 are at request levels Note: Forecasted capital spending includes CPUC, FERC and other spending. 2019-2020 based on 2018 CPUC GRC Tax Reform February Update testimony. See Capital Expenditure/Rate Base Detailed Forecast for further information, including potential investment excluded in forecasts. Delta represents change from February 2018 Business Update. ($ billions) $13.7 Billion 2018-2020 Capital Program • Capital expenditure forecast incorporates GRC, FERC and non- GRC CPUC spending  GRC decision pending; 2018 capital plan will allow SCE to ramp up its spending program over the three-year GRC period to meet ultimately authorized capital  2018 Grid Modernization spending focused on safety and reliability2  Includes $119 million of non-GRC CPUC capital for mobile home pilot program, charge ready pilot, and priority review transportation electrification projects in 2018-2019  Does not reflect proposed decisions for Alberhill construction license, nor standard review transportation electrification projects; to be updated upon issuance of final decisions • Authorized/Actual may differ from forecast  Since the 2009 GRC, CPUC has approved 81%, 89%, and 92% of capital requested, respectively  SCE has no prior approval experience on grid modernization capital spending and, therefore, prior results may not be predictive  Forecasted FERC capital spending subject to timely receipt of permitting, licensing, and regulatory approvals $3.8 $4.2 $4.8 $4.7 2017 (Actual) 2018 2019 2020 Distribution Transmission Generation Traditional Capital Spending: Grid Modernization Capital Spending: Grid Modernization Prior Forecast $3.8 $4.2 $4.8 $4.7 Delta ‒ ‒ ‒ ‒ 1 3 2 9May 2, 2018

SCE Rate Base Forecast – Request Level CPUC • Rate base based on request levels from 2018 GRC Tax Reform February Update FERC • FERC rate base, including Construction Work in Progress (CWIP), is approximately 19% of SCE’s rate base by 2020 • Reflects latest capital forecast and Incentive CWIP treatment for Alberhill, Mesa and Eldorado-Lugo-Mohave projects Other • Includes Tax Reform impact • Includes mobile home pilot program, charge ready pilot, and priority review transportation electrification • Excludes SONGS regulatory asset ($ billions) 3-year CAGR of 9.7% Note: Weighted-average year basis. 2017 based on 2015 GRC decision. 2018-2020 CPUC based on 2018 GRC Tax Reform February Update testimony, FERC based on latest forecast and current tax law, “rate-base offset” for the 2015 GRC decision excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs. Delta represents change from February 2018 Business Update 10 $26.2 $29.1 $31.8 $34.6 2017 (Authorized) 2018 2019 2020 Traditional Grid Modernization Prior Forecast $26.2 $29.1 $31.8 $34.6 Delta ‒ ‒ ‒ ‒ May 2, 2018

• 2018 GRC Application (A. 16-09-001) filed September 1, 2016 • Addresses CPUC jurisdictional revenue requirement for 2018-2020  Includes operating costs and capital investment  Excludes CPUC jurisdictional costs such as fuel and purchased power, cost of capital and other potential SCE capital projects (transportation electrification, Charge Ready, and storage outside of the GRC)  Excludes FERC jurisdictional transmission • SCE’s Updated Testimony for tax reform was filed February 16, 2018, and requests 2018 revenue requirement of $5.534 billion  $106 million decrease over 2017 GRC revenue requirement  Requests post test year GRC revenue requirement increases: $431 million in 2019 and $503 million in 2020  The requested increase represents an estimated 3% compound annual growth rate in total rates between 2017-2020 • GRC filing advances SCE strategy focusing on safety and reliability by continuing infrastructure investment and beginning grid modernization investments, mitigating customer rate impacts through lower operating costs GRC Application Filed Rebuttal Final Decision 2016 Q1 Q2 Q3 Q4 2017 Q1 Q2 Q3 Q4 Estimated Intervenor Testimony Proposed Decision 2018 SCE General Rate Case (GRC) Evidentiary Hearings Note: Schedule was set by CPUC, but excludes timing of final decision. The schedule is subject to change over the course of the proceeding. 2018 11May 2, 2018

SCE Key Regulatory Proceedings Proceeding Description Next Steps Key CPUC Proceedings 2018 General Rate Case (A. 16-09-001) Set CPUC base revenue requirement, capital expenditures and rate base for 2018-2020 Updated Testimony filed on February 16, 2018; hearing held March 19, 2018 Z-Factor Advice Letter (Advice Letter 3768-E) Advice letter requesting Z-Factor recovery of approximately $108 million incurred to obtain a 12-month, $300 million wildfire insurance policy for 2018 Protest and reply to protests have been filed; no set timeline for Commission review Distribution Resources Plan OIR (R.14-08-013) Power grid investments to integrate distributed energy resources Demo projects underway; Decision on the deferral framework and distribution forecasting issued in February; Decision on investment guidance issued in March 2018 Integrated Distributed Energy Resources OIR (R. 14-10-003) Creating consistent framework for guidance, planning and evaluation of Distributed Energy Resources (DERs) SCE launched its IDER Incentive Pilot Solicitation on January 12, 2018 with Final Selection notification occurring on May 11, 2018; Amended scoping memo issued to consider alternate DER sourcing mechanisms SONGS OII (I.12-10-013) OII resolved (December 2015); Proceeding record reopened in May 2016 Revised Settlement Agreement reached January 2018; awaiting CPUC approval Charge Ready Program (A.14-10-014) Implementation program for charger installations and market education Phase 1 pilot program approved January 2016; plan to file Phase 1 report in May 2018; Phase 2 filing expected in Q2 2018 2017 Transportation Electrification (A.17-01-021) TE proposals to address SB 350 transportation electrification objectives Ongoing workshops and data requests; Five priority review projects approved in January 2018; final decision for standard review projects expected in May 2018 Power Charge Indifference Adjustment OIR (R.17-06-026) Review, revise, and consider alternatives to the PCIA Scoping memo issued – Track 1 proposed decision in April 2018 and Track 2 proposed decision in July 2018 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 have begun; All parties will meet at FERC on May 15, 2018 12May 2, 2018

3 4 5 6 7 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 10/1/18 10/1/19 R a te ( % ) CPUC Cost of Capital CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/17 – 04/30/18) = 4.32% 100 basis point +/- Deadband Starting Value – 5.00% Two year settlement approved for 2018-2019 • ROE adjustment based on 12-month average of Moody’s Baa utility bond rates, measured from October 1 to September 30 • If index exceeds 100 bps deadband from starting index value, authorized ROE changes by half the difference • Starting index value based on trailing 12 months of Moody’s Baa index as of September 30 of each year – 5.00% CPUC Authorized Settlement Terms (2018- 2019) Capital Structure 2017 2018-2019 Common Equity 48% 10.45% 10.30% Preferred 9% 5.79% 5.82% Long-term Debt 43% 5.49% 4.98% Weighted Average Cost of Capital 7.90% 7.61% ROE fixed at 10.30% for 2018, independent of trigger mechanism ROE fixed at 10.45% for 2017, independent of trigger mechanism 13May 2, 2018

2018 Financial Assumptions ($ billions) SCE Capital Expenditures SCE Authorized Cost of Capital Other Items CPUC Return on Equity 10.3% CPUC Capital Structure 48% equity 43% debt 9% preferred FERC Return on Equity 11.5% with incentives (subject to refund pending FERC decision) EIX will provide 2018 earnings guidance after a final decision in the SCE 2018 General Rate Case Distribution $3.4 Transmission 0.6 Generation 0.2 2018 Plan $4.2 SCE Weighted Average Rate Base • FERC comprises about 20% of total rate base in 2018 • Based on GRC update submitted February 2018; incorporates impact of tax reform Traditional $28.8 Grid Mod 0.3 2018 Request $29.1 • Based on 2018 forecasted expenditures at SCE • Incremental wildfire insurance obtained at year-end at cost of ($0.29) per share; CPUC has not yet addressed recovery of these premiums or any other costs in excess of what has been requested in the GRC • Energy efficiency of $0.03 per share • Revenues recorded at 2017 levels until 2018 GRC decision is received (decision retroactive to January 1, 2018) • 2018 EIX Parent and Other core EPS guidance range: ($0.25) to ($0.30) per share  Holding company drag of 2 cents per share per month due to lower tax shield and higher interest expense  Includes EPS estimate for Edison Energy; continue to target breakeven run rate by year-end 2019 14 Note: All tax-affected information on this slide is based on our current combined statutory tax rate of approximately 28%. May 2, 2018

SCE Distribution System Investments 1. Other includes GRC energy storage, Charge Ready Pilot and mobile home pilot programs 2. 2018 Grid Modernization spending, included in distribution, is focused on safety and reliability; most spending focused on integration of distributed energy resources has been deferred Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing 45% of total distribution capital spend, but not yet reaching equilibrium replacement rate  Includes pole loading replacement program and overhead conductor replacements • Distribution grid requires upgrades to circuit capacity, automation, and control systems to support reliability as use of distributed energy resources increases • Includes grid modernization capital which is expected to become a larger portion of spend beyond 2018 2018 – 2020 Capital Spending Forecast for Distribution1,2 $10.9 Billion 2018-2020 Capital Spending Drivers • Automation of over 850 distribution circuits • Over 2,000 miles of cable replacements • 4kV cutovers/removals • Distribution preventive maintenance • Overhead conductor replacements • Circuit breaker replacements/upgrades Load Growth New Service Connections Infrastructure Replacement General Plant Grid Modernization2 Other 15May 2, 2018

200 120 50 0 50 100 150 200 250 Transmission Distribution Customer M W SCE 2018 Storage Portfolio *85 MW excess may offset T&D targets CPUC Energy Storage Program Requirements: • Storage Rulemaking (R.10-12-007) established 1,325 MW target for IOUs by 2024 (580 MW SCE share; spread as biennial targets during 2014-20); ownership allowed up to 290 MW for SCE • Flexibility to transfer across categories, expanded in Storage Rulemaking (R.15-03-011)* • Decision (D. 17-04-039) added AB 2868 opportunity for programs and investments of an additional 500 MW of distribution-level energy storage systems, distributed equally among the IOUs (166 MW SCE share; spread as biennial targets, 2018 and onward) SCE Procurement Activities to Meet CPUC Requirements: • SCE has procured over 500 MW of energy storage; ~364 MW of which is eligible to count towards CPUC targets. This puts SCE ~6 MW short of reaching 2018 Storage Targets, and ~216 MW from achieving 2020 Targets • SCE filed its 2018 Energy Storage and Investment Plan on March 1.  The 2018 Plan included AB 2868 proposals for Energy Storage Programs and Investments, in addition to procurement of energy storage via other solicitations (e.g., 20 MW min. for SB 801 – 2018 Aliso Canyon ES, + any eligible storage procured through IDER RFO, 2018 LCR RFP).  SCE expects to surpass its 2018 interim targets through the various procurement activities. 16 Eligible storage included in 2018 Storage Plan (pending approval) *Storage that is permitted to count in different categories due to flex counting rules Currently above targets 2018 Cumulative Procurement Target Energy Storage May 2, 2018

17 Transportation Electrification Overview Per SB 32, California’s goal to reduce total GHG emissions by 40 percent from 1990 levels by 2030 is 42% from current levels • Governor Order set a 2050 target of 80% below 1990 levels Many of California's policies to date focused on electric power, but other key areas need to be considered • Including the refining process, GHG emissions from the transportation sector is approximately 45% of the state’s emissions Commercial and Residential 11% Electrical Power 19% Agriculture 8% Industrial 23% Transportation 39% SCE is taking a leading role to ensure that transportation electrification plays a major part in reducing GHG and criteria pollutant emissions in California 2015 California GHG Emissions by Sector Note: Data for both charts from California Air Resources Board. May 2, 2018

SCE Transportation Electrification Proposals On January 20, 2017, SCE filed with the CPUC a wide-ranging plan to increase electrification of cars, buses, medium- and heavy-duty trucks and industrial vehicles and equipment • SCE proposed 6 near-term, priority review projects and 2 longer-term, standard review programs for a total of $574 million of total costs (includes both O&M and capital expenditures) • A proposed decision was issued on the standard review projects granting $208 million out of $554 million for medium- and heavy-duty with no after-the-fact reasonableness review • Only the five priority review projects approved by the CPUC are included in capital spending and rate base SCE’s Charge Ready Program targets the need for non-single family home charging and supports Governor’s Executive Order calling for 5 million zero emission vehicles by 2030 • Phase I ($22 million cost; $12 million rate base) approved by CPUC in January 2016 to support approximately 1,250 chargers (2016-2018) • Phase II request to be filed in Q2 2018 after completion of Phase I; >$200 million rate base opportunity to support remaining chargers in program, but could be substantially more SCE 2017 Transportation Electrification Application Proposals Program Name Category Timeframe Requested Total Cost1 Approved Residential Make-Ready Rebate Incentive Pilot Near-term $4 ✓ Urban Direct Current Fast Charge Clusters Infrastructure Pilot Near-term $4 ✓ Electric Transit Bus Make-Ready Infrastructure Pilot Near-term $4 ✓ Port of Long Beach (POLB) ITS Terminal Yard Tractor Infrastructure Pilot Near-term $0.5 ✓ POLB Rubber Tire Gantry Crane Electrification Infrastructure Pilot Near-term $3 ✓ EV Drive Rideshare Reward Incentive Pilot Near-term $4 ✕ Medium and Heavy-Duty Vehicle Charging Infrastructure Program Long-term $554 PD Issued New Commercial Electric Vehicle Rate Proposal Rate Design Program Long-term N/A PD Issued 1. Estimated Total Cost in 2016 $millions of constant dollars 18May 2, 2018

SCE Large Transmission Projects FERC Cost of Capital 11.5% ROE in 2018 (subject to refund): • ROE = Requested Base of 10.3% + CAISO Participation + weighted average of individual project incentives  Application for 2018 FERC Formula recovery mechanism filed on October 27, 2017  Requested 50 bp CAISO adder; approved, but application for rehearing requested by CPUC  ROE and proposed 2018 Transmission Revenue Requirement are accepted and suspended pending settlement discussions Summary of Large Transmission Projects Project Name Total Cost4 Remaining Investment (as of March 31, 2018) Estimated In-Service Date West of Devers1,2 $848 million $747 million 2021 Mesa Substation1 $646 million $521 million 2022 Alberhill System3 $486 million $448 million 2021 Riverside Transmission Reliability $405 million $397 million 2023 Eldorado-Lugo-Mohave Upgrade $233 million $190 million 2021 19 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. Received Proposed Decision from CPUC on April 4, 2018 denying SCE’s application for a certificate of public convenience and necessity for the Alberhill System Project. 4. Total Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval. SCE regularly evaluates the cost and schedule based on permitting processes, given that SCE continues to see delays in securing project approvals May 2, 2018

SCE Operational Excellence Top Quartile • Safety • Reliability • Customer service • Cost efficiency Optimize • Capital productivity • Purchased power cost High performing, continuous improvement culture Defining Excellence Measuring Excellence • Employee and public safety metrics • System performance and reliability (SAIDI, SAIFI, MAIFI) • J.D. Power customer satisfaction • O&M cost per customer • Reduce system rate growth with O&M / purchased power cost reductions Ongoing Operational Excellence Efforts 20May 2, 2018

Responding to Industry Change Long-Term Industry Trends Strategy • The technology landscape is evolving at an unprecedented pace, with innovation driving advances in cost and capabilities of distributed energy resources • Customer expectations are changing with increasing choices and alternatives, a growing priority of sustainability objectives, and flattening demand • The regulatory environment for utilities is complex, increasingly supportive of new forms of competition but unable to keep pace with new business models • Policies both in California and globally are setting aggressive greenhouse gas reduction targets SCE Strategy • Clean the power system by accelerating the de-carbonization of electricity supply • Help customers make cleaner energy choices to support electrification and leverage flexible energy demand • Strengthen and modernize the grid by replacing aging infrastructure and deploying technology • Achieve operational and service excellence with top tier performance in safety, reliability, affordability, and customer satisfaction Beyond SCE • Position Edison Energy as an independent energy advisor and integrator for large commercial and industrial customers 21May 2, 2018

• Energy is a significant risk large commercial and industrial customers face. Edison Energy creates competitive advantage for market leaders by quantifying this risk and designing the portfolio solution to protect shareholder value threatened by complex energy policies, technological advancements, and new products. • Optimized portfolio solutions based on robust analytics of the customer’s energy portfolio in alignment with their goals and strategic objectives • Implementation of solutions through existing service lines or brokering with third parties • Edison International investment $107 million as of March 31, 2018 Edison Energy Edison Energy Summary The Opportunity: Trusted Advisor and Solution Integrator 22 Managed Portfolio Solution Renewables & Sustainability Supply Solutions Demand Solutions Installations May 2, 2018

EIX Annual Dividends Per Share $0.80 $1.00 $1.08 $1.16 $1.22 $1.24 $1.26 $1.28 $1.30 $1.35 $1.42 $1.67 $1.92 $2.17 $2.42 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 1. 2018 Dividend annualized based on December 7, 2017 declaration increase Fourteen Years of Dividend Growth Target dividend growth at a higher than industry average growth rate within its target payout ratio of 45-55% of SCE earnings in steps over time 23 1 May 2, 2018

Appendix 24May 2, 2018

1. Cost of removal is the cost to remove existing equipment that is being replaced 2018 SCE GRC 25 Items Carried Over from 2015 GRC New Items from 2018 GRC Previous Intervenor Testimony • Requests continuation of Tax Accounting Memorandum Account (TAMA) adjusting revenues annually for over and undercollection of specified tax items • Forecasting over $85 million in 2018 O&M savings from Operational Excellence initiatives • Requests recovery for short- term incentive compensation plans for full-time employees ($41 million disallowance in 2015 GRC decision) • Requests continuation of pole loading capital recovery through balancing account • Capital expenditures of $1.8 billion for grid modernization capital to support improved safety and reliability and increased levels of distributed energy resources (DER) • Increased depreciation expense to reflect updated cost of removal estimates1  Limiting cost of removal request to mitigate customer rate impact beginning with $84 million increase in 2018  Further increases will likely be required over multiple GRC cycles • ORA - Proposed no Grid Modernization capital expenditures and ~90% of traditional capital expenditures • TURN - Proposed ~22% of Grid Modernization capital expenditures and ~85% of traditional capital expenditures May 2, 2018

SCE Historical Capital Expenditures ($ billions) $3.5 $4.0 $3.9 $3.5 $3.8 2013 2014 2015 2016 2017 26May 2, 2018

Detailed Capital Expenditures – 2017-2020 2017 (Actual) 2018 2019 2020 Total Distribution1,2 $3.1 $3.4 $3.2 $3.0 $12.7 Transmission1 0.5 0.6 0.8 0.9 2.7 Generation1 0.2 0.2 0.2 0.2 0.8 Total Traditional $3.8 $4.2 $4.1 $4.1 $16.3 Grid Modernization3 - - 0.6 0.6 1.3 Total $3.8 $4.2 $4.8 $4.7 $17.6 Capital Expenditure/Rate Base Detailed Forecast Detailed Rate Base at Request Levels – 2017-2020 2017 (Actual) 2018 2019 2020 Traditional Rate Base $26.2 $28.8 $31.1 $33.3 Grid Modernization - 0.3 0.7 1.3 Total $26.2 $29.1 $31.8 $34.6 1. Includes allocated capitalized overheads and general plant 2. Includes 2018 – 2020 capital expenditures of $105 million for Mobile Home Park, $49 million for Energy Storage, $10 million for priority review transportation electrification, and $4 million for Charge Ready Pilot 3. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding. ($ in billions) 27May 2, 2018

Distribution Power Grid of the Future One-Way Electricity Flow • System designed to distribute electricity from large central generating plants • Increasing penetration of distributed energy resources • Voltage centrally maintained • Limited situational awareness and visualization tools for power grid operators Renewable Generation Mandates Subsidized Residential Solar Limited Electric Vehicle Charging Infrastructure Variable, Two-Way Electricity Flow • Distribution system at the center of the power grid • System designed to manage fluctuating resources and customer demand • Digital monitoring and control devices and advanced communications systems to improve safety and reliability, and integrate DERs • Improved data management and power grid operations with cyber mitigation • Modernize utility distribution planning with distributed energy resources Maximize Distributed Resources and Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency Current State Future State 28May 2, 2018

Computing intelligence inside electrical substations Future circuit designs integrate Distributed Energy Resources and increase flexibility The distribution system will require transformative technologies in planning, design, construction and operation Net benefits to customers include increased safety, reliability, access to affordable programs, and ability to adopt new clean and distributed technologies State of the art operating tools for utility operators and engineers Remote sensors that collect localized information about the grid Devices that provide more flexibility during outage events Devices that provide stable voltage and power quality High speed wireless and fiber communications infrastructure Smart meters that provide information to facilitate customer reliability and affordability Grid Modernization Highlights Legend Remote Fault Indicator High speed bandwidth field area network (communication system) Intelligent Remote Switches Centrally controlled switched capacitor bank w/ voltage control 29May 2, 2018

Building next generation electric grid requires accelerating traditional Transmission and Distribution / Information Technology programs and investing in new capabilities • Upgrade portions of grid (such as 4kV system) to increase capacity, improve reliability, and address technology obsolescence • Automation to monitor and control grid equipment in real-time and improve flexibility of grid operations • Expansion of Communication Networks Capital will be deployed to achieve two primary objectives • Improving safety and reliability  Focus on worst performing circuits in conjunction with traditional infrastructure replacement activities • Increase DER integration and enable advanced operations on circuits with high forecasted penetration or where DERs can provide grid services 1. 2018 Grid Modernization spending is focused on safety and reliability and 2019-2020 spending is based on 2018 GRC Tax Reform February Update testimony; most 2018 spending focused on integration of distributed energy resources has been deferred and, if not approved in GRC decision, is expected to be requested in future GRC applications 2. Forecast excludes capitalized overheads SCE Grid Modernization – Request Level ($ billions) $1.3 Billion Capital Request for 2019-20201,2 $0.65 $0.61 2019 2020 2017 and 2018 capital expenditures related to grid modernization are included in traditional capital expenditures 30May 2, 2018

Distributed Energy Resources (DER) Proceedings 2018 Activities • Incentive Pilot Solicitation • Approval of DER contracts • Pilot Report on lessons learned • Societal Cost Test • Programs, Tariffs, and Streamlined Procurement 2018 Activities • DER Hosting Capacity analysis • Locational Net Benefits • DER forecasting and distribution planning alignment • DER driven grid modernization and integration into GRC • Distribution Deferral framework •Integration of DERs in distribution planning and operations •Development of tools and methodologies, including optimal locations & value of DERs •Framework for Grid Modernization •Field demonstrations Distribution Resource Plan (DRP) Proceeding’s Scope Elements •Define DER products & grid services •Sourcing DERs for grid need via competitive procurement, programs, and tariffs •DER cost-effectiveness methods •Utility incentives to pursue DERs for grid need, instead of traditional infrastructure •Utility role in DER markets; utility business model Integrated Distributed Energy Resources (IDER) Proceeding’s Scope Elements 31May 2, 2018

SCE Customer Demand Trends Note: See 2017 Edison International Financial and Statistical Reports for further information. 32 2013 2014 2015 2016 2017 Kilowatt-Hour Sales (millions of kWh) Residential 29,889 30,115 29,959 29,141 29,765 Commercial 40,649 42,127 42,207 41,565 41,873 Industrial 8,472 8,417 7,589 7,056 6,559 Public authorities 5,012 4,990 4,774 4,645 4,639 Agricultural and other 1,885 2,025 1,940 1,776 1,475 Subtotal 85,907 87,674 86,469 84,183 84,311 Resale 1,490 1,312 1,075 1,794 1,568 Total Killowatt-Hour Sales 87,397 88,986 87,544 85,977 85,879 Customers Residential 4,344,429 4,368,897 4,393,150 4,417,340 4,447,706 Commercial 554,5892 557,957 561,475 565,222 569,222 Industrial 10,584 10,782 10,811 10,445 10,274 Public authorities 46,323 46,234 46,436 46,133 46,410 Agricultural 21,679 21,404 21,306 21,233 21,045 Railroads and railways 99 105 130 133 137 Interdepartmental 23 22 22 22 24 Total Number of Customers 4,977,729 5,005,401 5,033,330 5,060,528 5,094,818 Number of New Connections 27,370 29,879 31,653 38,076 39,621 Area Peak Demand (MW) 22,534 23,055 23,079 23,091 23,508 May 2, 2018

California’s Energy Policy • On October 7, 2015, Governor Brown signed SB 350, which requires that 50 percent of energy sales to customers come from renewable power and a doubling of energy efficiency in existing buildings for California by 2030  Also requires Transportation Electrification investments and Integrated Resources Planning • 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 • 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 Carbon-free Efficient Electrification Energy Efficiency • Emissions targets met through optimization of renewables • 80% carbon-free electricity supported by energy storage • Accelerate electrification of the transportation sector  More than 7 million electric vehicles on California roads • Electrify nearly one-third of residential and commercial space and water heaters • Doubling of energy efficiency in existing buildings • Continuation of company programs and earnings incentive mechanism  SCE 2018 program budget: $289 million1  $0.03 per share earnings in 2018 Electric Power Company Roles Solar 40% Small Hydro 3% Geothermal 24% Wind 32% 2017 Renewable Resources: 31.6% of SCE’s portfolio Biomass 1% 1. Pending approval of proposed decision issued by CPUC on April 4, 2018, which approves SCE’s Business Plan and the associated budgets for 2018-2025 33May 2, 2018

SCE 2018 Bundled Revenue Requirement 34 Note: Rates in effect as of January 1, 2018. Represents bundled service which excludes Direct Access/CCA customers that do not receive generation services. SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 2015 2016 2017 2018 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 16.2 Fuel & Purchased Power (43%) Distribution (39%) Transmission (9%) Generation (9%) Other (0%) 2018 Bundled Revenue Requirement $ millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 4,869 7.0 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 4,362 6.2 Generation – owned generation investment and O&M 1,075 1.5 Transmission – greater than 220kV 1,032 1.5 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning, and prior-year over collections 5 0.0 Total Bundled Revenue Requirement ($millions) $11,343  Bundled kWh (millions) 69,856 = Bundled Systemwide Average Rate (¢/kWh) 16.2¢ May 2, 2018

35 9.7¢ 16.2¢ 8.0¢ 10.0¢ 12.0¢ 14.0¢ 16.0¢ 18.0¢ 20.0¢ 22.0¢ 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 ¢/kWh System Average Rate Historical Growth SCE’s system average rate has grown in line with inflation over the last 10 years SCE System Average Rate Los Angeles Area Inflation Comparative System Average Rates % Delta EIX – 16.2¢ -- PG&E – 19.5¢1 20% SDG&E – 22.0¢1 36% CAGR 20-yr ('98-’18) 10-yr ('08-'18) 5-yr ('13-'18) 2.7% 1.7% 0.4% 2.2% 1.9% 1.7% Energy Crisis and return to normal Higher gas price forecast post-Katrina leads to higher rates with subsequent refund of over collection Delay in 2012 GRC leads to shorter ramp-up of rate increase Rates reduced due to the implementation of 1) the SONGS Settlement, including NEIL insurance benefits, 2) lower fuel & purchased power costs, and 3) a lower 2015 GRC revenue requirement that includes flow-through tax benefits 1. PG&E Advice 5231-E, SDG&E Advice 3137-E May 2, 2018

• Assembly Bill 1171 permits cities and counties or a Joint Power Authority (JPA) 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 bundled service customer indifference  While not an impact on earnings, for every 1% of departing load, ~$6 million is shifted to remaining bundled service customers • On February 8, 2018, the Commission approved Resolution E-4907 requiring CCA’s to demonstrate compliance with annual Resource Adequacy (RA) requirements prior to commencing operations • Approximately 40% of SCE’s customer load has submitted an implementation plan to the CPUC for certification; timing of the load shift is uncertain at this time due to uncertainty related to the PCIA and compliance with RA requirements 1. AB 117 was introduced into the Assembly 1/22/2001 by Assembly member Migden, chaptered into law 9/24/2002 2. Track 1 refers to PCIA exemptions for care and medical baseline; Track 2 refers to evaluation and possible modification of the PCIA methodology Investor-Owned Utility (IOU) Community Choice Aggregation (CCA) Track 22: Review current PCIA Q4 2017 Q1 2018 Q2 2018 Q3 2018 Track 12: Opening/Reply Briefs Track 2: File testimony Track 1: Proposed decision Track 2: File opening briefs Track 2: Proposed decision Community Choice Aggregation (CCA) Overview PCIA OIR Timeline (R. 17-06-026) 30%-50% of SCE’s bundled service load could be part of a CCA by 2020 36May 2, 2018

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, nearly 400,000 residential customers migrated to TOU rate structures  Remaining 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) Surcharge, by 2019  “Super User Electric Surcharge” for usage 400% above baseline (~5% of current and forecasted residential load)  Minimum bills of approximately $10/month (applied to delivery revenue only) January 2014 2019 1.00 (55% of system usage) 2.19 (5%) Tier 1: 100% Tier 2: 101-400% SUE: >400% 1.25 (40%) Usage Level (% of Baseline)Usage Level (% of Baseline) Tier 1: 100% Tier 2: 101-130% Tier 4: >200% T ie re d R at e L e v e l (R e lati v e to T ie r 1 R at e ) Fixed Charge: (Single-Family) $0.94/month (Multi-Family) $0.73/month Minimum Bill: $10.28/month 37 T ie re d R at e L e v e l (R e lati v e to T ie r 1 R at e ) Tier 3: 131-200% 1.00 (51% of system usage) 1.20 (11%) 2.10 (16%) 2.30 (22%) Non-CARE, Unbundled Rates Fixed Charge: (Single-Family) $0.94/month (Multi-Family) $0.73/month Minimum Bill: $10.28/month May 2, 2018

Impacts of Abundant Solar Energy (Duck Curve) Season Existing Proposed 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 Weekends: All Weekdays and Weekends: All except 4-9pm Winter Weekdays: 9pm-8am Weekends: All Weekdays and Weekends: 9pm-8am Super Off-Peak Winter N/A Weekdays and Weekends: 8am-4pm 38 Proposed Time-of-Use (TOU) Period Changes • SCE has proposed to change its TOU pricing period definition for the first time in over 30 years  All non-residential and new residential NEM 2.0 customers are served on mandatory TOU rates • Abundant mid-day renewable energy lowers prices from 8 am-4 pm • Highest cost period is now 4 pm-9 pm, all-days • Proposal reduces stand-alone solar installation project economics, but improves business cases for projects that include energy storage May 2, 2018

39 • 262,576 combined residential and non-residential projects – 2,211 MW installed • 99.8 % solar projects • 256,387 residential – 1,382 MW • 6,189 non-residential – 829 MW • Approximately 4,038,536 MWh/year generated Note: NEM solar installations in SCE service territory include projects with solar PV only less than 1 MW. Residential Solar Installations in SCE Territory July 1, 2017 • Official start of NEM successor tariff; customers are subject to:  Mandatory TOU rate  Non-bypassable charges  Application fees July 31, 2017 • Residential customers who meet this deadline are grandfathered for current Time-of-use periods for maximum of 5 years (10 for non-residential) September 9, 2017 • Smart Inverters required on all solar installations Near Term Outlook • Combination of a flatter tiered rate and the mandatory TOU NEM 2.0 rate structure has helped contain and reduce the cost shift; further reductions are anticipated through new TOU pricing periods which are under review by the CPUC • Commission to revisit NEM Successor Tariff in 2019 where increased customer/demand charges and market priced export compensation rates will be explored Key Dates Monthly Installations and MW Installed 0 5 10 15 20 25 30 35 40 0 1000 2000 3000 4000 5000 6000 7000 2011 2012 2013 2014 2015 2016 2017 2018 M W Ins ta lle d Nu m ber o f R e si d e nti a l Ins ta lla tion s Installations MW SCE Net Metering Statistics (3/18) May 2, 2018

12.9 ₵ 16.4 ₵ US Average SCE 27% Higher SCE Rates and Bills Comparison 40 SCE’s average residential rates are above national average, but residential bills are below national average due to lower usage • SCE’s residential rates are above national average due, in part, to a cleaner fuel mix, high cost of living in the state, and lower system load factor than the rest of the country. • SCE’s residential customer usage is lower than the national average due to mild climate and higher energy efficiency appliance and building standards. • Average monthly residential bills are lower than national average as higher rate levels are more than offset by lower usage. Key FactorsKey Factors Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 2017. https://www.eia.gov/electricity/data/eia861m/index.html. 2017 Average Residential Rates (¢/kWh) 2017 Average Residential Bills ($ per Month) $127 $93 US Average SCE 27% Lower May 2, 2018

First Quarter Earnings Summary 41 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Impact of hypothetical liquidation at book value (HLBV) accounting method and expected loss on sale of SoCore Energy 3. SCE’s 2018 core EPS drivers other than income taxes are adjusted to reflect consistent tax rates; income tax line item reflects impact of change in tax rate 4. Excludes 2017 San Onofre revenue of $0.03, depreciation of $0.07, interest expense of $0.01 which was offset by income tax of $(0.11) 5. Excludes $0.10 of income tax benefits related to Tax Reform refunded to customers Note: Diluted earnings were $0.67 and $1.10 per share for the three months ended March 31, 2018 and 2017, respectively. Q1 2018 Q1 2017 Variance Basic Earnings Per Share (EPS)1 SCE $0.88 $1.07 $(0.19) EIX Parent & Other (0.21) 0.04 (0.25) Discontinued Operations    Basic EPS $0.67 $1.11 $(0.44) Less: Non-Core Items SCE $  $  $  EIX Parent & Other2 (0.13)  (0.13) Discontinued Operations    Total Non-Core Items $(0.13) $  $(0.13) Core Earnings Per Share (EPS)1 SCE $0.88 $1.07 $(0.19) EIX Parent & Other (0.08) 0.04 (0.12) Core EPS1 $0.80 $1.11 $(0.31) Key SCE EPS Drivers3 Revenue4 $  - CPUC (0.02) - FERC revenue 0.02 Higher O&M (0.10) Higher net financing costs (0.02) Income taxes5 (0.04) Other (0.03) - Property and other taxes (0.01) - Other income and expenses (0.02) Total core drivers $(0.19) Non-core items  Total $(0.19) Key EIX EPS Drivers EIX parent – Benefits on stock based comp in 2017 and tax reform $(0.12) Total core drivers $(0.12) Non-core items2 (0.13) Total $(0.25) May 2, 2018

SCE Annual Results of Operations • 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 ($ millions) 20171 20161 Earnings Activities Cost-Recovery Activities Total Consolidated Earnings Activities Cost-Recovery Activities Total Consolidated Operating revenue $6,611 $5,643 $12,254 $6,504 $5,326 $11,830 Purchased power and fuel — 4,873 4,873 — 4,527 4,527 Operation and maintenance 1,902 769 2,671 1,939 798 2,737 Depreciation and amortization 2,032 — 2,032 1,998 — 1,998 Property and other taxes 372 — 372 351 — 351 Impairment and other charges 716 — 716 — — — Other operating income (8) — (8) — — — Total operating expenses 5,014 5,642 10,656 4,288 5,325 9,613 Operating income 1,597 1 1,598 2,216 1 2,217 Interest expense (588) (1) (589) (540) (1) (541) Other income and expenses 97 — 97 79 — 79 Income before income taxes 1,106 — 1,106 1,755 — 1,755 Income tax (benefit) expense (30) — (30) 256 — 256 Net income 1,136 — 1,136 1,499 — 1,499 Preferred and preference stock dividend requirements 124 — 124 123 — 123 Net income available for common stock $1,012 — $1,012 $1,376 — $1,376 Less: Non-core earnings (481) — Core Earnings $1,493 $1,376 42May 2, 2018 1. Results of operations for 2017 and 2016 do not reflect the retrospective adoption of the new accounting standards update on the presentation of the components of net periodic benefit costs for defined benefit pension and other postretirement plans. Note: See Use of Non-GAAP Financial Measures.

Earnings Non-GAAP Reconciliations 43 1. Impairment and other charges of $66 million ($48 million after-tax) in the first quarter of 2018 resulting from Edison International's agreement to sell SoCore Energy to a third party. The net assets of SoCore Energy have been recorded at fair value, less expected transaction costs 2. Includes income related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method of $6 million ($4 million after-tax) for the first quarter ended March 31, 2018, compared to income of $1 million (less than $1 million after-tax) for the same periods in 2017. Note: See Use of Non-GAAP Financial Measures. ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings Earnings Attributable to Edison International Q1 2018 Q1 2017 SCE $286 $349 EIX Parent & Other (68) 13 Basic Earnings $218 $362 Non-Core Items SCE $ – $ – EIX Parent & Other1,2 (44) – Total Non-Core $(44) $ – Core Earnings SCE $286 $349 EIX Parent & Other (24) 13 Core Earnings $262 $362 May 2, 2018

EIX Core EPS Non-GAAP Reconciliations 44 Reconciliation of Edison International Basic Earnings Per Share to Edison International Core Earnings Per Share Note: See Use of Non-GAAP Financial Measures. Earnings Per Share Attributable to Edison International 2015 2016 2017 CAGR Basic EPS 3.13 $4.02 $1.73 (26%) Non-Core Items SCE Write down, impairment and other charges (1.18) — (1.38) Re-measurement of deferred taxes — — (0.10) Insurance recoveries 0.04 — — Edison International Parent and Other Re-measurement of deferred taxes — — (1.33) Edison Capital sale of affordable housing portfolio 0.03 — — Income from allocation of losses to tax equity investor 0.03 0.02 0.04 Discontinued operations 0.11 0.03 — Less: Total Non-Core Items (0.97) 0.05 (2.77) Core EPS $4.10 $3.97 $4.50 5% May 2, 2018

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, Senior Manager (626) 302-5493 allison.bahen@edisonintl.com 45May 2, 2018