EX-99.1 2 eixfebruary2018businessu.htm EXHIBIT 99.1 EIX BUSINESS PRESENTATION
February 23, 2018 Business Update February 2018 Exhibit 99.1

February 23, 2018 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 San Onofre, uninsured wildfire-related liabilities, and spending on grid modernization; • ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire- 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 and the recoverability of wildfire-related costs, and delays in regulatory actions; • 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 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 plan, and governmental approvals. Other important factors are discussed under the headings “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

February 23, 2018 2 Page Updated (U) or New (N) from October 2017 Business Update EIX Shareholder Value 3 U SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 U California Wildfire Risk Mitigation 7 N Capital Expenditures and Rate Base History and Forecast 8-11 N,U 2018 General Rate Case 12 U Key Regulatory Proceedings 13 U CPUC Cost of Capital 14 U 2018 Financial Assumptions 15 N Distribution and Transmission Capital Expenditure Detail 16-20 U Operational Excellence 21 EIX Responding to Industry Change 22 Edison Energy Group Summary 23 U Annual Dividends Per Share 24 U Appendix 2018 General Rate Case Overview 26 U Historical Capital Expenditures 27 U Capital Expenditure and Rate Base Detailed Forecast 28 U Power Grid of the Future, Grid Modernization 29-32 U SCE Customer Demand Trends 33 U California Energy Policy 34 U SCE Bundled Revenue Requirement, System Average Rate Historical Growth 35-36 CCA Overview, Residential Rate Reform and Other 37-40 U SCE Rates and Bills Comparison 41 U Fourth Quarter and Full-Year 2017 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 42-47 N,U Table of Contents

February 23, 2018 3 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 Group Strategy • Edison Energy - services for large commercial and industrial customers • SoCore Energy – commercial and community solar; undergoing a strategic review including possible sale

February 23, 2018 4 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

February 23, 2018 5 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 • 2018-2020 – $49 million of capital requested in 2018 GRC application • 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 • 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

February 23, 2018 6 SCE Decoupled Regulatory Framework Decoupling of Revenues from Sales Major Balancing Accounts • Sales • Fuel and Purchased power • Energy efficiency • Pension expense Advanced Long-Term Procurement Planning Forward-looking Ratemaking • 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 • Cost-recovery related balancing accounts represented more than 53% of costs • Trigger mechanism for fuel and purchased power adjustments at 5% variance level • Upfront contract approvals and prudency standards provide greater certainty of cost recovery (subject to compliance- related reasonableness review) • Forward and test year GRC with three-year rate cycle • Separate cost of capital mechanism Regulatory Mechanism Key Benefits

February 23, 2018 7 California Wildfire Risk Mitigation Hardening the infrastructure Prevention and mitigation Allocation of risk and liability • Effective statewide fire suppression resources • Effective vegetation management policies • Hazardous fuels reduction • Policies for residential and commercial development in high fire risk area • Operational mitigation  Inspecting and upgrading poles  Operating differently under Red Flag warnings  Preemptively de- energize lines in high fire risk areas during severe wind events • Partnering with state agencies on improved standards for climate resilient infrastructure • Stronger building codes in high fire risk areas • Assessing the design and operation of the system  Standards for new infrastructure in High Fire Risk Areas  Alternative risk- mitigation measures to limit fault current, proactive infrared scanning • Policies around allocation of financial risks, including fire suppression costs and damages • Reforming the application of inverse condemnation or 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

February 23, 2018 8 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

February 23, 2018 9 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 $4 million for Charge Ready 2. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures 3. 2018 spending at budget levels; 2019-2020 are at GRC request levels Note: Forecasted capital spending includes CPUC, FERC and other spending. 2019-2020 based on GRC update submitted February 2018 (incorporates impact of tax reform). See Capital Expenditure/Rate Base Detailed Forecast for further information, including potential investment excluded in forecasts. Delta represents change from October 2017 Business Update. ($ 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  Excludes standard review transportation electrification projects and Charge Ready Phase II • 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 $3.7 $4.9 $5.0 $4.9 Delta 0.1 (0.7) (0.2) (0.2) 1 3 2

February 23, 2018 10 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, which FERC approved Other • Updated to include Tax Reform impact • Includes mobile home pilot program, charge ready pilot, and priority review transportation electrification ($ billions) 3-year CAGR of 9.7% Prior Forecast $26.1 $29.2 $31.7 $34.3 Delta 0.1 (0.1) 0.1 0.3 $26.2 $29.1 $31.8 $34.6 2017 (Autho ized) 2018 2019 2020 Traditional Grid Modernization Note: Weighted-average year basis. 2017 based on 2015 GRC decision. 2018-2020 based on GRC update submitted February 2018 (incorporates impact of tax reform), 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.

February 23, 2018 11 SCE Rate Base Forecast Updates ($ billions) *Note: Numbers may not foot due to rounding. Incentive CWIP Approval at FERC for Mesa, Alberhill and Eldorado-Lugo-Mohave accelerates the inclusion of capital spend into FERC rate base. Previously projects would have accrued AFUDC until project in-service date and then become part of rate base. FERC Capital Changes reflects impacts of latest capital forecast. Permanent capital efficiencies related to SCE’s transmission line remediation program make up approximately $0.2 of the $0.6 billion reduction by 2020. The remainder is primarily due to timing of major project spend. GRC Request Case 2018 2019 2020 Prior Outlook – October 2017 $ 29.2 $ 31.7 $ 34.3 Tax Reform CPUC (0.0) 0.1 0.3 FERC  0.1 0.1 Subtotal Tax Reform (0.0) 0.2 0.4 Other FERC Changes* Incentive CWIP Approval 0.2 0.3 0.5 FERC Capital Changes (0.2) (0.5) (0.6) Subtotal FERC (0.0) (0.2) (0.1) Other CPUC Changes (0.0) 0.1 0.1 Total Change (0.1) 0.1 0.3 Updated Outlook - February 2018 $ 29.1 $ 31.8 $ 34.6

February 23, 2018 12 • 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 GRC 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

February 23, 2018 13 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 Ongoing workshops and data requests; intervenor and rebuttal testimony submitted; Briefs and reply briefs filed in September 2017; updated Testimony filed on February 16, 2018 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 growth scenarios expected in February; Proposed Decision on grid modernization expected in Q1 2018 Integrated Distributed Energy Resources OIR (R. 14-10-003) Creating consistent framework for guidance, planning and evaluation of DERs SCE launched its IDER Incentive Pilot Solicitation on January 12, 2018; Final Selection notification will occur on May 11, 2018 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 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

February 23, 2018 14 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 – 02/20/18) = 4.21% 100 basis point +/- Deadband Starting Value – 5.00% Two year settlement approved • 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 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 and 2019, independent of trigger mechanism ROE fixed at 10.45% for 2017, independent of trigger mechanism

February 23, 2018 15 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 up to $0.03 per share • Revenues recorded at 2017 levels until 2018 GRC decision is received (retroactive to January 1, 2018) • 2018 EIX Parent and Other EPS guidance range: ($0.25) to ($0.30) per share  Increased holding company drag to 2 cents per share per month related to lower tax shield and higher interest expense  Includes EPS estimate for Edison Energy; continued progress to breakeven run rate by year-end 2019

February 23, 2018 16 SCE Distribution System Investments 1. Other includes GRC energy storage, Charge Ready Phase I 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 2017 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

February 23, 2018 17 Energy Storage Given counting rules, SCE has already met the aggregate 2016 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) • Recent decision 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’s storage portfolio includes resources procured through storage- specific RFOs, broader solicitations (e.g., LCR RFO, PRP 2 RFO), SCE- owned pilots and demonstrations, and customer programs • SCE has procured close to 500 MW total, of which approximately 418 MW is eligible to count to the targets. The 418 MW includes:  120 MW from SCE’s Preferred Resources Pilot 2 solicitation, currently pending approval  Approximately 52 MW of Utility-Owned Storage o 12 MW are previous pilots and demonstrations o 40 MW sought cost recovery via the Aliso Canyon application • SCE’s filed its 2016 Energy Storage and Distribution Deferral Application (A.) 17-12-002 on December 1, 2017, which seeks contract approval of 10 MW of distribution connected storage • SCE’s Energy Storage Procurement and Investment Plan application will be filed March 1. The Plan will include AB 2868 proposals for Energy Storage Programs and Investments, in addition to the usual procurement of energy storage through other RFOs Cost Recovery Mechanism for Storage Utility-Owned Storage (“UOS”) (except Aliso Canyon RFP) Capital Expenditures – General Rate Case Third-Party Owned Storage Energy Resource Recovery Account Aliso Canyon UOS Application filed March 30 115 70 25 0 50 100 150 200 250 Transmission Distribution Customer M W SCE 2017 Storage Portfolio 85 MW excess may offset T&D targets Eligible storage included in approved 2016 Storage Plan New procurement; some contracts pending CPUC approval. Currently above targets 2016 Cumulative Procurement Target

February 23, 2018 18 California GHG Emissions Overview California’s goals to reduce total GHG emissions by 40 percent from 1990 levels by 2030 is 42% from current levels • Recent 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.

February 23, 2018 19 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) • 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 and SCE’s Clean Power and Electrification Pathway calling for more than 7 million electric vehicles by 2030 • Phase I ($22 million cost; $12 million rate base) approved by CPUC in January 2016 to support approximately 1,500 chargers (2016-2017) • 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 SCE 2017 Transportation Electrification Application Proposals Program Name Category Timeframe Estimated 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 TBD New Commercial Electric Vehicle Rate Proposal Rate Design Program Long-term N/A TBD 1. Estimated Total Cost in $millions of constant dollars

February 23, 2018 20 SCE Large Transmission Projects 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. 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 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 Cost3 Remaining Investment (as of Dec 31, 2017) Estimated In-Service Date West of Devers1,2 $848 million $757 million 2021 Mesa Substation1 $646 million $568 million 2022 Alberhill System $486 million $449 million 2021 Riverside Transmission Reliability $405 million $397 million 2023 Eldorado-Lugo-Mohave Upgrade $233 million $202 million 2021

February 23, 2018 21 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

February 23, 2018 22 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

February 23, 2018 23 • Edison Energy is an advisory and services company with the capabilities to develop and integrate an array of energy solutions to help commercial and industrial customers improve management of their energy costs and risks in dealing with increasingly complex tariff and technology choices • Edison Energy’s core advisory capabilities were formed through Edison International’s acquisition of three companies in December 2015: Altenex, Eneractive Solutions and Delta Energy • Edison International investment $103 million as of December 31, 2017 Edison Energy Edison Energy Group Summary SoCore Energy • Provider of distributed solar solutions focused on the following segments:  Commercial & Industrial  Electric Cooperatives & Municipalities  Community Solar  Advanced Energy Solutions - commercial and distributed energy storage • 150 MW of commercial-scale solar systems constructed and in operation as of December 31, 2017 • Edison International investment $248 million as of December 31 2017; undergoing a strategic review including possible sale The Opportunity: Trusted Advisor and Solution Integrator

February 23, 2018 24 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 Note: See Use of Non-GAAP Financial Measures. 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

February 23, 2018 25 Appendix

February 23, 2018 26 • 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 Items Carried Over from 2015 GRC New Items from 2018 GRC • 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 1. Cost of removal is the cost to remove existing equipment that is being replaced 2018 SCE GRC Previous Intervenor Testimony • 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

February 23, 2018 27 SCE Historical Capital Expenditures ($ billions) $3.5 $4.0 $3.9 $3.5 $3.8 2013 2014 2015 2016 2017

February 23, 2018 28 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 Transportation Electrification, and $4 million for Charge Ready 3. 2017 and 2018 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding. ($ in billions)

February 23, 2018 29 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

February 23, 2018 30 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

February 23, 2018 31 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 GRC update submitted February 2018 (incorporates impact of tax reform); 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 ($ 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 SCE Grid Modernization – Request Level

February 23, 2018 32 Distributed Energy Resources (DER) Proceedings 2018 Activities • Incentive Pilot Solicitation • Approval of DER contracts • Pilot Report on lessons learned • Societal Cost Test 2018 Activities • DER Hosting Capacity analysis • Locational Net Benefits • DER forecasting and distribution planning alignment • DER driven grid modernization and integration into General Rate Case • 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

February 23, 2018 33 2016 29,141 41,565 7,056 4,645 1,776 84,183 1,794 85,977 4,417,340 565,222 10,445 46,133 21,233 133 22 5,060,528 38,076 23,091 SCE Customer Demand Trends Kilowatt-Hour Sales (millions of kWh) Residential Commercial Industrial Public authorities Agricultural and other Subtotal Resale Total Kilowatt-Hour Sales Customers Residential Commercial Industrial Public authorities Agricultural Railroads and railways Interdepartmental Total Number of Customers Number of New Connections Area Peak Demand (MW) 2013 29,889 40,649 8,472 5,012 1,885 85,907 1,490 87,397 4,344,429 554,592 10,584 46,323 21,679 99 23 4,977,729 27,370 22,534 Note: See 2016 Edison International Financial and Statistical Reports for further information. 2014 30,115 42,127 8,417 4,990 2,025 87,674 1,312 88,986 4,368,897 557,957 10,782 46,234 21,404 105 22 5,005,401 29,879 23,055 2015 29,959 42,207 7,589 4,774 1,940 86,469 1,075 87,544 4,393,150 561,475 10,811 46,436 21,306 130 22 5,033,330 31,653 23,079 2017 29,765 41,873 6,559 4,639 1,475 84,311 1,568 85,879 4,447,706 569,222 10,274 46,410 21,045 137 24 5,094,818 39,621 23,508

February 23, 2018 34 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 Renewables Transportation Electrification Energy Efficiency Legislative Action • Emissions targets met through optimization of renewables, transportation electrification, energy efficiency Regulatory Approach: Company participation through infrastructure investment • SCE Charge Ready Program • Other medium and heavy duty transportation electrification in service territory Continuation of company programs and earnings incentive mechanism • SCE 2018 program budget: $299.6 million1 • $0.03 per share earnings in 2018 Electric Power Company Roles Solar 39% Small Hydro 3% Geothermal 24% Wind 33% 2017 Renewable Resources (Preliminary): 32.1% of SCE’s portfolio Biomass 1% 1. Pending approval of Advice Letter; SCE 2017 program budget of $333 million is in effect until approved

February 23, 2018 35 SCE 2017 Bundled Revenue Requirement Note: Rates in effect as of October 1, 2017. Represents bundled service which excludes Direct Access customers that do not receive generation services. SCE Systemwide Average Rate History (¢/kWh) 2010 2011 2012 2013 2014 2015 2016 2017 14.3 14.1 14.3 15.9 16.7 16.2 14.8 15.7 Fuel & Purchased Power (45%) Distribution (39%) Transmission (9%) Generation (9%) Other (-2%) 2017 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 5,130 7.1 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 4,386 6.1 Generation – owned generation investment and O&M 1,075 1.5 Transmission – greater than 220kV 1,064 1.5 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning, and prior- year over collections (380) (0.4) Total Bundled Revenue Requirement ($millions) $11,275  Bundled kWh (millions) 71,961 = Bundled Systemwide Average Rate (¢/kWh) 15.7¢

February 23, 2018 36 9.7¢ 15.7¢ 8.0¢ 10.0¢ 12.0¢ 14.0¢ 16.0¢ 18.0¢ 20.0¢ 22.0¢ 1990 1993 1996 1999 2002 2005 2008 2011 2014 2017 ¢/kWh System Average Rate Historical Growth SCE’s system average rate has grown in line with inflation over the last 25 years SCE System Average Rate Los Angeles Area Inflation Comparative System Average Rates % Delta EIX – 15.7¢ -- PG&E – 18.8¢ 16% SDG&E – 21.8¢ 27% CAGR 20-yr ('97-’17) 10-yr ('07-'17) 5-yr ('12-'17) 2.2% 1.2% 1.8% 2.1% 1.7% 1.3% 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

February 23, 2018 37 • 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  While not an impact on earnings, for every 1% of departing load, $6 million is shifted to other customers remaining in the system • Assembly Bill 1171 permits cities and counties or a Joint Powers Agency (JPA) to act as CCAs to purchase and sell electricity on behalf of the utility customers within their jurisdiction • Approximately 20% 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 because of enhanced Resource Adequacy demonstration requirements being considered by the CPUC • On February 8, 2017, the Commission voted on a Draft Resolution that mandates CCAs to purchase their full share of Resource Adequacy (RA) for the first year of operations 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) 40-50 percent of SCE’s electric load could be part of a CCA by 2025

February 23, 2018 38 • CPUC Order Instituting Ratemaking R.12-06-013 comprehensively reviewed residential rate structure, including a future transition to time of use (TOU) rates  In 2018, 400,000 residential customers migrated to TOU rate structure; remainder to be migrated by 2020-2021 • July 2015 CPUC Decision D.15-07-001 includes:  Transition to 2 tiered rate structure by 2019  “Super User Electric Surcharge” for usage 400% above baseline (~5% of current residential load)  In December 2017, IOUs filed customer charges (i.e. $5-10/month) to be effective with transition to TOU rate structure  Minimum bills of approximately $10/month, which would apply to delivery revenue only Current Rates (non-CARE, Bundled) – January 2018 Future Rates (non-CARE, Bundled) – 2019 Note: The baseline allowance varies by season and household. For this particular scenario, the baseline region selected was 9. For the summer, the baseline allowance is 420 kWh and 380 kWh for a non-all-electric and an all-electric household, respectively. For the winter, the baseline allowance is 322 kWh and 447 kWh for a non-all-electric and an all-electric household, respectively. 1.000 2.190 100% 101-400% >400% 1.250 Usage Level (% of Baseline)Usage Level (% of Baseline) 1.000 1.410 1.985 100% 101-400% >400% T ier D if feren ti a l (Ba se : T ier 1 ) Fixed Charge: $0.94/month (single-family), $0.73 (multi-family) Minimum Bill: $10.28/month T ier D if feren ti a l (Ba se : T ier 1 ) Residential Rate Design OIR Decision

February 23, 2018 39 SCE Net Metering Rate Structure NEM Rate Developments: • NEM allowed residential customers to receive rate credit for exported generation, and use these credits to offset energy purchased from the electric power company, leading to a cost-shift to non-NEM customers  Through tiered rate flattening, Residential Rate OIR decision was expected to reduce subsidy by 30% (under current TOU periods) or 56% (under proposed TOU periods), compared to subsidy level four years ago • Current NEM tariff ended on July 1, 2017  Customers on current tariff grandfathered for 20 years • In January 2016, CPUC voted (3-2) to adopt a successor to the current NEM tariff • PG&E, SDG&E, SCE, and TURN filed Applications for Re-hearing (AFRs) on March 7, 2016; Solar Parties filed protest responses to the AFRs on March 21, 2016; CPUC denied parties’ AFRs on September 22, 2016 SCE Net Energy Metering Statistics (December 2017): • 252,501 combined residential and non-residential projects – 2,121 MW installed  99.79 % solar  246,515 residential – 1,322 MW  5,986 non-residential – 799 MW  Approximately 3,887,092 MWh/year generated 7¢/kWh 19₵/kWh12₵/kWh 0 5 10 15 20 25 ¢/k W h Solar Subsidies (Illustrative) Avoided Generation (excludes RPS Premium) Subsidy Paid by Residential Ratepayers [1] Equivalent Solar Offset 1. Subsidy paid by non-residential ratepayers estimated to be lower than that paid by residential ratepayers. For instance, the equivalent solar offset, system-wide, is approximately 14 ¢/kWh for GS-1 customers, making the subsidy paid by non-NEM customers roughly 7¢/kWh. Exact figures pending analysis

February 23, 2018 40 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 Time-Of-Use 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 2019 (Estimated) • Commission to revisit NEM Successor Tariff Key DatesMonthly Installations and MW Installed 0 5 10 15 20 25 30 35 40 0 1000 2000 3000 4000 5000 6000 7000 2010 2011 2012 2013 2014 2015 2016 2017 MW I nstal le d N u m b e r o f R e si de n tial I nstal la ti o n s Installations MW

February 23, 2018 41 SCE Rates and Bills Comparison 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 rest of the country. • Average monthly residential bills are lower than national average. Higher rate levels are offset by lower usage.  Lower SCE residential customer usage than national average due to mild climate and higher energy efficiency building standards Key FactorsKey Factors Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 12 months ending Nov 2017. https://www.eia.gov/electricity/data/eia861m/index.html. 13.3 ₵ 16.4 ₵ US Average SCE 23% Higher 2016-17 Average Residential Rates (¢/kWh) 2016-17 Average Residential Bills ($ per Month) $125 $94 US Average SCE 25% Lower

February 23, 2018 42 Q4 2017 Q4 2016 Variance Basic Earnings Per Share (EPS)1,2 SCE $(0.33) $1.01 $(1.34) EIX Parent & Other (1.34) (0.04) (1.30) Discontinued Operations  0.04 (0.04) Basic EPS $(1.67) $1.01 $(2.68) Less: Non-Core Items SCE3 $(1.48) $  $(1.48) EIX Parent & Other3 (1.29)  (1.29) Discontinued Operations4  0.04 (0.04) Total Non-Core Items $(2.77) $0.04 $(2.81) Core Earnings Per Share (EPS)1 SCE $1.15 $1.01 $0.14 EIX Parent & Other (0.05) (0.04) (0.01) Core EPS1 $1.10 $0.97 $0.13 Key SCE EPS Drivers Revenue5 $0.14 - CPUC – Escalation 0.11 - CPUC – Other 0.02 - FERC revenue (0.01) - Other operating revenue 0.02 Higher O&M (0.01) Higher net financing costs (0.01) Income taxes 0.05 Other (0.03) - Property and other taxes (0.02) - Other income and expenses (0.01) Total core drivers $0.14 Non-core items3 (1.48) Total $(1.34) Fourth Quarter Earnings Summary Key EIX EPS Drivers EIX parent – Income taxes $(0.03) EEG – Higher operating revenue and other 0.02 Total core drivers $(0.01) Non-core items3,4 (1.33) Total $(1.34) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. 2016 Income Statement was updated to reflect the implementation of the accounting standard for share-based payments effective January 2016 3. See EIX Core EPS Non-GAAP reconciliation in Appendix 4. Impact primarily related to the resolution of tax issues and other impacts related to the EME bankruptcy 5. Excludes San Onofre revenue of $0.11 and interest expense of $0.01 which was offset by income taxes of $(0.12) Note: Diluted earnings were $(1.66) and $1.00 per share for the three months ended December 31, 2017 and 2016, respectively.

February 23, 2018 43 2017 2016 Variance Basic Earnings Per Share (EPS)1 SCE $3.10 $4.22 $(1.12) EIX Parent & Other (1.37) (0.23) (1.14) Discontinued Operations  0.03 (0.03) Basic EPS $1.73 $4.02 $(2.29) Less: Non-Core Items SCE2 $(1.48) $  $(1.48) EIX Parent & Other2 (1.29) 0.02 (1.31) Discontinued Operations3  0.03 (0.03) Total Non-Core Items $(2.77) $0.05 $(2.82) Core Earnings Per Share (EPS)1 SCE $4.58 $4.22 $0.36 EIX Parent & Other (0.08) (0.25) 0.17 Core EPS1 $4.50 $3.97 $0.53 Key SCE EPS Drivers Revenue,4,5,6 $0.45 - CPUC – Escalation 0.44 - CPUC – Other 0.04 - FERC revenue (0.07) - Other operating revenue 0.04 Lower O&M 0.07 Higher depreciation (0.07) Higher net financing costs (0.06) Income taxes4,5  Other (0.03) - Property and other taxes (0.05) - Other operating income 0.01 - Other income and expenses 0.01 Total core drivers $0.36 Non-core items2 (1.48) Total $(1.12) Key EIX EPS Drivers EIX parent – Income taxes and other $0.11 EEG 0.06 - Buyout of an earn-out provision in 2016 0.04 - SoCore Energy goodwill impairment in 2017 (0.03) - Operating revenue and income tax benefits 0.05 Total core drivers $0.17 Non-core items2,3 (1.34) Total $(1.17) 1. See Earnings Non-GAAP reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. See EIX Core EPS Non-GAAP reconciliation in Appendix 3. Impact primarily related to the resolution of tax issues and other impacts related to the EME bankruptcy 4. Excludes lower income tax benefits of $0.24 due to refunds for incremental tax benefits related to 2012 – 2014 repair deductions in 2016 5. Excludes higher income tax benefits for incremental tax repair deductions, pole-loading program-based cost of removal and tax accounting method changes of $0.46 6. Excludes San Onofre revenue of $(0.03) which was offset by depreciation of $0.01, property taxes of $0.01 and interest expense of $0.01 Note: Diluted earnings were $1.78 and $3.97 per share for the twelve months ended December 31, 2017 and 2016, respectively. Full Year 2017Earnings Summary

February 23, 2018 44 $11,830 4,527 2,737 1,998 351 — — 9,613 2,217 (541) 79 1,755 256 1,499 123 $1,376 — $1,376 $5,326 4,527 798 — — — — 5,325 1 (1) — — — — — $— $6,504 — 1,939 1,998 351 — — 4,288 2,216 (540) 79 1,755 256 1,499 123 $1,376 $12,254 4,873 2,671 2,032 372 716 (8) 10,656 1,598 (589) 97 1,106 (30) 1,136 124 $1,012 (481) $1,493 $5,643 4,873 769 — — — — 5,642 1 (1) — — — — — $— $6,611 — 1,902 2,032 372 716 (8) 5,014 1,597 (588) 97 1,106 (30) 1,136 124 $1,012 SCE Annual Results of Operations • Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards Earning Activities Cost- Recovery Activities Total Consolidated 2017 Earning Activities Cost- Recovery Activities Total Consolidated 2016 Operating revenue Purchased power and fuel Operation and maintenance Depreciation and amortization Property and other taxes Impairment and other charges Other operating income Total operating expenses Operating income Interest expense Other income and expenses Income before income taxes Income tax (benefit) expense Net income Preferred and preference stock dividend requirements Net income available for common stock Less: Non-core earnings Core Earnings Note: See Use of Non-GAAP Financial Measures. ($ millions)

February 23, 2018 45 Earnings Non-GAAP Reconciliations (*) 2016 Income Statement was updated to reflect the implementation of the accounting standard for share-based payments effective January 2016 1. Includes impairment and other charges of $716 million ($448 million after-tax) related to the Revised San Onofre Settlement Agreement and $33 million tax expense from the re- measurement of deferred taxes as a result of Tax Reform 2. Includes tax expense of $433 million recorded in the fourth quarter of 2017 for the re-measurement of deferred taxes as a result of Tax Reform. Also includes income related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method of $20 million ($12 million after-tax) and $21 million ($13 million after-tax) for the quarter and year-end ended December 31, 2017, respectively, compared to income of $1 million (less than $1 million after-tax) and $9 million ($5 million after-tax) for the same periods in 2016, respectively 3. Includes income from discontinued operations of $13 million after-tax and $1 million ($12 million after-tax) for the quarter and year-end ended December 31, 2016, respectively, which was primarily related to the resolution of tax issues related to EME Note: See Use of Non-GAAP Financial Measures. ($ millions) SCE EIX Parent & Other Discontinued Operations Basic Earnings Non-Core Items SCE1 EIX Parent & Other2 Discontinued Operations3 Total Non-Core Core Earnings SCE EIX Parent & Other Core Earnings Reconciliation of EIX GAAP Earnings to EIX Core Earnings $(109) (436) – $(545) $(481) (421) – $(902) $372 (15) $357 Q4 2016 (*) Q4 2017 Earnings Attributable to Edison International $1,012 (447) – $565 $(481) (420) – $(901) $1,493 (27) $1,466 20162017 $328 (12) 13 $329 $ – – 13 $13 $328 (12) $316 $1,376 (77) 12 $1,311 $ – 5 12 $17 $1,376 (82) $1,294

February 23, 2018 46 EIX Core EPS Non-GAAP Reconciliations Basic EPS Non-Core Items SCE Write down, impairment and other charges Re-measurement of deferred taxes Insurance recoveries Edison International Parent and Other Re-measurement of deferred taxes Edison Capital sale of affordable housing portfolio Income from allocation of losses to tax equity investor Discontinued operations Less: Total Non-Core Items Core EPS Reconciliation of Edison International Basic Earnings Per Share to Edison International Core Earnings Per Share (26%) 5% Note: See Use of Non-GAAP Financial Measures. $3.13 (1.18) — 0.04 — 0.03 0.03 0.11 (0.97) $4.10 Earnings Per Share Attributable to Edison International CAGR20172015 $4.02 — — — — — 0.02 0.03 0.05 $3.97 2016 $1.73 (1.38) (0.10) — (1.33) — 0.04 — (2.77) $4.50

February 23, 2018 47 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