EX-99.1 2 eixsceexhibit991a01.htm EDISON INTERNATIONAL BUSINESS UPDATE PRESENTATION DATED OCTOBER 31, 2017
October 31, 2017 Business Update October 2017 Exhibit 99.1

October 31, 2017 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 and proposed spending on grid modernization; • 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 outcome of San Onofre CPUC proceedings, and the 2018 GRC and delays in regulatory actions; • risks associated with higher rates for utility bundled service customers, caused by the authority of cities, counties and certain other public agencies to generate and/or purchase electricity for their local residents and businesses (known as Community Choice Aggregation or CCA), and other possible customer bypass or departure due to increased adoption of distributed energy resources or technological advancements in the generation, storage, transmission, distribution and use of electricity, and supported by public policy, government regulations and incentives; • 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), and governmental approvals; • ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses; and • 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. Other important factors are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s Form 10-K, most recent Form 10-Q, 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

October 31, 2017 2 Page Updated (U) from July 2017 Business Update EIX Shareholder Value 3 U SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 Capital Expenditures and Rate Base History and Forecast 7-9 U 2018 GRC Intervenor Testimony 10 U Key Regulatory Proceedings 11 U CPUC Cost of Capital 12 U Distribution and Transmission Capital Expenditure Detail 13-17 U Operational Excellence 18 EIX Responding to Industry Change 19 Edison Energy Group Summary 20 U 2017 Guidance 21 U Annual Dividends Per Share 22 Appendix 2018 GRC Overview 24-25 EIX and SCE Tax Reform 26 Historical Capital Expenditures 27 Capital Expenditure and Rate Base Detailed Forecast 28 U Power Grid of the Future, Grid Modernization 29-32 SCE Customer Demand Trends 33 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 N,U SCE Rates and Bills Comparison 41 U Third Quarter and YTD 2017 Earnings Summary, MHI Award Accounting, Results of Operations, Non-GAAP Reconciliations 42-49 U Table of Contents

October 31, 2017 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 • 8.3% 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

October 31, 2017 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 • 729,000 transformers • 119,000 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 (proposed) Limited Generation Exposure • Own less than 20% of its power generation • Future needs via competitive solicitations SCE Highlights

October 31, 2017 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 • 2018-2020 - $1.8 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 - $60 million of capital requested in 2018 GRC application • SCE’s storage portfolio – procurement target of 580 MW by 2020 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 • 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

October 31, 2017 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 55% 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

October 31, 2017 7 SCE Historical Rate Base and Core Earnings Rate Base Core Earnings 7% 5% 2011 – 2016 CAGR ($ billions) 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 $18.8 $21.0 $21.1 $23.3 $24.6 $25.9 2011 2012 2013 2014 2015 2016 $4.20$4.68$3.33 $4.10 $3.88 Core EPS $4.22

October 31, 2017 8 SCE Capital Expenditure Forecast – Request Level Note: Forecasted capital spending includes CPUC, FERC and other spending. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony. See Capital Expenditure/Rate Base Detailed Forecast for further information, including potential investment excluded in forecasts. Delta represents change from July 2017 Business Update. 1. 2016 and 2017 capital expenditures related to grid modernization are included in distribution capital expenditures ($ billions) $18.5 Billion Capital Program for 2017-2020 • Capital expenditure forecast incorporates GRC, FERC and non-GRC CPUC spending  Grid modernization spending of $1.8 billion during 2018 GRC period1  2017 traditional capital spending incorporates 2015 GRC decision and FERC spending  Includes $107 million of non-GRC CPUC capital spending for mobile home pilot program and charge ready pilot in 2017  Excludes transportation electrification 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 $3.5 $3.7 $4.9 $5.0 $4.9 2016 (Actual) 2017 2018 2019 2020 Distribution Transmission Generation Traditional Capital Spending: Grid Modernization Capital Spending: Grid Modernization Prior Forecast $3.8 $4.9 $5.0 $4.9 Delta ($0.1) - - - 1

October 31, 2017 9 SCE Rate Base Forecast – Request Level CPUC • Rate base based on request levels from 2018 GRC Rebuttal Testimony FERC • FERC rate base is approximately 20% of SCE’s rate base by 2020; includes Construction Work in Progress (CWIP) Other • No change from prior forecast • Excludes SONGS regulatory asset ($ billions) Note: Weighted-average year basis. 2016-2017 based on 2015 GRC decision. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony, FERC based on latest forecast and current tax law, except “rate-base offset” for the 2015 GRC decision excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs. 4-year CAGR of 8.3% $24.9 $26.1 $29.2 $31.7 $34.3 2016 (Authorized) 2017 2018 2019 2020 Traditional Grid Modernization Prior Forecast $26.2 $29.3 $31.8 $34.3 Delta ($0.1) ($0.1) ($0.1) -

October 31, 2017 10 SCE Rate Base Forecast Comparison to ORA and TURN – 2017-20204 ($ in billions) 2016 2017 2018 2019 2020 CAGR SCE’s Rebuttal Forecast $24.9 $26.1 $29.2 $31.7 $34.3 8.3% SCE’s Request Level Forecast at ORA Recommended Spending Levels $24.9 $26.1 $28.6 $30.4 $32.2 6.6% Difference ($0.0) ($0.0) ($0.6) ($1.3) ($2.1) SCE’s Request Level Forecast at TURN Recommended Spending Levels and Proposed Rate Base Adjustments5 $24.9 $26.1 $27.7 $29.5 $31.5 6.0% Difference ($0.0) ($0.0) ($1.5) ($2.2) ($2.8) ORA submitted testimony on April 7, 2017 – Key elements • Proposed no Grid Modernization capital expenditures and ~90% of traditional capital expenditures • Other items similar to ORA’s 2015 GRC testimony, including incentive compensation and traditional capital expenditures such as 4kV Cutovers and Overhead Conductor Program TURN and other intervenors submitted testimony on May 2, 2017 – Key TURN elements3 • Proposed ~22% of Grid Modernization capital expenditures and ~85% of traditional capital expenditures • Proposed rate base adjustment for historical capital expenditures, including a reduction of approximately $550 million related to certain distribution infrastructure replacement programs SCE Rebuttal filed June 16, 2017 General Rate Case Update – Intervenor Testimony 1. Relative to total rates 2. Includes $48 million one-time recovery of pre-2018 Balancing/Memorandum Accounts 3. Information has been updated to include any changes in positions from briefs and reply briefs filed in September 2017 4. Forecasting rate base considering the lower of ORA’s and TURN’s recommendations in each year would result in a lower rate base growth rate and revenue requirement 5. CAGR excluding rate base adjustments is 6.5% Proposed Revenue Requirement Increases1 ($ in millions) 2018 Increase Post Test Year 2019 2020 SCE Rebuttal2 $196/2.5% 3.8% 5.1% ORA $14/0.9% 2.7% 4.2% TURN3 $108/1.7% -0.1% 3.3%

October 31, 2017 11 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 Cost of Capital (A. 12-04-015) CPUC capital structure, cost of capital, and return on equity CPUC approved petition for modification on July 13, 2017; Advice Letter setting cost of debt and preferred filed September 29, 2017 and approved by CPUC Distribution Resources Plan OIR (R.14-08-013) Power grid investments to integrate distributed energy resources Demo projects underway; Current focus is on policy track, including grid modernization, deferral framework and DER forecasting Integrated Distributed Energy Resources OIR (R. 14-10-003) Creating consistent framework for guidance, planning and evaluation of DERs Proposed Resolution to be issued in October 2017 and voted on November 30, 2017; Solicitation to launch early December 2017 SONGS OII (I.12-10-013) OII resolved (December 2015); Proceeding record reopened in May 2016 CPUC issued ruling on October 10, 2017 that establishes next steps with an initial expedited schedule with hearings tentatively scheduled to end in early March 2018 with a commission decision to follow 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 2018 2017 Transportation Electrification (A.17-01-021) TE proposals to address SB 350 transportation electrification objectives Ongoing workshops and data requests; Proposed decision for priority review projects in Q4 2017; 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 Settlement in place through December 2017; replacement rate filed on October 27, 2017

October 31, 2017 12 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 (10/1/16 – 09/30/17) = 4.50% 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 approved filed advice letter setting the cost of debt and cost of preferred 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 independent of trigger mechanism ROE fixed at 10.45%, for 2017 independent of trigger mechanism

October 31, 2017 13 SCE Distribution System Investments 1. Other includes GRC energy storage, Charge Ready Phase I and mobile home pilot programs Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing 44% 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 2017 – 2020 Capital Spending Forecast for Distribution1 – Request Level $14.1 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 Modernization Other

October 31, 2017 14 Energy Storage Given counting rules, SCE has already met the aggregate 2016 targetsCPUC 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) 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 (note: all numbers rounded). The 418 MW includes:  120 MW1 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 2016 Energy Storage RFO has closed and SCE will file application seeking contract approval 2016 Legislation: • CPUC approved the Energy Storage Track 2 decision to implement AB 2868 and its requirement that the IOUs propose programs and investments for up to 500 MW of distributed energy storage systems. SCE’s portion is approximately 166 MW 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 1. SCE is currently counting some BTM MWs as energy storage, although agreement does not specifically require storage, as that is the likely technology to be used in these projects. Once installations are complete a more accurate true-up will be completed

October 31, 2017 15 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) • Proposal is not currently in capital expenditure and rate base forecast SCE’s Charge Ready Program addresses approximately 1/3 of forecast 2020 non-single family home charging demand in SCE territory and supports Governor’s 2012 zero-emission vehicle Executive Order – 1.5 million EVs statewide by 2025 • 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 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 Residential Make-Ready Rebate Incentive Pilot Near-term $4 EV Drive Rideshare Reward 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 Medium and Heavy-Duty Vehicle Charging Infrastructure Program Long-term $554 New Commercial Electric Vehicle Rate Proposal Rate Design Program Long-term N/A 1. Estimated Total Cost in $millions of constant dollars

October 31, 2017 16 Transportation Electrification 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

October 31, 2017 17 SCE Large Transmission Projects 1. CPUC approved 2. FEIR issued and revised costs are being developed 3. 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 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 FERC Cost of Capital 10.6% ROE in 2017: • ROE = Base of 9.30% + CAISO participation + weighted average of individual project incentives • FERC Formula recovery mechanism in effect through December 31, 2017 • Application for 2018 FERC Formula recovery mechanism filed on October 27, 2017  Requested Base ROE of 10.30% Summary of Large Transmission Projects Project Name Total Cost4 Remaining Investment (as of Sept. 2017) In-Service Date West of Devers1,3 $1.1 billion $1.0 billion 2021 Mesa Substation1 $608 million $565 million 2022 Alberhill System2 $397 million $360 million 2021 Riverside Transmission Reliability $233 million $226 million 2021 Eldorado-Lugo-Mohave Upgrade $269 million $262 million 2020

October 31, 2017 18 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

October 31, 2017 19 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

October 31, 2017 20 • 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 $101 million as of September 30, 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 • 106 MW of commercial-scale solar systems constructed and in operation as of September 30, 2017 • Edison International investment $228 million as of September 30, 2017; currently evaluating sale opportunities for the business The Opportunity: Trusted Advisor and Solution Integrator

October 31, 2017 21 $4.05 $4.32 (0.11)0.38 SCE 2017 EPS from Rate Base Forecast SCE Variances EIX Parent & Other EIX 2017 Core EPS Midpoint Guidance • O&M, financing and other benefits - $0.35 • Energy efficiency - $0.03 2017 Core Earnings Per Share Guidance – Building from SCE Rate Base • SCE authorized rate base $26.1 billion • Authorized CPUC capital structure - 48% equity and 10.45% ROE • FERC ROE of 10.6% (including incentives) • Energy efficiency earnings $0.03 per share • SONGS settlement as currently approved by CPUC • YTD incremental tax benefits from stock-based compensation and audit and return true-ups included:  SCE: $0.04 per share  EIX Parent & Other: $0.18 per share • No change in tax policy • 325.8 million common shares Key Assumptions • Holding Company - ($0.03) • Edison Energy Group - ($0.05) • SoCore Impairment – ($0.03) 2017 Earnings Per Share Guidance 2017 EIX Earnings Per Share Guidance As of July 27, 2017 As of October 30, 2017 Low Mid High Low Mid High EIX Basic EPS $4.13 $4.23 $4.33 $4.27 $4.32 $4.37 Less: Non-Core Items1 - - - - - - EIX Core EPS2 $4.13 $4.23 $4.33 $4.27 $4.32 $4.37 1. There were $1 million of non-core items for the nine months ended September 30, 2017 2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix On track to realize operational and service excellence targets with additional improvement attributable to tax benefits

October 31, 2017 22 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 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Note: See Use of Non-GAAP Financial Measures Thirteen 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

October 31, 2017 23 Appendix

October 31, 2017 24 • 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 Rebuttal Testimony filed June 16th requests 2018 revenue requirement of $5.859 billion  $196 million increase over projected authorized base rates, a 2.5% increase over total rates  Requests post test year increases: $480 million in 2019 and $556 million in 2020, 3.8% and 5.1% increases over presently authorized total rates, respectively • 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 2017 Q1 Q2 Q3 Q4 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

October 31, 2017 25 • 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 (cont.)

October 31, 2017 26 Key Reform Considerations Impact on Customer / Shareholder Comments No interest deductibility Negative Negative • Permanent increase in customer rates (top concern) • Costs passed through but lowers tax shield Lower tax rate (15%-20%) Positive Negative at EIX holding company • Lower customer rates • Remeasurement of EIX holding company tax assets and lower tax shield 100% capital expensing Mixed Mixed • Timing benefit only • Customer rates may be impacted by treatment of property-related deductions Net Deferred Tax Liability / (Asset) As of 12/31/2016; ($ in millions) SCE HoldCo Property-related and other $9,798 ($165) Operating loss / credit carryforward - (1,152)1 Net deferred tax liability / (asset) $9,798 ($1,317)1,2 1. Excludes $242 million of deferred tax assets allocated to third parties 2. Includes $58 million of state deferred tax assets EIX and SCE Tax Reform

October 31, 2017 27 SCE Historical Capital Expenditures ($ billions) $3.9 $3.5 $4.0 $3.9 $3.5 2012 2013 2014 2015 2016

October 31, 2017 28 Detailed Capital Expenditures at Request Level – 2016-2020 2016 (Actual) 2017 2018 2019 2020 Total Core Distribution1,2 $2.9 $2.9 $3.2 $3.2 $3.1 $15.2 Mobile Home Pilot Program - 0.1 - - - 0.1 Grid Modernization3 - - 0.5 0.7 0.6 1.8 Subtotal Distribution $2.9 $3.0 $3.7 $3.8 $3.7 $17.1 Transmission1 $0.4 $0.5 $1.0 $1.0 $1.0 $3.9 Generation1 $0.2 $0.2 $0.2 $0.2 $0.2 $1.0 Total $3.5 $3.7 $4.9 $5.0 $4.9 $22.0 Capital Expenditure/Rate Base Detailed Forecast Detailed Rate Base at Request Level – 2016-2020 2016 (Actual) 2017 2018 2019 2020 Traditional Rate Base $24.9 $26.1 $28.9 $31.0 $33.1 Grid Modernization - - 0.3 0.7 1.2 Total $24.9 $26.1 $29.2 $31.7 $34.3 1. Includes allocated capitalized overheads and general plant 2. Includes $12 million Charge Ready Phase I (2017) and $60 million of GRC Energy Storage (2016-2020; average $12 million per year) 3. 2016 and 2017 capital expenditures related to grid modernization are included in distribution capital expenditures Note: Totals may not foot due to rounding ($ in billions)

October 31, 2017 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

October 31, 2017 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

October 31, 2017 31 $0.54 $0.65 $0.61 2018 2019 2020 Building next generation electric grid requires accelerating traditional Transmission and Distribution / Information Technology programs and investing in new capabilities • Increased capacity: Upgrade portions of the grid (such as 4kV system) to increase capacity, improve reliability, and address technology obsolescence • Advanced and Integrated Capabilities: • Automation to monitor and control grid equipment in real-time and improve flexibility of grid operations • Communication Networks: Expansion of fiber optic network and field area network for real-time data transfer • Technology Platforms: Foundational tools for forecasting and planning; management systems to operate the distribution grid Capital will be deployed to achieve two primary objectives • Improving safety and reliability  Focus on worst performing circuits in conjunction with traditional infrastructure replacement activities • Increase DER integration and enable advanced operations on circuits with high forecasted penetration or where DERs can provide grid services 1. 2018-2020 CPUC based on 2018 GRC request rebuttal testimony; conceded grid modernization capital expenditures are expected to be requested in future GRC applications 2. Forecast excludes capitalized overheads SCE Grid Modernization – Request Level1 ($ billions) $1.8 Billion Capital Request for 2018-20202

October 31, 2017 32 Distributed Energy Resources (DER) Proceedings 2017 Activities • Utility incentive pilot, including a competitive solicitation framework and consultation with a stakeholder Distribution Planning Advisory Group • Regulatory approval of proposed pilot projects • Societal Cost Test and a Greenhouse Gas Adder 2017 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

October 31, 2017 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) 2012 30,563 40,541 8,504 5,196 1,676 86,480 1,735 88,215 4,321,171 549,855 10,922 46,493 21,917 83 24 4,950,465 22,866 21,996 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

October 31, 2017 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 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 2017 program budget: $258 million2 • $0.03 per share earnings in 2016 Electric Power Company Roles Solar 34% Small Hydro 2% Geothermal 26% Wind 36% 2016 Renewable Resources: 28.2% of SCE’s portfolio Biomass 2% 1. Assumes constant customer load 2. Pending approval of Advice Letter; SCE 2016 program budget of $333 million is in effect until approved

October 31, 2017 35 SCE 2017 Bundled Revenue Requirement Note: Rates in effect as of June 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 $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 5,130 7.1 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 4,386 6.1 Generation – owned generation investment and O&M 1,075 1.5 Transmission – greater than 220kV 1,064 1.5 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning, and prior- year over collections (340) (0.4) Total Bundled Revenue Requirement ($millions) $11,315  Bundled kWh (millions) 71,961 = Bundled Systemwide Average Rate (¢/kWh) 15.7¢

October 31, 2017 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

October 31, 2017 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 • Currently approximately 2% of SCE’s customer load has submitted an implementation plan to the CPUC for approval 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 12: Opening Briefs due Track 22: Review current PCIA Q4 2017 Q1 2018 Q2 2018 Q3 2018 Track 1: Reply briefs due 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

October 31, 2017 38 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 • July 2015 CPUC Decision D.15-07-001 includes:  Transition to 2 tiered rates by 2019  “Super User Electric Surcharge” for usage 400% above baseline (~5% of current residential load)  Continue fixed charge at $0.94/month, allowing IOUs to re-file fixed charge requests as early as 2018.  Minimum bills up to $10/month, which would apply to delivery revenue only Current Rates (non-CARE, Bundled) – October 2017 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 1.524 1.922 100% 101-400% >400% T ier D if feren ti a l (Ba se : T ier 1 ) Fixed Charge: $0.94/month Minimum Bill: $10.01/month T ier D if feren ti a l (Ba se : T ier 1 )

October 31, 2017 39 SCE Net Metering Rate Structure NEM Rate Developments: • NEM allowed residential customers to receive full-retail 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 about 20% • 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 (September 2017): • 242,198 combined residential and non-residential projects – 2,010 MW installed (of 2,240 MW cap)  99.7% solar  236,423 residential – 1,261 MW  5,775 non-residential – 748 MW  Approximately 3,664,152 MWh/year generated 7¢ 22₵15₵ 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 15¢/kWh (a low ballpark figure), making the Subsidy Paid by non-NEM Ratepayers, system-wide, roughly 8¢/kWh. Exact figures pending analysis

October 31, 2017 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 • 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 In st all ed N u m b er o f Re si d en ti al I n st alla tio n s Installations MW

October 31, 2017 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. Costs for low carbon energy are higher than those of high-carbon sources • Average monthly residential bills are substantially lower than national average. Higher rate levels are offset by lower usage  Lower SCE residential customer usage than national average, from 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 up through July 2017. https://www.eia.gov/electricity/data/eia861m/index.html 13.0 ₵ 16.2 ₵ US Average SCE 25% Higher 2016-17 Average Residential Rates (¢/kWh) 2016-17 Average Residential Bills ($ per Month) $124 $92 US Average SCE 26% Lower

October 31, 2017 42 Third Quarter Earnings Summary Q3 2017 Q3 2016(*) Variance Basic Earnings Per Share (EPS) SCE $ 1.43 $ 1.34 $ 0.09 EIX Parent & Other 0.01 (0.05) 0.06 Discontinued Operations — — — Basic EPS $ 1.44 $ 1.29 $ 0.15 Less: Non-core Items SCE $ — $ — $ — EIX Parent & Other — — — Discontinued Operations — — — Total Non-core $ — $ — $ — Core Earnings Per Share (EPS) SCE $ 1.43 $ 1.34 $ 0.09 EIX Parent & Other 0.01 (0.05) 0.06 Core EPS $ 1.44 $ 1.29 $ 0.15 Key SCE EPS Drivers Revenue 1,2 $ 0.18 - CPUC - Escalation 0.11 - CPUC - Other 0.05 - Other operating revenue 0.02 Higher O&M (0.01) Higher net financing costs (0.01) - AFUDC (Equity & Debt) 0.02 - Interest Expense (0.03) Income tax 2 (0.06) Other (0.01) - Property and Other Taxes (0.02) - Other Income and Expenses 0.01 Total core drivers 0.09 Non-core items — Total $ 0.09 Key EIX EPS Drivers EIX parent — Income taxes and other $ 0.03 EEG — Income taxes and other 0.03 Total core drivers 0.06 Non-core items — Total $ 0.06 (*) 2016 earnings was updated to reflect the implementation of the accounting standard for share-based payments effective January 1, 2016 1. Excludes San Onofre revenue of ($0.01) which was offset by property taxes of $0.01 2. Excludes higher income tax benefits for incremental tax repair deductions, pole-loading program-based cost of removal and tax accounting method changes : $0.41

October 31, 2017 43 Year to Date Earnings Summary YTD 2017 YTD 2016(*) Variance Basic Earnings Per Share (EPS) SCE $ 3.44 $ 3.21 $ 0.23 EIX Parent & Other (0.03) (0.20) 0.17 Discontinued Operations — — — Basic EPS $ 3.41 $ 3.01 $ 0.40 Less: Non-core Items SCE $ — $ — $ — EIX Parent & Other1 — 0.01 (0.01) Discontinued Operations — — — Total Non-core $ — $ 0.01 $ (0.01) Core Earnings Per Share (EPS) SCE $ 3.44 $ 3.21 $ 0.23 EIX Parent & Other (0.03) (0.21) 0.18 Core EPS $ 3.41 $ 3.00 $ 0.41 Key SCE EPS Drivers Revenue 2,3,4 $ 0.31 - CPUC - Escalation 0.33 - CPUC - Other 0.02 - FERC revenue (0.06) - Other operating revenue 0.02 Lower O&M 0.08 Higher depreciation (0.06) Higher net financing costs (0.05) - AFUDC (Equity & Debt) 0.02 - Interest Expense (0.07) Income taxes 2,4 (0.05) Other — - Property and Other Taxes (0.03) - Other Operating Income 0.01 - Other Income and Expenses 0.02 Total core drivers $ 0.23 Non-core items — Total $ 0.23 Key EIX EPS Drivers EIX parent — Income taxes and other $ 0.14 EEG 0.04 - Buyout of an earn-out provision in 2016 0.04 - SoCore Energy goodwill impairment in 2017 (0.03) - Income taxes and other 0.03 Total core drivers $ 0.18 Non-core items1 (0.01) Total $ 0.17 (*) 2016 earnings was updated to reflect the implementation of the accounting standard for share- based payments effective January 1, 2016 1. Impact of hypothetical liquidation at book value (HLBV) accounting method 2. 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 3. Excludes San Onofre revenue of ($0.14), property taxes of $0.01, interest expense of $0.01 and income taxes of $0.12. The higher income tax benefits are primarily related to the San Onofre tax abandonment in 2017 4. Excludes lower income tax benefits of $0.24 due to refunds for incremental tax benefits related to 2012 - 2014 repair deductions in 2016

October 31, 2017 44 $6,305 — 1,977 1,915 334 — 4,226 2,079 (525) 64 1,618 507 1,111 113 $998 $5,180 4,266 913 — — — 5,179 1 (1) — — — — — $— $11,485 4,266 2,890 1,915 334 — 9,405 2,080 (526) 64 1,618 507 1,111 113 $998 (370) $1,368 SCE Annual Results of Operations • Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards Earning Activities Cost- Recovery Activities Total Consolidated 2016 Earning Activities Cost- Recovery Activities Total Consolidated 2015 Operating revenue Purchased power and fuel Operation and maintenance Depreciation, decommissioning and amortization Property and other taxes Impairment and other charges Total operating expenses Operating income Interest expense Other income and expenses Income before income taxes Income tax expense Net income Preferred and preference stock dividend requirements Net income available for common stock Less: Non-core earnings Core Earnings Note: See Use of Non-GAAP Financial Measures ($ millions) $6,504 — 1,939 1,998 351 — 4,288 2,216 (540) 79 1,755 256 1,499 123 $1,376 $5,326 4,527 798 — — — 5,325 1 (1) — — — — — $— $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

October 31, 2017 45 2016 Retrospectively Adjusted EPS by Quarter 20161 Q4 Q3 Q2 Q1 Earnings (loss) per share attributable to Edison International Continuing Operations SCE $4.22 $1.01 $1.34 $0.98 $0.90 Edison International Parent & Other (0.23) (0.04) (0.05) (0.11) (0.04) Discontinued Operations 0.03 0.04  (0.01)  Edison International $4.02 $1.01 $1.29 $0.86 $0.86 Less: Non-Core Items SCE      Edison International Parent & Other 0.02   0.01 0.01 Discontinued Operations 0.03 0.04  (0.01)  Total Non-Core Items $0.05 $0.04   $0.01 Core Earnings (losses) SCE 4.22 1.01 1.34 0.98 0.90 Edison International Parent & Other (0.25) (0.04) (0.05) (0.12) (0.05) Edison International $3.97 $0.97 $1.29 $0.86 $0.85 1. As a result of rounding, the total of the four quarters does not always equal the amount for the year Note: Edison International and SCE adopted an accounting standard in the fourth quarter of 2016, effective January 1, 2016, which resulted in all of the tax effects related to share based payments being recorded through the income statement. Diluted EPS would have been, $1.00 for the fourth quarter of 2016, $1.27 for the third quarter of 2016, $0.85 for the second quarter of 2016 and $0.85 for the first quarter of 2016

October 31, 2017 46 MHI Award Accounting • On March 13, 2017, a decision was received from the International Chamber of Commerce International Court (ICC) regarding the MHI Arbitration • $47.1 million net proceeds received by SCE • CPUC will review the documentation of the final resolution of the MHI dispute and the legal costs incurred in pursuing claims against MHI to ensure such costs are not unreasonable in relation to the recovery obtained • Due to uncertainty associated with the treatment of the proceeds, no gain recorded MHI Arbitration Decision Calculation Total Liability Under Contract $137.5 Additional Interest (to be paid by MHI) 33.7 Total MHI Proceeds $163.7 Prior Invoice Paid by MHI (45.4) MHI Litigation Costs (to be paid by claimants) (58.1) Remaining Proceeds $60.2 Co-participants Share (13.1) SCE Cash Proceeds Received $47.1 ($ millions)

October 31, 2017 47 Earnings Non-GAAP Reconciliations "Note: See Use of Non-GAAP Financial Measures. Earnings for second quarter and year-to-date 2016 were updated to reflect the implementation of the accounting standard for share- based payments effective January 1, 2016. ($ millions) Reconciliation of EIX GAAP Earnings to EIX Core Earnings SCE EIX Parent & Other Discontinued Operations Basic Earnings Non-Core Items SCE EIX Parent & Other Discontinued Operations Total Non-Core Core Earnings SCE EIX Parent & Other Core Earnings Earnings Attributable to Edison International $435 (14) − $421 $ − − − $ − $435 (14) $421 $465 5 − $470 $ – – – $ − $465 5 $470 Q3 2016 Q3 2017 $1,048 (65) (1) $982 $ − 5 (1) $4 $1,048 (70) $978 $1,121 (11) − $1,110 $ – 1 – $ 1 $1,121 (12) $1,109 YTD 2016 YTD 2017

October 31, 2017 48 SCE Core EPS Non-GAAP Reconciliations Basic EPS Non-Core Items Regulatory and tax items Write down, impairment and other charges Insurance recoveries Less: Total Non-Core Items Core EPS Reconciliation of SCE Basic Earnings Per Share to SCE Core Earnings Per Share 5% 5% $3.33 — — — — $3.33 $4.81 0.71 — — 0.71 $4.10 $2.76 — (1.12) — (1.12) $3.88 Note: See Use of Non-GAAP Financial Measures. $4.46 — (0.22) — (0.22) $4.68 $3.06 — (1.18) 0.04 (1.14) $4.20 Earnings Per Share Attributable to SCE CAGR2011 2012 2013 2014 2015 $4.22 — — — — $4.22 2016

October 31, 2017 49 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