February 22, 2017 Business Update February 2017 Exhibit 99.1

February 22, 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 the determinations of authorized rates of return or return on equity, approval of proposed spending on grid modernization, the outcome of San Onofre CPUC proceedings, and delays in regulatory actions; • risks associated with cost allocation, including the potential movement of costs to certain customers, caused by the ability of cities, counties and certain other public agencies to generate and/or purchase electricity for their local residents and businesses, along with 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 the construction of 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, 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

February 22, 2017 2 Page New (N) or Updated (U) from November 2016 Business Update EIX Shareholder Value 3 U SCE Highlights, SCE Long-Term Growth Drivers, Regulatory Model 4-6 N Capital Expenditures and Rate Base History and Forecast 7-9 U 2018 GRC Overview 10-11 CPUC Cost of Capital 12 U Key Regulatory Proceedings 13 U Distribution and Transmission Capital Expenditure Detail 14-16 U Transportation Electrification Overview 17-18 N 2017 Guidance 19 N Operational Excellence 20 EIX Responding to Industry Change 21 U Edison Energy 22 U Annual Dividends Per Share 23 U Appendix EIX and SCE Tax Reform 25 N Historical Capital Expenditures 26 U Capital Expenditure and Rate Base Detailed Forecast 27 U Power Grid of the Future, Grid Modernization 28-31 U SCE Customer Demand Trends 32 U California Energy Policy 33 U SCE Bundled Revenue Requirement, System Average Rate Historical Growth 34-35 U Residential Rate Reform and Other 36-38 U SCE Rates and Bills Comparison 39 U Fourth Quarter and Full Year 2016 Earnings Summary, Results of Operations, Non-GAAP Reconciliations 40-46 N,U Table of Contents

February 22, 2017 3 EIX Strategy Should Produce Superior Value Sustained Earnings and Dividend Growth Led by SCE Positioned for Transformative Change SCE Rate Base Growth Drives Earnings • 8.6% 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 a higher than industry average within target payout ratio of 45-55% of SCE earnings Wires-Focused SCE Strategy • Infrastructure replacement –safety and reliability • Grid modernization –California’s low- carbon goals • Operational excellence Edison Energy Group Strategy • Energy as a service for large commercial and industrial customers - capital light business model • Pursuing solar and competitive transmission in select markets

February 22, 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 • 725,000 transformers • 103,000 miles of distribution and transmission lines • 3,100 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

February 22, 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 automation, communication, and analytics capabilities at optimal locations to integrate distributed energy resources • 2017 - Grid Modernization memorandum account request pending for proposed early stage capital expenditures • 2018-2025+ – first request in 2018 GRC filing; CPUC targets 2025 completion but may take longer Future transmission needs to meet 50% renewables mandate in 2030 and support reliability • 2017-2021 – Multiple projects approved by CAISO in permitting and/or construction • 2021-2030 – Future needs largely driven by CAISO planning process already initiated SCE owned investment opportunities (290 MW by 2024 under R. 10-12-007; additional 500 MW of storage opportunities under AB 2688) • Ongoing – small MWs approved to date; potential $60 million of additional funding through 2018 GRC application Utility investment in programs to build and support the expansion of transportation electrification in passenger and light, medium and heavy- duty vehicles • 2016 - Charge Ready Phase I approved • 2017 - Transportation Electrification application filed January 20 • 2017-2030 – Future Charge Ready Phase II and other pilot and full-scale programs supporting California GHG goals Infrastructure Reliability Grid Modernization Transportation Electrification Energy Storage Transmission

February 22, 2017 6 SCE Decoupled Regulatory Model Decoupling of Regulated Revenues from Sales Major Balancing Accounts • Fuel • Purchased power • Energy efficiency • Pension expense Advanced Long-Term Procurement Planning Forward-looking Ratemaking • SCE 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 • Trigger mechanism for fuel and purchased power adjustments at 5% variance level • Cost-recovery related balancing accounts represented more than 55% of costs • Upfront prudent standards with greater certainty of cost recovery (subject to compliance-related reasonableness review) • Three-year rate case cycle • Separate cost of capital mechanism Regulatory Model Key Benefits

February 22, 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. 2013-2016 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

February 22, 2017 8 SCE Capital Expenditure Forecast – Request Level Note: Forecasted capital spending includes CPUC, FERC and other spending. See Capital Expenditure/Rate Base Detailed Forecast for further information, including potential investment excluded in forecasts. 2021-2022 Delta reflects catch-up of prior forecast capital expenditures for delayed transmission projects. 2019 Delta reflects rounding difference in both periods ($ billions) $19.3 Billion Capital Program for 2017-2020 • Capital expenditure forecast incorporates GRC, FERC and non-GRC CPUC spending  Grid modernization spending of $2.3 billion during four- year period  2017 traditional capital spending incorporates 2015 GRC decision and FERC spending  Includes $289 million of non-GRC CPUC capital spending for grid modernization and 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 approvalsPrior Forecast $4.5 $5.0 $5.2 $4.9 N/A Delta ($0.3) — — $0.1 $0.2 $3.5 $4.2 $5.0 $5.1 $5.0 2016 (Actual) 2017 2018 2019 2020 2021-2022 Distribution Transmission Generation Traditional Capital Spending: Grid Modernization Capital Spending: Grid Modernization

February 22, 2017 9 SCE Rate Base Forecast – Request Level CPUC • Rate base based on request levels from 2018 GRC and 2018 positive true-up from authorized to forecast 2017 rate base FERC • FERC rate base is approximately 19% of SCE’s rate base by 2020; includes Construction Work in Progress (CWIP) • Incorporates latest FERC spending outlook Other • 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, 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. 2021-2022 Delta reflects catch-up of prior forecast rate base for delayed transmission projects 4-year CAGR of 8.6% Prior Forecast $26.4 $29.6 $32.4 $35.1 N/A Delta ($0.2) ($0.3) ($0.4) ($0.5) $0.5 $24.9 $26.2 $29.3 $32.0 $34.6 2016 (Authorized) 2017 2018 2019 2020 2021-2022 Traditional Grid Modernization

February 22, 2017 10 • 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 • Requests 2018 revenue requirement of $5.885 billion  $222 million increase over presently authorized base rates, a 2.7% increase over total rates  Requests post test year increases: $533 million in 2019 and $570 million in 2020, 4.2% and 5.2% 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

February 22, 2017 11 • Capital expenditures of $2.1 billion for grid modernization capital to support improved safety and reliability and increased levels of distributed energy resources (DER)  Requested approval to establish memorandum account to facilitate $210 million of grid modernization capital expenditures in 2016-2017; these expenditures support 2018 GRC grid modernization capital request May need to evaluate grid modernization capital plan if memorandum account not approved • 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.)

February 22, 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 at e (% ) CPUC Cost of Capital CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/16 – 02/01/2017) = 4.60% 100 basis point +/- Deadband Starting Value – 5.00% Return on Equity (ROE) adjustment mechanism extended through 2019 • ROE adjustment based on 12-month average of Moody’s Baa utility bond rates, measured from October 1 to September 30 • If index exceeds 100 bps deadband from starting index value, authorized ROE changes by half the difference • Starting index value based on trailing 12 months of Moody’s Baa index as of September 30– 5.00% • Two year settlement awaiting CPUC approval  ROE set at 10.30%; 2018 true-up of cost of debt/preferred CPUC Authorized Settlement Terms Capital Structure 2017 2018-2019 Common Equity 48% 10.45% 10.30% Preferred 9% 5.79% TBD Long-term Debt 43% 5.49% TBD Weighted Average Cost of Capital 7.90% TBD ROE fixed at 10.30%, for 2018 independent of trigger mechanism ROE fixed at 10.45%, for 2017 independent of trigger mechanism

February 22, 2017 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; awaiting schedule to be set by ALJ; intervenor testimony expected in Q2 2017 Cost of Capital CPUC capital structure, cost of capital, and return on equity Filed Petition for Modification on February 2, 2017; awaiting CPUC approval; Filing of 2020 application on April 22, 2019 Distribution Resources Plan OIR (R.14-08-013) Power grid investments to integrate distributed energy resources SCE plan submitted July 2015; CPUC scoping memos issued January 2016 and October 2016; split into three tracks with additional sub-tracks Integrated Distributed Energy Resources OIR (R. 14-10-003) Creating consistent framework for guidance, planning and evaluation of DERs Ruling comments and replies filed in May 2016; ongoing workshops and recommendations on proceeding SONGS OII (I.12-10-013) OII resolved (December 2015); Proceeding record reopened in May 2016 First meet and confer session on January 27, 2017; CPUC reports from meetings due April 28, 2017 Charge Ready Program (A.14-10-014) Implementation program for charger installations and market education Phase 1 pilot program approved January 2016; request for Phase 2 to be submitted after Phase 1 completion Alternative-Fueled Vehicle OIR (R. 13-11-007) Scope broadened March 2016 to address SB 350 transportation electrification objectives Q2 2016 workshops held; utility project proposals filed January 20, 2017 Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates ROE moratorium expired July 2015; settlement in place through December 2017; replacement rate to be filed in the Q4 2017

February 22, 2017 14 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 $14.9 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 Modernization Other

February 22, 2017 15 SCE Large Transmission Projects 1. CPUC approved 2. Presently under CPUC environmental review 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 10.5% ROE in 2017: • Base ROE = 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 expected to be filed in Q4 of 2017 Summary of Large Transmission Projects Project Name Total Cost4 Remaining Investment In-Service Date West of Devers1,3 $1.1 billion $1.02 billion 2021 Mesa Substation1 $608 million $585 million 2020-2021 Alberhill System2 $397 million $361 million 2021 Riverside Transmission Reliability2 $233 million $228 million 2021 Eldorado-Lugo-Mohave Upgrade $269 million $264 million 2020

February 22, 2017 16 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 50% of total target (290 MW SCE share) • Flexibility to transfer across categories, recently 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 500 MW total, of which 424 MW is eligible to count to the targets (note: all numbers rounded)  The 424 MW includes 60 MW from SCE’s Preferred Resources Pilot 2 solicitation, currently pending approval  The 424 MW includes approximately 55 MW of Utility-owned Storage o 15 MW are previous pilots and demonstrations o 40 MW will seek cost recovery via the Aliso Canyon application in Q1 2017 • SCE’s Energy Storage and Distribution Deferral RFO is currently in progress and will close Q3 2017 New Legislation • AB 2688 authorizes the CPUC to approve up to an additional 500 MW, to be divided evenly among IOUs. CPUC has not yet opened a proceeding to implement the statute Cost Recover Mechanism for Storage Utility-Owned Storage (UOS)1 (except Aliso Canyon RFP) Capital Expenditures – General Rate Case Third-Party Owned Storage Energy Resource Recovery Account Aliso Canyon1 (UOS) Special Application – targeted Q1 2017 1. Typically recovered through GRC capital expenditures, but as a special circumstance, UOS procured through Aliso Canyon RFP will require a separate application for cost recovery 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 22, 2017 17 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 after completion of Phase I: proposal details TBD 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 Runner 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

February 22, 2017 18 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 greater than 50% of the state’s emissions. Commercial and Residential 9% Electrical Power 20% Agriculture 8% Industrial 21% Transportation 36% Other 6% SCE is taking a leading role to ensure that transportation electrification plays a major part in reducing GHG and criteria pollutant emissions in California 2014 California GHG Emissions by Sector Note: Data for both charts from California Air Resources Board

February 22, 2017 19 $4.05 $4.14 (0.25)0.34 SCE 2017 EPS from Rate Base Forecast SCE Variances EIX Parent & Other EIX 2017 Core EPS Midpoint Guidance • O&M and financing benefits - $0.31 • Energy efficiency - $0.03 2017 Core Earnings Per Share Guidance – Building from SCE Rate Base • SCE authorized rate base $26.2 billion • Energy efficiency earnings $0.03 per share • Authorized CPUC capital structure - 48% equity and 10.45% ROE • FERC ROE of 10.5% • No change in tax policy • 325.8 million common shares • MHI arbitration decision not included  Legal costs are expensed as core as they are incurred  SCE’s share of any award, if any, would first be used to recover the previously recorded expenses, and will be recorded as core  Balance would be treated as non-core Key Assumptions Low Mid High SCE $4.39 EIX Parent & Other (0.25) EIX Basic EPS $4.04 $4.14 $4.24 Less: Non-Core Items - - - EIX Core EPS $4.04 $4.14 $4.24 • Holding Company - ($0.17) • Edison Energy Group - ($0.08) 2017 Earnings Per Share Guidance as of February 21, 2017 2017 EIX Earnings Per Share Guidance

February 22, 2017 20 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 22, 2017 21 Responding to Industry Change • Public policy and large commercial customers prioritizing sustainability objectives • Innovation facilitating conservation and self-generation • Regulation supporting new forms of competition • Flattening domestic demand for electricity • Power grid of the future will be more complex and sophisticated to support increasing use of distributed resources and transportation electrification SCE Strategy • Invest in, build, and operate the next generation electric power grid • Operational and service excellence • Enable California public policies Edison Energy Group • Position as an independent Energy Advisor and Integrator for large commercial and industrial customers – capital light business model • Solar opportunities focused on commercial and industrial customers, co- operatives and community solar programs • Founding member of Grid AssuranceTM Long-Term Industry Trends Strategy

February 22, 2017 22 • Create portfolio energy services that help simplify and optimize energy needs for large commercial & industrial customers:  Help customers capture the maximum value of energy optimization by managing risk and making better decisions around procuring energy, investing in capital improvements, and managing operations  Help customers manage through technological / regulatory changes with integrated offerings from acquired businesses Edison Energy launched in March 2016 to become the trusted advisor to the largest users of energy nationwide Changing Customer Needs The Opportunity: Trusted Advisor and Solution Integrator Edison Energy Focus: Commercial & Industrial

February 22, 2017 23 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

February 22, 2017 24 Appendix

February 22, 2017 25 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

February 22, 2017 26 SCE Historical Capital Expenditures ($ billions) $3.9 $3.5 $4.0 $3.9 $3.5 2012 2013 2014 2015 2016

February 22, 2017 27 Detailed Capital Expenditures at Request Level – 2016-2020 2016 (Actual) 2017 2018 2019 2020 Total Core Distribution1,2 $2.9 $3.0 $3.2 $3.2 $3.1 $15.4 Mobile Home Pilot Program - 0.1 - - - 0.1 Grid Modernization - 0.2 0.6 0.8 0.7 2.3 Subtotal Distribution $2.9 $3.3 $3.8 $4.0 $3.8 $17.8 Transmission1 $0.4 $0.7 $0.9 $1.0 $1.0 $4.0 Generation1 $0.2 $0.2 $0.2 $0.2 $0.2 $1.0 Total $3.5 $4.2 $4.9 $5.2 $5.0 $22.8 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 $26.2 $29.0 $31.2 $33.2 Grid Modernization - - 0.3 0.8 1.4 Total $24.9 $26.2 $29.3 $32.0 $34.6 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 $12 million per year) ($ in billions)

February 22, 2017 28 Distribution Power Grid of the Future One-Way Electricity Flow • System designed to distribute electricity from large central generating plants • Very few 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 manage two-way flows • Improved data management and power grid operations with cyber mitigation Maximize Distributed Resources and Electric Vehicle Adoption • Distribution power grid infrastructure design supports customer choice and greater resiliency Current State Future State

February 22, 2017 29 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 Automated switched capacitor bank w/ voltage control

February 22, 2017 30 $0.03 $0.18 $0.64 $0.75 $0.71 2016 (Actual) 2017 2018 2019 2020 Building next generation electric grid requires accelerating traditional Transmission and Distribution / Information Technology programs and investing in new capabilities • Increased capacity: Upgrade portions of the grid (such as 4kV system) to increase capacity, improve reliability, and address technology obsolescence • Advanced Capabilities: Automation to monitor and control grid equipment in real-time • Communication Networks: Expansion of fiber optic network and field area network for real-time data transfer • Technology Platforms: Foundational tools for forecasting and planning; management systems to operate the distribution grid Capital will be deployed to achieve two primary objectives • Improving safety and reliability  Focus on worst performing circuits in conjunction with traditional infrastructure replacement activities • Increase DER integration and enable advanced operations on circuits with high forecasted penetration or where DERs can provide grid services 1. Forecast excludes capitalized overheads 2. Pending approval of memorandum account for 2016 and 2017 forecast and 2018 GRC decision for 2018-2020 forecast SCE Grid Modernization – Request Level ($ billions) $2.3 Billion Capital Request for 2017-20201,2

February 22, 2017 31 Distributed Energy Resources (DER) Proceedings Expanded scope • Competitive DER solicitation framework: product definition, rules, plans, standard contracts, “review groups,” and DER valuation methodology • Electric power company roles in DER markets, business models, and financial interests • Consider localized DER incentives Scope elements • Integration Hosting Capacity • Locational Net Benefits • Data Access • Planning alignment • Power Grid Modernization Investments; integration into General Rate Case • Integration of DERs in planning and operations • Identification of optimal locations and value of DERs • Development of tools and methodologies • Field demonstrations Distribution Resource Plan (Near term proceedings through early 2017) • Determine how DERs can meet system needs • Develop sourcing framework for DERs • Align DER cost-effectiveness frameworks Integrated Distributed Energy Resources (Phase 1 through 2016)

February 22, 2017 32 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 2015 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

February 22, 2017 33 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  To meet the 50% RPS requirement by 2030, SCE will need to increase its renewable purchases by 17.7 billion kWh, or 85%1 • On September 8, 2016, Governor Brown sighed SB 32, which requires statewide GHG emissions to be reduced to 40% below the 1990 level 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 2017 program budget: $258 million2 • $0.03 per share for 2016 Electric Power Company Roles Solar 26% Small Hydro 2% Geothermal 37% Wind 33% 2016 Preliminary Renewable Resources: 28.3% 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

February 22, 2017 34 SCE 2017 Bundled Revenue Requirement Note: Rates in effect as of October 1, 2016. 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 15.8 Fuel & Purchased Power (45%) Distribution (39%) Transmission (9%) Generation (9%) Other (-2%) 2017 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 5,130 7.1 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 4,386 6.1 Generation – owned generation investment and O&M 1,075 1.5 Transmission – greater than 220kV 1,064 1.5 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning, and prior- year over collections (276) (0.3) Total Bundled Revenue Requirement ($millions) $11,379 ÷ Bundled kWh (millions) 71,961 = Bundled Systemwide Average Rate (¢/kWh) 15.8¢

February 22, 2017 35 9.7¢ 15.8¢ 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 Energy Crisis and return to normal cost of service rates Higher gas prices post-Katrina leads to higher rates with subsequent refund of over collection Delay in 2012 GRC leads to shorter ramp-up of rate increase ¢/kWh Rates reduced from 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 System Average Rate Historical Growth SCE’s system average rate has grown at slightly less inflation over the last 20 years SCE System Average Rate Los Angeles Area Inflation Comparative System Average Rates % Delta EIX – 15.8¢ -- PG&E – 18.8¢ 19% SDG&E – 21.8¢ 38% CAGR 20-yr ('97-’17) 10-yr ('07-'17) 5-yr ('12-'17) 2.4% 0.7% 0.5% 2.5% 0.8% 0.4%

February 22, 2017 36 Residential Rate Design OIR Decision • CPUC Order Instituting Ratemaking R.12-06-013 comprehensively reviewed residential rate structure including a future transition to time of use (TOU) rates • 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, allowed IOUs to re-file fixed charge requests as early as 2018.  Minimum bills up to $10/month which applies to delivery revenue only Current Rates – January 2017 Future Rates - 2019 Fixed Charge: $0.94/month Minimum Bill: $10.00/month Note: Graphs not to scale; 2019 rate levels are based on current revenue requirements 17.2¢ 38.5¢ 100% 101-400% >400% 22.0¢ Usage Level (% of Baseline) ¢/ kW h Usage Level (% of Baseline) 16.3¢ 24.9¢ 31.4¢ 100% 101-400% >400% ¢/ kW h Fixed Charge: $0.94/month Minimum Bill: $10.00/month

February 22, 2017 37 SCE Net Metering Rate Structure 7¢ 24¢17¢ 0 5 10 15 20 25 30 ¢/ kW h Solar Subsidies (Illustrative) Avoided Generation (excludes RPS Premium) Subsidy Paid by Other Ratepayers Equivalent Solar Offset NEM Rate Developments: • NEM allows 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 is expected to reduce subsidy by about 20% • Current NEM tariff ends on July 1, 2017 or earlier if NEM installations reach the 5% cap (2,240 MW for SCE)  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 2016): • 210,857 combined residential and non-residential projects – 1,714 MW installed (of 2,240 MW cap)  99.9% solar  205,786 residential – 1,093 MW  5,071 non-residential – 620 MW  Approximately 3,151,302 MWh/year generated

February 22, 2017 38 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 • NEM customers will be required to take service under mandatory Time-of-Use rate • SCE is not expected to hit 5% NEM cap (2,240MW SCE share), prior to July 1, 2017 2019 • Commission to revisit NEM Successor Tariff Key Dates Monthly Installations and MW Installed 0 10 20 30 40 50 60 0 1000 2000 3000 4000 5000 6000 7000 2010 2011 2012 2013 2014 2015 2016 M W In st al le d N um be r of R es id en ti al In st al la ti on s Number of Installations MW Installed

February 22, 2017 39 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 – cost for low carbon energy are higher than high carbon sources • Average monthly residential bills are substantially lower than national average as higher rate levels offset by lower usage  39% 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 Ending July 2016 1. Average 2016 only residential rate (¢/kWh) 2. Average 2016 only residential bill ($/month) 13.0 16.2 US Average SCE 24.3% Higher 2015-16 Average Residential Rates (¢/kWh) 2015-16 Average Residential Bills ($ per Month) $123 $91 [2] US Average SCE 26.4% Lower ¢ ¢ [1]

February 22, 2017 40 Q4 2016 Q4 2015 Variance Basic Earnings Per Share (EPS)1,2 SCE $1.04 $(0.25) $1.29 EIX Parent & Other (0.02) 0.03 (0.05) Discontinued Operations 0.04 (0.02) 0.06 Basic EPS $1.06 $(0.24) $1.30 Less: Non-Core Items SCE3 $ − $(1.14) $1.14 EIX Parent & Other4 − 0.04 (0.04) Discontinued Operations5 0.04 (0.02) 0.06 Total Non-Core Items $0.04 $(1.12) $1.16 Core Earnings Per Share (EPS)1 SCE $1.04 $0.89 $0.15 EIX Parent & Other (0.02) (0.01) (0.01) Core EPS1 $1.02 $0.88 $0.14 Key SCE EPS Drivers Revenue6,7 $0.16 - CPUC – Escalation 0.09 - CPUC – GRC return on pole loading rate base (0.03) - CPUC – Other 0.09 - FERC revenue and other 0.01 Lower O&M 0.09 Higher depreciation (0.06) Higher net financing costs (0.05) Income Tax6,7 _ Other 0.01 - Property and other taxes (0.01) - Other income and expenses 0.02 Total core drivers $0.15 Non-core items3 1.14 Total $1.29 Fourth Quarter Earnings Summary Key EIX EPS Drivers EIX parent – Lower corporate expenses and other $0.02 EMG – Sold portfolio in 2015 and other (0.03) Total core drivers $(0.01) Non-core items4,5 0.02 Total $0.011. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. Includes full year basic earnings impact of $0.09 due to the adoption of new accounting standards update on share-based payments ($0.05 of this benefit was attributable to prior quarters). See 2016 Retroactively Adjusted EPS by Quarter in Appendix for the impacts on basic and diluted earnings per share for each quarter of 2016 3. See SCE Core EPS Non-GAAP reconciliation in Appendix 4. Impact includes hypothetical liquidation at book value (HLBV) and sale of affordable housing portfolio 5. Impact primarily related to the resolution of tax issues and other impacts related to the EME bankruptcy settlement 6. Excludes income tax benefits for incremental tax repair deductions and pole loading program-based cost of removal of $0.27 7. Excludes San Onofre revenue of $0.02 which was offset by income taxes of $(0.02) Note: Diluted earnings were $1.05 and $(0.24) per share for the three months ended December 31, 2016 and 2015, respectively. See 2016 Retroactively Adjusted EPS by Quarter in Appendix for impacts related to the new accounting update

February 22, 2017 41 2016 2015 Variance Basic Earnings Per Share (EPS)1 SCE $4.22 $3.06 $1.16 EIX Parent & Other (0.23) (0.04) (0.19) Discontinued Operations 0.03 0.11 (0.08) Basic EPS $4.02 $3.13 $0.89 Less: Non-Core Items SCE2 $ − $(1.14) $1.14 EIX Parent & Other3 0.02 0.06 (0.04) Discontinued Operations4 0.03 0.11 (0.08) Total Non-Core Items $0.05 $(0.97) $1.02 Core Earnings Per Share (EPS)1 SCE $4.22 $4.20 $0.02 EIX Parent & Other (0.25) (0.10) (0.15) Core EPS1 $3.97 $4.10 $(0.13) Key SCE EPS Drivers Revenue5,6 $0.41 - CPUC – Escalation 0.35 - CPUC – GRC return on pole loading rate base 0.05 - CPUC – Other (0.06) - FERC revenue and other 0.07 Lower O&M 0.09 Higher depreciation (0.16) Higher net financing costs (0.11) Income taxes5,6 (0.23) - 2015 change in uncertain tax positions (0.31) - Higher tax benefits 0.08 Other 0.02 - Property and other taxes (0.04) - Other income and expenses 0.06 Total core drivers $0.02 Non-core items2 1.14 Total $1.16 Full Year 2016 Earnings Summary Key EIX EPS Drivers EMG – Sold portfolio in 2015, income taxes and other $(0.08) EEG – Buyout of an earn-out provision, higher development and operating costs and other (0.07) Total core drivers $(0.15) Non-core items3,4 (0.12) Total $(0.27) 1. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2. See SCE Core EPS Non-GAAP reconciliation in Appendix 3. Impact includes hypothetical liquidation at book value (HLBV) and sale of affordable housing portfolio 4. Impact related to the resolution of tax issues and other impacts related to the EME bankruptcy settlement 5. Excludes revenue and income taxes for incremental tax repair deductions and pole loading program-based cost of removal of $0.15 and $(0.24) of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions 6. Excludes San Onofre revenue of $0.08, which was offset by income taxes of $(0.11), depreciation expense of $0.01, property taxes of $0.01 and interest expense of $0.01 Note: Diluted earnings were $3.97 and $3.10 per share for the twelve months ended December 31, 2016 and 2015, respectively

February 22, 2017 42 $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) $1,368 SCE Results of Operations • Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards Earning Activities Cost- Recovery Activities Total Consolidated 2016 Earning Activities Cost- Recovery Activities Total Consolidated 2015 Operating revenue Purchased power and fuel Operation and maintenance Depreciation, decommissioning and amortization Property and other taxes Impairment and other charges Total operating expenses Operating income Interest expense Other income and expenses Income before income taxes Income tax expense Net income Preferred and preference stock dividend requirements Net income available for common stock Less: Non-core earnings Core Earnings Note: See Use of Non-GAAP Financial Measures ($ 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

February 22, 2017 43 2016 Retroactively 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

February 22, 2017 44 Earnings Non-GAAP Reconciliations Note: See Use of Non-GAAP Financial Measures ($ 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 $(80) 9 (8) $(79) $(370) 12 (8) $(366) $290 (3) $287 $339 (7) 13 $345 $ – – 13 $ 13 $339 (7) $332 Q4 2015 Q4 2016 Earnings Attributable to Edison International $998 (13) 35 $1,020 $(370) 19 35 $(316) $1,368 (32) $1,336 $1,376 (77) 12 $1,311 $ – 5 12 $17 $1,376 (82) $1,294 20152016

February 22, 2017 45 SCE Core EPS Non-GAAP Reconciliations Basic EPS Non-Core Items Tax settlement Health care legislation 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

February 22, 2017 46 Use of Non-GAAP Financial Measures Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. A reconciliation of Non-GAAP information to GAAP information is included either on the slide where the information appears or on another slide referenced in this presentation. EIX Investor Relations Contact Scott Cunningham, Vice President (626) 302-2540 scott.cunningham@edisonintl.com Allison Bahen, Senior Manager (626) 302-5493 allison.bahen@edisonintl.com