EX-99.1 2 eixseptember2016business.htm EXHIBIT 99.1
September 2, 2016 Business Update September 2016 Exhibit 99.1

September 2, 2016 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 regulatory assets 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; • 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 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 transmission and distribution infrastructure replacement and expansion projects, 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 retirement and decommissioning of nuclear generating facilities. 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 Exhibit 99.1

September 2, 2016 2 Page New (N) or Updated (U) from July 2016 Business Update EIX Shareholder Value 3 U SCE Highlights, Regulatory Model 4‐5 Capital Expenditures and Rate Base History and Forecast 6‐8 U 2018 GRC Overview 9‐10 N Distribution and Transmission Capital Expenditure Detail 11‐15 U,N CPUC Cost of Capital 16 2016 Guidance 17 Growth Drivers Beyond 2017 18 U SCE System Average Rate 19 Key Regulatory Proceedings 20 Operational Excellence 21 EIX Responding to Industry Change 22 Edison Energy 23‐25 Annual Dividends Per Share 26 Appendix SCE Tax Memorandum Account 28 U Historical Capital Expenditures 29 Capital Expenditure and Rate Base Detailed Forecast 30 N Power Grid of the Future, Grid Modernization 31‐35 U,N SCE Bundled Revenue Requirement, System Average Rate Historical Growth 36‐37 Residential Rate Reform and Other 38‐40 SCE Customer Rates and Demand 41‐42 California Energy Policy 43‐44 Second Quarter 2016 Earnings Summary, Results of Operations, Non‐GAAP Reconciliations 45‐50 Table of Contents Exhibit 99.1

September 2, 2016 3 EIX Strategy Should Produce Superior Value Sustainable Earnings and Dividend Growth Positioned for Transformative Change Rate Base and Core Earnings Growth • 8.5% average annual rate base growth through 2020 Constructive Regulatory Structure • Decoupling • Balancing accounts • Forward-looking ratemaking Sustainable Dividend Growth • Target dividend growth at a higher than industry growth rate within its target payout ratio of 45-55% of SCE earnings in steps over time SCE Focus on Lower-Risk Energy Delivery • Wires assets represent over 90% of utility plant as of December 31, 20151 SCE Growth Drivers • Public safety and reliability • California’s low-carbon environmental policy objective Edison Energy Group Competitive Strategy • Integrate emerging technologies and business models to serve commercial and industrial customers • Pursue other infrastructure opportunities, e.g. competitive transmission and water resources 1. Includes assets classified as transmission, distribution and general plant Exhibit 99.1

September 2, 2016 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 investments • 1.4 million power poles • 725,000 transformers • 103,000 miles of distribution and transmission lines • 3,100 MW owned generation Above average annual rate base growth driven by • Public safety and reliability • California’s low-carbon policy objectives ‒ Distribution Resources Plan (DRP) ‒ Electric vehicle charging ‒ Energy storage Limited Generation Exposure • SCE owns less than 20% of its power generation needs • Future generation’s needs via competitive market SCE Highlights Exhibit 99.1

September 2, 2016 5 SCE Decoupled Regulatory Model Decoupling of Regulated Revenues from Sales Major Balancing Accounts • Fuel • Purchased power • Energy efficiency • Pension-related contributions Advanced Long-Term Procurement Planning Forward-looking Ratemaking • SCE earnings are not affected by changes in retail electricity sales • Differences between amounts collected and authorized levels are either billed or refunded to customers • Promotes energy conservation • Stabilizes revenues during economic cycles • Trigger mechanism for fuel and purchased power adjustments at 5% variance level • Cost-recovery via balancing accounts represented more than 55% of 2015 costs • Sets prudent upfront standards allowing greater certainty of cost recovery (subject to reasonableness review) • Three-year rate case cycle • Separate multi-year cost of capital proceeding Regulatory Model Key Benefits Exhibit 99.1

September 2, 2016 6 SCE Historical Rate Base and Core Earnings Rate Base Core Earnings 8% 7% 2010 – 2015 CAGR ($ billions) Note: Recorded rate base, year-end basis. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix. 2013-2015 rate base excludes SONGS $16.8 $18.8 $21.0 $21.1 $23.3 $24.6 2010 2011 2012 2013 2014 2015 Core EPS $4.68$3.01 $3.33 $4.10 $3.88 $4.20 Exhibit 99.1

September 2, 2016 7 SCE Capital Expenditure Forecast Note: Forecasted capital spending includes CPUC, FERC and other spending. See “Capital Expenditure/Rate Base Detailed Forecast” in Appendix. ($ billions) $3.8 $4.5 $5.0 $5.2 $4.9 2016 2017 2018 2019 2020 Distribution Transmission Generation Traditional Capital Spending Categories: Grid Modernization Capital Spending: Grid Modernization $23.3 Billion Capital Program for 2016-2020 at Request Level • Capital expenditure forecast incorporates GRC, FERC and non-GRC CPUC spending  Grid modernization spending of $2.3 billion during five-year period  2016-2017 traditional capital spending incorporates 2015 GRC decision and FERC spending consistent with July 29 Business Update  Certain non-GRC CPUC capital spending of: - $210 million for grid modernization in 2016-2017 - $187 million for Mobile Home Park Conversion pilot program in 2016-2017 • 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 Exhibit 99.1

September 2, 2016 8 SCE Rate Base Forecast • Incorporates 2015 GRC final decision, except “rate-base offset” excluded because of write off of regulatory asset related to 2012-2014 incremental tax repairs • CPUC rate base based on request levels from 2018 GRC • FERC rate base is approximately 19% of SCE’s rate base by 2020; includes Construction Work in Progress (CWIP) • Excludes SONGS regulatory asset ($ billions) Note: Weighted-average year basis. 2016-2017 based on 2015 GRC decision. 2018-2020 based on 2018 GRC request. Rate base calculated under current tax law. 5-year CAGR of 8.5% at Request Level $24.9 $26.4 $29.6 $32.4 $35.1 2016 2017 2018 2019 2020 Traditional Rate Base Grid Modernization Exhibit 99.1

September 2, 2016 9 • 2018 GRC Application (A. 16-09-001) filed September 1st • Addresses major portion of 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 discrete SCE capital projects (such as SCE Charge Ready – transportation electrification infrastructure program)  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 consistent with SCE strategy to focus on safety and reliability by continuing infrastructure investment and beginning grid modernization investments while mitigating customer rate impacts through lower operating costs GRC Application Rebuttal Final Decision 2016 2017 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Estimated Intervenor Testimony Proposed Decision 2018 SCE General Rate Case (GRC) Summary Evidentiary Hearings Note: Actual schedule to be set by CPUC in a future regulatory order. The schedule is subject to change over the course of the proceeding. Exhibit 99.1

September 2, 2016 10 • Capital expenditures include $2.1 billion of proposed grid modernization capital to support improved safety and reliability and increased levels of distributed energy resources (DER)  Requested approval to establish a 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 is not approved • Need to increase 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) to adjust 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 Summary (cont.) Exhibit 99.1

September 2, 2016 11 SCE Distribution System Investments 1. Other includes: Energy Storage, Charge Ready Pilot and Mobile Home Park Conversion Distribution Trends • Continued focus on safety and reliability with infrastructure replacement representing 46% 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 2016 – 2020 CPUC Expenditures for Distribution Assets1 $17.8 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 Exhibit 99.1

September 2, 2016 12 $0.03 $0.18 $0.64 $0.75 $0.71 2016 2017 2018 2019 2020 Building next generation electric grid will require accelerating traditional Transmission and Distribution / Information Technology programs and investing in new capabilities • Increased capacity: Upgrade portions of the grid (such as 4kV system) to increase capacity, improve reliability, and address technology obsolescence • Advanced Capabilities: Automation to monitor and control grid equipment in real-time • Communication Networks: Expansion of fiber optic network and field area network for real-time data transfer • Technology Platforms: Foundational tools for forecasting and planning; management systems to operate the distribution grid Capital will be deployed to achieve two primary objectives • Improving safety and reliability  Focus on worst performing circuits in conjunction with traditional infrastructure replacement activities • Increase DER integration capacity and enable advanced operations on circuits with high forecasted penetration or where DERs can provide grid services 1. Forecast excludes capitalized overheads 2. Pending approval of memorandum account for 2016 and 2017 forecast and 2018 GRC decision for 2018-2020 forecast SCE Grid Modernization Forecast ($ billions) $2.3 Billion Capital Request for 2016-20201,2 Exhibit 99.1

September 2, 2016 13 Energy Storage SCE has already met the aggregate 2016 targets • CPUC Energy Storage Program: – 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) • First storage-only RFO completed November 2015 – Three contracts for 16.3 MW were submitted for CPUC approval in December 2015 • SCE filed its 2016 Storage Procurement Plan on March 1, 2016 detailing current portfolio and plans for second Storage RFO in late 2016 • SCE’s storage portfolio also includes SCE-owned pilots and demonstrations, customer programs, and storage procured through various solicitations • In response to CPUC Resolution E-4791, SCE recently issued the Aliso Canyon Energy Storage RFO for 3rd party-owned storage and a Request for Proposals (RFP) for sellers to design, build, and transfer energy storage facilities to SCE Exhibit 99.1

September 2, 2016 14 SCE Charge Ready Program • Electric vehicle Charge Ready Program Phase 1 pilot approved by CPUC January 2016 − Authorizes spend of $22 million on pilot implementation for charger installations and Market Education Programs ($12 million rate base) − Advice letter approval to spend funds granted April 2016 • Pro-active, two-phased program to support installation of up to 30,000 EV charging stations to be included in rate base – Phase 1: pilot for 1,500 chargers and market education program (2016 – 2017) – Phase 2: 28,500 chargers (2018 – 2022) • Addresses approximately 1/3 of forecast non-single family home charging demand in SCE territory in 2020 • Request for Phase 2 to be filed with CPUC after completion of Phase 1 − $225 million total rate base opportunity if Phase 2 follows Phase 1 approach SCE’s Charge Ready Program supports Governor Brown’s 2012 zero-emission vehicle Executive Order – 1.5 million EVs statewide by 2025 • Level 1 (120V) and Level 2 (240V) chargers (L2 with Demand Response capability) • 10 chargers per site minimum • Participants own / operate / maintain chargers • Capital cost per charging station: $11,200 Exhibit 99.1

September 2, 2016 15 SCE Large Transmission Projects Note: Total Project Costs are nominal direct expenditures, subject to CPUC and FERC cost recovery approval. 1. CPCN approved August 2016 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 FERC Cost of Capital Comparable to CPUC 10.45% ROE which includes: • Base ROE = 9.30% + CAISO participation + weighted average of individual project incentives • FERC Formula recovery mechanism in effect through December 31, 2017 Summary of Large Transmission Projects Project Name Total Cost Remaining Investment In-Service Date Tehachapi 4-11 $2.5 billion $180 million 2016-2017 West of Devers1,3 $1.1 billion $1.0 billion 2021 Mesa Substation2 $600 million $600 million 2020-2021 Alberhill System2 $400 million $360 million 2021 Riverside Transmission Reliability2 $230 million $230 million 2021 Exhibit 99.1

September 2, 2016 16 CPUC Cost of Capital 3 4 5 6 7 10/1/12 10/1/13 10/1/14 10/1/15 10/1/16 10/1/17 R a t e ( % ) CPUC Adjustment Mechanism Moody’s Baa Utility Index Spot Rate Moving Average (10/1/15 – 6/30/16) = 5.14% 100 basis point +/- Deadband Starting Value – 5.00% Return on Equity (ROE) adjustment mechanism extended through 2017 • 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, 2012 – 5.00% • CPUC extended Cost of Capital filing from April 2016 to April 2017 • CPUC approved the Joint Petition for Modification to suspend adjustment mechanism through 2017 in February 2016 CPUC Authorized Capital Structure Cost Common Equity 48% 10.45% Preferred 9% 5.79% Long-term Debt 43% 5.49% Weighted Average Cost of Capital 7.90% ROE set at 10.45%, independent of trigger mechanism Exhibit 99.1

September 2, 2016 17 $4.09 $3.91 (0.18) 2016 SCE EPS Midpoint Guidance EIX Parent & Other 2016 Core EIX EPS Midpoint Guidance As of May 2, 2016 As of July 28, 2016 Low Mid High Low Mid High EIX Basic EPS $3.82 $3.92 $4.02 $3.82 $3.92 $4.02 Less: Non-Core Items1 0.01 0.01 0.01 0.01 0.01 0.01 EIX Core EPS2 $3.81 $3.91 $4.01 $3.81 $3.91 $4.01 • Revenues based on GRC final decision • Energy efficiency earnings of $0.05 per share • Authorized CPUC capital structure – 48% equity; 10.45% ROE • FERC ROE comparable to CPUC ROE • No change in tax policy • 325.8 million common shares outstanding • MHI arbitration decision not included Key Assumptions2016 Earnings Guidance 2016 Earnings Guidance Reaffirmed 1. Non-core items recorded for the six months ended June 30, 2016 2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 2016 earnings guidance reaffirmed, though SCE will likely outperform and EIX Parent & Other will likely underperform current guidance Exhibit 99.1

September 2, 2016 18 SCE Growth Drivers Beyond 2017 Infrastructure Reliability Investment • Sustained level of infrastructure investment required until equilibrium replacement rates are achieved and then maintained - includes underground cable, poles, switches, and transformers1 Grid Modernization • Accelerate automation, communication, and analytics capabilities at optimal locations to integrate distributed energy resources into planning and operations • DRP required under AB 327 to identify optimal locations, additional spending, and barriers to deploying distributed energy resources – filed July 1, 2015 • On July 13, 2016, requested Grid Modernization memorandum account for proposed early stage capital expenditures Transmission • California ISO 2013-2014 Transmission Plan2 - approved Mesa Substation Project (system reliability post- SONGS and renewables integration) with target in-service date of 2020 • West of Devers (2019-2021) incorporated from prior Transmission Plans with target in service date of 2021 • Future transmission needs to meet 50% renewables mandate in 2030 – CAISO planning process underway Energy Storage • 290 MW SCE owned investment opportunity through 2024 SCE Charge Ready Program • If approved by CPUC, planned Phase 2 will deploy approximately 1/3 of charging infrastructure needed by 2020 to serve EVs at long-dwell time locations (other than single family residences) Transportation Electrification • Personal, mass transit, goods movement – CPUC Scoping Memo issued March 30, 2016 1. Source: A.13-11-0032015 GRC – SCE-01 Policy testimony; equilibrium replacement rate defined as equipment population divided by mean time to failure for type of equipment 2. Approved by the California ISO Board of Governors March 20, 2014 Exhibit 99.1

September 2, 2016 19 (0.3¢) (0.5¢) (1.4¢) (0.1¢) 0.3¢ 0.4¢ 0.3¢ 2015 SAR 2015 ERRA Settlement 2015 GRC Expiration of Prior Refunds Other CPUC 2016 FERC 2016 ERRA Changes January 2016 SAR FERC Balancing Account June 2016 SAR 16.2¢ 14.9¢ 15.0¢ 2016 System Average Rate SCE’s system average rate is lowest among the California IOUs (¢/kWh) 2 Comparative System Average Rates1: % Delta EIX – 14.9¢ -- PG&E – 18.2¢ 22% SDG&E – 20.4¢ 37% Note: Forecasted rates post 2016 are not provided because it is difficult to provide an accurate forecast of future rates. 1. Rates as of September 1, 2016 2. Includes public purpose, 2016 SONGS revenue requirement and other Exhibit 99.1

September 2, 2016 20 SCE Key Regulatory Proceedings Proceeding Description Next Steps Key SCE Proceedings Cost of Capital CPUC capital structure, cost of capital, and return on equity CPUC approved the Joint Petition for Modification to suspend adjustment mechanism through 2017; Filing of 2018 application in April 2017 Distribution Resources Plan OIR (R.14‐08‐013) Power grid investments to integrate distributed energy resources SCE plan submitted July 2015; CPUC scoping memo issued January 2016; three phases Integrated Distributed Energy Resources OIR (R. 14‐10‐003) Creating consistent framework for guidance, planning and evaluation of DERs Florio 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 reopened in May 2016 CPUC decisions on pending challenges to the SONGS Settlement Agreement Key FERC Proceedings FERC Formula Rates Transmission rate setting with annual updates ROE moratorium expired July 2015; settlement in place through December 2017 Other Proceedings Energy Storage RFO (A.15‐12‐003) Solicitation for 16.3 MW launched December 2014 Selection September 2015; Contracts submitted for CPUC approval on December 2015 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 originally focused on 1.5 million EV target; scope broadened March 2016 to address broader SB 350 transportation electrification objectives Q2 2016 workshops to be followed by Q3 2016 CPUC invitation for transportation electrification applications Exhibit 99.1

September 2, 2016 21 SCE Operational Excellence Top Quartile • Safety • Cost efficiency • Reliability • Customer service Optimize • Capital productivity • Purchased power cost High performing, continuous improvement culture Defining Excellence Measuring Excellence • Employee and public safety metrics • System 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 Exhibit 99.1

September 2, 2016 22 EIX is 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 EIX Competitive Strategy • Edison Energy – Position as Integrator for Energy-as-a-Service platform serving large commercial and industrial customers • Edison Transmission – Competitive opportunities outside SCE service territory and founding member of Grid AssuranceTM • Edison Water Resources – Desalination of brackish water and on-site wastewater recycling initial areas of focus Long-Term Industry Trends Strategy Exhibit 99.1

September 2, 2016 23 • Create energy services that help simplify and optimize energy needs for large commercial & industrial customers: – Help customers better assess and capture the value of energy optimization, paving the way for greater third-party energy services – Help customers manage through technological / regulatory changes Evolving customer needs and uncertainty around changing technologies, regulation and business models create a business opportunity for a trusted advisor role Changing Customer Needs The Opportunity: Trusted Advisor and Solution Integrator Edison Energy Focus: Commercial & Industrial Exhibit 99.1

September 2, 2016 24 Edison Energy: Acquired Businesses Summary • Provides comprehensive renewable energy advisory and procurement services to leading Fortune 1000 companies, universities and municipalities • Created a proprietary market access platform where it typically procures energy for its clients by negotiating multiyear power purchase agreements that help control energy costs and improve the environmental performance of their operations • A leading provider of custom energy consulting services for large, multiple site, commercial and industrial energy users with a focus on enabling them to achieve significant energy cost savings and control • Collaborates with clients to help them make strategic decisions to achieve their overall business objectives, offering consulting services in energy procurement, supply and energy asset management, utility bill payment and invoice auditing, energy data management, energy price risk management, regulatory support, renewable energy integration and energy efficiency/demand response • A full-service energy consulting, engineering and project development firm specializing in the analysis, design, development and installation of energy efficiency projects, green initiatives for building systems, and power generation solutions for optimization and environmental control • Focused on building HVAC and controls, new energy technologies, renewable energy, power plant environmental systems, and energy awareness and education • Hundreds of solar solutions designed and installed across 16 states, SoCore offers multisite retailers, REITs and industrial companies portfolio-wide solar solutions that provide energy cost savings and carbon reduction opportunities Exhibit 99.1

September 2, 2016 25 On May 9, 2016, six electric power companies announced the official launch of Grid Assurance, LLC, an independent company providing transmission sparing solutions for critical electric transmission equipment. The company is offering its subscribers a cost-effective way to enhance grid resiliency and protect their customers from prolonged transmission outages. • Grid Assurance will address potential high impact events on the bulk transmission systems: - It will own critical equipment with long manufacturing lead times to account for risk beyond what is covered by “operational spares” - It will provide secure, off-site storage in strategic locations, and support transportation of needed equipment to its subscribers - Subscribers will pay a subscription fee based on Grid Assurance’s costs. Subscribers will have access to inventory and will have the right to call on inventory following a “Qualifying Event” such as physical attacks, electromagnetic pulses, solar storms, cyberattacks, earthquakes and severe weather events - Regulatory construct will provide subscribers cost certainty as subscription fees will be calculated in a manner similar to FERC formula rates for transmission assets - Subscription to the sparing service will be available to all transmission owning entities • Grid Assurance is currently meeting with potential subscribers and identifying entities that will subscribe to the service; it expects to begin identifying inventory in 2016 Grid Assurance™ Overview Edison Transmission is one of the companies developing Grid Assurance Exhibit 99.1

September 2, 2016 26 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 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Note: See use of Non-GAAP Financial Measures in Appendix Twelve Years of Dividend Growth Target dividend growth at a higher than industry growth rate within its target payout ratio of 45-55% of SCE earnings in steps over time Exhibit 99.1

September 2, 2016 27 Appendix Exhibit 99.1

September 2, 2016 28 SCE Tax Memorandum Account • 2018 GRC continues tax accounting memorandum account (TAMA) established in 2015 GRC decision, which tracks tax benefits or costs associated with changes in: - tax accounting methods - tax laws and regulations impacting depreciation or tax repair - forecasted tax repairs deductions (actual vs. amounts authorized) - depreciation or tax repair deductions as a result of an audit; and - any impact of a private letter ruling related to normalization • Once a year, aggregate over or undercollection will be calculated and refunded to or collected from customers • $42 million regulatory liability at June 30, 2016; in Q2 2016, $206 million transferred to a balancing account for refund to customers Tax Repair Deductions Bonus Depreciation • No earnings impact associated with incremental tax repair deductions • No rate base impact • Flow-through rate making applies • Earnings impacts occur in relevant year of extension rather than next GRC cycle • Normalization rate making applies Tax Policy Rate Base and Earnings Implications Exhibit 99.1

September 2, 2016 29 SCE Historical Capital Expenditures ($ billions) $3.8 $3.9 $3.9 $3.5 $4.0 $3.9 2010 2011 2012 2013 2014 2015 Exhibit 99.1

September 2, 2016 30 Detailed Capital Expenditures – 2016-2020 2016 2017 2018 2019 2020 Total Core Distribution1,2 $2.9 $2.9 $3.2 $3.2 $3.1 $15.3 Mobile Home Park Conversion 0.1 0.1 - - - 0.2 Grid Modernization 0.0 0.2 0.6 0.8 0.7 2.3 Subtotal Distribution $3.0 $3.2 $3.9 $3.9 $3.8 $17.8 Transmission1 $0.5 $1.0 $0.9 $1.0 $0.9 $4.4 Generation1 $0.2 $0.2 $0.2 $0.2 $0.2 $1.1 Total $3.8 $4.5 $5.0 $5.2 $4.9 $23.3 Capital Expenditure/Rate Base Detailed Forecast Detailed Rate Base – 2016-2020 2016 2017 2018 2019 2020 Traditional Rate Base $24.9 $26.4 $29.3 $31.6 $33.7 Grid Modernization - - 0.3 0.8 1.4 Total $24.9 $26.4 $29.6 $32.4 $35.1 1. Includes allocated capitalized overheads and general plant 2. Includes $12 million Charge Ready Pilot (2016) and $69 million of Energy Storage (2016-2020; average $14 million per year) ($ in billions) Exhibit 99.1

September 2, 2016 31 Distribution Power Grid of the Future One-Way Electricity Flow • System designed to generate electricity from large central plant • Very few distributed energy resources • Voltage relatively simple to maintain • Limited situational awareness and visualization tools for power grid operators Renewable Generation Mandates Subsidized Residential Solar Lack of Electric Vehicle Charging Infrastructure Variable, Two-Way Electricity Flow • Distribution system at the center of the power grid • System designed to serve variable 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 Exhibit 99.1

September 2, 2016 32 Grid Modernization Framework SCE will leverage its automation and infrastructure replacement programs to implement circuit-specific solutions that improve safety and reliability, while updating the system for continued DER adoption Distribution Automation Installation of more sensors and intelligent switches on the distribution system Substation Automation Installation of next-generation substation protection controls and communication systems that enable grid devices to “plug and play” into the distribution system Communications Systems Upgrade/Installation of wireless and fiber optic networks to allow for safe and secure coverage of data transfer between automated devices across the power grid Technology Platforms and Applications Software investments for grid analytics, long-term planning and modeling Power Grid Reinforcement Acceleration of infrastructure replacement programs G r i d M o d e r n i z a t i o n July 2015 DRP Filing 2018 GRC Application Advanced Grid 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 to enable DER penetration and operation Technology Platforms Foundational tools for forecasting and planning; management systems to operate the power grid Increased Grid Capacity for DERs Upgrade portions of power grid to increase capacity, improve reliability, and address technology obsolescence Exhibit 99.1

September 2, 2016 33 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 Exhibit 99.1

September 2, 2016 34 CPUC 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) Exhibit 99.1

September 2, 2016 35 2015 - 2017 2018 - 2020 2021 – 2023 + Implement foundational information technology, communication systems, and system planning tools Enhance automation and improve interoperability with Distributed Energy Resources Optimize operation of Distributed Energy Resources and distribution market operation T e c h n o l o g y E x p e c t e d R e s u l t G R C C y c l e Align work management and develop workforce strategy Ramp up resources and develop talent pipeline Compliance, safety, and reliability; preparation for future power grid state New business opportunities enabled; full deployment of grid modernization New distribution system platform for distribution market operations P e o p l e a n d P r oces s SCE is evolving its DRP timeline based on January 2016 scoping memo, July 2016 memorandum account request and the 2018 General Rate Case application Grid Modernization Road Map Exhibit 99.1

September 2, 2016 36 SCE 2016 Bundled Revenue Requirement Note: Rates in effect as of June 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 14.3 14.1 14.3 15.9 16.7 16.2 Fuel & Purchased Power (43%) Distribution (39%) Transmission (9%) Generation (10%) Other (-1%) 2016 Bundled Revenue Requirement $millions ¢/kWh Fuel & Purchased Power – includes CDWR Bond Charge 4,928 6.7 Distribution – poles, wires, substations, service centers; Edison SmartConnect® 4,185 5.7 Generation – owned generation investment and O&M 1,080 1.5 Transmission – greater than 220kV 978 1.3 Other – CPUC and legislative public purpose programs, system reliability investments, nuclear decommissioning (211) (0.3) Total Bundled Revenue Requirement ($millions) $10,960  Bundled kWh (millions) 73,744 = Bundled Systemwide Average Rate (¢/kWh) 14.9¢ Exhibit 99.1

September 2, 2016 37 9.7¢ 16.2¢ 14.9¢ 8.0¢ 10.0¢ 12.0¢ 14.0¢ 16.0¢ 18.0¢ 20.0¢ 22.0¢ 24.0¢ 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 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 ¢/kWh 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 System Average Rate Historical Growth SCE’s system average rate has grown at inflation over the last 20 years SCE System Average Rate Los Angeles Area Inflation Exhibit 99.1

September 2, 2016 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 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, but rejected requests for increased fixed charges allowing 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 – June 2016 18.2¢ 40.8¢ 100% 101‐400% >400% 23.3¢ Usage Level (% of Baseline) ¢ / k W h Future Rates - 2019 Usage Level (% of Baseline) 15.7¢ 22.9¢ 29.2¢ 100% 101‐200% 200‐400% >400% ¢ / k W h Fixed Charge: $0.94/month Minimum Bill: $10.00/month Fixed Charge: $0.94/month Minimum Bill: $10.00/month Note: Graphs not to scale. 2019 rate levels are based on current revenue requirements Exhibit 99.1

September 2, 2016 39 SCE Net Metering Rate Structure 7¢ 24¢17¢ 0 5 10 15 20 25 30 ¢ / k W 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 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. SCE Net Energy Metering Statistics (June 2016): • 186,329 combined residential and non-residential projects – 1,463 MW installed (of 2,240 MW cap) – 99.8% solar – 181,762 residential – 947 MW (4.21% penetration) – 4,567 non-residential – 516 MW (0.66% penetration) • Approximately 2,528,064 MWh/year generated Exhibit 99.1

September 2, 2016 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 10 20 30 40 50 60 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2010 2011 2012 2013 2014 2015 2016 M W Installed N u m b e r o f R e s i d e n t i a l I n s t a l l a t i o n s Number of Installations MW Installed July 1, 2017 • NEM customers will be required to take service under mandatory Time-of-Use rate 2019 • Commission to revisit NEM Successor Tariff Key Dates Monthly Installations and MW Installed Exhibit 99.1

September 2, 2016 41 SCE Rates and Bills Comparison 13.1 16.5 US Average SCE 26% Higher 2015 Average Residential Rates (¢/kWh) 2015 Average Residential Bills ($ per Month) ¢ ¢ SCE’s average residential rates are above national average, but residential bills are below national average due to lower energy usage • SCE’s residential rates are above national average due, in part, to a cleaner fuel mix – cost for renewables are higher than high carbon sources • Average monthly residential bills are lower than national average – higher rate levels offset by lower usage – 41% lower SCE residential customer usage than national average, from mild climate and higher energy efficiency building standards • Public policy mandates (33% RPS, AB32 GHG, Once-through Cooling) and electric system requirements will drive rates and bills higher Key FactorsKey Factors Source: EIA's Form 826 Data Monthly Electric Utility Sales and Revenue Data for 2015 $127 $94 US Average SCE 26% Lower Exhibit 99.1

September 2, 2016 42 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 2011 29,631 39,622 8,490 5,206 1,318 84,267 3,071 87,338 4,301,969 546,936 11,370 46,684 22,086 82 22 4,929,149 19,829 22,443 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 YTD 2016 12,960 19,926 3,618 2,230 776 39,510 623 40,133 4,406,167 564,056 10,596 46,487 21,317 132 22 5,048,777 19,016 N/A Exhibit 99.1

September 2, 2016 43 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 • In order to meet the 50% RPS requirement by 2030, SCE will need to increase its renewable purchases by 20.2 billion kWh, or 110% Renewables Electric Vehicles 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 • Distribution power grid investments to meet EV impact Continuation of company programs and earnings incentive mechanism • SCE 2016 program budget: $333 million • $0.05 per share 2016 earnings potential Electric Power Company Role Solar 26% Small Hydro 2% Geothermal 37% Wind 33% Actual 2015 Renewable Resources: 24.3% of SCE’s portfolio Biomass 2% Exhibit 99.1

September 2, 2016 44 AB32 Emissions Reduction Programs Cap & Trade 22% Other 23% Low Carbon Fuel Standard 19% RPS 14% Energy Efficiency 15% High GWP Gases 7% California Cap and Trade Program • Assembly Bill 32 (2006) – reduces State greenhouse gas (GHG) emissions to 1990 levels by 2020 (~16% reduction) • Cap and trade program basics: – State-wide cap in 2013 – decreases over time – Compliance met through allowances, offsets, or emissions reductions – Excess allowances sold, or “banked” for future use – Linkage with Quebec cap and trade program in 2014, planned linkage with Ontario in 2018 • SCE received 31.4 million 2015 allowances vs. a financial exposure to only 24.5 million metric tons of GHG emissions that same year • Allowances sold into quarterly auction and bought back for compliance – SB 1018 (2012) – auction revenues used for rate relief for residential (~93%), small business, and large industrial customers Exhibit 99.1

September 2, 2016 45 Q2 2016 Q2 2015 Variance Basic Earnings Per Share (EPS) SCE $0.97 $1.18 $(0.21) EIX Parent & Other (0.11) (0.02) (0.09) Discontinued Operations (0.01)  (0.01) Basic EPS $0.85 $1.16 $(0.31) Less: Non-Core Items SCE $  $  $  EIX Parent & Other1 0.01  0.01 Discontinued Operations2 (0.01)  (0.01) Total Non-Core Items $  $  $  Core Earnings Per Share (EPS)3 SCE $0.97 $1.18 $(0.21) EIX Parent & Other (0.12) (0.02) (0.10) Core EPS3 $0.85 $1.16 $(0.31) Key SCE EPS Drivers Revenue4,5,6 $0.10 - CPUC – Escalation 0.09 - CPUC – Timing of GRC (0.06) - CPUC – GRC return on pole loading rate base 0.03 - CPUC – Other 0.01 - FERC revenue and other 0.03 Higher depreciation (0.04) Higher net financing costs (0.02) Income taxes5,6 (0.27) - 2015 change in uncertain tax positions (0.31) - Higher tax benefits 0.04 Other items 0.02 Total $(0.21) Second Quarter Earnings Summary Key EIX EPS Drivers EIX parent – Higher corporate expenses $(0.02) EMG – Sold portfolio in 2015 (0.03) EEG – Buyout of an earn-out provision, higher operating and development costs (0.05) Non-core items1,2 - Total $(0.10) 1. Impact of hypothetical liquidation at book value (HLBV) accounting method 2. Discontinued Operations: Legacy tax matter related to EME 3. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 4. Excludes San Onofre revenue of $0.02 and interest expense of $0.01 which were offset by income taxes of $(0.03) 5. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.04 6. Excludes $0.24 of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions Note: Diluted Earnings were $0.84 and $1.15 per share for the three months ended June 30, 2016 and 2015, respectively Exhibit 99.1

September 2, 2016 46 YTD 2016 YTD 2015 Variance Basic Earnings Per Share (EPS) SCE $1.85 $2.12 $(0.27) EIX Parent & Other (0.17) (0.04) (0.13) Discontinued Operations    Basic EPS $1.68 $2.08 $(0.40) Less: Non-Core Items SCE $  $  $  EIX Parent & Other1 0.01 0.02 (0.01) Discontinued Operations    Total Non-Core Items $0.01 $0.02 $(0.01) Core Earnings Per Share (EPS)2 SCE $1.85 $2.12 $(0.27) EIX Parent & Other (0.18) (0.06) (0.12) Core EPS2 $1.67 $2.06 $(0.39) Key SCE EPS Drivers Revenue3,4,5 $0.15 - CPUC – Escalation 0.17 - CPUC – Timing of GRC (0.12) - CPUC – GRC return on pole loading rate base 0.05 - CPUC – Other (0.01) - FERC revenue and other 0.06 Higher O&M (0.04) Higher depreciation (0.06) Higher net financing costs (0.03) Income taxes4,5 (0.29) - 2015 Change in uncertain tax positions (0.31) - Higher tax benefits 0.02 Total $(0.27) YTD 2016 Earnings Summary Key EIX EPS Drivers EIX parent – Higher corporate expenses $(0.01) EMG – Sold portfolio in 2015 (0.04) EEG – Buyout of an earn-out provision, higher operating and development costs (0.07) Non-core items1 (0.01) Total $(0.13) 1. Impact of hypothetical liquidation at book value (HLBV) accounting method 2. See Earnings Non-GAAP Reconciliations and Use of Non-GAAP Financial Measures in Appendix 3. Excludes San Onofre revenue of $0.03, interest expense of $0.01, and property taxes of $0.01 which were offset by income taxes of $(0.05) 4. Excludes revenue and income taxes for 2016 incremental tax repair deductions and pole loading program-based cost of removal of $0.17 5. Excludes $0.24 of refunds to customers for incremental tax benefits related to 2012 - 2014 repair deductions Note: Diluted Earnings were $1.66 and $2.06 per share for the six months ended June 30 2016 and 2015, respectively Exhibit 99.1

September 2, 2016 47 $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 $1,368 (370) $998 SCE Results of Operations • Earning activities – revenue authorized by CPUC and FERC to provide reasonable cost recovery and return on investment • Cost-recovery activities – CPUC- and FERC-authorized balancing accounts to recover specific project or program costs, subject to reasonableness review or compliance with upfront standards Earning Activities Cost- Recovery Activities Total Consolidated 2015 Earning Activities Cost- Recovery Activities Total Consolidated 2014 Operating revenue Purchased power and fuel Operation and maintenance Depreciation, decommissioning and amortization Property and other taxes Impairment and other charges Total operating expenses Operating income Interest expense Other income and expenses Income before income taxes Income tax expense Net income Preferred and preference stock dividend requirements Net income available for common stock Core earnings Non-core earnings Total SCE GAAP earnings Note: See Use of Non-GAAP Financial Measures in Appendix ($ millions) $6,831 — 2,106 1,720 318 163 4,307 2,524 (528) 43 2,039 474 1,565 112 $1,453 $6,549 5,593 951 — — — 6,544 5 (5) — — — — — $— $13,380 5,593 3,057 1,720 318 163 10,851 2,529 (533) 43 2,039 474 1,565 112 $1,453 $1,525 (72) $1,453 Exhibit 99.1

September 2, 2016 48 Earnings Non-GAAP Reconciliations Note: See Use of Non-GAAP Financial Measures in Appendix ($ 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 $384 (5) – $379 $ – 1 – $1 $384 (6) $378 $315 (37) (2) $276 $ – 2 (2) $ – $315 (39) $276 Q2 2015 Q2 2016 Earnings Attributable to Edison International $689 (11) – $678 $ – 6 – $6 $689 (17) $672 $601 (54) (1) $546 $ – 4 (1) $3 $601 (58) $543 YTD 2015 YTD 2016 Exhibit 99.1

September 2, 2016 49 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 $3.19 0.30 (0.12) — — — 0.18 $3.01 (1%) 7% $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 in Appendix $4.46 — — — (0.22) — (0.22) $4.68 $3.06 — — — (1.18) 0.04 (1.14) $4.20 Earnings Per Share Attributable to SCE 2010 CAGR2011 2012 2013 2014 2015 Exhibit 99.1

September 2, 2016 50 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 Exhibit 99.1